ML20147H892
| ML20147H892 | |
| Person / Time | |
|---|---|
| Issue date: | 12/11/1978 |
| From: | Office of Nuclear Reactor Regulation |
| To: | |
| Shared Package | |
| ML18078B291 | List: |
| References | |
| RTR-WASH-1400 NUDOCS 7812270412 | |
| Download: ML20147H892 (250) | |
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MEMORANDUM FOR: Harold R. Denton, Director - Office of Nuclear Reactor Regulation FROM: Victor Stello, Jr., Director l Division of Operating Reactors j
SUBJECT:
USE'0F WASH-1400 IN THE LICENSING PROCESS - ITEMS l
~ IDENTIFIED BY HAL ORNSTEIN I This is in response to your November 21, 1978 memorandum which requested an assessment of the items identified in the November 17, 1978 memorandum from S. Hanauer. The 11/17/78 memorandum lists ,
4 4tems that are.within the D0R work scope. ~These items were l presented in our November.22, 1978 memorandum to you which reported the results of our Division survey. The Ornstein items are 5, 9, 29/63 and 61. O V Item 5, D. C. Power Reliability, was identified by DSS and DOR. We concurred with the DSS assessment. The Ornstein recommendation I is the same, and is therefore acceptable. I Item 9 Reactor Vessel supports, was presented as D0R item 3 (Asymmetric Blowdown Loads). In Task Action Plan A-2, pipe break , probability estimates were used to support staff engineering I judgment for continued operation of affected plants; we did not recommend reconsideration. Therefore, we disagree with the Ornstein reconinendation. Item 29/63, Technical Specification Surveillance Frequencies, was identified by DPM as Allowable Outage Times for ECCS Components. In our 11/22/78 memorandum we stated that "we do not believe that reconsideration is warranted." Therefore, we disagree with the Ornstein recommendation. The " square root method" as noted by Ornstein, which apparently refers to common mode failure quantification, was not used in this. work.
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Nov < G78 Harold R. Denton ' Item 61, ECCS Analysis - Big Rock Point, was presented as 00R item 9. Ornstein's recommendation coincides with ours and is therefore acceptable. - No reconsideration is warranted. Victor Stello, Jr., Director Division of Operating Reactors cc: L. Nichols J. Miller B. Grimes D. Eisenhut R. Baer O __-_m.u.m ___. _
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NOV 2 21978 .- i MEMORANDUM FOR: Harold R. Denton, Director l Office of Nuclear Reactor Regulation FROM: Victor Stello, Jr. , Director ~ l Division of Operating Reactors
SUBJECT:
USE OF WASH-1400 IN THE LICENSIPG PROCESS We have completed our survey as you requested on October 30, 1978 Attachment 1 was provided to noted 00R staff. We have identified eleven items within the Division related to licensing l actions. A summary of these items is enclosed as Attachment 2. This summary contains a statement of each use of WASH-1400 logic or numerical gD i results or related methods and the category as determined by D0R staff. O Some difficulties were experienced among the staff in selecting a particular category. In those cases where the Division office thought a different category more appropriate for a particular item it is noted parenthetically. Each cognizant staff member has accepted readily the re-categorization by the Division office. We have identified one past practive as noted in item 6 that we may propose to change in the future. In our Fire Protection Safety Evalu-ation Reports we have routinely quoted a probability related statement from NUREG-0050 which references WASH-1400. This statement has been used merely to support the staffs' overall technical judgment. Attached are copies of documents received from the Division survey - Attachment 5. ITEMS PRESENTED BY OTHER DIVISIONS DPM has presented two issues that affect D0R. These are items 1 and 3, in the November 13, 1978 memorandum from R. Baer to H. Berkow - copy ~
' attached as Enclosure 3.
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NOV 21978 C Harold R. Denton ' Item 1 in the R. Baer memorandum is presented as 00R item 9 a. We have re-categorized this item as Category 4. Item 3 notes that technical assistance work by Science Applications made use of the ECCS fault trees and failure rates from WASH-1400. Using the quantitative results of modified fault trees on a relative basis, reported ECCS outage data, and judgment, slight increases in allowable outage times for some ECCS components for PWRs and BWRs were implemented in the standard technical specifications. 00R believes that this is a . Category 3 item. We do not believe that reconsideration is warranted. l DSS has presented 1 issue that affects D0R. This is item 1 in the November 16, 1978 memorandum from F. Rosa to R. Mattson - copy attached as Enclosure 4. On pages 15-16 of NUREG 0305, endorsement is given of the WASH-1400 probability of loss of electrical power following a postulated LOCA. We concur with the DSS classification as Category 2/3. We, too, believe it appropriate to reconsider this issue during com-pletion of Task Action Plan A-30, " Adequacy of Safety-Related Power Supplies." Victor Stello, Jr. , Director i Division of Operating Reactors Attachments:
- 1. Survey Memorandum I 2 Summary of 00R Uses )
- 3. Nov.13,1978 Memo !
- 4. Nov. 16, 1978 Memo l 5 Documents l -
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l, ATTACHMENT 1
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I MEMORANDUM FOR: Branch Chiefs Division of Operating Reactors FROM: Victor Stello, Jr. , Director Division of Operating Reactors l
SUBJECT:
USE OF WASH-1400 IN THE LICENSING PROCESS l
.1 The attached memorandum from Mr. Denton mquests that we survey the staff to identify licensing and,other regulatory actions or staff positions that have used or referred to the risk assessment models and results of WASH-1400 since August 1974. Please read the instruc-tions in the attached memorandum carefully and provide Landon Nichols with the requested information in a coordinated response for each D0R branch by c.o.b. November 15, 1978. Each branch chief should provide his recomendation for categorization,of each identified item, as noted in the attachment.
V All staff should, of course, consider past as well as present work
. assignments. This is most applicable to our project management staff.
If identified documents as noted in the attachment are " classified," as may be the case in Reactor Safeguards, please provide the title and date of the documents, a brief summary of the subject, and I categorization; hold the documents. ' The AD for Engineering and Projects should prepare a coordinated response for the STS Group. Technical Assistants should respond through their supervision, s
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V Ll Y VictorStelio,Jr., irector Division of Operating Reactors Attachment 10/3 W78 memorandum from H. Denton - cc: B. Grimes T. Telford J. Miller W. Russell (~} tg D. Eisenhut J. Carter W. Pasedag L. Nichols
1 November 20, 1978 p ATTACHMENT 2 V
SUMMARY
g Division of Operating Reactors Use of WASH-1400 In The Licensing Process
'l . Safeguard Vital Area Analysis -
LASL under technical assistance contract to the NRC is using fault 'l tree and event tree logic in analyzing nuclear plant vital areas. Fault trees from WASH-1400 have been used as part of the overall l logic structure. No numerical estimates from WASH-1400 have been used. Category 5. j O e
- 2. Staff Testimony at Clearance Rule Hearings The staff referred to the " consequence tables" in WASH-1400 during presentation of testimony. This reference and other remarks about the Reactor Safety Study were in the ontext of responding to inquiries by the Board of the maximum consequences of an act of sabotage to a nuclear power plant. Also, in response to Board questions it was stated by the staff that WASH-1400 contained comparability data such as " dam failures and consequences from fires and earthquakes- ." Category 4: (Note: this does not fall into any of the 5 categories; no reference was made to risk). -
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l l O b 3 ,' Asymmetric Blowdown Loads - Task A-2 j On page A-2/6 of the Task Action Plan, Rev. No.1, May 1978 pipe I failure probability estimates from WASH-1400 were used as infor-I mation supporting the staff engineering judgment for continued operation of affected plants, Category 3, - 1 4 Safety Evaluations - Steam Generator Tube Integrity Pipe failure probability estimates from WASH-1400 were used as supporting information to the engineering judgment of the staff ) for continued short-term operation of 3 reactors experiencing steam p i 1 Q generator tube failures, Continued 60 day operation was granted to Surry 1, February,1977; Turkey Point 4, February,1977; and Surry 2, April, 1977 The amendments to these facility licenses are no ; longer effective. Category 3, 5 Extension of ECCS Exemption - Dresden 1 Supporting information to the staff's engineering judgment was obtained by constructing simp 1tfied fault trees of selected ECCS equipment, and deriving numerical probability estimates using failure rates from WASH-1400, Exemption from 10 CFR 50,45 was extended from 12/31/77.to10/31/78. The results of the probability logic were not used in the SER, Category - Not Applicable, (Note: This should O be classified as Category 3),
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l l 4 V 6 Fire Protection-SERs ; All Fire Protection Safety Evalution Reports contain a quote from y the review group report on the fire at Browns Ferry (NUREG 0050). l The quote is in part, "the study (WASH-1400) concludes that the l potential for a significant release of radioacitvity from such a - fire is about 20% of that calculated from all other causes analyzed." This quote has been part of the staffs bases for allowing continued operation of the facilities until implementation of facility modifications, Category 3,
- 7. Overpressure P'rotection - Haddam Neck Following the hydraulic system review of the Overpressure Protection System (OPS) for Haddam Neck the staff has tentatively accepted the results of a quantitative fault tree analysis as supporting basis I for omitting as a design base transient inadvertent water injection into the primary system through the high pressure safety injection. .
1 pump-(HPSIP). The fault-tree was constructed primarily of possible operator errors that may combine to cause the event. Failure probabilities were taken from WASH-1400. The pressure relieving equipment installed for the mitigation of j other potential overpressure scenarios would not totally mitigate O) 1 v 1
l l (3 4-the HPSIP mass input event, The peak RCS pressure during a postulated HPSIP injection would be about 35 psig above the Technical Specifications Appendix G 11mit.. The licensee pro-vided as requested by the staff value-impact assessments for the installation of additional equipment arrangements to totally mitigate a potential HPSI event, Based on the HPSIP probability estimate, the value-impact assessments, the fact that other pressure relief equipment keeps the peak RCS pressure to within 35 psig of the limit during the HPSIP mass input event, and the use of administrative controls, the staff has tentatively concluded that additional hardware need not be installed to totally mitigate a HPSIP event. A final staff acceptance of this tentative position will be made after completion of the staffs review of the applicants' proposed electrical and control system. No licensing action has been taken. Category 5 '(Note: this may be construed to be a Category 3 item.
- 8. Continued Operation of Vermont Yankee For a 30-day period beginning February 13, 1976 continued operatton was allowed until hold-down devices were installed on the torus, The licensee presented as supporting information pipe failure pro- _
babilities from WASH-1400 The staff, with more conservative failure pg estimates, effectively endorsed probability values as supporting b
1 information to the staff judgment in granting continued operation. ;; Other factors affecting staff judgment were the AP mode of . operation, recent inservice inspections of affected piping, and shortperiodoftime(30 days). Category 1. (Note: this should be classified as' Category 3). - O . l O
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- 9. Big Rock Point ECCS Exemptions
- a. Big Rock Point.'s (BRP) ECCS System is composed of Ring Spray and Nozzle' Spray Systems, each having separate risers and motor operated .
isolation valves (MOVS). BRP requested, and was granted a lifetime l exemption from the single failure criteria of Appendix K as applied - to the LOCA caused by a break in either spray system concurrent with the failure of the other spray system. Additionally, CPCo was granted one cycle (cycle 14) exemptions which included exemption i from the Appendix K single failure criteria as applied to LOCA concurrent with a failure of the Ring Spray System. The one cycle exemption was requested since the NSS performance could not be substantiated-in light of recent test data, and CPCo was given until Cycle 15 startup to perform tests verifying the adequacy of the NSS. The cycle 14 exemptions have been terminated. The staff used failure rate estimates to support technical judgments Category 5.(this should be classified as Category 4).
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of the ECCS.
- b. More recent test information showed that even ring spargers similar to BRP's RSS may incur performance degradation in a steam environ-ment. Therefore, CPCo was requested to substantiate the performance of.the-RSS, but could not. CPCo requested a one cycle exomption from the single failure criteria of Appendix K as applied to failures of the NSS, since this would result in total reliance on the RSS
'for core cooling. The staff evaluated the probability of a non-refloodable LOCA and the failure of the NSS, and the probability
( : of a LOCA in the NSS (refloodable LOCA) and the failure of the .) feedwater system. The staff's recommendation that the one cycle
'1 exemption be granted was not based on these probability assessments alone. Several other factors related to the BRP ECCS performance and reliability were considered by the staff, and our conclusions 4 reflect an integrated assessment. Category 5. (Note: this should I be classified as Category 3).,
- 10. San Onofre Limited Time ECCS Exemption Component failure rate data from WASH-1400 were used as bases to support an exemption for 6 months from the single failure criteria.
The exemption has expired. Category 1. (Note: this should be classified as Category 3),
- 11. Fracture Toughness and Potential For Lamellar Tearing - Task A-12 On page A-12/3,4 of the Task Action Plan, Rev. No.1, May 1978 pipe failure probability estimates from WASH-1400 were used as information supporting the engineering judgment of the staff for continued plant operation. Category 3.
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MEMORANDUM FOR: Herbert Berkow, Program Assistant to the Director, - Division of Project Management 3 FROM: Robert L. Baer, Chief, Light Water Reactors Branch No. 2, DPM
SUBJECT:
USE OF WASH-1400. IN THE LICENSING PROCESS This memorandum is written in response to Roger Boyd's and Harold Denton's I ' memoranda of October 30 and November 1,1978 on the same subject. I have J been involved in three regulatory actions that have made scme use of the results and/or methodology of WASH-1400. These are discussed individually below.
- 1. Big Rock Point (Category 5)
In 1976 Consumers Power Compang (CPCo) requested an exemption from the ECCS single f ailure criterion of 10 CFR Part 50.46~, and Appendix K, Paragraph I.D.l. As one aspect of the staff's review, we requested CPCo to provide estimates of failure t probabilities for the combination of LOCA events and various
\ postulated failures in which the single failure criteria was not fully satisfied by of the design of the Big Rock Point Nuclear Power Plant. The staff evaluated the information provided by CPCo and also performed on independent assessment using methodology similar to that employed in WASH-1400. This effort would be designated to be in Category 5 in accordance with Mr. Denton's memorandum.
A discussion of the staff's review is contained in Enclosure 1. The specific discussion of probabilistic analyses is presented on pages 3 through 7 of that Enclosure. It should be noted that the staff's recommendation to the Commission regarding
. granting of an exemption to Big Rock Point considered many aspects of the issue, not only the probabilistic analyses performed by CPCo and the staff. Enclosure 1 contains the following paragraph:
"Although the staff has based it recommendation upon technical judgment relating to the perfor-mance capability of the entire ECCS and existing design. margins at Big Rock, it has also performed I an independent assessment of the reliability of certain systems installed at Big Rock to provide p
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core cooling in the event of a LOCA resulting i from a break in one'of the core spray lines. As part of this assessment, the staff estimated the failure probability of the valves in the core-
i l l 'g/ Herbert Berkow r; , , ,, 1 spray lines, combined with estimates of spray line break probability and failure probability , of other portions of plant systems that can ' provide core cooling. The use of failure ' estimates was one aspect of the staff assessment used to provide a better understanding of system reliability and plant safety." l
- 2. Branch Position on Residual Heat Removal (Category 2) ,
The results of WASH-1400 showed that transient events were a major contributor to the probability of core melt. For PWR's, transient events represented a major contributor to the probability of core melt for release Categories 2 and 7.* In both of these categories, failure to remove decay heat after successful reactor trip was calculated to be a more probable cause of core melt than failure to trip the reactor. Transient events for BWR's represented the major contribution to core melt probability for release Categories 1 through 3.** pi For Category 2 releases, the probability of core melt as a result i of the failure of decay heat removal systems was calculated to be I gd greater than the probability due to failure to render the reactor suberitical. For Category 1 and 3 releases, WASH-1400 calculated , the two probabilities to be within a factor of two of each other. ' Based on the results discussed above, it appeared to me that the design requirements for systems that remove decay heat in nuclear power plants should be evaluated to determine whether additional requirements should be imposed. A task group was formed and this eventually lead to a position on residual heat removal systems that was approved by R %. It should be noted that neither the numerical data or methodology of WASH-1400 was used to develop the position. Rather, the results of WASH-1400 showed a potential need for increased requirements in this area._ Of the categories listed in Attachment 1 of Mr. Denton's memo, Category 2 is the most appropriate.
*There were eight release categories associated with PWR core melt events with with Category 1 being the most severe.and Category 8 being the least severe.
A d- **There were four release categories associated with BWR core melt events with Category 1 being the most severe and Category 4 being the least severe.
[J t . Herbert Berkow , " 'M 1 1"" l l
- 3. Allowable Outage Times for ECCS Components (Category 2 or 5) J The allowed outage times for components in safety systems are q included in the plant technical specifications that are part of '
the plants operating license. These have been based largely on i engineering judgment. ! In order to help determine whether reliability and probabilistic techniques, such as those used in WASH-1400, could be extended to establish allowable outage times on a quantitive basis, two contracts were awarded to Science Applications, Inc. (SAI). The first contract was awarded in February 1975. The first phase of this contract was completed and a final report on this effort issued on August 1975. The second phase of the contract was cor'"ed and a report issued in July 1977. The second contract wa: o ied in March 1977 and a report was issued in June 1978. The .cracts were limited in scope to investigating the feasi-bility of extending WASH-1400 techniques to the quantification of allowable outage times for ECCS components. The first phase of the initial SAI contract addressed the Peach Bottom and Surry Nuclear Power Plants which were the,two plants analyzed in WASH-1400. The fault trees for safety systems involved in a LOCA, were reviewed for their modeling complete-ness and quantitive adequacy with regard to their application to allow outage times. As a preliminary basis for these evaluations, conditional systems unavailabilities were calcu-lated in which one component was assumed to be down for servicing. The second phase of this contract extended the application for conditional unavailabilities to a RESAR-3 Pressurized Water Reactor (Trojan). Fault trees were drawn for the LOCA safety systems for the Trojan Nuclear Power Plant and conditional
, availabilities were again calculated for every major component in the system.
The fir'al SAI contract was an extension of the initial contracts and involved investigating possible ways system unavailabilities could be used in establishing allowable outage times. Information and data requirements were investigated and theoretical approaches were reviewed for possible specification of values and ranges of al.lowable outage times.
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l 1 i l Herbert Berkow.. -' ( r ; ,;g . The only. direct _'use of the results of the SAI studies in the licensing processithat I am aware of is report in Enclosure 2. This memo recommends relatively slight increases in allowable ' outage times for some ECCS components and has been implemented in the standard' technical specifications. As noted in this ' document, the results of the first SAI contract were used as one input that. led to slight revisions of the allowable outage times. An equally important input was a survey of:the actual frequency of ECCS outages during the period from about January 1, 1974 to about September 30, 1975. This effort j could be placed in either Category 2 or 5. g?,4,y'x ,L. Robert L. Baer, Chief Light Water Reactors Branch No.-2
- Division of Project Management 1
Enclosures:
As Stated
. cc w/o enclosures:
D. B. Vassallo P.. Check N. Anderson C. Berlinger T. Novak / - C. Graves #. / L. Nichols e 6
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! ATTACHMENT 4 NOV 101978 MEMORANDUM FOR: Roger J. Mattson, Director Division of Systems Safety FROM: Faust Rosa, Chief Power Systems Branch, DSS l , THRU:
Y. for Benaroya, Acting Plant Systems, DSS Assistant Director \
SUBJECT:
USE OF WASH 1400 IN THE LICEMSING PROCESS The following list presents the reguiatory actions and supporting docu-ments identified by Power Systems Branch in response to your October 30 request on this subject. Thecategorizationis(inmyopinion)in accordance with the definitions in Enclosure 1 of H. R. Denton's memoran . J dum to the Division Directors dated October 30, 1978. Reculatory Action / Document _ Category * (None) 1
- 1. NUREG 0305 " Technical Report on DC Power 2(also3) '\
Supplies in Nuclear Power Plants" (see N pages15-16)
- 2. "The Reliability of the DC Power System" 2(also3.5)
(presentation to the ACRS, 7/15/77. F. Rosa) s .
- 3. Memo to R. F. Fraley from F. Rosa " Technical 5(also4) '
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Safety Issue f24 NUREG 0153 Grid Availability / . GDC 17 Requirements" -
- 4. Memo to M. Kehnemuyi.from R. Tadesco " Review 5(also4)
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of Regulatory Guide 1.63 Working Paper"
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*5. Task Action Plan A-25 "Non Safety Loads on (3,4,5)
Class 1E Power Sources"
*6. Task Action Plan A-30 " Adequacy of Safety- (3,4,5)
Related Power Supplies"
- Action not yet completed, but will probably ' '
fall into one or all of categories indicated. 5
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t Roger J. Mattson l'N 1 C G76 I have reviewed the above docicents and do not feel that these actions should be reconsidered in view of the Lewis Committee reconnendations, except for Items 1 and 2. Since Item 6 is the followup action to the problem (Adequacy of DC Power Supplies) addressed by items 1 and 2, this reconsideration can be perforr.ed in the course of conpleting this item. A copy of each item (except (1) is attached. Faust Ro(ta, \ Chief ' Power Systems Branch i Division of Systems Safety l
Enclosure:
As stated O i DISTRIBUTION: CENTRAL FILE NRR READING PS READING PSB READING RFITZPATRICK READING tO V DSS:PSB DSS:PSB DSS: RFitzpatrick:s1 FRosa RBenaroya ,. 11/16/78 11/ /78 11/ /78
t ATTACHMENT 5 I O I DOCUMENTS AND t6 GENERAL SURVEY INFORMATION RELATED TO "USE.0F WASF 1400"
' IN
- DIVISION OF OPERATING REACTORS
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REF: Memorandum From V. Stello to H. Denton, , dated 11/22/78 j l l I l I l 1 l 4
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%, *... / p 14 sa MEMORANDUM FOR: Landon Nichols Division of Operating Reactors FROM: Robert A. Clark, Chief Reactor Safeguards Licensing Branch Division of Operating Reactors
SUBJECT:
USE OF WASH-1400 IN THE LICENSING PROCE">S As requested by the Director, Division of Operating Reactors, October 31, 1978, the following Branch activities are identified as having used infor-mation in WASH-1400: (1) Safeguard Vital Area Analysis b(g As a part of the 73.55 security plan review, the staff is making a I confinnatory evaluation of Type I vital areas for all operating reactors and for 0.L.'s. LASL engineers perfonn the analysis using methodology developed by Sandia Laboratory under contract to AEC/NRC. The methodology first appeared in the Sandia Reports '_' Safety and Security of Nuclear Power Reactors to Acts of Sabotage (U)" Part 1, 2, and 3, March 1975, classified Secret-NSI and is strongly dependent upon fault tree / event tree logic. The improved (i.e. enlarged) version of this methodology that has been developed and is now being used by LASL, with Sandia assistance, has not been documented in a report or user's manual . The improved version has added many of the fault trees / event trees from WASH-1400 in developing the " generic" fault trees / event trees for PWR's and BWR's. None of the probability or reliability infor-mation is used in this analysis and there is no reliance on specific numerical estimates of WASH-1400. The results of the evaluation are transmitted from LASL to RSLB in a letter report that is withheld from public disclosure in accordance wi th 10 CFR 2.790(d). The site specific fault trees / event trees are - classified as Confidential NSI and are kept in approved security repositories at either LASL or RSLB. O This reference-is judged to fall in Category 5. 1
l l l ( d k l Landon Michols fiOV 141978 , 2.. Staff Testimony At Clearance Rule Hearings WASH-1400 was referred to in the hearings on the proposed Part 11 l as enveloping the worst possible consequences of sabotage. In thic ' context, neither absolute nor relative use of the fault tree / event l tree analyses was made, only the maximum consequence estimates of l WASH-1400 were referred to. This reference is judged to fall into l Category 4. i-i 4 Robert A. Clark, Chief Reactor Safeguards Licensing Branch Division of Operating Reactors, NRR v
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1 I N UCLE AR REG UL ATO R Y COM/AISSIO N r, 1 IN THE MATTER OF: . I Rulemaking, 10 CFR Parts 11, 50 & 70 s Docket No. RM 50-7 l Place - Washington, D. C. Dat'
- Wednesday, July 12, 1978 Pages 422-557 i
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(202:3474700 ACE .~EDERAL REPORTERS. INC. 0llicial Reporters ua Ner a Caci cl Pravt
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l 4 i I, and sa_'ety was also of concern. And we have addressed both g-s 2 [ issues in this proposed regulation. ( ) 3 i DR. HALL: What are the consequences , t".en, which i
! ~ 1 4 are contemplated in the licensing of a nuclear power plant? l i
5 The national, maximum, consequences? 6 MR. JONES: The maximum consequence would be the 7! ccre meltdcwn and the releases indicated in WASH-1400. I think i 8' Jim can address th a t . ! 9 MR. MILLER: I think the references to WASH-1400 ll l I 10 , were given earlier this morning and, of course, there are 11 consequence tables. We are implementing the physical security , 12 , as was mentioned I believe on Monday to prevent a sabotage gg 13 event that could lead to a release of the magnitude of Part
%- 1 14 100. l l
15 MR. EALL: You are saying physical security measures 16 to prevent? i 17 MR. MILLER: Tha: is correco. 18 MR. EALL: So that even if there were an insider 19 with evil incent he couli not acccmplish this' ' i 20 ' MR. MILLER: That is the charter that is given in 21 7355, an insider is incluc.ed in two different places; in 7355 i j 22 (a) (1) , wherein the insider assists in an active fashion and l . 23 passive. f ashion to the external threat; and in 7355 (a) (2) . i
,d l wherein he acts alone.
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DR. EALL: So, then, the clearance program
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'is ' slated to be an overlay on top of that; is that correct?
I O t 2' ~ MR. MILLER: . In the case we are talking about
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we -- it is the Staff's position that the clearance program d will go a long way in preventing the internal threat from 5 existing. There are other measures , of course. Many of the 6 plants , the newer plants , are constructed such that they have 7' dual safety trains separated by walls, if you will. j
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8 This is what we talk about when we talk about 9
"ccmpartr.entali zation" . .
I i 10 i There are, as you know, redundant systems in all II of the plants f o r s afe ty . These are separated within plants ; 12 by walls , although some are not. 13 DR. HALL: I )\ Well, the position of NRC is that you \s- i Id I cannot grant a license unless the plant can operate with a i l 15 high degree or a reasonable degree -- could you supply the ' l 16 ' i t correct words -- relating to safety of the general public? i I7 f MR. MILLER: I believe the correct words where 18 safety is concerned as " reasonable assurance"; the correct I l' words in 7355 as far as physical security is concerned is I 20 '
"high assurance" .
21 DR. EALL: The question which has been raised
.22 and I thin.t =ust be discussed in these proceedings is , if you -
22 , have already provided for that assurance, why do you need ' 24 t3;3 - additional assurance? Why does the S taff feel it? ly)mn.ine.
,c MR. MILLER: As far as the sabotage event is 4
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concerned with the publication of 7 355 in effective form ("'s y; was as. f ar as I can remember the first time that the question -( 3 of active participation -- if I may use that word -- of an l 4:
" insider" was addressed. -
5 On ' daat basis the S taf f at that time took the cosition 6' that for those sensitive areas in a nuclear power plant -- I' I we use the term " vital" areas, there needs to be additional
- 3 protection against the " insiders " .
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'i 9 We proposed two alternatives , and we then of fered to I 10 i the industry to propose other alternatives. ,
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We proposed the two-man rule for those areas in 12 addition to the access requirements such as a determination of ! j (~' q 12 need to enter the area, special locking devices for the doors ;
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1 14 we also proposed to further compartmentalize, lock, if you
.15 I will, the separations of two trains , or the caging, or some way l 16 l
of protecting of vital equipment. , i .i 17
' t Since that time we have had several alternative i s 18
, propcsals by industry thathave been quite extensive. They 19 :
. involve the furuher securing of individual cabinets ; in some i 20 f
cases, we believe this is acceptable, in other cases plant , 21 designs are such that they do not lend themselves to this. Therefore , we feel as an alternative , as has been .
'3 rentioned, would be to increase the trustworthiness and relia-ta o.oo,mt be. i bility. of ~ the employees .
23 Therefore, we have proposed the new ;
+ .
4
~ . _ ,
t I clearance for those individuals who must according to the y-~ I 2 utility go unescorted into the vital areas. g 3 DR. HALL: The way you have described that sounds i i 4 as though it were an alternative, and you consider it as such? , 2
.5 XR. MILLER: For unescorted access , as we have .
6' said, and I believe it is item 5 on the board, we have offered 7 to several utilities as an alternative to two-man rule , the J 3 proposal that they provide a U-clearance for their employees . i 9 As you are well aware, I am sure, -- 10 DR. HALL: No, I am not. 11 - MR. MILLER: I am sorry? , 12 DR. HALL: I should make myself clear: is the
.g
) I3 clearance program an alcernative to meeting the requirements ,
i Id of 73.55? 15 If I may comment on that? MR. JONES: ) 16 I 1 The statement of considerations that was issued : I7 with 73.55 stated that the licensee as an interim measure - l l l l l I8 ! should use ANSI 18.17 until the Commission decided on the kind i l If I 19 of an access authorization program that promulgated the regs 20 i for that. So 73.55 initially did include the aspect of some
,I type of neasure or determination of employee trustworthiness
-e
" and reliability, as stated in the statement of considerations ' -
j of 73.55, this was a part of' the original regulation. ! t
/N 's ;
( ,- semmn. ine. DR. HALL: 'All right. . l
" .5#
i Sut,'Mr. Jones , you understand what is bothering I
t l- me? (% (d( 2 MR. . JONES: It is an added measure of' assurance, 3 and it was always included, that the trustworthiness of the l 4 individuals in these vital areas was always considered as one l; l 5 of the necessary aspects of the total security program. There - l
! 6' are tradeoffs.-
~
l f 7 DR. HALL: The problem is, the reactor has been 3 designed, analyzed and accepted as being able to operate I 9 such that the maximum accident will not endanger more than a i 10 certlin amount. I leave it to you. 11 hui you have then added provisions such that no one 12 persen inside operating from within the reactor can cause an
. 1
\ 13 accident greater than that amount for which it has been ; l
)
14 analy:ed to be safe. l t 15 Now, I am asking for the rationale o'f the added i i 16 , personnel clearance program which' was being put forward as ; i 17 ! being an' additional insurance or an added necessary insurance 18 ' above that which has already been laid on; and this is still 19 addressing the ' question asked by the Commission 'in Item No. 1. ' l, 20 ] MR. JONES: Well, when you say we have designed ; i 21 , the plant so that' an insider cannot cause an accident, this is i 22 l not strictly true; in that the plants .are aasigned with ~ l 23 redundant' safety sys tems 'so that the accidents do not occur.
/ , !
'd
(('))%.mn.ine. But new we are not talkina about' accidents . We are now talking 25 ;about s abo tage . 1 1
-w,
1' DR. HALL: Let me go back then to this report.
.,-~~ , 't A ,)i 2 .i Is this report. co be . accepted that says an act of sabotage can I
j
. 3 -
be no greater than that which has been included in the envelope l
~
4 . . of accidents concerning the licensing? - 5 MR. JONES: I believe I am correct tha t HASH-1400 6 is not the' criteria for licensing reactors. 7 DR. RALL: Gran te d. 3 l MR. JONES: All WASH-1400 says is that they have ! ] I 9 addressed the maximum occurrence, and a saboteur could not cause! { l to l anything a re th an tha t . They are not saying that a saboteur I '
? l 11 could not cause that.
l . 12 DR. HALL: I understand. {\s l' 13
/ What is.your, or the Staff's positien, do you accept la Ii i
this report by the Sandia
- aboratory as being reasonable and ;
i 15 i accurate? i l - l
'6 MR. JONES: Yes. . I 1
- 17 t !
l DR. HALL: So that a saboteur could not cause la
.an accident greater than that which is centemplated in the i
19 Safety Analysis Report? l 9
'0 l l
MR. JONES: Right. Correct. i 2 I DR. HALL: Which is to say, I agree with you that it is.imolied he could cause at le as t that. i 31 MR. JONES: Yes. [N g, !
\ 2 I .DR. HALL: But no more than.
v p e,comn.' me. ; . .
-)
! ' '3 l-4
! MR. JONES: But no more than.
i e
.I l
l I l But th at accident is a considerable catastrophe. , V 1 2, .DR. HALL: It certainly is a considerable catastrophe 3 ' to the utility . i . MR. JONES: And to the general public. 5 DR. RALL: And to the general public; but not to the 6 nation and not to the government? 7 XR. JONES: Not to the government , that is, it is 3 a cuestion that has been raised; and one point I might make which 9 is, that all nuclear power reactors are included in the i i i 10 Cepartment of Defense Key Facilities List, which -- let me be II careful I don' t talk about classified information -- l 12 DR. HALL: Probably targeted by Russia, too. ! 1
/N (j I3 MR. JONES: Well, the power function of the utilities I l ' - Id i is considered as well, as a part of the defense of the country; .
15 of course, if you took them all out; you are talking about ! I
~
l 16
, just one: okay, how far do you go? Nevertheless , nuclear I
I7 i power plan:s are considered, are listed in the COD Key i 18 l ,
. Facilities List.
I9 DR. HALL: That extends to all generating f acilities I 20 or major generating facilitie.s? ! I 2I MR. JONES: Righ t. l 22 DR. HALL: Whether nuclear or fossil or hydro, does - 23, it not? ' (st y* l
.: MR. JONES: I believe that is correct.
\s)Heemn, J ne. ,
t
*5
, CEAIRMAN t/ERKUIL: Which would not be an adequate
! 1 i i 4
i
.f 1 rationale I suppose for. imposing the same sort of security l ,r ^ !
. requirements on every other utility?
( 2 3 MR. JONES: Well, as I said our major concern in j d radiological sabotage is public health and safety, exposure, 5 hazardous exposure to radiation resulting from reactor sabotage. 6' CRAIRMAN VERKUIL: So in your need under number one, 7 you are really not relying on the common defense and security I 3 basis' 1 l 9, MR. JONES: No, i I 10 CHAIRMAN VERKUIL: I see. i I II You are relying as a basis for justifying this 12 rule, the need for this rule, you are relying on public health j l I i I3 and safety? Id MR. JONES,: That is correct.. 15 MS . FRINGS : Mr. Jones,withregardto--becauseI,! I 16 as an attorney, and a layman on nuc' lear matters I know little ! 1 17 cr nothing about the technical details of a nuclear pcwer plant;! 18 ' so I wonder if ycu could explain for the benefit of those of 19 us who don't quite understand all of the technical details , i I i 20 I would like to know if- the maximum radiological sabotage l t I 21 incident were to occur at a nuclear pcwer plant, and we do have 22 an emission of radiation of the maximum amount, let us say, l 1
- 23. 1 ceu;d scme one erv . to exclain in layman's terms what kind of fs j -
'2d i a health or safety risk is going to occur? !
\ -
'_,~._ -a. . '
25 '- There is going to be radiation: what will the I '
,1
. . _ - _ _ - l
li consequences be? Will there be an immediate hazard to people f~g ( ) 2 who live ~~ in a certain radius ? Will there be a long- te rm t x_/ l 3 possible disease impact upon people? 4 I really don't have any concept of what is going 5 to happen' l 6 MR. JONES: Bo th . 1 1 7 MS . FRINGS : Bo th? So, what sorts of things? 3 You know, I have read about, for example, as a i i 9 consequence of an atomic bomb exploding, which is different? 10 MR. JONES: That is different. Il MS. FRINGS : So, is it ' anything comparable? Or what 12 other kinds of results would occur? 13 MR. JONES: The consequences are not quite as great ( Id ' or as great as an atomic bomb. Do you have data? 15 MR. MILLER: I think I would refer you e WASH-1400 16 , and the consequence tables that are in that document. l I 17 ;i DR. HALL: I don't think that is a part of the record.' : 1 IS MS. FRINGS: I realize that. I appreciate your 19 ' referring to it; so that we can look at that so we do have some-20 .hing on the record for the benefit of the public who may not
, 21 be lcoking at these documents?
i , 22 DR. HALL: If you could -- l-23 l MR. JCNES: We will put it in the record. e j l f r%
'2d DR. HALL: Excuse me, I think that would be V)i s. cornet inc. ,
23 very difficult -- and the Board , although I happen to be familiar
'l I
l' I
2 3
. . .f. I-
.j with nuclear materials, the Board as a majority is not. And '
2 to swamp the .3oard with the report of WASH-1400 would be just -E i 3-an. unfriendly act. l )- .
)
I i f 1 3 i (Laughter.) . 5 4 6 7-t f
- 8. .
9 i 10 l 11-. I I I g 13
. i la ; j i
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17 , 18 i. i i , 19 l 20 f i I . l .l 22- . g 24 i accorters. . ine.
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III 1' MS. FRINGS: I would also submit that it is not [ s t i ;3 2. just important for the Board to understand this. After all, ~(V - i3 3 this is a public hearing, and we are trying to advise the l 4 public what the consequences would be. S MR. LIEBERMAN: I was just going to add that the 6* Executive Summary of WASH-1400 attempts, I think, to give ! 7 scme perspective on the question. It's not a very thick j g dccument, and that signt be relevant. 9 The general question of the safety or t$e conse- , 10 , quences of reactors is not something that can really be J 11 answered in, shall we say, twenty-five words or less. It 12 really involves many considerations and many factors, and I
-~g just to give a short summary here might really not do any } 12 .
14 of us a good service. l l 15 DR. FALL: You couldn't summarize Part 50 re- - i 4
- l 16 quirements? I 17 MR. LIE 3ERMAN: We'could certainly do that. -
I la ' Maybe M* M411 er could speak to that, s 1 19 MS. FRINGS: Before you get into that, let me just i l 8 i 20 ask, is tr.e Executive Summary written in laymen's terms or l 21 is it a technical document that only a scientist would under- . I i j 22 ' stand? j_ 22 MR. LIE 3ERMAN: I think it's understandabla to O 24 l a layman. That's the purpose of the Executive Summarv. (% n a =nm. inc. l 25 MR. MILLER: Let's address the Executive Summary I l i : I >
I for ; dst a minute. The Executive Summary in the consequence ; 3 2 area, . postulating an event as you have postulated it -- maxi-
\
' 5 '3- mum release, maximum. sabotage event -- addresses factors 4 sucn as immediate fatalities, latent fatalities, property SH, damage from such things as contamination. l 6; MS. FRINGS: You say it addresses them. Does 1 7', it conclude- that these things could occur? l - 3 MR. MILLER: It gives the exact numbers and dollar l/ 9 costs.
. \
10 MS. FRINGS: Okay. That's the kind of thing I 11 was interested in. I 12 MR. MILLER: We will make those tables available f i N' i 13 from the report. I I I 14 MS. FRINGS : I think that would be ve~ ry helpful. l t i 15 DR. EALL: Do you have any idea when you can make [ 16 them available to us? ' 17 ! MR. LIESE3 MAN: .We can have it done by this l l 18 afternoon or tomorrow. i 19 , CHAIRMAN VERKUIL: Is there any attempt to compare ! i 20 , the consequences of other disasters? l
-.21 MR. LIEBERMAN: That's in NASH-1400. They compare ,
22 it to airplane accidents and other things of this sort. ~ 23 CHAIRMAN VERKUIL: Could we extract that? I'm
.)
- ('~' 24] advised by the friendly act of my colleague here that we asomn. inc. i 25 ) don ' t have to go into WASH-14 00. Could you extract the t 4
i
't 6
-e
l j ; ccmpare.bility data?- 1 .- , 4,, ,
-: - What we'd like'to.get a sense for is whether a l t
m 1-2 l,
't l (s-)- 3 0 similar kind of disaster could occur in a variety of other l
,f
- 4!
situations which would not Be presumably subject to the same- l l' 3- kind of protection you have sought. , -E i
-t , i
~
6! MR. MILLER: Yes, I think most of that informa-l =- l l l tion is in Chapter 6, and we can supply it. It has things ; 7l ; i ! 8l such as.damLfailures and; consequences from fires and earth- ! 9 i quakes,.thatl type of information. , i [ 10 ' CEAIRMAN VERKUIL: That would be most helpful. j i ! i 11 j (Tne Board conferring.) 12 I wonder if we might just take a 5-minute break? 13 ,- We are hooing to close by around noon, as I understand this
.I s ja ! room has other uses. I believe we can. We'll take a short i
1 l. 15 break now. 16 (Recess.) - 17 j - CHAIRMAN VERKUIL: Let's reconvene, please.
.I l 18U MS TRINGS: We will proceed by going into some ,
e 3 , o 19 ;l questions on Issue 2, which is a discussion of the advantages l
'l i, -
i
l 20 ] and disadvantages of alternative programs to the screening ;
1 21 ] ' program that has been proposed. ! 1 . i 1 22 ] A couple of my questions will be based on things ; i n - ; 23 il! raised by other participants. I believe this question was
,s 24 rassec by Westinghouse when. they testified. They were s
S E N enorfert,Inc. i. 23- making the~pcint that the DOD and DOE programs require very a
.!. i.
l .! i i 1 I ! L . - _ . i
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,8 % UNITED STATES - . .:' ' - ,4 NUCLEAR REGULATORY COMMISSION
{ .. , I Td I j WASHINGTON, D. C. 20555
- s
%***** ~y,,
NOV i 61978 MEMORANDUM FOR: B. K. Grimes, Assistant Director for Engineering and Projects, DDR FROM: V. S. Noonan, Chief Engineering Branch, DDR
SUBJECT:
RESPONSE TO SURVEY ON USE OF WASH-1400 IN THE LICENSING PROCESS In response to the subject requested survey by memo, dated October 31, 1978, from V. Stello, Jr., the Engineering Branch, Division of Operating Reactors, has identified the following two cases that materials in WASH-1400 had been used as back-up justification in the licensing process for short term operation:
- 1. Generic Task A Task Action Plan: Asymmetric Blowdown Loads on PWR Reactor Vessel - Category 3 .
- 2. Safety Evaluation Reports on Steam Generator Operation for v Surry Unit 1 dated February 8,1977, Turkey Point Unit 4 dated February 8,1977, and Surry Unit 2, dated April 1,1977 - '
Category 3. [ m VincentS.Noona/n,mn Chief Engineering Branch Division of Operating Reactors cc: V. Stello, Jr. D. G. Eisenhut / L. R. Nichol v W. S. Hazelton B. D. Liaw K. Wichman S. Hosford J. Strosnider b
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UNITED STATES NUCLEAR REGULATORY COMMISSION I "'( j WASHINGTON, D. C. 20555 { ,kh}*' LL. 42. q October 4,1978 l l l NOTE TO: Task Managers for Category A Tasks l 1 FROM: Mike Aycock
SUBJECT:
TASK ACTION PLAN FOR CATEGORY A TASKS . l l Attached you will find a copy of the Task Action Plan for your task. l This version of the plan is on tape in CRESS and is available for j your use when revisions to your plan are made (mark-up a copy of your plan when proposing revisions and make changes to the tape only after the revision has been approved). This version of your Task Action Plan includes the ALAB-444 writeup and has been released to the public in conjunction with testimony for the Yellow Creek and/or Black Fox CP hearings. The testimony on generic issues for these l 4 cases has been :1ponsored jointly by myself, Larry Crocker and the l D project manager for each case. You are free to distribute these I Task Action Plans as you deem necessary. l l h:: Mike Aycock
Enclosure:
As Stated cc: R. Boyd (w/o enclosure) R. DeYoung (w/o enclosure) R. Mattson (w/o enclosure) V. Stello (w/o enclosure) Lead Supervisors (w/o enclosure)
- i f3 l
l 1 l
n , O Task A-2 ASYMMETRIC BLOWDOWN LOADS ON REACTOR PRIMARY COOLANT SYSTEM 'E Lead NRR Organization: Division of Operating Rehetors (DOR) Lead Supervisor: Darrell G. Eisenhut, A/D for Systems and Projects, D0R _ Task Manager: Steve B. Hosford, EB/ DOR Applicability: Light Water Reactors PWR Project Completion Date: December 1978 BWR Project Completion Date: Unscheduled . O e O
l i l Task A-2 I Rev. No. 1 May 1978 +
- 1. DESCRIPTION OF PROBLEM On May 7, 1975, the NRC was informed by Virginia Electric & Power Company that an asymmetric loading on the reactor vessel supports resulting from a postulated reactor coolant pipe rupture at a specific %
location (e.g., the vessel nozzle) had not been considered by West- l inghouse or Stone and Webster in the original design of the reactor i vessel support system for North Anna, Units 1 and 2. In the event of a postulated LOCA at the vessel nozzle, asymmetric LOCf loading could result from forces induced on the reactor internals by transient differential pressures across the core barrel and by forces on the vessel due to transient differential pressures in the reactor cavity. With the advent of more sophisticated computer codes and the accom-panying more detailed analytical models, it became apparent to West-inghouse that such differential pressures, although of short duration, could place a significant load on the reactor vessel supports, thereby affecting their integrity. Although first ioentified at the North Anna facility, this concern has generic implications for all PWRs. Upon postulation of a break in a reactor coolant pipe, at the above-mentioned locations, several rapidly occurring events could cause ~ internal and external transient loads to act upon the reactor vessel. For the reactor vessel pipe break at the inlet nozzle, asymmetric pressure changes take place in the annulus between the core barrel n\ (d and the vessel. Decompression could occur on the side of the vessel annulus nearest the pipe break before pressure on the opposite side changes. The momentary difference in pressure across the core barrel could induce lateral loads in opposite directions on the core barrel - and the reactor vessel. Vertical loads could also be applied to the core internals and to the vessel due to the vertical flow resistance through the core and asymmetric axial decompretsion of the vessel. Simultaneously, as fluid escapes through the break, the annulus between the reactor vessel and biological shield wall could become asymmetrically pressurized resulting in a difference in pressure across the vessel causing additional horizontal and vertical external loads on the vessel. In addition, the vessel could be loaded by the effects of initial tension release and blowdown thrust at the pipe break. The loads occur simultaneously. For a reactor vessel outlet break the same type of loadings could occur, but the internal loads would be predominantly vertical due to more rapid decompression of the upper plenum. For each of the above-mentioned postulated breaks, the time history of the reactor vessel support reactions due to the complete set of simultaneous horizontal and vertical loads should be calculated. . A-2/1
Task A-2 Rev. No._1 . May 1978-2 In the event'that such loadings would result in a significant degree of failure'within the reactor pressure vessel sup' port system and consequent vessel movement, there is a potential that this could (1) result in damage to the ECCS lines connected to the coolant loops, (2) affect the_ capability of the control rods to functi6n properly, and 1
)
(3) result in damage to other reactor coolant system components (pump and steam generator supports). In addition, the differential pres- , sures occurring during subcooled blowdown could result in stresses on-fuel assemblies caused by lateral core barrel and core plate motion. This could degrade heat transfer capability if fuel spacer grids are deformed by impacting either each other or the core baffle. (This loading can occur independently of vessel support failure.) The above-described phenomena'also apply generally to BWRs, but the potential loads are not expected to be as large since the pressure in the reactor vessel is lower and the reactor coolant is less subcooled.
- 2. PLAN FOR PROBLEM RESOLUTION A. Background ,
Following disclosure of this problem during the OL review of North Anna Units 1 and 2, a survey of all operating PWR reactors was conducted in October 1975. That survey showed that neither O of the.above-described transient differential pressures had been considered in the design of the reactor vessel supports for any operating PWR facility. In June 1976, the NRC requested all operating PWR licensees to proceed to assess the adequacy of the reactor vessel supports at their facilities with respect to these newly-identified loads. Most licensees having a common NSSS vendor took identical or similar positions with respect to this request and did not respond as requested. Most licensees with Westinghouse plants proposed an augmented inservice inspection program (ISI) of the reactor vessel safe-end-to-end pipe welds.in lieu of providing the detailed analysis we requested. Licensees with Combustion Engineering plants submitted a probability study (prepared by' Science Applications,
.Inc.) in support of a conclusion that a break at this location has such a low probability of occurrence that no further analysis l is necessary. B&W licensees have engaged Science Applications, i Inc. for a similar study (not yet submitted). I O A-2/2
A Task A-2 Rev. No. 1 ' May 1978
^
When the W and CE owners group reports were received in September 1976, DOR formed a review Task Group consisting of members from DOR, DSS and EDO to evaluate these alternate proposals. In . addition, EG&G Idaho, Inc. was contracted to perform an inde- : pendent review of the submitted probability study. A short review schedule was established since it appeared that most licensees would hold off on further analysis pending our con-sideration of their submittals. Our review of the proposed alternates has been completed. The Task Group and EG&G independently reached the same conclusion: that the alternate proposals set forth in these reports should - not be accepted in lieu of the requested analyses. The basis is that a sufficient data base does not exist within the nuclear industry to provide satisfactory answers to many information needs we identified. This information would be needed to support this "no-break" approach. Further investigation of pipe break probabilities is planned by the staff, see item (3) below. B. Plan . (1) Letters will be sent to all licensees and applicants stating that an analysis must be undertaken to assess the design O adequacy of the reactor vessel supports and other struc-tures to withstand the loads when asymmetric LOCA forces are taken into account.* We will point out that it may be possible to group plants such that-only a limited number of plants need be analyzed, and that it may be possible to provide a simple "fix" (e.g... pipe restraints) which will permit bounding the problem. Therefore, the letters will request licensees and applicants to submit their schedule for completion of the task. (2) The staff will meet with the licensees constituting both the W and the CE owners group to explain why the probabil-ity study reports could not be accepted. We will also provide them all the questions that have been generated to date as a result of our review of the W and CE topical reports. (We will not issue formal requests for additional i information on these topicals to these groups of licensees.) ! 7Includinganassessmentofasymmetricloadsproducedbylargepipe breaks outside the reactor vessel cavity. - O cu l A-2/3 L . _ . _ ._ _
l Task A-2 I Revi No. 1 l May 1978 (3) We will review and approve vendor models and codes prior to plant-specific application. (This has been completed for W analysis methods.) (4) The staff will develop explicit guidelines and acceptance a criteria for the asymmetric LOCA load analysis, including load combinations and acceptable alternatives where, depend-ing on the construction or operating status of a given plant, application of the guidelines per se could require modifications that are judged to be a practical impossibility. Such alternative guidelines would be designed to provide an adequate and acceptable LOCA load generic issue consistent with safe plant shutdown requirements. ~ 1 (5) The staff will conduct a pipe break probability study that ; will encompass (a) advances that are being made in nondestruc-tive examination techniques, (b) an improved flaw distribution data base of actual NSSS materials, and (c) development of a realistic break opening model to describe pipe break 3 characteristics. The pipe break probability study will be . ; used to confirm the adequacy of staff decisions related to the continued operation of plants for the interim period until an analysis of these loads is conducted. t (6) The staff will perform a series of sensitivity studies to independently evaluate the effect of noding upon the mag-nitude and distribution of pressures within typical reactor cavity designs. Results of sensitivity studies will be utilized to prepare guidelines for the evaluation of the volumes within the confines of the reactor cavity.
- 3. BASIS FOR CONTINUED PLANT OPERATION AND LICENSING PENDING COMPLETION OF TASK The safety issue addressed by this Task Action Plan (TAP) is primarily applicable to pressurized light water reactors (PWRs). As discussed in Section 1, the potential asymmetric loading conditions for boiling water reactors (BWRs) appear to be of lesser safety significance; however, this TAP includes provisions for further review of the sig-nificance of this concern with respect to BWRs.
With respect to PWRs, each NSSS vendor (i.e., Westinghouse, Babcock and Wilcox, and Combustion Engineering) has submitted topical reports which describe analysis methods for assessing the internal asymmetric blowdown loads. In accordance with the schedule for completion of ' this TAP, staff review and approval of these topical reports will be completed by December 1978 (the Westinghouse analysis methods have already been approved by the staff). The internal asymmetric blowdown p loadr also apply to BWR plants; however, the potential loads are not A-2/4 O
Task A-2 Rev. No.'l May 1978 O g expected to be-significant since the reactor vessel pressure and sub-cooling are substantially lower than for PWR plants (i.e., 1000 psia and approximately 40 BTV/lb. respectively for BWRs compared to 2200 psia and 100 BTU /lb. for PWR plants). Topical reports have not been submitted by all the vendors and architect engineers that deal with asymmetric cavity and reactor vessel external 9 loads in BWRs and PWRs. These reviews are conducted by the staff on a case by case basis. Technical assistance programs are unde may to resolve those aspects related to the reactor vessel cavity asymmetric loads and structural response methods and criteria. It is expected that these programs will be completed in F( 79 and will provide acceptable methods and models for independent staff analysis. Current - staff evaluations include case by case reviews of applicants' mass and energy blowdown calculations, reactor cavity loads including pressurization and vessel internal loads, and the resulting structural response. The results and conclusions drawn from these ongoing staff-activities are subject to confirmation in the course of development of the generic methods and models that will be the output of this generic task. , For PWRs and BWRs currently under licensing review for a Construction Permit, the staff is requiring applicants to commit to address this f3n safety issue as part of the subsequent applications for Operating Licenses. The CP applicants are also required to perform plant (V specific analyses of mass and energy release and reactor cavity pressurization for purposes of establishing asymmetric design loads at the CP stage while the generic methods are being reviewed and developed as part of this task. Since staff approval of the analysis methods is anticipated well in advance of the time for consideration of this safety issue at the Operating License review stage for plants now under CP review and since necessary modifications,* if any, to the plant design can be accomplished while the plant is being construc-ted, the staff has concluded that, pending completion of this task, Construction Permits can be granted with reasoable assurance that (1) there will be a satisfactory resolution of this concern prior to Such modifications , i.e. , installation of physical restraints to limit the postulated break area within the reactor cavity and/or to provide additional piping support, have been implemented late in the constructiun stage of several facilities (North Anna Units Nos. 1 and 2, Farley Unit No. 1). Modifications of this type can also be accomplished after construction is completed, as evidenced by the modifications proposed by the licensee for Indian Point Unit No. 3, an operating facility. It - should be noted; however, that physical space (access) limitations at certain older operating reactors may preclude the accomplishment of such modifications. A-2/5 4
. Task'A 'Rev. No. 1 May.1978 O' ,
. operation,'and (2)' operation will not present undue risk to the health and safety of the public.
CP applicants are required to perform plant specific analyses . using the best available methodology for their designs. Also, the e staff reviews and performs audit calculations to ensure the reason-ableness of the' currently available models; e.g., mass and energy 1 blowdown calculations, cavity pressure loads, and methodology for ' load combinations. I I For PWRs and BWRs under review for an Operating License, the staff j will require applicants to perform a plant specific analysis of their J facility using the best available methodology and criteria for their a design and to implement-any design modifications which are necessary ! prior to the issuance of an Operating License. Applicants are also required to commit.to perform an evaluation of their facility follow-ing staff approval of the generic analysis method should the method-ology or criteria developed from this task warrant such reevaluation.
-Based upon this commitment and the rationale presented below for continued operation of licensed facilities, we have concluded that, ~
pending completion of this task, Operating Licenses can be granted for facilities within this category with reasonable assurance that operation will not present an undue risk to the health and safety of i the public. j O For PWRs and BWRs currently licensed for operation, we have concluded that there is reasonable assurance that continued operation, pending - completion of this task, does not constitute an undue risk to the health and safety of the public for the following reasons. As discussed below, the likelihood of occurrence of an initiating event of sufficient magnitude to seriously challenge the structural adequacy of the vessel support members or other structures is low. The disruptive failure of a reactor vessel itself has been estimated to lie between 10 8 and 10 7 per reactor year -- so low that it is not considered as a design basis event. The rupture probability of pipes is estimated to be higher. WASH-1400 used a median value of 10 4 for LOCA initiating ruptures per plant year for all pipe sizes 6" and greater (with a lower and~ upper bound of 10 5 and 10 3, respect-ively). We believe that considering the large size of the pipe in question (up to 50" 0.0. and 4-1/8" thick), the' lower bound is more appropriate since tnese pipes are more like vessels in size. In addition, the quality control of the piping used in nuclear power plants is the best available and somewhat better than that of the - j- piping used in the WASH-1400 study. The above-mentioned factors, coupled with the facts that (1) the break of primary concern must be large; (2) the break must occur . A-2/6 1 c
Task A-2 Rev. No. 1 May 1978 / O essentially instantaneously; and (3) these welds are currently subject to preservice and inservice inspection by volumetric and surface techniques in accordance with ASME Code Section XI, lead us to conclude , that the probability of a pipe break resulting in substantial transient l loads on the vessel support system or other structures is acceptably .I small and that reactor operation and licensing of facilities for ': operation can continue during the interim period of approximately two _ years while this matter is being resolved. It is anticipated that the plant-unique analyses, which will be performed folicwing staff approval of the generic analysis uethods, will indicate that design modifications may be necessary to restore the originally intended safety margins at certain operating facilities. ; Such modifications, i.e., installation of physical restraints to i limit the postulated break area within the reactor cavity, have already been shown to be feasible. In the event that design modifica- l tions are judged to be impossible for specific operating facilities, alternative solutions, including such things as augmented inservice inspection, will be required to ensure adequate safety margins.
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- 4. NRR TECHNICAL ORGANIZATIONS INVOLVED A. Analysis Branch, Division of Systems Safety. Has lead respon-sibility for review of vendor hydrodynamic analysis methods and
/cT codes. U Manpower Estimates: 0.2 man year in FY 1977; 1 man year in FY 1978; 1 man year in FY 1979. B. Core Performance Branch, Division of Systems Safety. Has leat' responsibility for reviewing vendor analysis methods for cal-culating loads on fuel assemblies resulting from subcooled decompression for plants under CP and OL review (not yet licensed for operation). Manpower Estimates: 0.1 man year in FY 1977; 0.5 man year in FY 1978; 0.5 man year in FY 1979. C. Containment Systems Branch, Division of Systems Safety. Respon-sible for reviewing vendor models and methods for calculating asymmetric cavity loads for all plants, and associated vendor models. Manpower Estimates: 0.1 man year in FY 1977; 0.5 manyear in FY 1978; 0.5 man year in FY 1979. U 4 A-2/7 m
i Task A-2 Rev. No. 1 May 1978 O V 0. Mechanical Engineering Branch, Division of Systems Safety. Responsit'le for review of structural aspects of vendor analysis methods and codes for plants not licensed for operation. Responsible for developing structural acceptance criteria (with - Engineering Branch, 00R). MEB will investigate the applicabil- " ity of-this problem to BWRs (with Engineering Branch, 00R). , Manpower _ Estimates: 0.2 man year in FY 1977; 1.0 man year in FY 1978; 1.0 man year in FY 1979. E, Engineering Branch, Division of Operating Reactors. Responsi-ble for review of structural aspects of analysis methods and ' codes applicable to operating reactors (including loads on fuel assemblies). Responsible for development of structural accept-ance criteria (with Mechanical Engineering Branch, 055). EB will investigate the application of this problem to BWRs (with MiB, DSS). Manpower Estimates: 0.2 man year in FY 1977; 1.5 man years in FY 1978; 1.5 man years in FY 1979. , F. Operating Reactors Branch #1, Division of Operating Reactors. Responsible for the coordinatior, and management of this Techni- [O cal Activity. Manpower Estimates: 0.05 man year in FY 1977; 0.20 man year in FY 1978; 0.20 man year in FY 1979.
- 5. TECHNICAL ASSISTANCE A. Managed by 00R (Engineering Branch):
Contractor: EG&G Idaho, Inc. Funds Available: $105K in FY 1977 and $180K in FY 1978 This is an NRC program to independently model representative Westinghouse 4-loop (Indian Point 3), B&W (Arkansas Nuclear One Unit 1), and CE (not yet selected) plants for the purpose of assessing the loads on all major structures and components resulting from asymmetric LOCA loads. The purpose of this pro-gram is to develop an independent NRC capability for performing inelastic dynamic analyses. Sensitivity studies will be per-formed to evaluate the effects of various break opening times, effects of component stiffness, and three-dimensional coupling . effects. O V A-2/8
Task A-2 Rev. No. 1 May 1978 -g! B. Managed by DSS (Mechanical Engineering Branch): Contractor: EG&G Idaho, Inc. Funds Available: $80K in FY 1977 and $100K in FY 1978 This is an NRC/ DSS program to provide the staff with the ana-lytical tools necessary to independently verify the selection of design basis pipe rupture locations; and to verify that the criteria for assurance of integrity under LOCA & SSE loads for reactor coolant pg ing, the reactor vessel, steam generators, main coolant puros a'd the supports for these components have been implement ~ m ectly. Verification analyses for a CE plant (San Onc fn o a B&W plant (Bellefonte 1), a BWR plant and a 4-loop i ,aouse plant will be run to verify results reported by the . slicants. Support models will be designed to be revised as necessary to represent various support config-urations utilized by Architect / Engineers of the plants under CP/0L review.
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- 6. INTERACTIONS WITH OUTSIDE ORGANIZATIONS
, A. W Owners Group of licensees
! \ C) The W owners group of licensees is an ad hoc organization of most(butnotall)ownersofoperating3 plants,formedforthe purpose of sponsoring and proposing the augmented inservice inspection program (WCAP-8802) in lieu of furnishing the detailed analysis requested by NRC. This group of licensees has engaged Westinghouse Electric Corporation as its principal consultant. With the advent of the NRC decision to request all licensees for a detailed analysis and to set aside - at least for the present
- the ISI proposal, the continued role of this licensee group is undetermined.
B. CE Owners Group of Licensees The CE owners group of licensees is also an ad hoc organization of most owners of operating CE plants. This group sponsored the probability study prepared by Science Applications, Inc., which concluded that the probability of severe pipe breaks that could trigger the loads under consideration is below the thresh-old of concern. The future role of this licensee group is also _ undetermined. j A-2/9
Task A-2 Rev. No. 1 p May 1978 k C. B&W Owners Group of Licensees Tnis group is composed of owners of B&W plants having nuclear steam supply systems of the same design (177 fuel assemblies, " a skirt supported vessels.) This group has engaged SAI and B&W as its consultant for the preparation of a probability study . similar to the one done by SAI for the CE owners group. This report has not yet been submitted. D. ACRS This task is closely related to one of the generic items J identified by the ACRS and, accordingly, will be coordinated with the Committee as the task progresses.
- 7. ASSISTANCE REQUIREMENTS FROM OTHER NRC OFFICES l l
None
- 8. POTENTIAL PROBLEMS -
A. 7'rea owners groups representing most operating PWRs have been tormed and either will propose or have proposed solutions dif-ferent from the requested analysis (augmented ISI, probability
\s studies). Therefore, strong industry resistance to our request for some form of analysis is possible.
B. Rigorous application of the generic structural acceptance criteria may require modifications that are judged to be impos-sible for some older plants. For these cases, alternative solutions may be required. 9 O A-2/10
h t ta gt d UNITED STATES j %,t 3 NUC1. EAR REGULATORY COMMIS$10N I
- S W ASHINGTON, D. C. 20656
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Ik #E , February 11, 1977 - gmC/4,/
*e,<<
Docket No.: 50-280 Virginia Electric & Power Company ATTN: Mr. W. L. Proffitt Senior Vice P w ident - Power P. O. Box 26666 Richmond, Virginia 23261 Gentlemen: On February 8,1977, we issued an Order for Modification of License for Surrv Power Station Unit No. 1. Our Order amended Facility C\ Operating License No. DPR-32 and permits continued operation for 60 equivalent days from February 8,1977. Our Order also contained Q1 other limitations for operation of Surry Unit No.1. In our Order l we indicated that our Safety Evaluation was in preparation and would 1 be issued subsequent to the Order. Enclosed is our Safety Evaluation relating to steam generator tube integrity upon which our Order of February 8, 1977, is based. Please note that the Safety Evaluation contains descriptive statements and implementing requirements regarding the limitations listed in our Order of February 8,1977. The February 8, Order contained an error in Section III, Paragraph 4, line 3. Enclosed is a signed original of a Corrective Order. A copy of the Corrective Order is being filed with the Office of the Federal Register for publication. Sincerely, < l J hN gs-,.f Robert W. Reid, Chief - Operating Reactors Branch #4 Division of Operating Reactors
Enclosures:
O) (_ Safety Evaluation Corrective Order cc w/ enclosure: See next page
l I l Virginia E*ectric & Power Company cc w/ enclosure (s): Michael W. flaupin, Esq. Hunton, Williams, Gay & Gibson i P. 0. Box 1535 Richmond, Virginia 23213 4
. Swem Library College of William & fiary .
Williamsburg, Virginia 23185 Mr. Sherlock Holmes, Chairman Board of Supervisors of Surry County Surry County Courthouse Surry, Virginia 23683 Chief Energy Systems Analyses Branch (AW-459) l Office of Radiation Programs ) l, U. 5. Environmental Protection Agency ; Room 645 East Tower i 401 M Street, S.W. ) Washington, D.C. 20460 \ U. S. Environmental Protection Agency Region III Office ATTN: - EIS COORDINATOR Curtis Building (Sixth Floor) , l 6th and Walnut Streets ' Philadelphia, Pennsylvania 19106 Cormonwealth of- Virginia Council on the Environment 903 9th Street Office Building l Richmond, Virginia 23219 1 O l 1 l 1
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!O SAFETY EVALUATION REPORT SURRY UNIT NO. 1 STEAM GENERATORS DOCKET NO. 50-280 BACKGROUND Water Chemistry l For many years a sodium phosphate treatment for PWR secondary ! coolant was widely used for U-tube design steam generators that I
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removed precipitated or suspended solids by blowdown. It was successful as a scale inhibitor, however, in the early use, many PWR U-tubed steam generators with Inconel-600 tubing experienced I stress corrosion cracking. The cracking was attributed to free caustic which can be formed when the Na/PO4 ratio exceeds the recommended limit of 2.6. In addition, some of the insoluble metallic phosphates, formed by the reaction of sodium phosphates with the dissolved solids in the feedwater, were not adequately removed by blow- ) down. These precipitated phosphates tended to accumulate as sludge on the tube sheet and tube supports at the central portien of the tube bundle where restricted water flow and high heat flux occurs. Phosphate concentration (hideout) at crevices in areas of the steam generator, noted above, caused localized wastage resulting in thinning of the ' tube wall. The problem of stress corrosion cracking was corrected by maintaining the Na/P04 ratio between 2.6 and 2.3. Although the recommended Na/PO4 ratio was maintained, it did not correct the phosphate hideout problem that caused wastage of the Inconel-600. Largely to correct the wastage and caustic stress corrosion cracking encountered with the phosphate treatment, most PWRs with a U-tube design steam generator using a phosphate treatment for the secondary coolant have'how converted to an all volatile chemistry (AVT). . In -1975, radial deformation, or the so-called " denting," of steam generator tubes occurred in several PWR. facilities after 4 to 14 p, months operation, following the conversion from a sodium phosphate treatment to an AVT chemistry for the steam generator secondary coolant. Tube denting occurs predominately in rigid regions or so-called "hard spots" in the tube support plates. These hard spots
D (V
- are located in the tube lanes between the six rectangular flow slots ,
'7 in the support plates near the center of the tube bundle and around the peripherial locations of the support plate where the plate is wedged to the wrapper and shell. The hard spots areas do not contain the array of water circulation holes found elsewhere in the support plates . _
The phenomenon of denting has been attributed to the accelerated cor-rosion of the carbon steel support plates at the tube / tube support plate intersection (annuli). The corrosior. product (magnetite) from the carbon steal plate has expanded volumetrically to exert sufficient compressive forces to dent the tube and crack the tube
.sppport plate ligaments between the tube holes and water circulation holes, due to an in-plane expansion of the support plate. As a result of the tube support plate expansion, the rectangular flow slots began to " hourglass;" 1.e., the central portion of the parallel flow slot walls have moved closer so that some of flow slots are now narrower in the center than at the ends.
U-Bend Cracks On September 15, 1976, during normal operation, one U-tube in the innermost row parallel to the rectangular flow slots in steam gener-
. ator A at Surry Unit No. 2 rapidly developed a substantial primary tosecondaryleak(about80gpm). After removal of the damaged tube and subsequent laboratory analysis, it was established that the leak resulted from an axial crack, approximately 4-1/4 inches in length,
- in the U-bend apex due to intergranular stress corrosion cracking that initiat,gd from the primary side. Since the initial parallel flow slot wall in the top support plate has moved closer, the support -
plate material around the tubes nearest this central portion of these flow slots has also moved inward, in turn forcing an inward displace-O\ ment of the legs of the U-bends at-these locations. This inward
movement of the legs of the U-bends at these locations caused an increase in the hoop strain and ovality of the tubes at the U-bend # apex. It is this additional increase in strain at the apex of the U-bend which is believed to be required to initiate stress corrosion cracking of the Inconci 600 alloy tubing exposed to PWR primary coolant. Laboratory examination of 71 U-bends removed from flow slot locations in rows 1, 2, and 3 of the Surry Units Nos. 1 and 2 and Turkey Point Unit No. 4 steam generators has shown that intergranular cracking at the U-bend apex was found only in the row 1 tubes. Of the 71 tubes removed from these operating reactors, which are
'the most severely affected, no cracks have been found in tubes with computed equivalent strains less than 13.5% after approximately l
/7 11,065 hours of effective full power operation since detection of the I first tube tient. However, this same equivalent operating time led to the tube failure at Surry Unit No. 2, where the equivalent strain was estimated to be >14.3%. This indicates a strain level af which rapid development of stress corrosion cracking may occur in U-bends ' of steam generators of this design. Recent test work also indicates that long incubation periods are
- needed for the development of stress corrosion cracking at some l strain rates N Tests indicated that at 12.5% outer fiber strain, E Inconel 600 U-bend specimens tested in high purity water at 650*F took a long incubation time (>12,000 hours) for the nucleation.of an intergranular crack, longer time 13,000 hours for >30% penetration and more thaD.18,000 hours to fail .
~l AlthoughL these test results are not directly applicable to the PWR steam generator tubing at Surry, they do confirm the observed operating experience that (1) a long incubation time is required to h
d initiate intergranular cracking in Inconel 600 material, and (2) a
(3 .. G) i high strain is required for crack propagation. In this regard, the staff requested that the licensee address the i following concern:
"Hourglassing" may continue and close the flow slots in the top i support plate increasing the strain at the U-bend apex of the tubes in rows 2 and beyond. l In response to this concern, and to supplement plugging of row 1, VEPC0 has installed stainless steel 304 alloy blocks in each of the ,
six flow slots in the top support plate of all three Surry Unit No.1 l steam generators. These blocks will prevent further closure of the l flow slots and inward displacement of the legs of the U-bends, 'thereby preventing further anticlastic straining at the U-bend apex of these tubes in rows 2 and beyond. As a result, intergranular stress corrosion p) (, cracking of those tubes at the U-bends in row 2 and beyond is not anticipated during near tenn (next year) normal operation. However, the flow slot blocking devices would cause: (1) an increase in strain in the support plate, (2) peripherial expansion of the support plate between wedge locations, (3) an increase of tube denting in the "hard spot" regions, and (4) additional bearing stresses on the wedges, wrapper, channel, and steam generator shell due to the peripherial
, expansion of the support plate. The net overall effect of flow slot blocking devices would be similar to complete closure of the flow slots. However, VEPC0 had also increased selective tube plugging in the hard spot regions for the prevention of tube leaks at dented Totations.
Support Plata. Expansion . Continued growth of the magnetite in the tube-tube support plate - annuli results in a non-uniform increase in strain in the support plates and corresponding in-plane expansion. In this regard, the [] staff requested that the licensee' address the following concerns: V -
O V- -
"1. Severe cracking of the support plate may result due to the contin-uing in-plane expansion of the support plate.
- 2. The rhte of in-plane exparsion in any support plate could increase the severity of tube denting in "hard spot" regions. Severe denting would restrain the tubes in the support plate and the plate may have a tendency to buckle or otherwise deform and thus exert additional bending loads on tubes. -
- 3. With the closure of all the flow slots in any one support plate additional loads could be transmitted (due to thein-plane expansion of the plate) to the wedges, wrapper, channal spacer, tubes and the steam generator vessel. '
- 4. Thermal-hydraulic performance could be affected with the c1osure of all the flow slots in any support plate."
Anti-vibration Bar Fretting Q On November 17, 1976 Southern California Edison Co pany (SCEC) reported to I&E, Region V, that, during the inspection of the San Onofre Unit No.1 steam generators, excessive wear or mechanical fretting of anti- ' vibration bars was found in one of the steam generators. A failure of l these bars could result in excessive flow induced vibration that might affect tube integrity, especially for those plants where the tube
, denting phenomenon was observed at the top support plate. . Subsequent . investigation revealed that the anti-vibration bar design of San Onofre Unit No. 1 and Connecticut Yankee is unique in comparison with other Westinghouse plants. Differences in the design are summarized as follows:
- a. Material,5,- carbon steel for San Onofre Unit 1 and Connecticut Yankee; Inconel 600 for new models (44 and 5
- b. Bar Cross-section_ - 3/8 inch round bars; changed to squi lars in the new models.
p c. Clearances - (L-35 mils); was changed to (L-20 mils) for new d d. models where L is the tube spacing. Changes in V-bar configuration and spacing.
- a- .
[ DISCUSSION On January 19, 1977, Virginia Electric & Power Company (VEPCO), the licensee, was issued Amendment 29 to Facility Operatina License No. DPR-32 to operate Surry Power Station Unit No.1 twenty (20) equivalent days with a primary coolant temperature greater than 350*F. Prior to January 19, 1977, the licensee (VEPCO) had, by letters dated January' 3,1977 and January 14, 1977 submitted an analys.is of steam generator tube integrity for Surry No. 1. This information expanded upon the previous analyses concerning the U-bend cracking phenomenon in the steam generators of Surry Unit No. 2. VEPC0 has performed corrective action including the installation of flow slot blocking devices to prevent further occurrences of U-bend cracking in the steam generators of Unit No.1 and proposed to return to power for (~x two (2) effective full power months (EFPM). Because of staff's concern as to the adequacy of analyses of the effectiveness and the
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consequences of the proposed corrective actions described in the January 14, 1977 submittal, the proposed two months of power operation was not granted. Instead, a period of 20 EFPD's of operation was approved with a stipulation that additional information be provided, as delineated in the Appendix A to the January 19, 1977 license i
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actions (Amendment 29). The response to these questions were trans-mitted by letter, dated February 4,1977, in which the licensee had also requested an additional period of four (4) months of power operation beyond the current 20 EFPD operations granted on January 19, '977. l In the January 14, 1977 submittal, the licensee provided calculations to indicate tnat an equivalent strain of 13.5% at the U-bend apex _! represents a lower bound for intergranular cracking as a result of tube support plate deformation at the center of the flow slot locations. All the row 1 tubes with I.D. cracks had equivalent strains of 13.6% p) (, to 15.2% and those tubes with less than 13.5% had no cracks. The
V total effective strain at the U-bend apex for all row 1 tubes would be approximately 15.7% if complete flow slot closure were to occur. ? Similar calculations for tubes in rows 2, 3 and 4 indicate that the - total equivalent strain decreases as the U-bend radius increased, I even if the flow slots were to close completely. The maximum equivalent strain for.any tube in row 2 is 10.1% to 10.9%, 7.4% to 8.3% for any tube in row 3, and 6.3% to 7.1% for any tube in row 4. Therefore, the susceptability for intergranular cracking of tubes beyond row 1 would be substantially less because of the larger U-bend radius,less plastic pre-straining, and thus small residual stresses. As a further corrective action to prevent the possibility of inter-granular cracking at the-U-bend apex for tubes beyond row 1, the licensee (VEPCO) has installed stainless steel blocksin each of p the flow slots in the top tube support plate of all three Surry Unit i V steam generators. These blocks will prevent further closure of the flow slots and inward displacement of the legs of the U-bends, thereby preventing further anticlastic straining at the U-bend apex of those tubes in rows 2 and beyond. The licensee had also provided results of preliminary calculations j to evaluate the effects of installing flow slot blocking devices.
, First, the calculations were made for three loading conditions corresponding to the uniform in-plane growth of the top support plate at 0.014 ud 0.021 inch per inch strains, and an uneven in- I plane growth of tu top support plate at 0.042 and 0.030 inch per inch strains in the Sot and cold sides, respectively. Results of these three c,ases are quite similar all indicating maximum strains in the hard spot regiora. There are no significant cl.anges in the
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regions of high strain ii going from 0.014 to 0.042 inch per inch strain. Thae three anal,y tes were performed without the flow slot I p blocking device and, therc fore, rpresent the in-plane growth of (j' the top support piste durfig past operation.
4 O " In order to evaluate the effects of the flow slot blocking, further analyses were made for a loading condition, corresponding to the . 0.021 inch per inch strain, applied to the already defonned plate that had been subjected to the loading condition corresponding to 0.014 inch per inch strain, with and without the blocking devices. Results of these two analyses indicated a negligible amount of increase in strain and a small amount of deformation of the perimeter . of the plate. Therefore, the licensee concluded that:
- 1. The expansion of the periphery is not in direct proportion with the increased expansion and,
- 2. the expansion of the plate at the perimeter is not worse with the flow slots blocked than it is without the blocks inserted.
In the February 4,1977 submittal, the licensee correlated support p plate expansion with actual months of operation by means of a finite b element model which utilized a pseudo-thermal expansion technique. In order to do this, relationships between field data, EFPM's and results of the finite element analysis were established. Since the denting phenomenon extends over the ent' ire plate, there is good correlation between measured denting and expansion of a dented plate. Although the finite element model is not detailed enough to yield
, denting rates, it does quantify the extent of flow slot closure for a prescribed axpansion. Since the amount of closure over an extended period of EFPM's is available from field data, a relationship between model closure and EFPM's can be established. The rate of expansion is independent of boundary effects, the insertion of blocking devices, and time. Tgeprocedureforcalculatingtherateofexpansionper EFPM is as follows:
For_ a plate expansion of 0.014 inch per inch in the hot side and 0.010' inch per inch in the cold side, the resulting average flow slot p closure is 0.675 inch.. For the actual plate, the most conservative
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V .n. I rate of closure as derived from field data for the top support plate . is 0.15 inch / month. Thus, the 0.675 inch of closure represents 4.5 # months of power operation, and the equivalent strain rates or the H magnetitie growth rates are determined to be 0.0031/0.0022 inch per inch per month for the hot / cold side. Therefore, for an additional two months of operation, additional loads equivalent to 0.0062/0.0044 ' inch per inch strains in the hot / cold side were applied. Similarly,
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an equivalent loading condition with 0.0124/0.0088 inch 'per inch strains in the hot / cold side represents an additional four months : of operation beyond the insertion of blocking devices in all six flow slots in the top support plate. The results of these two analyses show an insignificant change in the strain pattern. The licensee, therefore, concluded that an additional four months of operation was justified with selective plugging of tubes in the affected hard spot O regions. U Also, in the February 4,1977 submittal, the licensee provided a program of. combined analytical, experimental, and field data acquisi-tion for the long term resolution of the entire denting issue. A Westinghouse status report will be complete in March 1977, and, thereafter, further plugging or a change in the operational mode would be implemented, as required, on a case by case basis. EVALUATION By letter dated February 4,1977, the licensee (VEPCO' proposed to continue power operation of Surry Unit No.1 for an additional four (4) months beyond the twenty (20) equivalent power days approved by the NRC on January 19, 1977. This proposal was based ~ upon the data and the supporting conclusions discussed previously. The NRC staff has reviewed the information submitted by the licensee and concurs in the following: [3 1. Further U-bend failures are not likely to occur within the proposed four months of operation because of the following:
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- a. Laboratory examinations of 71 tubes removed from Surry Units 1 and 2 and Turkey Point Unit 4 steam generators indicate that cracking was confined only to row one tubes,
- b. All tubes in row one are plugged.
- c. Effective U-bend strain is 30-50% lower in row 2 than in row l .
- d. Flow slot blocking devices have been inserted to arrest fuather flow slot closure and thus prevent further antic'lastie l
straining of the U-bend tubes. l
- 2. Support plate expansion or continuing magnetite growth in the proposed period of operation will have insignificant effect.s on i the wrapper and the steam generator vessel. Therefore, the wrapper and the vessel integrity during normal operating and accident p conditio'ns will not be affected by continued support plate ex- l
'( pansion.
Due to insertion of the flow slot blocking devices additional loads are transmitted to the steam generator shell through the load path of the support plate, wedge, wrapper and channel spacer. Based on preliminary " crush" tests performed by Westinghouse the maximum load that can be developed along this load path is 60,000 pounds.
. Analysis of the bearing stress along this load path indicates that all stresses are less than the yield strength. Such stresses on the steam generator shell are highly localized and self limiting and will not adversely affect the integrity of the shell under l accident conditions.
- 3. Since the total area of all six flow slots is only a small fraction of the total area for flow circulation, the effect of the flow slot -
blocking devices and hourglassing on the thermal hydraulic per-formance of the steam generator will be negligible. There will be a slight decrease in the circulation ratio and the liquid flow l velocities, with an increase in raw steam quality. But these are so small that they may be disregarded. l
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- 4. With regard to the anti-vibration bar degradation problem revealed during the inspection of San Onofre Unit No. 1 #
. steam generators, there is no reason to believe that similar -
problems.will occur at Surry Unit No.1 because there are basic
. differences in'both the design and the material used. Anti-vibration bars in Surry Unit 1 steam generators are made of Inconel 600 instead of carbon steel, of square cross-section ~
3 instead.~of round, and have smaller clearances than tho e originally employed at San Onofre Unit No. 1.
- 5. Since the timethat Surry established AVT chemistry control, wastage and caustic stress corrosion cracking experience has been- quite satisfactory. No substantial tube degradation from these corrosion mechanisms is expected to occur during normal operation.
O Consideration of Continued Dentino: With respect to the effect of I continued support plate expansion on continued tube denting, however, the staff does not agree that the proposed additional four (4) months of power. operation can be fully justified on the basis of the in-formation thus far submitted. The licensee has been unable to quantify the effects on tubes at intersections due to the continuing growth
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of magnetite. Therefore. concern over a possible increase in tube failures.at the tube / support intersections cannot be completely alleviated. Also, because of the absence of an explicit plugging criteria directed toward tubes subjected to increased plate strain, there is some concern that the integrity of some un-plugged dented tubes cannot be maintained during postulated accidents. There are, h[ wever, several factors which support a shorter operating _ period ~with more stringent operating conditions while additional information:is being generated; 1.e., qualitative and preliminary quantitative integrity data, the low consequences of the relatively g . limited tube leakage that would be expected under postulated accident [ conditions'and the very low probability of an initiating accident L l L
e coincident with large numbers of tube failures. The qualitative and preliminary quantitative integrity data is " sumarized as follows:
- a. Preliminary analyses of the support plate expansion (with a flow slot blocking device) indicated small hard spot strain increases and~ plate perimeter deformations.
- b. Most of the tubes in hard spot regions and those that have leaked previously have' been plugged, based on the logic derived from past experience. This corresponds, in general, with the calculated strain pattern due to a conservatively estimated magnetite growth rate.
- c. All leaks associated with dented tubes experienced to date have been small, well below commonly acceptable leakage limits.
- d. Possible through-wall cracks in the dented regions; i.e., tube /
(] V support plate intersections, are constrained by the support plates; I therefore, cracks should not burst during postulated accidents, until the crack grows substantially beyond the tube support plate region.
- e. Through wall cracks at dented locations, with the amount of leak-ages experienced to date, have been stable during normal operation
, (no rapid failures), and are not anticipated to become unstable during postulated accidents.
- f. Even though some non-through-wall cracks may exist and may crack through during postulated accidents, the associated leakage rate with such an event would be similar to that resulting from through wallcracjsfoundduringnormaloperationandthecrackwouldnot be unsta'ble.
Regarding the consequences of tube failures postulated under loadings imposed by independently initiated transients or accidents, scoping p calculations which postulate such additional tube failures have been ( performed by the staff to obtain perspective on the magnitude of the potential hazard and to determine the degrec of assurance of tube integrity required.
i d The two accident events which result in loadings significantly different than those seen in normal operation are the loss of , _ coolant accident (which results in external, or collapse, forces on the steam generator tubes) and the steam line break accident (which results in internal, or burst, forces on the steam generator tubes). The potential safety significance of steam generator tube failures during a loss of coolant accident is that steam entering the primary system through failed tubes could cause a ba'ck-pressure which would retard the entry of emergency core cooling water into the core. The potential safety significance of steam generator tube failures during a steamline break accident is that radioactivity normally retained within the primary coolant system could be released to the environment. This radioactivity could include radioactivity ; in the primary coolant prior to the accident and radioactivity ( released from the fuel during the fuel temperature transient V resulting from the accident. The staff assessment of LOCAs with tube leakage shows that relatively small leakages (less than about 5 gpm) are within the typical uncer-tainty in computing the reflooding rate for approved ECCS performance calculations and do not warrant concern. Greater leakages (less than about 50 gpm) show a measurable effect of several percent on
' allowable nuclear peaking factors. However, the iormal margin between actual operating peak power distribution and the allowable power peak-ing limits precludes exceeding the criteria of 10 CFR Part,50.46.
For the case of a postulated main steamline break, we estimate, using conservative assumptions (Table 1), that steam generator tube leak rates as high as 250 gpm may be tolerated without exceeding a 2-hour dose to the thyroid of 150 rem at the site boundary. This
~
calculation was performed under the assumption that the coolant activity limits specified in the Standard Technical Specifications Q for Westinghouse plants are in force at the Surry Unit i plant . Such activity limits and sampling requirements have Been
( v s set forth in the Order and details are attached hereto as Appendix B. In addition, to assure that our assumptions on the course of such a main steamline break ac'.ident are valid, the licensee has committed to mit.. in operator procedures for this event and confirm that the operator will have the information and instructions to depressurize
~
the primary system, thus stopping any leak through the tubes, within about 30 minutes of initiation of this sequence of events. We have also considered the less probable event in which the steamline and steam generator tube failures occur at a time when the plant is O operating with high coolant activity resulting from previous power \ level changes. As a result, we are imposing limitations on the operation of Surry Unit No. I to limit the allowable primary coolant iodine activity following power transients to 10.0uCi/g j of Dose Equivalent I-131. This will provide assurance that, were the steamline break with resulting tube. leaks not exceeding 250 gpm postulated to occur at such a time, the calculated doses'would not
, exceed the 10 CFR Dart 100 guidelines (Table 2).
However, for the reasons outlined elsewhere in this report, tube failures with high leak rates are not anticipated for the types of cracking associated with tube denting. Moreover, the additional limitations developed by the NRC staff assure that the development of degradation .in tube integrity will be detected and operation termin-ated before it becomes significant. For these reasons, even under ., accident conditions we would not expect leakage in excess of about 50 gpm. The dose consequence discussed above would be reduced accordingly.
A Additionally, we have estimated the failure probability of breaks in the primary or secondary system piping which might lead to conditions ,; imposing severe stresses on the steam generator tubes thus potentially , causing failures. In this analysis we considered the probabilities associated with large pipe breaks because we conclude that significant loads and high radiological consequences resulting from small breaks in the primary or secondary system are less likely than from large _ pipe breaks. Transient forces under small break conditions are smaller and larger margins exist with respect to significant con-sequences given an event with additional tube leakage. For example, the failure to close a single safety valve during a transient would result in a depressurization of the secondary system over many minutes (as opposed to about two minutes for a large pipe break) and would not result in uncovering the steam generator tubes (providing some washout of iodine from any primary system coolant flashed into the secondary system through tube failures). We estimated the failure probability of large pipes in the primary and secondary. system to be that associated with piping greater than six inches in diameter as given in WASH-1400. The median value given in WASH-1400 for such piping is 10-4 per plant per year with an uncer-tainty spread of from 10-3 to 10-5 per plant per year. In addition, the short period of time (60 aays) that the faci 1 Tty will ~ ope'r&TE pTTor to J further determination on steam generator integrity margins will significantly reduce the likelihood of an unacceptable event. On this basis, we conclude that the likelihood of a large pipe failure' leading to a severe steamline break or loss of coolant accident (LOCA) during 60 days of operation is on the order of one chance in fifty thousand (2 x 10-5). The probability of a LOCA or a steamline break leading to . large additional-leakage (more than about 250 gpm) fro'm the primary to secondary system is significantly lower than this value. r's b
4 4 ( t .. k . Additional Limitations Because of the need to assure that any stress corrosion cracking which occurs during operation remains small and stable, and that an extensive number of tubes do not incur penetrating cracks or substantial part thru-wall cracks, the staff has developed certain additional operating limitations. These limitations are designed to , assure, in the absence of adequate analytical assessment thus far, the detection of the onset of tube degradation before it becomes of iminent safety concern. A reduction of the plugging limit for primary to secondary leakage, described below, will assure that no individual crack will reach such proportions that it may become unstable during normal or accident loading conditions. O A substantial increase in the frequency at which leaking tubes are encountered.could signal the development of more extensive general degradation. The potential for such a development during operation has been substantially alleviated by the limitations described below, requiring operation to be terminated in the event that the frequency of the detecti.on of leak.i,ng tubes par plant should increase s substantially to more than 1 in twenty days. Specifically, the restriction is that no more than two (2) tube leaks per plant during any twenty (20) day period. This restriction, by limiting the potential ~ number of heat up and cool down cycles resulting from tube plugging, also minimizes concern for possible thermal ratchetin'g. While these ennditions assure an adequate level of integrity for short term operation, more complete analyses of the structural effects of _ continued tube support plate corrosion is needed in order to provide adequate assurance of continued integrity for larger periods beyond A an additional 60 days after February 8,1977. The staff requirements
O y ~
.s for additional information are described below. When such information c.
is received it will be assessed by the staff to determine whether or not the facility can continue to operate beyond the additional 60 days considered herein without further inservice inspection. The specific limitations developed by the staff are:
- a. The leakage limits shall be reduced from 1.0 to 0.3 gpm per ~
steam generator (See Appendix A ),
- b. The concentration of iodine $n the primary coolant shall be limited to 1.OuC1/ gram during normal operation and to 10uci/ gram Dose Equivalent I-131 during power transients (See Appendix B).
e c. Reactor operation will be terminated if primary to secondary leakage which is attributable to 2 or more tubes per plant occurs during a 20 day period. Leakage means the occurrence of measur-able ' activity on the secondary s'ide which is identi.fied as a leak. Nuclear Regulatory Commission approval shall be obtained before resuming reactor operation. The information requested in Appendix C will be supplied by the licensee within 45 days of the date of this order. Upon completion of the NRC staff review of this data a determination will be made whether to allow continued operation or whether to require cold shut-down to perform inservice inspection and/or to provide additional supportive data. CONCLUSIONS ,, For the foregoing reasons, we have concluded that:
- 1. the limitations set forth herein will provide reasonable assurance g that the public health and safety will not be endangered by Q. operation cf the facility in the manner described herein,
- 2. such activities will be conducted in compliance with the Commission's
, regulations, 'and will not be inimical to the common defense and
" Q v ,
6 security or to the health and safety of the public. Date: Feb*uary 11, 1977 l
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l I i O l REFERENCES
- J
- 1. H.A. Domian, et al. Effect of Microstructure on Stress Corrosion ,
Cr:cking of Alloy 600 in High Purity Water. Corrosion, Vol. 33, P. 26, (January 1977).
- 2. R.L. Cowan and G.M. Gordon. Intergranular Stress Corrosion Cracking and Grain Boundary Composition of Fe-Ni-Cr Alloys, Pr.epring G-14 of paper presented at Stress Corrosion Cracking and Hydrogen Embrittlement of Iron Base Alloys Conference, Firming, France (June 1973).
- 3. J. Blanchet H. Coriou and et al. Influence of Various Parameters on Intergranular Cracking of Inconel 600 and X-750 in Pure Water at Elevated Temperature, Preprint G-13 of paper presented at Stress Corrosion Cracking and Hydrogen Embrittlement of Iron Base Alloys Conference, Firminy, France, (June .1973).
- 4. F.W. Pement and N.A. Graham. Stress Corrosion Cracking in High ,
Purity Water, Scientific Paper 74-186-TUCOR-P1, Westinghouse Research Laboratories (June 23,1974).
- 5. Ph. Berge. H.D. Bui, J.R. Donati and D. Villard, Corrosion, Vol. 32,
- p. 357, (September 1976).
1 P Y e l O l l 1 l l
se TABLE 1
.3 ASSUMPTIONS USED IN ANALYSIS OF POSTULATED MAIN STEAM LINE FAILURE WITH LARGE STEAM GENERATOR TUBE LEAKS
~
- 1. Reactor Power = 2546 Mwth
- 2. Steam Generator tube leak of 250 gpm
- 3. Leak stops after 30 minutes
- 4. Iodine spiking factor of 500
- 5. Meteorological conditions corresponding to a 30-meter elevated release with fumigation and 0.4 m/see wind speed at a distance of 503 meters (X/Q = 1.7 X 10-3 sec/m3 ), _.
- 6. Primary coolant activity prior to the accident of
. 1. pCi/g of Dose Equivalent I-131.
+
t' .
\ '
- v
'-
- s, , .
) 0
~
u a . TABLE 2 ASSUMPTIONS USED IN ANALYSIS OF POSTULATED MAIN STEAM LINE FAILURE WITH LARGE STEAM GENERATOR TUBE LEAKS AND WITH A PRIOR IODINE SPIXE ,
- 1. Reactor Fower = 2546 Hvth
- 2. . Stea= Generator tube leak of 250 spn
(j 3. Leak stops after 30 einutes 1
\s_s/
- 4. Iodine spiking factor of 500
- 5. Meteorological conditions corresponding to a 30-meter I
elevated release with fumigation ando.4 m/see wind speed l 3 3 at a distance of 503 meters (x/Q = 1.7 x 15 sec/c ).
- 6. Primary coolant activity prior to the accident of
- 10. pCi/g of Dose Equivalent I-131
/* ,
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i a . , APPENDIX A l LIMITS ON PRIMARY TO SECONDARY COOLANT LEAKAGE j
- 1. In addition to the limits set forth in the Technical Specifications for this facility, the primary system leakage shall be limited to assure that total primary to secondary leakage through all steam generators not f
isolated from the Reactor Coolant System shall not exceed 1 gpm nor 0.3 gpm through any one steam generator not isolated from the Reactor Coolant System.
- 2. For detection of leakage exceeding the rate limits the tubes shall be plugged and the incident reported to the NRC.
V ll l
._ - - . . - . - . - . - . - . .- - - . . ~ . - - -
APPENDIX B l (/ s REACTOR COOLANT SYSTEM SPECIFIC ACTIVITY LIMli!NG COND) TION FOR OPERATION 3.1.D The specific activity of the primary coolant shall be limited to:-
- a. 1 1.0 uti/ gram DOSE EQUIVALENT I-131, and ,
- b. 1 41/T pCi/ gram.
APPLICABILITY: MODES 1, 2 3, 4 and 5 ACTION: , MOD::a , 2 and 3*
- a. With the specific activity of.the primary coolant > 1.0 uCi/ gram I
, DOSE EQUIVALENT.1-131 but less than 10. pCi/ gram Dose Eouivalent i I-1 31 opera tion pI g
may continue for up to 48 hours provided that operation under j d these circumstances shall not exceed 10 percent of the unit's total yearly operating time. The provisions of Specification l 3.0.4 are not applicable.
- b. With the specific activity of the primary coolant > 1.0 pCi/ gram DOSE EQUlVALENT l-131 for more than 48 hours during one con-tinuous time interval or exceeding 10. uCi/ gram Dose Eouivalent I-131 6 hours.
beinatleastHOTSTANDBYwithT,yg<500*Fwithinj
- c. With the specific activity of the primary coolant > 41/T l pCi/ gram, be in at least HOT STAN0BY with T < 500*F within 6 hours. avg ;
MODES 1, 2, 3, 4 and 5 a.#" With the specific activity of the primary coolant > 1.0 pCi/ gram DOSE EQU! VALENT I-131 or > 41/f pCi/ gram, perform the sanpling and analysis requirements of item 4a of Table 3.1.0-l' until the . specific activity of the primary coolant is restored to within j A REPORTABLE OCCURRENCE shall be prepared and its limits. submitted to the Comission pursuant to Specification 6.9.1. ; This report shall contain the results of the specific activity ; hd analyses together with the following inforration: l rnrr,gwo w 7. l _ _ _ _ __ . _ _. . _ a
.I e,
W - REACTOR COOLANT SYSTEM 1 ACT,1,0N : (Continued) .
- 1. Reactor power history starting 48 hours prior to the first sample in which the limit was exceeded.
- 2. Fuel burnup by core region,
- 3. Clean-up flow history starting 48 hours prior to the first sample in which the limit was exceeded,
~
- 4. History of de-gassing operations, if any, starting 48 hours l prior to the first sample in which the limit was exceeded. l and S. The time duration when the specific activity of the primary coolant exceeded 1.0 pCi/ gram DOSE EQUIVALENT.1-131.
l D 1 1 SURVEILLANCE REQUIREMENTS The specific activity of the primary coolant shall be determined to be within the limits by performance of the sampling and analysis program of Table (3'1.0-1). e I
/* , % ,/ ,
1 L l n - -
O ' O O-:
. . 'l u
TABLE 3.1.0-1 PRIMARY COOLANT SPECIFIC ACTIVITY SAMPLE AND AP.ALYSIS PROGRAM TYPE OF MEA 5UREMENk SAMPLE AND ANALYSIS MODES IN WHICH SAMPLE AND ANALYSIS FREQUENCY AND ANALYSIS REQUIRED
-1. Gross Activity Determination At least once per 72 hours 1, 2, 3, 4
- 2. Isotopic Analysis for DOSE EQUIVA- 1 per 14 days 1 LENT I-131 Concentration
- 3. Radiochemical for E Determination 1 per 6 months
- 1
- 4. Isotopic Analysis for Iodine a) Once per 4 hours, l,2,3,4,5 Including I-131. I-133, and I-135 whenever the specific activity exceeds 1.0 uC1/ gram DOSE EQUIVALENT I-131 or 41/E uCi/ gram, and b) One sample between 1, 2, 3 2 & 6 hours following a THERMAL POWER change exceeding 15 percent of the RATED THERMAL -
POWER within a one
. hour period.
#U ntil the specific activity of the primary coolant system is restored within its limits. r Sample to be taken af ter a minimum of 2 EFFD and 20 days of POWER OPERATION have elapsed since reactor was last subcFitical for 48 hours or longer.
g a e 9 me*- ** - - - - - - - - - - - - - - - - - - - - - -_-- L--- -- - -- --------- ---- ----- ----_- - - _ - ------ - -------.- - n i. , :
4 O b PLANT SYSTEMS _ ACTIVIT; 'I LIMITING CONDITION FOR OPERATION ____ 3.6.C The specific activity of the secondary coolant system shall be
<0.10 pCi/ gram DOSE EQUIVALENT l-131.
APPLICABILITY: MODES 1, 2, 3, and 4. ACTION: With the specific activity of the secondary coolant system > 0.10 uCi/ gram DOSE EQUIVALENT l 1. be in at least HOT STANDEY within 6 hours and in COLD SHUTDOWN withhi the following 30 hours.
'IRVEILLANCE REQUIREMENTS The specific activity of the secondary coolant system shall be v a ermined to be within the limit by performance of the sampling and analysisprogramofTable(3.6.C-1).
.at*
\ -
y . , . i _s Tf.0LE 3.6.C-1 SECONDARY COOLANT SYSTEM SPECIFIC ACTIVITY a _ SAMPLE AND ANALYSIS PROGRAM TYPE OF MEASUREMENT SAMPLE AND ANALYSIS l AND ANALYSIS FREQUENCY l ll
- 1. Gross Activity Determination At least once per 72 hours. l
- 2. Isotopic Analysis for DOSE a) 1 per 31 days, when- !
EQUIVALENT I-131 Concentration ever the gross activity detennination indicates ; iodine concentrations l' greater than 10% of the allowable limit. j 0 V b) 1 per 6 months, when-j ever the gross activity ; determination indicates r iodine concentrations below 10% of the allow-able limit. . i b g 1 _i i
}
l I i . i l I
.. .~ ..
i DEFINITION 5= _ _ , _ __
=
T - AVERAGE Dl51NTEGRATION ENERGY T shall-be the average (weighted in proportion to the concentretion of each radionuclide in the reactor coolant at the time of sampling) of the sum of the average beta and gam.a energies per disintegration (in MeV) for isotopes, other than iodines, with half lives greater than 15 minutes, making up at least 95% of the total non-iodine activity in the coolant. DOSEEQUlVALENTl-131
. DOSE EQUIVALENT l-131 shall be that concentration of 1-131 (uCi/ gram) which alorie would produce the same thyroid dose as the quantity and iso-topic mixture of 1-131, 1-132, 1-133, 1-134, and 1-13S actually present.
The thyroid dese conversion factors used for this caleviation sh'11 be [ those listed in Table 111 of TID-14844, " Calculation of Distance Factors \ for Power and Test Reactor Sites." OPERATIONAL MODES REACTIVITY % RATED AVERAGE COOLANT M0_D_E, E CONDITION, K_ff THERMAL POWER
- TEMPERATURE
- 1. POWER OPERATION > 0.99 > 5% > 350*F
- 2. STARTUP. > 0.99 < 5% > 350*F
- 3. HOT STANDBY < 0.99 0 >_ 350*F
- 4. HOT SHUTDOWN < 0.99 0 350*F > T
> 200*F avg
- 5. COLD SHUTOOWN < 0.99 0 < 200*F
- 6. REFUELING ** < 0.95 0
~
< 140*F Excluding decay heat.
** Reactor vessel head unbolted or removed and fuel in the vessel.
=
e ,< s - .Q* APPENDIX C REQUEST FOR INFORMATION 3,
- 1. The Licensee should correlate the effects of tube support plate expansion on the strain in the tubes in the "hard spot" regions, develop.a plugging criteria, before and after blocking the flow slots, and provide.the basis for the plugging criteria. "
- 2. Provide an estimate of U-bend residual stresses for tubes in rows 2, 3 and 4.
- 3. Provide a summary of the Westinghouse experimental programs regarding denting, intergranular stress assisted corrosion, corrosion rate, the results to date, and the schedules and milestones for future work or implementation of any further plugging.
- 4. Provide material and processing specifications as requested in Question 23 of January 21, 1977, letter R.W. Reid to W.L. Proffitt.
- 5. Provide main steam line break and loss of coolant accident consequence analysis and the justification for an assumed number of tube failures concurrent with the event and resultant leakage.
4 d'
4 O V w UNITED STATES OF AMERICA NUCLEAR REGULATORY COMMISSION In the >btter of ) _
)
VIRGINIA ELECTRIC AND POWER COMPANY ) Docket No. 50-280
)
Surry Power Station, Unit No.1 ) CORRECTIVE ORDER On February 8,1977, the Nuclear Regulatory Commission issued an Order for Modification of License in the captioned matter. Said b U/ Order contained a typographical error in provision number 4. This Corrective Order will rectify such error. Accordingly, pursuant to the Atomic Energy Act of 1954, as amended, and the Comission's Rules and Regulations in 10 CFR Parts 2 and 50, IT IS ORDERED THAT Facility Operating License No. DPR-32 is hereby amended by revising provision 4, of Section III of the Order for Modification of License, in the captioned matter, dated February 8,1977, to read as follows:
- 4. The concentration of radiofodine in the primary coolant shall be limited to 1 vCi/ gram during normal operation and ,
to 10 pCi/ gram during power transients as defined in the
~
Safety Evaluation. FOR THE NUCLEAR REGULATORY COMMISSION ye,.v -<. Wd en C. Rusche, Director Office of Nuclear Reactor Regulation
. . J p: tv) b $. p.
f % UNITED STATS $ [-# 4d NUCLEAR AEGULATORY COMMISSION I I k_ i . $ WASHINGTON, D. C. 20S55 O G is,%Ji!h[ !
-*f NOV 151978 MEMORANDUM FOR: L. R. Nichols, Technical Assistant to the Director, .i Division of Operating Reactors :4 FROM: G. Lainas, Chief, Plant Systems Branch, Division -
of Operating Reactors
SUBJECT:
USE OF WASH-1400 IN THE LICENSING PROCESS V. Stello's memorandum of October 31, 1978 requests that each branch chief provide you with a coordinated response from his branch which identifies those licensing and other regulatory actions or staff positions, in their areas of responsibility, that have used or referred to the risk assessment models and results of WASH 1400 since its issuance in August 1974. Attached in table form is the coordinated' response from the Plant Systems Branch, which includes background information to assist you in making your recommendations for reconsideration of the listed licensing actions. Also attached, is a copy of each licensing document for the items listed in the table. O c Q.) ,'
. / d-e
()G. ainas, Chief
/ Plant Systems Branch Division of Operating Reactors
Enclosure:
As stated cc w/ enclosure (table only) V. Stello D. Eisenhut G. Lainas R. Ferguson D. Tondi B. Buckley E. Butcher V. Panciera
4 LICENSING DOCUMENTS BASED UPON WASH-1400 LICENSING ' DOCtMENT- CATEGORY- BACKGROUND Safety Evaluation of the Does not fit in any The document was used to support the SER for Dresden , Reliability of Essential Category 1 through 5. unit 1 Operating License, Amendment No. 23, which , Emergency Core Cooling The evaluation used granted an extention to October 31, 1978 of the
- Systems at Dresden Unit 1 component failure rates plant's exemption from 10 CFR 50.46. In'the SER the=
December 29 1977 published in WASH-1400 - staff concluded that the probability of certain - as input to the specific' systems at Dresden, Unit 1 being unavailable for event / fault trees devel- emergency core cooling was acceptably low. This oped for the evaluation conclusion was. based:in part on the methods and data reported in WASH-1400. However, no reference was made to WASH-1400 in the SER for the Amendment. In any case, the ECCS exemption extention has run out and the plant is now shutdown for modifications to bring the plant into full compliance with 10 CFR 50.46. i
' Fire Protection SER's ' for Operating Plants 3 Part 8 - The Conclusion section of fire protection t SER's contains a quotation from the Special Review Group report on the drowns Ferry Fire-(NUREG-0050).
This quotation makes reference to certain WASH-1400
- conclusion regarding the contribution of fires to the overall accident risk which. illustrates the-staff's conclusion that continued operation of the facility, does not present an undue risk to the health and
' safety of the.public. (A copy of.a typical Section 8
- is attached).
The staff is currently revising Section 8 to delete . the part that refers to WASH-1400. -(A copy of the proposed revision to Section 8 is also attached). , 1
-_m_______
i -. \ *I
' c
'4I ~ UNITED STATES ~
!' o NUCLEAR REGULATORY COMMISSION DEC,2 9 #
- r. , $ WASHING TON, D. C. 20555 Og
...../ - .
2 MEMORANDUM FOR: K. R. Goller, Assistant Director for Operating Reactors Division of'0perating Reactors FROM: D. G. Eisenhut, Assistant Director for 0perational Division of Operating Reactors
SUBJECT:
RELIABILITY 0F. ESSENTIAL ECCS E0VIPMENT AND SUPPORTING SYSTEMS AT DRESDEN, UNIT 1 (TAC 7059) The Plant Systems Branch has performed an evaluation of each of the systems at Dresden, Unit 1 that is needed for emergency core cooling to determine the likelihood that these systems will be available in the event of a postulated LOCA. This evaluation was performed to provide information for use by the Reactor Safety Branch in its overall review of Commonwealth Edison's request for an extension of the Commission's exemption of'Dresden, Unit 1 from the requirement to - have an ECCS that is capable of satisfying the single failure criterion -1 ' O in accordance with 10 CFR Part 50, Appendix K. The systems we reviewed were those previously identified by the Reactor Safety Branch as being essential?for emergency core cooling. The results of our evaluation are reported in Enclosure 1 separately l for each system.' Based on our review we conclude that there is reasonable assurance that emergency core cooling systems will be available within the times specified in the evaluation for a complete spectrum of postulated LOCAs at Dresden, Unit 1. Since the action under consideration by the Commission is related only to compliance with 10 CFR 50, Appendix K, we did not in our evaluation consider external events (e.g., earthquakes) as potential failure mechanisms which could simultaneously disable essential systems-and initiate a LOCA. However, due to the importance of the systems.under , review, we did reqdest that the Engineering Branch participate in l the October 3,1977 tour of the plant and in discussions with the -l
' licensee for the purpose of making a judgment as to the capability of '
the-reactor coolant. pressure boundary and essential systems to ; withstand loads induced by eismic events. The' Engineering Branch ' participated in the plant tur'and in the discussions with the licensee - I o 2and: concluded that the overa11' probability of. a seismic event occurring during the next: year and causing damage to the plant that I could' result-in unacceptable peak guel clad temperatures is low enough- (i.e.,; about 11x 10-4 t o 10- ) to justify continued operation .) L
DEC. 2 91977 r i for a one-year period. However, the Engineering Branch states that operation of the plant beycad the one-year extension should be considered only if at least one train of the ECCS can be shown to be seisnitcally qualified, from the source of cooling water to the . reactor vessel (see Enclosure 2). : In addition, the Engineering Branch has recommended that the following modifications to essential systems be made to increase their resistance to damage from a seismic event during the requested one-year extension period. l.- The plant's 125V d.c. battery should be restrained for seismic I loads consistent with the Dresden Unit 2/3 criteria.
- 2. Essential electrical switchgear (e.g., the fire protection system power center located in the Unit 1 crib house) should be restrained for seismic loads.
- 3. Loose equipment (e.g... dust cover.c) in essential electrical cabinets and panels should be reinstalled and tightly restrained.
No loose material (e.g., connectors, terminal box covers, etc.) should be stored in these cabinets or panels. We recommend that these modifi ations be made as soon as possible. V. C YlU LL D. G. Eisenhut, Assistant Director for Operational Technology Division of Operating Reactors
Contact:
E. Butcher l 492-8077 l
Enclosures:
As stated cc w/ enclosures: D. Eisenhut W. Butler R. Woods S. Hosford P. O'Connor - D. Silver D. Tondi E. Butcher p M. Taylor t ]. R. Baer PSB Section A
DEC. 2 C # Enclosure 1 ( SAFETY EVALUATION OF THE RELIABILITY OF ESSENTIAL EMERGENCY CORE COOLING SYSTEMS AT DRESDEN, UNIT l' INTRODUCTION Each of the systems at Dresden, Unit 1 that is essential to emergency core cooling was reviewed to determine the likelihood that these . systems will be available in the event of a postulated loss-of-coolant accident. A summary description of each system is provided below along with the results of our evaluation. The conclusions stated in this evaluation are based on our review of information obtained during our visit to the plant site on October 3, 1977, and on the information provided by the licensee in: (1) its request - dated July 8,1977, for an extension of the ECCS exemption; (2) the failure modes and effects analysis of the ECCS provided with its letter dated October 20, 1976; and (3) the responses to our requests i for additional information provided in its lettersdated November 11, ! 1977 and December 14, 1977. The failure rates for equipment, and ' the probability of occurrence of the events considered in this evaluation, are based on data reported in.the Reactor Safety Study, WASH-1400 and discussions with the Proba'bilistic Analysis Branch of the ' Office of Nuclear Regulatory Research. .
-l
'l EVALUATION cT (d
I
- 1. Offsite A. C. Power System To improve the reliability of the offsite electrical power system during the period of the requested exemption extension, l the licensee has added a 345/138 kV transformer at the site to connect the Unit 1 138 kV switchyard to the 345 kV switchyard of Units 2 and 3. With this modification, Unit 1 can now receive offsite electrical power from any one of six 138 kV circuits or six 345 kV circuits through two independent auxiliary power transformers. These transmission circuits approach the plant from all four directions and automatic transfers between offsite sources are provided at the 4 kV level to maintain a continuous source of offsite electrical power for the plant's auxiliary systems.
Based on our review, we have concluded that the recent installation of the 345/138 kV tie at the Dresden site will result in substantial additional reliability for the Unit 1 offsite electrical power system. With this modification the system is at least as reliable as the other systems that were considered in the NRC - staff's Reactor Safety. Study (WASH-1400). Therefore, the probability of a loss of offsite power at Dresden, Unit 1 coincidgntwithaLOCAcanbeassumedtobenogreaterthan p 1 x 10 / year as established in WASH-1400 for the average utility grid system. (j
DEC. 2 91977
/O V 2. Onsite A. C. Power System.
The existing onsite a.c. power system consists of a single 500 kW I diesel generator which serves the two existing essential services l 480 V a.c. buses. This diesel generator currently is the only O source of onsite electrical power to the low pressure core spray i system and the long-term cooling post incident system. The diesel . generator is automatically started and connected to both essential service buses in the event of a loss of offsite power. The only high pressure source of cooling water that can be served from the existing diesel generator is the emergency primary feedwater pump. This pump is only capable of providing - approximately 100 gpm to the vessel. In order to provide an onsite electrical power source for high capacity, high pressure cooling water injection, the licensee:will install a temporary 2500 kW diesel generator for service during the period of the requested exemption extension. This diesel generator will be automatically started and connected to the plant's power distribution system in the event of a loss of offsite power. It will be capable of serving one 1750 HP primary feedwater pump, one 350 HP condensate pump, and an additional 100 HP of miscellaneous valve and control loads simultaneously. (O v
) As modified, the onsite electrical power system will provide one automatically started immediate source of power to the core spray system; one automatically initiated source of power for a high pressure primary feedwater pump; and two sources of power for long-term cooling. The reliability of each of the diesel generators is estimated to be 3 x 10-4/per demand. This estimate is based on data reported in WASH-1400.
- 3. D. C. Control Power One 125 d.c. station battery provides d.c. control power for all the plant's systems except for the existing 500 kW diesel generator which has its own battery. Where essential systems are divided into two trains (e.g., low pressure core s r:y and post-incident systems), the control circuits for separate trains are powered from separate 125V d.c. power buses, both of which are connected to the single station battery. A separate battery charger is provided for each bus. The battery chargers are connected to the 500 kW diesel generator and each is capable of carrying all the d.c. loads normally supplied by the battery, except the initial high inrush currents immediately -
following load shedding initiated by a loss of offsite power. Therefore, since the diesel generator has its own battery, the battery chargers can be considered a second independent source of d.c. power for all but the most severe operating conditions. J
DEC. 2 91977 l l V For short-term response to a LOCA concurrent with a loss'of offsite power, the reliability of the d.c. system as a whole is controlled by the probability of the station battery failing on demand. We esti ate the probability of a station battery failure as - 1 x 10 / demand.- y 1 In the long-term, three sources of d.c. power are available (i.e., the station battery and two battery chargers). The probability of all the d.c. power sources being unavailable is considered to.be negligible. Therefore, the reliability of the d.c. system as a whole will be controlled in the long term by the likelihood-of spontineous failures of both of the d.c. power buses. We estimate the likelihood of such a failure to be no - more probable than two simultaneous spurious circuit breaker operations. Over.a 30-day period, the accumulated failurg probability woul )
.or about 5 x 10 g be.
approximately However, (720 due to the hours) x in(1assuming uncertainty x 10-0/hr/ breaker that a bus failure would be no more probable than a spurious circuit brgaker operation, we believe a more conservative value of 1- x 10-3 should be used to estimate the overall probability of a complete loss of d.c. power during the long-term response to a LOCA. ,
- 4. Core Spray System The low pressure core spray system has three 50% capacity pump trains, two 100% capacity strainers, and two 100% capacity injection valve trains. The system takes suction from the fire protection system.and sprays water directly onto. the core through a single penetration in the vessel head and a sparger' located above the core. The system has two redundant electrical and control systems that can withstand a single failure, with the exception of. the loss of onsite a.c. power. ' .The system was installed in the early 1970's and is designed to seismic Category I criteria, except for the fire protection system connection, the 125V d.c.
control power, and the 480V a.c. motive power. In order to assure the reliability of the instrumentation which automatically initiates the core spray system and the emergency condenser, the licensee has replaced the plastic covers on each of the primary steam drum level switches and has reviewed the design of these switches and the sphere high pressure sensors to verify that they can function in the required service environment. Based on our review of the information submitted by the licensee. - we-find that-the core spray system is a highly reliable system which is not susceptible to random single equipment failures that O
DEC. 2 91977-
-4 O) s V
could disable both 100% capacity trains. Accordingly, we conclude that the system is at least as reliable as the core spray systems n i studied in WASH-1400, i.e., the probability of the cqre spray system being unavailable during a LOCA is < 5 x 10-J/ demand.
- 5. Primary Feedwater System The primary feedwater system is required to perform the high pressure coolant injection function in the event of a break in the primary coolant system which is too small to depressurize the system before the core is uncovered. Three 1750 HP primary feedwater pumps are provided. These pumps take suction from the condenser hot well backed up by the condensate storage tank and q the "A" storage tank. The cooling water is discharged to the primary steam drum after passing through the feedwater control regulating valve and three motor operated valves. The feedwater control regulating valve is controlled by a differential pressure sensing device which measures the water level in the primary steam drum. During normal operation, the control valve is maintained at approximately 80% of the full open position. The valve is locked in the "as is" position if a loss of control power occurs.
In the event of a LOCA or a reactor scram, the " solid" water level in the primary steam drum would decrease and the normal control system response would be to move the flow control valve to the O full open position. The licensee has not provided any information d to demonstrate that the degraded environment resulting from the LOCA would not cause a spurious signe.1 fruin the control system which could close the flow control valve. The 1icensee, has however, stated that even if the control system should fail and close the flow control valve, the operator could take innediate action from the control room to open a bypass valve. To improve the likelihood that the primary feedwater system will be available as a high pressure source of cooling water, the licensee is proposing to take the following actions:
- a. As discussed in item (2) above, a temporary 2500 kW diesel generator will be installed at the site. In the event of a loss of offsite power this diesel generator will start automatically and automatically provide power to one feed-water and one condensate pump which will be kept on standby during normal operation.
- b. The only motor-operated valve which is subject to spurious l operation and which cannot be bypassed, will be locked in -
the open position during normal operation. i t v) I I m
5- DEC. 2 91977 O c. The feedwater flow control : valve and the other motor operated V valves can be bypassed from the control room and emergency procedures will be modi _fied to instruct the operator to check the' feedwater control valve position in the event of LOCA and to open the bypass valve if the control valve has ; failed closed. The licensee estimates that because of the - known'importance of the water level,'the level alarms, and the close proximity of the indicators and controls, it is likely that the operator would take action in about 15 seconds and no later than two minutes, from the time that a problem.in maintaining a feedwater flow path becomes noticeable. Other manually operated valves which could 3 block feedwater flow can be manually bypassed locally. J i Based'on our review of the feedwater control system, we conclude that in the event of a loss of offsite power and/or a LOCA the most likely course of events would be for the feedwater flow control valve to-remain in the open position. In the event that an equipment failure or a transient rising primary steam drum level caused the valve to close, we conclude that there is reasonable assurance that the operator would take immediate action to open a bypass valve and maintain feedwater flow. .This action could be accomplished within two minutes as stated by the licensee and it is reasonable to assume that it would be accomplished no later than ten minutes after the primary , strum drum low water v level is alarmed in the control room. We further conclude that in the event of a LOCA and the loss of offsite power, there is reasonable assurance that the onsite electrical power system as it is proposed to be modified can automatically provide power to one feedwater and one condensate pump within 30 to 50 seconds after the event.
- 6. Emergency Condenser The existing emergency condenser can be used to depressurize the primary system in the event of a small break LOCA. With the emergency condenser as a pressure relief system, the low pressure core spray system can provide emergency core cooling for the small pipe break spectrum.
The emergency condenser is automatically actuated by a low pr_imary steam _ drum level or high sphere pressure condition (the same instrumentation actuates the core spray system, see item 4 above). When the system is actuated, two 125V d.c. motor operated valves open to connect two 50% capacity condensing . coils to the primary steam drum and thereby the primary system is automatically depressurized. O
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DEC,2 9 177 6-h V Due to the simplicity of the system, the unavailability of the emergency condenser at 100% capacity will be controlled by the likelihood that one of the motor operated control valves will fail. to open on demand. The probability of such an event is estimated in WASH-1400 as 1 x 10-3/ demand for one valve. Therefore, the likelihood that-the emergency condenser will not be avail- .1 able is about- 2 x 10-4/ demand for 100% capacity and about i 1 x 10-6/ demand for 50% capacity. H l
- 7. Post Incident System Long-term emergency core cooling is provided by the existing )
post-incident system. .The. system has two pumps that take 2 i suction from screened drains at the bottom of the containment sphere and discharge -the cooling water to the reactor vessel through the core spray sparger. Electrical power for the system is provided from the essential services 480V a.c. buses which can be powered by either the existing 500 kW or the proposed 2500 kW temporary diesel generator. The post-incident system is a manually initiated system and is therefore susceptible to operator errors. However, since. the system is only required for long-term core cooling, adequate -j time is available for corrective action-in the event of an ; C operator error. The core spray pumps remain in a standby condition in the event the post incident pumps become unavailable.
)
1 Based on our review, we conclude that the post incident system, , backed up by the core spray system is not subject to random ) single equipment failures or operator errors that could prevent long-term emergency core cooling. 8.. Fire Protection System l The Dresden Station fire protection system is a combination of ! the Unit 1 and Unit 2/3 systems connected together by the station yard loop. The Dresden, Unit 1 emergency core spray system takes suction from the station yard loop. The yard loop can be pressurized with water from several different sources. Following is the sequence by which these sources are relied upon to 4 pressurize the yard loop: I
- a. Unit 2/3 Service Water Pumps During normal operation, the Unit 2/3 service water pumps are'the preferred sourcesof water to the yard loop. There -
are five pumps available with four normally operating l (two per unit). Each pump has a capacity of 15,000 gpm ' at.91 psig. In the event of a complete loss of offsite ! f N y- -
DEC. 2 91977 U electrical power, all of the Unit 2/3 service water pumps will trip off and will not restart automatically from onsite power. Therefore, the. Unit 2/3 service water system cannot be considered an immediate automatic i source of cooling water for the emergency core spray j system.
- b. Unit 1 Screen Wash Pumps If the Unit 2/3 service water system becomes unavailable, the yard loop pressure will drop. When the pressure drops to 80 psig, an alarm powered by the Unit 1 125V l d.c. battery will sound in the Unit 1 control room. -l At 75 psig, both Unit 1 screen wash pumps (100 HP each) l are started automatically and are capable of providing l 2200 gpm at 110 psig to the yard loop. However, in the event of a loss of offsite power the automatic starting of these pumps is blocked to prevent overloading the existing Unit 1500 kW diesel generator during the ECCS starting sequence. After the other ECCS loads have started, at least one screen wash pump could be manually ,
loaded onto the diesel generator. l
- c. Unit 1 Diesel Fire Pump If either the Unit 2/3 service water pumps or the Unit 1 screen wash pumps are not available, as would be the case immediately following a loss of offsite power, the Unit 1
.self-contained diesel fire water pump would start .
automatically when the yard loop pressure dropped.to 70 psig. l The Unit 1 diesel fire water pump has a 1000 gpm capacity at 100 psig,
- d. Unit 2/3 Diesel Fire Pump In addition to the Unit 1 self-contained fire water pump starting.when the yard loop pressure drops to 70 psig, the Unit 2/3 diesel fire pump will also automatically start. This pump has a capacity of 2000 gpm at 125 psig.
Based on our review, we conclude that with the exception of a loss of offsite power, the Dresden Station fire protection system is not susceptible to disabling random single active component failures. In the event of a loss of offsite power and the random single failure of the Unit 2/3 diesel fire - pump, manual action would be required by a station operator to place one of the several available sources of water in service to pressurize the yard loop.
.a. DEC. 2 9197 D _ CONCLUSION have evaluated to an overall' capability for core cooling, shown in Figurewe
- 1. have prepared the fault tree logic structure the modifications proposed by the licensee, there is assurance that emergency core cooling systems will be available within the times specified above for a complete spectrum of postulated LOCAs at Dresden. Unit 1.
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/p"<oug*o UNITED STATES Enclosure 2 '
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' HEMORAllDUM FOR: W. Butler, Chief, Plant Systems Branch, DOR FROM: .L. Shao, Chief. Engineering Branch, DOR
SUBJECT:
SAFETY EVALUATI0tl 0F DRESDEf1 UtlIT 1 FOR ECCS COMPLIANCE EXTEtlTI0tl (TAC 70S9) The Plant Systems Branch, 00R requested the Engineering Branch, 00R for technical assistance in evaluating the seismic adequacy of the RPS and , balance of plant safety systems for Dresden Station Unit 1. Dresden-Station Unit 1 is presently requesting a one year extension to an ECCS l
. exemption. which. expires on December 31, 1977. .
l 1 H. W. Woods (RSB), C. H. Berlinger (RSB), E. Butcher (PSB), P. O'Connor I (ORB-2), and S. Hosford (EB), attended a safety evaluation conference i at Dresden Station Unit 1, on October 3,1977, which included a plant ' inspection. V ' The Engincering Branch was specifically concerned with the operability of essential systems, both incchanical and electrical, during and following a seismic event, and in the structural adequacy of the essential structures. Several areas of concern were identified and are listed below.
- 1. Essen'tial Piping Systems Currently none of the essential piping systems, with the exception of part of the core spray flow path, are designed or restrained for seismic loads.
- 2. Cable Trays
' A sample analysis (by the Licensee) identified at least one cable-
' ' tray supr> ort which would see stress values 70% above the material yield stress for an OBE event. The Licensee stated that a more refined
'.. '- ana' lysis'would de'monstrhte' adequacy, but this' was ~ not evident by -
.-e our inspection of the support and the complexity of the geometry.
4
- 3. Emergency D. C. Power Source r
,', The Emergency D. C. Power batteries were not restrained for seismic q O) loads.
Contact:
S. Ilosford l 3- 49-28060' l: .- . . - ,
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V)- W. Butler -
- 4. Electrical Cabinets The fire protection system power center in the intake building was not restrained for seibnic loads. A survey of the electrical i
, control cabinets'in the unit one control center revealed a number-of relay dust covers to be off the relays and laying loose on the bottom of the cabinets. ,
a Conclusions The Engineering Branch assessed the probabilities associated with both a seismic event occurring, within the next year, and of consequential failures in essential systems necessary to cause a core melt. The - overall probability of a core melt due to se year was estimated to be on the Qrder of 10-{smic to 10-6loads in the next ; l The Engineering Branch feels that this probability is low enough to 1 justify continued operation for the period of one year. Operation ( of this plant beyond the one year extension should be considered only if at least one completely operational ECCS system is available, which V is seismically qualified from source of water to the reactor vessel. Recommendations , Based on our inspection of Dresden Station Unit 1, the Engineering Branch proposes the following modifications, although these are not factored into the.above conclusions, we feel these modifications are relatively minor in nature and will increase' the lev'el of safety in the event of a seismic occurrence.
- 1. Emergency d.c. batteries should be restrained for seismic loads consistent with Unit 2 criteria.
2 ,, Electrical cabinets, like the fire protection power center, should be restrained for seismic loads when they are either essential or backup equipment. Dust covers should be replaced. -
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s L. C. Shao, Chief Engineering Branch Division of Operating Reactors _
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f(UcLL AR nEGUI. ATORY COWESION i. / , 7 p e., cuil j' WAUIG IO% U C W'Y' 4' . , ,'/* ,a' f January 6, 1978 Docket No. 50 Commonwealth Edison Company ) ATTN: fir. R. L. Bolger Assistant Vice President Post Office Box 767 Chicago, Illinois 60690 Gentlemen: j The Conmission has issued the enclosed Amendment No. 23 to facility Operating License No. DPR-2 for Dresden Nuclear Power Station Unit No.1. -The amendment is in response to your request dated July. 8,1977, and supplements thereto dated November 11, 1 flovember 15, November 28, and December 14, 1977. : l The amendment extends the exp'iration 'date of the Commission's l August 21, 1975 ECCS exemption and the date for compliance with the l p Conmission's June 23, 1976 IEEE-279 Order from December 31, 1977 to October 31,~1978. The amendment also deletes license conditions which have been complied with and formally incorporates into the license, the remaining applicable provisions of the June 23, 1976 and August 21', 1975 Commission Orders. .In addition, the amendment adds new. interim license conditions deemed to be necessary by the NRC staff._ We have modified your requested extensions to change the expiration date to October 31 instead of December 31' because planned shutdown for decontamination in November 1978. Copies of the related Safety Evaluation and Notice of Issuance also are enclosed. Sincerely, Y -: DDT K. Davis, Acting Chief Operating Reactors Branch //2 Division of Operating Reactors
Enclosures:
- 1. A:nendment- flo. 23 to DPR-2 l 2 .- Safety Evaluation l
- 3. . Noticc of Issuance I
'L/ 'cc w/ enclosures: ' sce.next page-e )
l .
~ Commonweal th Edison Company January 6, 1978 cc w/ enclosures:
Mr. John W. Rowe Isham, Lincoln & Beale Counselors at law , One First National. Plaza, 42nd Floor Chicago, Illinois 60603 lir. B. B. Stephenson Plant Superintendent _! Dresden Nuclear Power Station Rural Route #1 Morris, Illinois 60450 lllinois Departnent of Public Health - w/ enclosures and CECO filings ATTN: Chief, Division of Nuclear ' dtd.11/11,15 & 28/77, & 12/14/77 Sa fety . 535 West Jefferson Springfield, Illinois 62761 ; 11r. William Waters O 1 Chairman, Board of Supervisors of Grundy County Grundy County Courthouse i
' Morris, Illinois. 60450 Chief, Energy Systems Analyses Branch (AW-459)
Office of Radiation Programs U. S. Environmental Protection Agency Room 645, East Tower
- 401 14 Street, S. W.
Washington, O. C. 20460 l U. S. Environmental Protection Agency Federal Activities Branch Region.V Cffice ATTN: - EIS C0ORDINATOR-230 South Dearborn Street Chicago, Illinois 60604 Q -
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6.0, t COMM0MWEALTH EDISON C0!1PANY DOCKET 110. 50-10 I DRESDEN fiUCLEAR POWER STATION UNIT NO. 1
- AMENDMENT.T0 FACILITY OPERATII.'G LICENSE i i
Amendment flo. 23 4 License No. DPR-2
- 1. The Nuclear Regulatory Comission (the Commission) has found that:
A. The application for amendment by the Commonwealth Edison Company (the licensee) dated July 8, 1977, as supplemented by filings dated-November 11, 15, 28 and December 14, 1977,
. complies with the standards and requirements of the Atomic Energy Act of 1954, as. amended (the Act), and the Commission's rules and regulations set forth in 10 CFR Chapter I; / B.
The request for. extension of the August 21, 1975 Exemp tion dated July 8,1977, as supplemented by filings of l flovember 11, 15, 28 and December 14, 1977, is authorized I by law and will not endanger life or property or the common I defense and security and is otherwise in the public interest. i C. The facility will operate in conformity with the application, the provisions of the Act, and the rules and regulations of the Commission;
) ;
I j D. .There is reasonable assurance'(i) that the activities authorized by this amendment can be conducted without endangering the health and safety of the public, and (ii) that such activities ) will be conducted in compliance with the Commission's regulations- ] E. The issuance of this ameadment will na't be inimical to the common' defense and security or to the health and safety of i the public; and-F. The issuance of thi:, amendment is in accordance with 10 CFR - Part 51 of the Conmission's ' regulations and all applicable requirements have been satisfied.' ' f
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- 2. Accordingly, racility License f!o. DpC-2 is herchy amuided as indicated below:
A. Replace paragraph 2.C(3) that was added by the June 23, 1970 Commission's Order for Modification of License with the following: . 2.C(3)l Licensee Cocaitments Relateri to IEEE-279 - 1968: 1 Commonwealth Edison r. hall compir te the modifications I identified in their June 30, 19/5 letter (ll. I;. Stephenson, H CECO to J. G. Keppler, i!RC) and their January 12, 1976 l letter (R. L.1;olger, CECO to the Director of lluclear ' Reactor Regulation, URC) prior to returning Dresden l Nuclear Power Station Unit No. 1 to service following the I!ovember 1978 outage to deuintominate the primary cooling system. This outage is presently scheduled to , l begin in Noven:ber 1978. Dresdon Unit No. 1 shall not be operated af ter October 31, 1978 unicss these modi fica tion", have been completed, n B. Replace Paragraph 2.C(4) with the follcwing: I ( )\ 2. C(4 ) Exemptpn from 10 CIT f GO.46, Aprendix K-(1) . As requested, exemption is granted fro:t the require:nents of 10 CFR 50.46 with retpect to the design and diversity of emergency systens and the diversity of emergency power sources, but not from the specific performr.r.cc require-ments of the FAC. (2). Comn.enweal th f.dicon shall comply wi:h sucl. condi tione, now in ef fect or which may hereaf ter be in: posed hv the Director of.lluclear Reactor Regulation relatiim to inspection, testing, ,or operatirig of the
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Dresden ECCS. (3). Commonwealth Edison shall exert its besL cf forts to complete the proposed I:CCS modifications at the earliest possible date. (4). The exercption shall expire on October 31, 1978. ( s
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U C. Add the following itemr,2.C(5) and 2.C(6) which add interin l license conditions and surveillance reqairements required by t he Regulatory Staf f: 2.C(5) Interim I.icense Condi tions: Commonwealth Edison shall not operate Dre:. den Sta t ion Unit Ro.1 after Uccember 31,19/7 unless the follouing conditions are satisfied: (1). Motor operated valve NO 130 shall be electrically disabled in the full open position. - (2). An operating procedure shall require the operator to determine the feedwater control valve position following a LOCA and to open bypass valve M0 60 if the control valve has f ailed closed. . (3). Install and utilize a 345/133 l'V transformer connecting the Dresden Unit No.1 138 KV systti. with the Dresden Units ilos. 2 and 3 345 KV sysu m. Install and mintain in place, a f1Nibin hose f'N (4). connection between the Dresden i fire pump and the l Q suction to the core spray system. . (5). The Dresden Unit No.1 ttation batteries shall be restrained to withstand potential seismic loads. (6). Electrical Motor Control Cabinets containing controls for essential or backup ECCS equipment shall be estrained for potential seismic loads. (7). The backup diesel generator and assor.iated feedwater pump and condensate pun.p shall be operable or the reactor shall be placed in hot shutdown within 24 hours. (8). Five smoke detectors shall be installed and operable in the cable tunnel. These detectors shall alara ii. the cont rol room and the reactor shall be scrcmed innediately if the smol.e detector alarm is autenatically actuated by fire or smoke. .
, (9). lhe existino reactor protection system surveillance procedure shall be modified to require that the PM O
( ,/ functional capability be verified utekly at the scet a solenoid fuse cabinet in the containment rather than from the control room.
? ,- m~ 4 ( ) LJ (10). An hourly inspection of the scram solenoid circuit between the reactor control ro .n and the containment !. hall be carried out, initil the screm solenoid circuit is modified to eliminate the potential of hot shorts in the scram solenoid circuit that can prevent a reactor scram. Replacement of the er.ist;ng circuit with one contained in grounded conduit
- is an acceptable method to eliminate this potential. _
(11). Commonwealth Edison shall submit a monthly progress report to the Nuclear Regulatory Commission which indicates Commonwealth Edison's progress toward co:npletion of their scheduled ECCS modifications and IEEE-279 and fire protection modifications including related activities which could affect these projects such as the decontamination program and construction of a new radwaste facility. O)
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2.C(6) Surveillance Requirements: (1). The backup diesel generator shall be manually started and loaded once each month to demonstrate operational readiness. The test shall continue until both the diesel engine and the generator are at equilibrium conditions of temperature while full load output.is maintained. (2). Every week the specific gravity and voltage of the back up diesel battery shall be measured. (3). Once a month the o.uantity of diesel fuel for the back up diesel shall be verified to be o greater than 4500 gallons.
- 3. This license amendment is effective as of its date of issuance.
FOR lilE NUCLEAR REGULATORY COMMISSION r- ~~s
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c} n V ctor Stello, Jrfl,. Di rector
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Division of Operating Reactors [ ') Office of Nuclear Reoctor Regulation (_/ Date of Issuance: January 6,1978
b e SAFETY EVALUATION IN SUPPORT OF EXTENDING THE
/ E.CCS EXEMPTION AND THE DATE FOR COMPLIANCE D) 'WITH THE COMMISSION'S ORDER RELATED TO REACTOR PROTECTIVE SYSTEM MODIFICATIONS COMMONWEALTH EDISON COMPANY ORESDEN UNIT h0. 1 DOCKET NO. 50-10 l
1.0 BACKGROUND
The Dresden Nuclear Power Station Unit No.1 was designed and constructed in the late 1950's and was issued Facility Operatina License No. OPR-2 on October 14, 1960. Dresden Unit No. 1 is the first nuclear power plant licensed for commercial operation. Subsequently, the Nuclear Regulatory Commission (formerly the , Atomic Energy Comission) has developed and adopted new regulatory requirements and has provided guidance to the nuclear industry in the form of codes and standards which identify acceptable methods to comply with the Comission's requiations. s The Comission has identified significant areas at Dresden No.1
)
[Q which require modifications to the facility as it was originally constructed. These areas include the installation of a High Pressure Coolant Injection System, the modification of the Reactor Protection System, and the installation of an automatic fire protection system. These modifications have been determined neces-sary by the Comission to provide substantial additional protection for the health and safety of the public and to meet specific require-ments of Comission regulations promulgated subseauent to the issuance of the Dresden Unit No.1 Operating license in 1960.
2.0 INTRODUCTION
2.1 ECCS Exemption Extension The Comission directed installation of Emergency Core Cooling Systems (ECCS's) for all power plants in July 1971 under its policy statement regarding Interim Acceptance Criteria. The ' acceptance criteria for these systems were finalized with the issuance of 10 CFR 50.46 and Appendix K. To date, all operating facilities have completed installation of an ECCS except Dresden Unit No. 1. In this case, as in several others, the Commission . granted a series of variances and exemptions which allowed continued operation while backfitting of an ECCS was in progress. O Q
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l l k.s The last such exemption relating to Dresden Unit No.1 was granted to Commonwealth Edison on August 21, 1975, to allow operation until December 31, 1977. By letter dated July 8,1977, the Commonwealth Edison Company (CECO)
"equested that he expiration date of the Commission's August 21, 1975 Exemption /om certain requirements of 10 CFR 50.46, be extended to December 31, 1978.
2.2 June 23, 1976 Order Modifications By the same July 8,1977 letter, Commonwealth Edison also reauested that the date for compliance with the Commission's June 23, 1976 Order for Modification of License be similarly extended to December 31, 1978. This order required that Commonwealth Edison submit to the Commission, by September 1976:
- 1. Additional information relating to the efficacy of the Dresden Unit No. 1 containment spray system.
- 2. Details of proposed modifications that are necessary to make the design of plant protection systems conform with O the requirements of Sections 4.2, " Single Failure Criterion,"
and 4.6, " Channel Independence" of IEEE Std. 279-1968.
- 3. Detailed analyses of all portions of plant protection systems, including the proposed modifications, which show that the modified systems meet the single failure criterion.
- 4. Results of analyses and/or tests which demonstrate that all instrumentation and electrical equipment essential to safety can function in the environment during and following an accident. If satisfactory results are not obtained, describe l the modifications necessary to assure that all instrumentation and electric equipment essential to safety can function in the environment.
Commonwealth Edison has complied with items 1, 2 and 4 by their submittals of September 30, 1976, and November 15, 1976. Accordingly, these requirements are being deleted from License DPR-2. This deletion is an administrative action and does not inolve a signifi-cant hazards consideration. v
U The Order further required that Commonwealth Edison complete their proposed reactor protection system modifications, fire protection system installation and environmental qualification of electrical equipment and instrumentation important to safety, by December 31, 1977. Commonwealth Edison has been unable to complete these modifica.tions and has requested an extension to permit time to complete these requirements of the Order. s 3.0 . EVALUATION We have reviewed Commonwealth Edison's July 8,1977 request ~ IReference 1) for extension to determine whether the public interest warranted the extension, and to assure that the health and safety of the public would not be adversely impacted. In our review, we examined: 1. The loss of coolant accident analysis and the performance capabili-ties of the existing plant systems upon which reliance must be plJced to assure that the performance requirements of 10 CFp E0.46 will be met; 2. O Commonwealth Edison's progress in complyina with the Commission's V August 21, 1975 Memorandum and Order of Exemption and June 23, 1976 Order for Modification of License;
- 3. Modifications to the facility proposed by Commonwealth Edison to provide added assurance that operation beyond December 31, 1977 does not adversely impact the health and safety of the public; and
- 4. The capability of the facility to withstand random sinale failures in the reactor protection system without completion of all of the modifications required by the June 23, 1976 Order, for the additional period of operation requested by Commonwealth Edison's July 8,1977 exemption request.
3.1 Loss of Coolant Analysis We have. evaluated the loss-of-coolant accident (LOCA) analyses submitted by Commonwealth Edison Company for Dresden Unit No. I with the present core loading (References 2 and 3). We also reviewed the safety equipment assumed to function in the LOCA analyses. ,
v 3.1.1 ECCS-LOCA Model and Analysis Results The analyses were performed utilizing a slightly modified version of the. General Electric Company Non-Jet-Pump Boiling Water Reactor Evaluation Model (the model). The model generally has been reviewed and approved as meeting all requirements of Appendix K to 10 CFR 50.46. The modifications that were made to the model to accommo-date certain unique features of Dresden 1 (principally the dual-cycle primary system and safety system credit for operation of the - feedwater system and emergency condenser) have not been given
- final staff approval. However, after a preliminary review of the ~
modified model as applied to Dresden 1, we conclude that the model is reasonably conservative and can be used for the purpose of evalu-ating this exemption request and determining whether or not the plant meets the performance requirements of 10 CFR 50.46. All analyses using this model were performed. assuming 102% of licensed core power and Maximum Average Planar Linear Heat Generation Rate (i.e., MAPLHGR, a measure of local power) allowed by current Technical Specifications unless otherwise stated. ! We conclude that if credit is assumed for operation of certain j equipment as specified below, Dresden 1 meets all performance reautre-
\
ments of 10 CFR 50.46 (related to peak cladding temperature, local oxidation, core-wide metal-water reaction, coolable geometry, and long term cooling) when the reactor is operated according. to current LOCA-related Technical Specifications, e.g., Maximum Average Planar Linear Heat Generation Rate (MAPLHGR) and power-to-void ratios. 1 3.1.2 Review of Safety Equipment Needed to Meet Performance Requirements The staff's major review effort on the exemotion extension request 1 concentrated on determining whether or not the equipment assumed I to operate in the LOCA analyses would in fact be operable following a LOCA. We reviewed pertinent information including Pioing and Instrument Diagrams (P & ID's) of all vital systems, obtained updated P & ID s where necessary, reviewed CECO's rasponses to numerous staff questions regarding the equipment's design, reliability and operating history, and finally several staff members spent two days at the plant site conducting a first-hand ! ~ O
.h
examination of- the vital. ECCS safety equipment. The conclusions and assessments contained within the following list of vital equipment are based on all of the abnve review activities. The equipment that must be assumed operable following a LOCA to meet the performance requirements of 10 CFR 50.46 is: 3.1. 2.1 The Core Spray (CS) System. This system takes water from the Fire System, and uses any two out of three 50% capacity pumps to supply water to the ring spray header which distributes the water over the core to provide cooling. Rated flow for this system can be achieved - only after the core has been depressurized to below 140 psig due to low pressure desian of -the system. The core spray system is the only system capable of providing short term cooling in the specific case of a LOCA having a break location which precludes the possibility of reflooding the core (e.g., bottom breaks). It employs a single-active-failure-proof piping network with parallel active components so that it is vulnerable only to passive failure of non-parallel portions of piping. A considerable' amount of such non-parallel piping. exists between the CS pumps and the core spray header, approximately 200 f t. This run of piping is restrained against seismically induced motion and has been subjected to periodic in-
) service inspections. No defects have been detected in this pipino d and its failure is not likely.
3.1. 2. 2 The Post Incident _(PI) System. This system consists of two pumps l (with one CS pump on standby as backup if either PI pump should fail) and an active-single-failure-proof piping network to provide the plant's only long term core cooling capability for non-reflood-able breaks. The PI system takes water from the containment sump and pumps it through the PI heat exchangers (which are cooled by water from the Fire System) into the single-active-failure-proof CS system described above, where it is distributed over the core. After cooling the core, the flow then goes out the break back to , the containment sump, completing the closed loop cooling system.
.Like the CS system, the PI system is capable of cooling the core only after the core has. been depressurized.
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,g 3.1.2.3 The Fire System. The CS and PI systems each require water from the Fire System to perform their safety functions. The Fire System pro-vides the necessary net-positive-suction head to the CS pumps (10 psig is required) and it provides the secondary cooling water to the PI heat exchangers. The Fire System is a site-wide system inter-connected to Dresden 2/3, containing multiple sources of watef (in-cluding several screen wash pumps, two diesel fire pumps, and ser-vice water pumps) and several alternate piping routes which could be used to supply the necessary water. The principal vulnerability of the system is possible damage to its buried piping network, for example, due to an earthquake. Even with the new above-qround - flexible hose connection from certain pumps (Dresden 1 screen wash and diesel fire pumps) to the CS suction header, this vulnerability still is present since a significant amount of existing pioina cannot be isolated from the new flexible connection. That is, flow might no out postulated breaks in such existing piping instead of to the CS pumps. The licensee has estimated that the probability of a seismic event occurring at jhe Dresden site which could cause slinht damaqe to be low (about 5x10' per year). The staff judges the likelihood of more severe earthquakes which could cause failures in essential safety system is to be even lower. Consequently, we rely on the low proba-bility of an earthquake during the extension period in order to allow O credit for availability of the Fire System. N"] 3.1.2.4 The Feedwater (FW) System. The FW system functions followinn a LOCA by injecting high pressure, relativel.y cold water into the core. This causes the primary system to depressurize. Such depressuriza-tion is essential following certain size and location breaks for the low pressure core spray system to function in time to prevent 10 CFR 50.46 performance criteria from being exceeded. The D-1 plant does not have the capability to relieve core pressure either automatically or manually by opening relief valves. Continuous, uninterrupted operation of two feedwater pumps and their associated condensate pumps is required to assure that performance criteria of 10 CFR 50.46 are met. This requires the availability of offsite power, plus the assumption that no single failure will disable the FW system. These are principle provisions of the exemption whose extension is being requested. The probability is considered high that offsite power will be continuously available. We have conducted a preliminary review of the FW system, its control system, and the fJ
m operating history of the FW system, and we conclude that there is reasonable assurance that the FW system will not experience a single failure following a LOCA, for the following reasons:
- 1. Modifications have been made to lock out the power supply to the only motor operated valve in the system which cannot be bypassed and which could disable the FW system if it were to drive to the closed position;
- 2. The FW system automatic controller only operates one valve, which will fail as-is with loss of power (normally 80% open ~
when the core is operating at full power); '
- 3. The level sensing instrumentation on the FW control system is a delta-pressure switch, which essentially measures collapsed water level, i.e., the true amount of coolant mass in the core.
That is, the FW system controller is not likely to sense a 3 swollen (high) level in the primary system if such a swollen level ware to occur due to pressurization followinq a LOCA. Therefore, the FW automatic controller is not likely to cause the FW control valve to drive closed, with the attendant possi-p) (U bility of failure in the closed position, which would delay FW system availability until the valve could be re-opened or
- I bypassed; I
- 4. Experience during past scrans due to turbine trip (similar to l a small break LOCA as far as the core and the FW controller is concerned) have resulted in initial water level decreases due to void collapse caused by the pressure increase, this causes the FW valve to remain at its former setting or drive j to a more open position, further reducing the probability of '
FW system unavailability due to a valve failing in the closed < position following a LOCA. ' 3.1.2.5 Emergency Condenser (EC). The EC is a large tank of water with two submerged independent tubing bundles. Opening one valve in either of the bundles allows primary system steam to rise into one of the submerged tubing bundles from the primary system; the primary steam is condensed within the bundle, and falls by gravity back into the primary system. The EC thus aids the FW System in deoressurization of the primary system for smaller breaks, so that the low pressure CS system can function. Credit for _ only one of the two systems (1/2 EC) is assumed in showing compliance with performance criteria of 10 CFR 50.46, since single failure of either inlet valve could cause 1/2 of the EC to fail (The assumption of this single failure is not p precluded by the exemption whose extension is renuested). l l
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%) 3.1.3 LOCA Analyses Assuming Degraded Equipment Availability Although operation of all equipment specified above is necessary to provide compliance with all cerformance criteria of 10 CFR 50.46, the following conclusions can be made with respect to LOCA analysis results assuming certain degraded equipment performance. Except for any deviations specifically noted below, all results are from analyses which use the same modified ECCS model and inputs discussed earlier. Since the CS, PI, and Fire systems can each tolerate any active single failure with no resultinq performance degradation as discussed above, and since a single failure in the EC has already been assumed in the analysis results, these conclusions are confined - to degraded performance of the FW system. If the FW system is lost simultaneous with the LOCA dgto loss of offsite power, then Commonwealth Edison (CECO) states that one FW pump will automatically restart within 30 to 50 seconds nowered by the new on-site diesel generator. The conservatism of these times will be confirmed by preoperational testing performed by CECO. Assuming these times, then LOCA analyses, assuming one FW pump is regained in 30 seconds and 50 seconds, show peak clad temperatures (PCT's) of 2317*F and 2414 F, respectively, for the limiting break size.* These PCT's are beyond the performance requirements of 10 Q i 1 CFR 50.46, but considering the conservatism believed to be in the V modified ECCS model as applied to Dresden 1, they provide some indi- ! cation that core melt would be avoided under these degraded condi- l tions, should they occur. CECO has also provided-a calculation for the case where the FW system is lost simultaneo FW system credit).p)with the For LOCA this and case, extreme never two regained (i.e., no additional modifications were made to the modified ECCS model** and one change was made to the input The 0.15 to 2.0 ft. break areas are limiting when FW delays are assumed: larger breaks depressurize quickly through the break without dependence upon the FW system; smaller breaks never uncover ' or remain uncovered for a shorter time before the FW system and 1/2 of the EC depressurize the core and allow operation of the CS system.
**l) Decay heat equal to 1.0 times "ANS" value, compared to 1.2 times "ANS" value required by Appendix K. The NRC staff is aware of data to support use of "1.0 times ANS"; this change in " Appendix K" require- -
ments may be approved at some future date.
- 2) Credit for 154% of the Emergency Condenser (EC). That is, analysis did not assume single failure of 1/2 of the EC, and did assume
,s credit for measured test data that shows EC performance to be 54% better
( than design values (which design values were used in all other calcu-
's lations reported).
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i . assumptions to the model.*** These changes make the result less conservative than others reported, and somewhat discontinuous with respect to those other results. However, the results are believed to be still conservative, and they do result in a predicted PCT below 2400*F, again providing some indication that core melt would not occur under these extremely degraded conditions, should they occur. 3.1.4 Conclusions Related to LOCA Anal _vses As stated above, we conclude:
~
- 1. That the ECCS-LOCA model used for the analyses provided is reasonably conservative and can be used for the purpose of determining whether or not the plant meets the performance requirements of 10 CFR 50.46. Employing this model, we have concluded. that the performance requirements of 10 CFR 50.46 will 'be met following a postulated LOCA.
- 2. That there is reasonable expectation that the equipment assumed to function in the ECCS-LOCA analyses, which show full compliance with the performance requirements of 10 CFR 50.46, will in fact function following a LOCA, and that this expectation has been
[] somewhat improved by equipment channes made since granting of Q the original exemption.
- 3. That even if some of the equipment needed to assure full compliance with performance requirements of 10 CFR 50.46 does not function, there is still reason to believe that core melt s would not occur.
Analyses were performed assuming a derated maximum allowable local power consistent with the plant's current Technical Specifi-cations, which are required to account for possible degradation of core spray flow due to steam redistribution effects. Dependina on how " flat" the core can be operated, the local power limits cause an effective total core power derate of 20% to 30",. Credit for effect of this "derate" on local power is assumed in this analysis. (As noted, all other analyses reported above did not assume credit for this derate.) O
V 3.2 Capability of the Reactor Protection System to Withstand Single Failures The Reactor Protection System (RPS) at Dresden Unit No.1 is i basically a two channel system (Channels A and 8). Within each i channel, two or more relay contacts for each plant parameter , monitored are connected in series ( A1, A2, etc.). If any one ' sensor controlling one of the relay contacts within a channel senses a trip condition then the channel trips. The output of each channel is connected to one of two scram solenoid valves - in series for each control rod. Both of the scram solenoid valves for an individual control rod must be opened to scram the rod. Therefore, the RPS channels A&B must trip before a scram is initia ted. This arrancement provides a high degree of protection from both a nuisance trip due to a spurious signal or a failure to scram all of the control rods as a result of random equipment l functional failures. However, as noted above, due to the physical arrangement of the RPS components, a single gross physical failure of certain tenninal blocks, instrument racks, sphere penetrations and wire ways, or a hot short around certain relay contacts, could n prevent a scram from one or more of the monitored plant parameters.
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(C/ In order to make an assessment of the extent to which the plant is vulnerable to the above listed failure modes, members of the staff visited the plant on October 3,1977, to meet with the licensee and physically inspect the RPS. At this meeting, the staff reviewed detailed schematic diagrams and analyses of the potential failure modes that had been performed by the licensee. Based on these discussions and on our review of infonnation previously submitted by the licensee .in its letter dated December 10, 1975, we were able to determine that the following design features represent the most significant vulnerability of the RPS to single failures:
- 1. Channel A and B input sensors in some cases are mounted on the same instru ant rack and are not separated by space or barriers (e.g., all the high reactor pressure sensors are mounted on rack ER-1).
- 2. Channel A and B input sensors in some cases ar wired on the same local terminal block and/or are in the same cable (e.g.,
all the sensors for the primary steam isolation valve closure trip and the low condenser vacuum trip are wired on a terminal - block at the turbine stand). l (G l I l
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- 3. Channel A and B input senbar wirinq is at least partially routed in common cable traf s and uses common containment sphere penetrations (e.g., cables for all the Peactor Vessel Level, Primary Steam Drum Level, Reactor Pressure and RPS Scram Backup trips use the same penetration).
- 4. All the Channel A and B individual trip parameter and scram solenoid bus. circuit wiring is terminated in the RPS ACliary Panel ( AP-5) located in the control room. The scram solenoid buses are terminated at this panel approximately 41/2 inches from the Channel A and B power sources on the opposite side of a wiring grill. A hot short of the scram solenoid bus to the A or B circuit power supply could prevent an automatic or manual scram of all the control rods.
- 5. Both Channel A and B RPS scram solenoids must be deenergized to scram the reactor. A hot short on either scram solenoid bus cable between the scram solenoid bus fuse cabinet in the containment sphere and Panel AP-5 in the control room could prevent a manual or automatic scram of all the control rods.
The scram solenoid bus cables share both penetrations and cable trays with sources of the 125V a.c. power necessary
} for a hot short that could prevent a scram. i Items 1 through 3 above are of lesser significance than items 4 and I 5 because they are examples of potential single failures that could prevent a scram from some, but not all, of the plant parameters moni tored. These circuits are deenergized to trip. Therefore, failures are likely to be in the safe direction with the exception of hot shorts. In the case of hot shorts, several shorts with no degraded voltage would be required simultaneously in different circuits to prevent a scram by all the sensed parameters. There i
are ten plant parameters monitored (e.a., high containment sphere l pressure, high neutron flux) with a minimum of two separate sensors i per channel which could produce a channel trip when the reactor is in the run mode. The probability of a single failure, during the extension period, that could disable a sufficient number of RPS trip input parameters to cause a significant fuel damage is acceptably low. The types of single failures (i.e., hot shorts) that could result from the conditions described in items 4 and 5 are of much greater significance than the failures described in items 1 through 2 because these single hot shorts could prevent a scram of all the - control rods from all of the plant parameters monitored. Even though the consequences of such failures are very significant, the n
.-_A. _ - . _ _ ___t______m_ . - . - -
O probability of their occurrinq is acceptably low as discussed in the following paragraph. In the case of item 4, the terminal blocks subject to hot shorts are on opposite sides of a wiring grill and are covered by flat insulating shields which leave very little bare conductor surface , exposed as a mechanism for hot shorts. Any shorting conductor l would have to be U-shaped, about 41/2 inches wide, and fit into i a space about 1/2 inch square at each end, or have sufficient i energy to physically damage the insulating shields, terminal blocks i and steel wiring grill so as to brina the shorting circuits toqether without at the same time grounding them. Within the wirina grill, it is possible that the cables subject to hot shorts are in direct l contact with each other separated only by the insulation on the conductors. Based on our physical examination of these circuits at the plant, we have concluded that the only shorting mechanism for these cables that could be considered credible during the extension period would be a fire. Since the wiring grill on Panel AP-5 is located in the control room, the operators would be immediately aware of a fire and could initiate a manual scram I p/ before the fire burned long enough to create a hot short. Even i U if the postulated fire were not controlled, or the reactor was not manually scrammed, the short would most probably eventually go to ground and cause a reactor scram because the wiring arill and panel are made of~ metal and are grounded. In order to discuss the failure mechanism in item 5 it is necessary to further describe the reactor control rod scram solenoid circuits. The control rods are divided into three aroups at the scram solenoid fuse cabinet located in the containment sphere. Each control rod in a group is controlled by two scram solenoids in the group that must be deenergized to scram. Each of the three groups is energized by a circuit between panel AP-5 located in the control room and the scram solenoid fuse cabinet. The three circuits for a11' three groups of the separate A or 8 scram solenoids are in a common cable jacket along with the- common wire which is grounded. Therefore, there are two cables; one cable for each set of scram solenoids A or B, that traverse the plant area from the containment sphere throuah the sphere penetrations and the cable tunnel to the control room in close proximity to sources of hot shorts which could preven,t a scram
'of the reactor. _
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The failure mechanisms for hot shorts for these cables would have to be something that could penetrate both insulating ,iackets around a scram solenoid bus circuit and the potential source of shortina power, and at the same time bring these cables into contact with each other without also coming into contact with a grounding source such as the common wire carried within the scram solenoid bus cables. The only failure mechanism that we have been able to identify that could be considered credible during the next extension period would j be a fire. This ccncern will be resolved by the installation of the ' fixed automatic fire suppression system proposed by CECO. l During the additional exemption period of operation proposed l without an automatic fire suppression system, we have determined that the installation of a fire detection system that alerts the operator of a fire in t" oble tunnel supplemented by manual fire suppression capability for the entire cable tunnel and a pro-cedural requirement to manually scram the reactor if a fire is I detected, coupled with a modified scram solenoid circuit which 6ssure shorts to ground, provide adequate assurance that the reactor can be safely shut down in the event of a fire in the cable tunnel.
,Q Until these additional measures are implemented to prevent potential Q hot shorts of the scram solenoid circuit caused by a fire in the cable tunnel, Commonwealth Edison will supplement the fire pro-tection in this area with an hourly fire watch.
Regarding environmental qualification of electrical equipment, the equipment that must function in the LOCA environment has been reviewed to assure that proper operation would be expected. Both the licensee and staff are continuing to evaluate this area to assure that other safety related equipment needed to function under accident induced environmental condf tion will not fail due to those environmental conditions. On December 21, 1977, the staff requested CECO, as part of the Systematic Evaluation Program, to examine the environmental qualification of all electrical equipment inside and outside of containment that must function for any Design Basis Event such as a LOCA. The staff expects to complete its review of this issue within the next three months; if during this tiine any deficiencies are uncovered appropriate action will be taken to ensure protection of the public health and safety.
l , l Q l 3.3 Conclusion Relating to Interim Operation Prior to Completion of Fire Protection and Environmental Modifications As discussed above, CECO has implemented interim fire protection measures to assure that the reactor protection system is safeguarded I against cable tunnel fires and has verified that all electrical com-ponents needed to actuate the emergency core cooling system are qualified to operate in the LOCA environment. We have reviewed these measures taken by the licensee and conclude - that their implementation increases the margin of safety during the interim period until October 31, 1978, provides sufficient assurance that the health and safety of the public is not endangered by such I operation, and is acceptable to the Regulatory staff. 3.4 Compliance With the Requirement of the Existing ECCS Exemption and the June 23,1976 Order 3.4.1 ECCS Modifications
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Commonwealth Edison has completed the detailed design of the Dresden high pressure coolant injection (HPCI) system and has submitted the design to the Commission by letter dated October 16, 1975. In response to questions generated by the Commission's review of CECO's design report, CECO has supplemented its design report by additional infonnation dated July 26, August 31, and October 20, 1976. The Regulatory staff review of the design report and its supplements is continuing. Commonwealth Edison currently has completed activities leading to the purcha:e of approximately 90% of the equipment and installation services for the HPCI system. CECO projects a most probable completion date for the H?CI system project of February 1979. Construction of the building designed to house the HPCI system is now scheduled for completion in March 1978. This completion date has been delayed. The design. delay was principally associated with the need to enlarge the HPCI building over the preliminary design. The construction delay was attributed to problems with discovery of slightly contaminated soil and the harsh 1976/1977 winter while constructing the HPCI building. The projected completion schedule above includes these delays. The presently pacing item for installation of the HPCI system is equip- - ment delivery for HPCI pump motors, service water and fuel oil transfer pur.ps and fire protection equipment. This equipment is expected to be available in August,1978. Installation and pre-operational testing O i t V
. is expected to be completed by December 31, 1978. The licensee proposes to shutdown in the Fall of 1978, decontaminate the reactor coolant system in November,1978, and connect the HPCI system and other related equipment.
3.4.2 Reactor Protection System and Fire Protection Order Commonwealth Edison has complied with the requirements contained in Paragraph 2.C(3)a of our June 23,1976 " Order for Modification of License" which dealt with Ceco's. submittal of design information related to their proposed modifications. '~ However, due to equipment procurement problems and the desire to complete these modifications concurrently with the HPCI installation outage after the primary system decontamination CECO has been unable to. complete its modification by December 31, 1977, as specified in the June 23,1976 Order. The completion of the modifications to the reactor protective system will involve modifications in high radiation areas. Some of these areas are scheduled to be decontaminated in the Dresden pi chemical cleaning outage presently scheduled for November,1978. CECO's modifications to be carried out in the lower radiation fields. vd The Regulatory staff concurs with CECO's intent of reducing the exposures associated with these modifications by completing the modifications after the Dresden 1 decontamination has been completed. In regard to the length of extension needed by the licensee to complete this project, the staff does not agree that a need exists to extend the exemption past the proposed decontamination shutdown in the Fall of 1978. This is because an ECCS is not required for plants not operating at power. Therefore, the extension is being granted only until October 31, 1978. The NRC staff in an effort to assure that the modifications identified in the August 1975 and June 1976 Orders are implemented as quickly as possible, has imposed a license condition that requires CECO to submit a monthly report of the progress in com-plying with these Orders and other related activities such as decon-tamination which could impact CECO's schedules. With regard to the modifications to the fire protection system required by the staff's June 23, 1976 Order, CECO has been unable - to install a fixed automatic fire protection system as reauired. O
e 16 - In the interim period of operation until the fixed autonatic system is installed Commorwealth Edison has installed a fire detection system in the cable tunnel and has extended the coverage of a manually operated fire hose station to provi@ complete coveraae of the cable tunnel. 3.5 Interim Facility Modifications and Procedural Chances 3.5.1 Changes Proposed by the Licensee In order to increase the reliability of the systems relied upon to - mitigate the consequences of a Loss-of-Coolant Accident at Dresden Unit No.1, Commonwealth Edison has proposed eloht interim changes to the facility and its operating procedures. The eight chances are:
- 1. Electrically disable feedwater valve it0130 in the full open position to prevent a failure of this valve from rendering the feedwater system inoperable.
- 2. tiodify the abnormal operating procedures to instruct the operator s
to check the feedwater control valve nosition during a LOCA and , to open bypass valve M0 50 if the control valve has failed.
- 3. Install and utilize a 345/138 KV transformer to connect the Dresden Unit flo.1 138 KV system with the Dresden Unit Nos. 2 and 3 345 KV system. This enhances the reliability of the off site power supply to Dresden Unit flo.1.
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- 4. Remove the plastic face from each of the drum level switches.
This will qualify these switches to nerform their ECCS function l in a LOCA environment.
- 5. Review the sphere hiah pressure and drun level sensors, switches, and cables which initiate the ECCS to determine that they can function in a LOCA environment and make modifications as necessary.
- 6. During the Summer,1977 refueling, a leak test of the orimary coolant boundary was performed in accordance with the applicable edition of the ASME Boiler and Pressure Vessel Code, Section XI.
This test provides further assurance of the hiah decree of integrity of the primary coolant boundary pining. v
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- 7. To augment the highly reliable off site power and the existing on site diesel oenerator, a backup diesel aenerator will bn available at the plant site by December 31, 1977. This diesel generator will orovide a redundant source of on site power for long term cooling functions.
- 8. The fire protection system will be modified such that lona term cooling can be accomplished without relying on portions of its underground piping. This modification involves providing ,
fittings in the fire protection system pipinq near the core spray and post incident pumps and in the cribbouse. These - fittings will provide a means to connect piping or hose between the fire protection system pumps and the energency core coolinq systems in the event the permanent connection via the under-ground piping system is unavailable. We have reviewed these changes and conclude that they will provide additional assurance that the Dresden Unit No.1 Emergency Core Cooling System will function as required during a LOCA and we are amending Facility Operating License DPR-2 to require that these modifications must be completed to permit operation af ter p December 31, 1977. 3.5.2 Additional Changes Identified During NRC Review In addition to the eight changes proposed by Commonwealth Edison in its July 8,1977 extension request, our review has identified certain other modifications which we require to provide a high degree of assurance that the ECCS will function as required. These additional changes have been discussed with the Commonwealth Edison staff and they have agreed to imolement them. The changes are:
- 1. The Dresden Unit No. I station batteries shall be restrained to withstand seismic loads.
- 2. Electrical cabinets containing controls for essential or backup ECCS equipment shall be restrained for seismic loads.
- 3. The new backup diesel cenerator shall be operable and must be capable of starting automatically and operating one feedwater pump and condensate pump within 50 seconds of a loss of offsite power. -
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- 4. The new flexible hose connecting the Dresden 'Jnit No. I fire pump and the suction of the core spray system shall be connected and remain connected throughout the extension period.
- 5. All missing protective covers and terminal board insulatina shields shall be replaced within the reactor protection system and ECCS electrical cabinets and any extraneous items stored in these cabinets shall be removed.
- 6. Five smoke d6tectors shall be installed in the cable tunnel to detect cable fires. The reactor will be manually scrammed ~
immediately upon detection of a fire.
- 7. The existing reactor protection system surveillance procedure shall'be modified to reouire that the RPS functional canability be verified weekly at the scram solenoid fuse cabinet in the containment rather than from the control room.
- 8. Rewire scram solenoid circuit with shielded cable and institute an hourly fire watch until rewired.
p). ( U In our review of the facility modifications pronosed by Commonwealth Edison, we have identified additional 'nodifications and orocedural changes which we consider necessary to provide additional assurance that the ECCS will function as required. We conclude that with the licensee's proposed modification supplemented by these additional modifications identified by the staff, the margins of safety at Dresden Station will be increased and that ooeration during the extension until October 31, 1978, is acceptable. 4.0 FINDING RELATED TO GRANTING OF A FURTHER EXEMPTION I We have reviewed Commonwealth Edison's July 8,1977 submittal and the affidavits attached thereto which provided CECO's exolanation for the delay in completion of the modifications, and have con-I cluded that CECO has shown good cause why the ECCS exemption expiration date and the date for compliance with the June 23, 1976 Order should be extended to permit continued operation of the ! Dresden plant while continuing to modify the facility. Our conclusion is based upon our determination that delays I encountered by CECO have been due to items which they have been _ unable to predic.i. .,dch as procurement difficulty, the presence of the contaminated soil underlyina the construction site and the harsh winter weather that' slowed their schedule. I O v l 1 L , 1 l
O The affidavits filed by Commonwealth Edison further demonstrate that the unavailahility of Dresden Unit No. I beyond December 31, 1077, will require the use of up to 83 million gallons of fuel oil at a cost of approximately 26 million dollars. The bulk of this cost would be passed directly to Commonwealth Edison's consumers. Thus, the NRC staff concludes that the extension of time fron December 31, 1977, to October 31, 1978, to permit the completion of required
. modifications at Dresden isnit No. I would be in the public interest given the absence of any undue risk in continued operation.
5.0 ENVIRONMENTAL CONSIDERATION
We have determined that the amendment does not involve a change in effluent types or total amounts nor an increase in power level and will not result in any significant environmental impact. Havinn made this determination, we have further concluded that the amendment involves an action which is insignificant from the standpoint of environmental impact and pursuant to 10 CFR s51.5(d)(4) that an environmental impact statement or negative declaration and environ-mental impact appraisal need not be prepared in connection with the ) issuance of the amendment. l O
6.0 CONCLUSION
\"l We have concluded, based on the considerations discussed above, that: (1) there is reasonable assurance that the health and safety of the public will not he endangered by operation in the proposed
)
manner. (2) such activities will be conducted in conoliance with 1 the Commission's regulations and the issuance of this amendment will not be inimical to the common defense and security or to the health and safety of the public, and (3) that the exemption is authorized by law and will not endanger life or property or the common defense and security and is otherwise in the public interest. We have also concluded that in relation to the additional license conditions required by the staff and the deletion of previous license conditions that have been complied with, that: (1) because the amendment does not involve a significant increase in the. probability or consequences of accidents previously considered and docs not involve a significant decrease in a safety margin, the amendment does not involve a significant hazards consideration, (2) there is reasonable assurance that the health and safety of the public will not be endangered by oneration in the proposed - manner, and (3) such activities will he conducted in compliance with' the Commission's regulations and the issuance of the amendment will not be inimical to the common defense and security or to the health and safety of the public. Date: January 6,1978
, . . . . - . . . .. - . . ..-- - - . ~ . - .. - _ - . . -
REFERENCES
- 1. NRC Memorandum and Order in the matter of Commonwealth Edison Company, August'21, 1975.
- 2. Lette'r to B. Rusche, NRC, from R. L. Bolger, Commonwealth Edison Company, l with attached Dresden Unit No.1 LOCA Analysis, July 31, 1975.
- 3. Attachment 3 to letter to E. Case, HRC, from R. L. Dolger, Commonwealth Edison Company, The XN-1 Heatup Analysis Supplement to Dresden Unit No.1 LOCA Analysis, August 3,1977.
~
- 4. Letters to D. K. Davis, NRC, from M. S. Turback, Connonwealth Edison
-Company, dated November 11,15 and 28,1977.
l l I
7590-01 f'i Q . UNITED STATES HUCLEAR REGULATORY COMMISSIO!1 DOCKET N0_._50-10 COMt10HWEALTH EDI_ SON C0f!PANY NOTICE OF ISSUANCE OF AMENDMENT TO FACILITY OPERATING LICENSE The U. S. Nuclear Regulatory Commission (the Commission) has issued ~I Amendment No. 23 to Facility Operating License Ho. OPR-2, issued to Commonwealth Edison Company (the licensee), which revised the license for operation of Dresden Station Unit No.1 (the facility) located 'in Grundy County, Illinois. The amend:aent is ef fective as of its date of issuance and exempts the f acility fron certain safety requirements. The amendment: (1) extends by exemption from the requirements of 10 CFR 50.46 the date from December 31, 1977, to October 31, 1978, for the license. to modify the. Reactor Protection System and Fire Protection System, which was required by the Connission's Order for tiodification of License dated June 23, 1976, (2) extends by exemption from the require-ments of 10 CFR 50.46 the expiration date of the Commission's August 21, 1975 Emergency Core Cooling System (ECCS) Order from December 31, 1977, to October 31, 1978, (3) adds interim license conditions to the license deemed necessary by the Commission's staff to provide added assurance that the Emergenc/ Core Cooling System will . function as required, and (4) formally incorporates the remaining applicable provisions of the June 23, 1976, and August 21, 1975 Order in the license. . d i
O The requested exemption by the licensee was for a period ending December 31, 1978, however, the exemption has been issued to expire October 31, 1978, to coincide with the planned shutdown of the facility for decontamination. The application for the amendment and exemption complies with the standards and requirements of th- Atomic Energy Act of 19 A, as amended (the Act), and the Commission's rules and regulations. The Commission has - made appropriate findings as required by the Act and the Commission's rules and regulations to 10 CFR Chapter I, which are set forth in the license amendment. In connection with item (1) above, Notice of Proposed Issuance of Amendment to Facility Operating License was published in the Federal Register on November 11, 1977 (42 F.R. 58801). For item (2) Notice of Request for Extension of ECCS Exemption was published in the Federal Register on November 30, 1977 ( 42 F.R. 60989). No requests for hearing i 1 or comments were received on items (1) and (2). Prior public notice of l l items (3) and (4) above was not required since these actions do not involve a significant hazards consideration. The Commission has determined that the issuance of this amendment i and exemption will not result in any significant environmental impact
< and that pursuant to 10 CFR 651.5(d)(4) an environmental impact statement-or negative declaration and environmental impact appraisal need not be prepared in -connection with issuance of this amendment.
O
For further details with respect to this action, see (1) the applicatdon for amendment and extension dated July 8,1977, and supplements thereto dated November 11,15 and 28,1977, and December 14, 1977, (2) Amendment No. 23 to License No. DPR-2, and (3) the Commission's related Safety Evaluation. All of these items, including the referenced Orders, are available for public inspection at the Commission's Public Document
- 1 Room, 1717 H Street, N. W., Washington, D. C. A single copy of items (2) and (3) may be obtained upon request addressed to the U. S. Nuclear Regulatory Commission, Washington, D. C. 20555, Attention: Di rector, Division of Operating Reactors.
Dated at Bethesda, Maryland this sixth day of January,1978. Q THE NUCLEAR REGULATORY COMMISSION O /
- kN.~-
on K. Davis, Acting Chief 1 Operating Reactors Branch #2 i Division of Operating Reactors l a l
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8.0 CONCLUSION
S The licensee has performed a fire hazards analysis and has proposed Additional , J certain modifications to improve the fire protection program. modifications have been proposed by the licensee during the course of our review, which are based upon the. fire hazards analysis and our onsite These proposed modifications evaluation of the fire protection program.In addition, we have concluded that the are sumurized in Section 3.1. licensee should implement certain evaluations or improvements related to l the fire protection program. These are summarized in Section 3.2. - l I Significant steps are being taken to provide additional assuran Additional safe condition during and following potential fire situations. incomplete evaluation of be necessary before we can conclude that the overall fire protection at the Palisades facility will satisfy the provisions of BTP 9.5-1 and , Appendix A thereto, which the staff has established for satisfactory ! long-term fire protection. licensee's proposed modifications described herein are We find that the acceptable botn with respect to the improvements in the fi the facility,.while the remaining items are completed. r% In the report of the Special Review Group on 'he Browns Ferry Fire (V) (NUREG-0050) dated February 1976,. consideration, of the safety of operation of all operating nuclear power plants pending the completion of from our detailed The following quotations fire protection evaluation was presented. the report summarize the basis for our conclusion that the operation of the facility, pending resolution of the incomplete items and the implemen-tation of all facility modifications, does not present an undue risk to the health and safety of the public.
" A pr'obability assessment of public safety or risk in quantitative As the terms-is given in the Reactor Safety Study (WASH-1400).
result of the calculation based on the Browns Ferry fire, the study concludss that the potential for a significant release of radioactivity from such a fire.is about'20% of that calculated from all other causes analyzed. This indicates that predicted potential accident l risi.s fron all causes were not greatly affected by consideration of i the Browns Ferry fire. This'is one of the reasons that urgen action The study (WASH-1400) also points out that 'rather straig measures,-such as may already exist at other nuclear plants, can j significantly reduce the likelihood of a potential core melt accident . that might result f rom a large fire.' i j
" Fires occur rather frequently; however, fires involving equipmeht I unavailability comparable to the Browns Ferry fire are quite infrequent The Review Group believes that (see Section 3.3 of [NUREG-0050]).
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'( steps already taken since March '1975 (see Section 3.3.2) have reduced this frequency significantly.
-" Based on its review of the events transpiring before, during and i after the Browns Ferry fire, the Review Group concludes that the probability of disruptive fires of the magnitude of the Browns Ferry event i,5 small, and that there is no need to restrict operation of nuclear power plant s for public safety. However, it.ic clear that much can and should be done to reduce even further the likelihood of disabling fires and to improve assurance of rapid extinguishment of fires that occur. Consideration should be given also to features that.would increase further the ab'ility of nuclear facilities to withstand large fires without loss of important functions should such fires occur." I j
We have determined that the license amendment does not authorize a change in effluent types or total amounts nor an increase in power Itvel and will not result in any significant environmental impact. Having made this determination, we have further concluded that the amendment involves an action which is insignificant from the standpoirt of environmental impact and pursuant to 10 CFR SI.5(d)(4) that an enviro, mental impact statement, or negative declaration and environmental impact poraisal need not be l prepared in connection with the issuance of this amendment. l
,ss
( ) We have concluded, based on the considerations discussed above, that: (1)
\s_ / because the amendment does not involve a significant increase in the probability or consequences of accidents previously considered and does not involve a significant decrease in a safety margin, the amendment does not involve a.significant hazards consideration, (2) there is reasonable by operation in the proposed manner, and (3) such activities will conducted in compliance with the Commission's regulations and the issuance 4 of this or to theamendment health andwill not be safety inimical of the to the. common defense and security public.
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'd 8. 0 CONCLUSIONS 1 l The licensee has performed a fire hazards analysis and has proposed ' certain modifications to improve the fim protection program. Additional modifications have been proposed by the licensee during the course of our review, which are based upon the fire hu ards analysis and our onsite evaluation of the fire protection proppait ines? proposed modifications are sumu rized in Section 3.1. In addition, we have concluded that the licensee should implement certain evaluations or improvements related to the fi m protection program. These are summarizec in Section 3.2. , Significant steps are being taken to provid? additional assurance that I safe shutdown can be accomplished and the plant can be maintained in a _ safe condition during and following potential fire sit'!ations. Additional evaluation of incomplete items, discussed in the preceding sections, will be necessary before we can conclude that the overall fire protection at the Paliudas facility will satisfy the provisions of BTP 9.5-1 and l Appendix A thereto, which the staf f has established for satis f actory l long-term fire protection. l We find that the licensee's proposed modifications describer acceptable botn with respect to the improvements in tne ,-r ' program *. hat they provide and with respect to continu W sef , the facility, while the remaining items are completed (O L In the report of the Soecia! Review Group on the Broon-(NUREG-0050) dated February 1976. consideration of tne *o of all operating nuclear power plants pentiing the cont: ~ .e fire protection evaluation was pre ted The fc 1r+ n; .. n the report summarize the basis fo/ger}hNchuN 8u $ F? the facility,pc-f ; ,; S m m -_
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the hc abh d sseU afe' mofHthe 9 k. led +.cep dloca. d). h %es{en "A prob ility as ssment of pub it safety or fisk in qua ' cat e term s given . the Reactor afety Study ADi- 1400 ) . - +v re t of the alculation b ed on the B wns Ferry f' e, tw .u<s c ncludes t t the poten 'a! for a si .ficant rel se of r#: t, from such fire is ab .t 20% of th calculated .rce ali etner causes alyzed. Th' indicates at predict potent'ai acc4 ri s l.s rom all cau s were no reatly affe edbyconsidfer't i e 0+ the owns Ferry ire, Thi is cne of th reasons thatj., gen acti i regard to r ducing ri due to pote ial fires is et requiry:7 he study SH-1400) " so points out hat 'rather raightfcr 'rd measur es uch as m alreaoy exist t other nucl r plants, an . signi ' antly red e the likelih of c poten ' 1 core m3P acciner.t tha ight res from a large 1re.'
" Fires occur rather f requent.ly; howm- ires 'n '
-e unavailhbility comparable to the Bruans arry -
s qui, i. . : quem / \ (see Section 3.3 of [HUREG-0050]). Tne vie- .cliv :na: U 8-1
/ steps already taken since March 1975 (see Section 3.3.2) have reduced
(]v/ this frequency significantly,
" Based on its review of the events transpiring before, during and after the Browns Ferry fire, the Review Group concludes that the probability of disruptive fires of the magnitude of the Browns Ferry event is small, and that there is no need to restrict operation of nuclear power plants for public safety. However, it is clear that much can and should be done to reduce even further the likelihood of disabling fires and to improve assurance of rapid extinguishment of fires that occur. Consideration should be given also to features that would increase further the ability of nuclear faci H ties to withstand large fires without loss of important functions should such Iires occur."
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4 # We have determined that the license' amendment does not authorize a change in effluent types or total amounts nor an increase in power level and will not result in any significant environmental impact. - Having made this determination, we have further concluded that the amendment involves an action which is insignificant from the standpoint of environmental impact and pursuant to 10 CFR 51.5(d)(4) that an environmental impact statement, or negative declaration and environmental impact appraisal need not be prepared in connection with the issuance of this amendment. We have concluded, based on the considerations discussed above, that: (1) because the amendment does not involve a significant increase in the prnbat'ility or consequences of accidents previously considered and does - not involve a significant decrease in a safety margin, the amendment-does not involve a significant ha:ards consideration, (2) there is reasonable assurance that the health and safety of the public will not be endangered by operation in the proposed manner, and (3) such cctivities will be conducted in compliance with the Commission's regulations and the issuance of this amendment will not be inimical to the common defense and security cr to the health and safety of the public. b M $
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, L. / 6 N i T. UrNTED STATES r ,. I I NUCLE AR REGULATORY CC.'N,ilSSION f$ -j { WASHINGTON, D. C. 2GM5
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,,,,,- ? ". . ': 'c MEMORANDUM FOR: Landon R. Nichols, Technical Assistant, Divi sion of Operating Reactors FROM: Paul S. Check, Chief, Reactor Safety Branch, Division of Operating Reactors
SUBJECT:
USE OF WASH-1400 _ RSB has only one instance to report involving the use of WASP-1400 that to our knowledge isn't being reported by others. _Haddam Neck (50-213) Overpressure Protection RSB concluded that the OPS mitigates all credible mass and heat input events with the exception of HPSIP mass input event. RSB's finding that the HPSIP mass addition could be omitted was based primarily on a proba-bility result derived from a fault tree analysis. ( ( I have classified this usage of WASH-1400 as Category 5 (Denton to Directors, October 30, 1978 ). The RSB SER is enclosed. , f
,, itt Paul S. Check, Chief Reactor Safety Branch Division of Operating Reactors
Enclosure:
As stated cc: D. Eisenhut T. Marsh C. Beriinger O
7-
/# " *%, UNITED STATES A !" ' t, NUCLEAR REGULATORY COMMiss!ON
) { i WASHINGTON, D. C. 20555 3 ....
} filAY S 1978 1
Docket No.: 213. MEMORANDUM FOR: Dennis Ziemann, Chief,. Systematic Evaluation Projects Branch, 1 00R ' FROM: Robert L. Baer, Chief, Reactor Safety Branch, DOR
SUBJECT:
. REVIEW OF HADDAM NECK OVERPRESSURE PROTECTION SYSTEM l
~'
(TACS #7053) PLANT NAME: Haddam Neck DOCKET NUMBER: 50-213 RESPONSIBLE BRANCH: ORB-2 PROJECT MANAGER: W. Russell OPERATIONAL TECHNOLOGY BRANCH INVOLVED: Reactor Safety l
-REVIEW STATUS: Complete l The Reactor Safety Branch' Safety Evaluation of the proposed Haddam O has been completed and the -
Neck Overpressure ProtectionhatSystem .(OPS)heWopFsed~0PS~nifl (d results are attached.fWe concl'u3e~1 t credible' mass"and' heat input events with the exception of the HPSIP mass input event. . Based on the arguments and calculations presented
.in Section 4 of.the attached SER, we also conclude that there is suffi- l cient justification for the HPSIP mass' addition event to be omitted as I can OPS design base transient. / The Electrical, Instrumentation and Cofifrsl System SER for the Haddam Neck OPS will be furnished separately by the Plant Systems' Branch.
In your le R to Connecticut Yankee Atomic Power Company forwarding the approved Technical Specification Changes relevant to overpressure protection, please inform the licensee that failures to meet the . Limiting Conditions for Operation specified in these Changes are 30 day reportable events. Additionally, any pressure transients which cause the OPS to function, thereby indicating the occurrence of a serious pressure transient, is also a 30 day reportable event. Sufficient information should be ' forwarded by the licensee with these reports to provide a clear picture of the actions of plant personnel and the variation in system parameters during the course of these transients.
~
se-:{ % %q obert L. Bae. Chief Reactor Safe
- ich
Enclosure:
as stated cc: V. Stello N. Anderson - S. Weiss T. Novak W. Russell D. Eisenhut M. Fletcher G. Lanik. D. Tondi P. Shemanski B. Grimes ' ..C. :rlinger- J. Rosenthal G. Zech L. Marsh D. Davis- r. Nffman W. Butler D. Ziemann
- e 1
i i i SAFETY EVALUATION REPORT OF l THE OVERPRESSURE PORTECTION SYSTEM FOR i 4 HADDAM NECX l
)
MAY 1978 l l t 4 i
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- 1. 0 INTRODUCTION .
By letters dated September 12, 1977, and March 6, 1978 (References 12 l
'and 16) Connecticut Yankee Atomic Power Company (CYAPCO) submitted to the NRC a plant specific analysis in support of the proposed reactor vessel Overpressure Protection System (OPS) for Haddam Neck Nuclear Power Station. This information supplements other documentation submitted by CYAPCO over the past 17 months. (References 2, 3, 4, 7, 8, 10, 11, 14, 15)
Staff review of all information submitted by CYAPCO in support of the proposed Overpressure Protection System is complete and the staff has found that tne system provides adequate protection from overpressure transients. A detailed safety evaluation follows.
2.0 BACKGROUND
Over the last few years, incidents identified as pressure transients have occurred in pressurized water reactors. This term " pressure l transients," as used in this report, refers to events during which the temperature pressure limits of the. reactor vessel, as shown in the p,)
- facility Technical Specifications, are exceeded. All of these incidents V occurred at relatively low temperature (less than 200 degrees F) where the reactor vessel material toughness (resistance to brittle failure) is reduced.
The " Technical Report on Reactor Vessel Pressure Trnasients" in NREG-0138 (Reference 17) summarizes the technical considerations relevant to this matter) discusses the safety concerns and existing safety margins of operating reactors, and describes the regulatory actions taken to 1 resolve this. issue by reducing the likelihood of future pressure I transient events at operating reactors. A brief discussion is presented here. ' l l 2.1 yessel Characteristics Reactor vessels are constructed of high quality steel made to rigid specifications, and fabricated and inspected in accordance with the time proven rules of the ASME Boiler and Pressure Vessel Code. Steels used are particularly tough at reactor operating conditions. However, since reactor vessel steels are less tough and could possibly fail in a brittle manner if subjected to high pressures at low temperatures, - power reactors have always operated with restrictions on the pressure
. allowed during startup and shutdown operations.
At operating temperatures, the pressure allowed by Appendix G limits is in excess of the setpoint of currently installed pressurizer code 2 i i
n v safety valves. However, most operating PWRs were not originally designed to have pressure relief devices to prevent pressure transients during cold conditions from exceeding the Appendix G limit.
- 2. 2 Regulatory Actions-By letter dated August 11, 1976, (Reference 1) the NRC requested that CYAPCO begin efforts to design and install plant systems to mitigate the consequences of pressure transients at low temperatures. It was also requested that operating procedures be examined and administrative -
changes be made to guard against initiating overpressure events. It was felt by the staff that proper administrative controls were required to assure safe operation for the period of time prior to installation of the proposed overpressure mitigating hardware. CYAPC0 participated as a member of a Westinghouse (W) user's group which was formed to support the analysis effort required to verify the adequacy of the proposed Overpressure Protection System. Using input data provided by the members, W performed transient analysis (Reference 18) applicable to aT1 licensee's in the user's group. ( CYAPC0 responded (Reference 2 and 3) with.information describing their interim measures to prevent pressure transients. Based on some " scoping" l calculations done by Westinghouse for the user's group, the licensee presented, in Reference 4, discussion of the hardware modifications which were to be proposed pending after further analyses. These hardware changes assumed the ability of the existing pressurizer power (air) operated relief valves (PORV), to mitigate all pressure transients. The staff forwarded questions from our review of these submittals in our January 10 and February 14, 1977 letters to the licensee, References 5 and 6. The staff's April 1, 1977 letter, Reference 9, requested CYAPC0 to ensure that the likelihood of an overpressure transient as a result of improper RCP operation was minimized. The licensee's April 26, 1977 submittal, Reference 10, addressed the staff's concerns regarding RCP operation. After meetings, conference calls and detailed RCS pressure transient analyses, CYAPCO rejected their initial intent to rely on the existing PORV's, and presented a report describing the proposed installation of . new low pressure spring loaded safety valves (SLSV's) and associated motor operated isolation valves (MOV's) on the pressurizer. The final Overpressure Protection System (OPS) report (Attachment 2'to September
.7, 1977 submittal, Reference 19) indicated, however that CYAPC0 had O -not analyzed the RCS pressure response resulting from the single HPSI
( pump mass input event. This was not in accordance with the staff's
.3
O U criteria, discussed in Section 2 3 herein, so that staff requested (Reference 13) the licensee to provide an analysis of the event. If the Appendix G maximum allowable pressure was predicted to be exceeded with the proposed OPS, CYAPC0 was to propose system modifications meeting our design criteria, and to provide a value - impact assessment to make these modifications.
- The staff visited the plant on November 17, 1977 and observed the OPS l components and controls being installed and discussed with plant staff j the administrative and procedural controls taken to preclude the HPSIP -!
mass input transient. The licensee's November 30, 1977 and March 6, 1978 submittals (Reference 14 and 16) provided an analysis of the HPSIP mass input event and the staff requested value-impact assessment. CYAPC0 proposed Technical Specifications in support of the Haddam Neck OPS in their January 30, 1978 submittal, Reference 15,
- 2. 3 , Design Criteria Through a series of meetings and correspondence with PWR vendors and pd licensees, the staff developed a set of criteria for an acceptable overpressure mitigating system. The basic criterion is that the mitigating system will prevent reactor vessel pressures in excess of these allowed by Appendix G for the design basis events discussed in l Section 2.4. Specific criteria for system performance are- 1 I
(1) .0perator Action: No credit can be-taken for operator action for ten minutes after the operator is aware of a transient. (2) Sinale Failure: The system must be designed to relieve the pressure transient given a single failure of an active component in addition to the failure that initiated the pressure transfert. (3) Testability: .The system must be testable on a periodic basis consistent with the system's employment. (4) Seismic and IEEE 279 Criteria: Ideally, the system should meet seismic Cateogry I and IEEE-279 criteria. The basic objective is that the system should not be vulnerable to a common failure that
.would both initiate a pressure transient and disable the overpres- -
sure mitigating system. Events such as loss of instrument air and loss of offsite power must be considered. Another criterion required by the staff in the design of the pressure l
- mitigating system was that the electrical, instrumentation, and control
. systems provide alarms to alert the operator to (1) properly enable i
4 1
the system at the appropriate temperature during cooldowns and (2) indicate if a pressure transient is in progress. In the initial letters to all PWR licensees, Reference 1, the staff also required the installation and use of permanent RCS pressure and temperature recording devices. 2.4 Design Basis Events The incidents that have occurred to date have been the result of - operator errors or equipment failures. Two varieties of pressure transients can be identified: a mass input type from charging pumps, safety injection pumps or safety injection accumulators; and a heat addition type, which causes thermal expansion, from sources such as steam generators, reactor coolant pumps (RCP), pressurizer heaters or decay heat. On Westinghouse designed plants, the most common cause of the over- 1 pressure transients to date has been isolation of the letdown path. Letdown during low pressure operations is via a flowpath through the , (~N RHR system. Thus, isolation of RHR can initiate a pressure transient ! if a charging pump is left running.*' Although other transients occur Q with lower frequency, those which result in the most rapid pressure increases were identified by the staff for analyses. The most limit-ing mass input transient identified by the staff is inadvertent injec-tion by the largest safety injection pump. The most limiting thermal expansion transient is the start of a reactor coolant pump with a 50 degree F temperature difference between the water in the reactor vessel and the water in the steam generator (secondary). The largest safety injection pump at Haddam Neck is the high pressure safety injection pump (HPSIP) which has a flowrate above 2100 gpm at a discharge pressure of 500 psig (from Figure 4, Reference 19). This is more than double the maximum flowrate of the HPSIP in other plants desired by Westinghouse.** Due to the very large relieving capacity
/ necessary to mitigate the Haddam Neck HPSIP mass input event, and other plant specific considerations described and evaluated in Section 4, the licensee has designed A recent RCS pressure excursion was caused by the securing of the -
RHR pumps while the RCS was in a cold, shutdown and water-solid condition. The RCP's were left operating (heat input of about 4.2 MW) and the core was generating about 13.6 MW of decay heat. The loss of the low temperature heat removal capability, plus O " the possible partial loss of letdown, caused the pressurization, d From figure 2.3.2 of Reference 18, other HISIP's in W designed plants (with the exception of Yankee-Rowe and San Onofre) have flowrates ranging' from 500 to 900 gpm at 500 psig. 5
. .- - .. . ~ - .- . - . . - _ _ - _ - _ .
O the OPS to mitigate all credible mass'and heat input events with the exception of the HPSIP mass.-inpdt.
' 3. 0 : SYSTEM'0ESCRIPTION AND EVALUATION.
Based on calculations performed by CYAPC0 using RCS pressure transient sensitivity studies-(furnished by Westinghouse) and using Haddam Neck plant. specific data, the. licensee rejected their initial proposal of an 0PS utilizing the' existing pressurizer PORV's.* CYAPCO elected to design, purchase and install low pressure ' spring loaded safety valves , (SLSV's) and motor operated isolation valves (MOV's) on new piping.to be-added'to the pressurizer. The system is described below. A three inch (00) pipe penetrates the pressurize steam space and branches into two.two inch (00)' pipes containing the PORV's and their MOV's. Downstream of the PORV's (discharge) the lines join and are
.. routed to the pressurizer relief _ tank (PRT). The licensee has added two'more~two-inch (00). pipes,:each connected to the three inch (00) .
pipe leaving the pressurizer. Each line contains two MOV's upstream of~aSLSV,andthedischargepipes-arejoinedtothePORVcommon discharge pipe. Both SLSV s.are set to open at 380 psig, and when all four MOV's are open, a pressure transient is terminated below the O' . Appendix G limit by opening of one or both SLSV. During RCS cooldowns, the.four.MOV's are electrically opened, and to ensure proper OPS lineup, an enabling alarm annunciates (audible and visual) when RCS pressure is below 380 psig, temperature'is below 340*F, and any of'the four OPS MOV's are closed.** To ensure the MOV's are not prematurely' opened, the MOV's are' electrically interlocked so that none can be opened unless RCS pressure is below 400 psig and RCS temperature is below.340'F. To preclude erroneous MOV closure the~ licenses will i remove all power from the MOV operators once-the' valves have been opened. During RCS startup and heatups, power is manually reinstated to the MOV's when RCS temperature is above 340*F and the four MOV's are shut. Additional assurance that the MOV's are shut prior to l system pressurization is provided by an alarm which annunciates-whenever RCS temperature is above 340* and the MOV's'are open. The. staff finds'the use of redundant SLSV's and associated MOV's an acceptable concept.for the mitigation of the design base events discribed.in Section 2.4. Our discussion and evaluation of the system proposed by CYAPC0 follows:
" The-calculations are discussed in Reference 19 and in Section 3.4 herein.
**This alarm is supplemented by an "RCS pressure transient" alarm that annunciates when pressure is above.400 psig and temperature.below:
O -340aF. These two alarms' work in' conjunction.with administrative procedures ~ in ensuring;the CYAPC0 OPS is properly aligned. 6'
- ~. -
.- = . . -
l 3.1 Electrical Controls , (Plant Systems Branch input)
- 3. 2 Testability.
Testability will be provided. The licensee has stated that the four OPS M0V's will be mechanically tested in accordance with the require- - ments specified in Section XI of the ASME code, and will be electrically tested by confirming proper motor and valve movement in response to an input signal (e.g., opening or closing). A channel functional test associated with the MOV interlocks and controls will be conducted once per refueling shutdown. The SLSV's setpoint will also be verified each refueling outage by either a bench test, (removal of the SLSV for test at a testing facility), or by an in place test done by pressurizing the RCS up to the SLSV setpoint with alternate sets of MOV's open so that each SLSV can be checked. The licensee's testing requirements are further clarified in the technical specifications proposed in O their reference 15 submittal and discussed in Section 5.2 herein, and are acceptable. 3.3 Appendix G The Appendix G curve submitted by CYAPC0 for purposes of overpressure transient analysis is based on fourteen (14) year period of full power operation. The licensee has utilized the zero degree heatup curve (isothermal curve), which is acceptable since most pressure transients have occurred during isothermal metal conditions. Margins of 60 psig , and 10*F are included in the curves to account for possible instrument l inaccuracies. The Appendix G limit at 100*F according to the 14 EFPY isothermal curve is 590 psig. The staff finds that the use of the l isothermal,-14 EFPY Appendix G curve is acceptable for OPS performance l design. l 3.4 Setpoint Analysis RCS overpressure transient analyses were performed by Westinghouse for the members of the owner's group. The one loop version of the LOFTRAN code (Reference WCAP 7907) was used for the analysis of mass input _ type transients and the four loop version was used for the heat input transients. Both versions required some changes to the input modeling and initialization. LOFTRAN is currently under review by the staff and is judged to be an acceptable code for treating problems of this q type. l N.) l l 7
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O The Westinghouse generic analyses (Reference 18) provided sensitivity studies that' enabled PWR licensees to calculate the pressure overshoot (P -P 3 for both types of transients (mass and heat input) with a b iety bI) plant parameters. .The pressure overshoot is due to the I effects of PORV delay and stroke' times. CYAPC0 used the sensitivity studies to evaluate the OPS performance using their existing PORV and specific plant parameters (pump flowrate, system volume, PORV stroke time and S/G heat transfer area). The CYAPC0 calculations (shown in Appendix A of Reference 19). demonstrated the inability of the existing PORV's to mitigate the de' sign base events because of their relatively ~ slow stroke time. Therefore, the licensee designed and installed an OPS utilizing passive SLSV's. Since the Westinghouse ;ensitivity studies were performed assuming the use of a PORV to relieve system pressure and since the time dependent
. flow characteristics of the PORV and SLSV differ,* the licensee could not.use these. studies directly to affirm OPS performance without making additional assumptions '(see Section 3.4.1). However, the portion of the RCS pressure transient prior to PORV opening is applicaole to Haddam Neck, and the licensee and staff used this part j of the analyses in verifying the proposed OPS performance. Certain 0 assumptions in the Westinghouse transient analysis are conservative relative to the actual Haddam Neck RCS and associated system parameters.
Some of these'are listed below:.
)
- 1. The'RCS was assumed to be rigid with respect to metal expansion.
- 2. No credit was taken.for the reduction in reactor coolant bulk modulus at RCS temperatures above 100*F (constant bulk modulus at all RCS temperatures).
- 3. No credit was taken for the shrinkage effect caused by low temperature SI water added to higher temperature reactor coolant.
- 4. The entire volume of water in the steam generator secondary was assumed available for heat transfer to the primary. In reality, the fluid immediately' adjacent and above the tube bundle would be the primary source of energy in the transient.
"The_PORV.and SLSV relief rates depend on upstream pressure and flow
~
area. Both the PORV and SLSV upstream pressures are pressurizer pressure. .The PORV flow area is independent of upstream pressure once the setpoint'has been reached, and depends only on the air operator's stroking characteristics whereas the SLSV flow area varies directly O, with upstream pressure until the value is fully open at 110% of PSET*
'8
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O
- 5. The overall steam generator heat transfer coefficient was
; assumed to be the free convective heat transi'ar coefficient of the secondary side. The forced convective heat transfer l coefficient of the primary side, and the tube metal resistance have been ignored thus resulting in a conservative (high) coefficient.
[
- 6. The RCP flowrate assumed in the heat input analysis was l .95,000 gps whereas the actual Haddam Neck RCP flow is about .
62,000 gpm. The staff agrees that these assumptions are conservative. Another significant conservatism associated with the determination of the OPS performance is the assumption that only one SLSV is available for pressure relief. Unlike the PORV, the SLSV is free of actuating circuits and pilot valves and is considered a passive device. The upstream isolation valves are opened during plant cooldown and have their power removed, and are therefore also passive devices. Verification of the licensee's proposed OPS is described below with respect to each of the limiting design base events. 3.4.1 Mass Input Case The mass addition from a single. centrifugal charging pump (CCP) with a concurrent total loss of letdown and the RCS in a water-solid condition was identified by CYAPCO as the most limiting mass inout case requiring mitigation by a SLSV.* Based on this event, the licensee calculated the required SLSV_setpoint such that the Appendix G limits are not exceeded. The staff verified the licensee's calculations and performed independent checks. Both the staff's and the licensee's calculations are discussed below. CYAPC0 determined the CCP flow at discharge pressures below about 1300 psig by extrapolating the head-flow curve ** (Figure 5 of Reference 19) then calculated the SLSV capacity using manufacturers data and assuming
" As discussed in Section 2.4, the licensee has not considered the HPSIP mass input event as one of the design base events used to determine the SLSV setpoint and OPS performance acceptability.
** Extrapolation of CCP flow data will give a maximum but possibly unrealistic flowrate. The pump flowrate is limited by the avail-able NPSH and the motor overcurrent trips. CYAPC0 estimates _
that CCP flow can't go above about 640 gpm due to the maximum ' available suction head. l C ' l 9
l the valve to be fully open (Figure 6 of Reference 19). From these curves, CYAPCO estimated that at a RCS pressure of 380 psig, the CCP flow into the system is about 860 gpm and the SLSV relieving rate is about 890 gpm, thus showing that the maximum RCS pressure during this event would be below 380 psig. Since the Appendix G pressure limit at 100?F is about 590 psig, this calculation shows that if the SLSV setpoint is sufficiently below 590 psig, the SLSV will mitigate this event. The SLSV setpoint was chosen to be 380 psig and CYAPC0 determined the overall SLSV flow performance (Figure 1, curve for " Single SLSV Without Flashing"). The staff notes that using this curve, the peak ~ RCS pressure for this event is about 418 psig. The staff examined the possible effects of liquid flashing by using data supplied by.a SLSV manufacturer for a valve design similar to the Haddam Neck SLSV.* This data indicates that a flow reduction of about l 60% could be experienced if 350*F liquid flashed in the SLSV throat.** l Using this data, the staff estimated the relief rates from one and both SLSV's, and these curves are shown on Figure 1. Based on these estimates and the extrapolated CCP head-flow curve, the peak RCS pressure is about 1220 psig with a single SLSV and about 625 psig with both SLSV's operating._ The maximum allowable pressure at a RCS
; temperature of 350*F is above 1220 psig, so the staff concludes that, for a mass addition event, flashing does not compromise the OPS performance.
As a further check, the staff used the Westinghouse sensitivity studies, Reference 18. Although these studies assume the operation of a PORV rather than a SLSV, the capacities of the reference PORV and SLSV are I similar,*** and the opening characteristics of the SLSV are superior.**** ; Therefore, if the predicted peak RCS pressure using the W studies is acceptable, then the peak pressure with the SLSV will also be acceptable. Crosby, the manufacturer of the RHR safety valve used by Kewaunee supplied this data to Wisconsin'Public Service Company, who then submitted it to the staff in support of the Kewaunee overpressure protection system.
** Since the pressurizer liquid temperature is allowed to be as much as 200*F hotter than the RCS, it is possible for the SLSV discharge to be hotter than 350 F. However, the pressurizer is cooled down using spray flow which is at the RCS cold leg temperature. Since the spray nozzle is at the top of the pressurizer, which is where the SLSV penetrates the pressurizer, the staff considers 350*F a sufficiently conservative temperature for estimating flashing effects.
*** Comparing Figure 1 herein to Figure 2.2.1 of Reference 18, the fG PORV flow is about 50 gpm greater than the SLSV flow at 380 psig.
.h ****The licensee states that the SLSV " pops" open is less than 500 msee.
10
Figure 1
,q SLSV Flow Characteristics
( 1500 _ _ -_. (P , = 380 psig)
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p-V Using actual or conservative plant specific paramters, the staff calculated the peak RCS pressure to be about 445 psig which is below Appendix G limit at 100*F. We conclude that the W sensitivity studies also~ support the proposed SLSV setpoint.and performance, and therefore, based on the arguments and calculations presented above, the Haddam Neck OPS mitigates the design base mass addition event. 3.4.2 Heat Input Case Inadvertent startup of a single reactor coolant pump (RCP) in an idle, . water-solid RCS with a primary to secondary temperature difference (across the steam generator tubes) of 50 F was identified by CYAPC0 as , the most limiting heat input case. The SLSV setpoint and performance j were substantiated by noting that the PORV and SLSV have similar I capacities and in all W heat input analyses, Reference 18, the PORV was shown to have suffTcient capacity even though overshoots were experienced due to PORV delay and stroke times. Since the SLSV's stroke time is much less than the PORV's and there is virtually no l delay time, the licensee concluded that the performance of the SLSV l was acceptable. l 1 ('- The staff used the Westinghouse predictions of RCS pressure response before PORV operation to determine the SLSV capacity requirements for the limiting heat input event. The determination was made by coupling two calculations:
- 1. Using the Westinghouse predictions of the RCS pressure response for various mass input rates into a water-solid RCS of volume similar to Haddam Neck, the staff determined the relationship between mass input rate (gpm) and the rate of RCS pressure rise (psi /sec).
- 2. Using the Westinghouse predictions of the RCS pressure response due to the startup of a reactor coolant pump (RCP) in an idle water-solid RCS of volume similar to Haddam Neck's and with an RCS/SG AT of 50 F, the staff determines the relationship between initial RCS temperature ( F) and the rate of RCS pressure rise (psi /sec).
l Once these relationships were determined, the RCS expansion rate versus initial RCS temperature, (for a constant RCS/SG AT), during the RCP startup transient was calculated, to determine the necessary SLSV - relieving capacity. Using Figures M15, Hll and H12" of the Westinghouse analyses, Reference 18, the relationships described above were determined, and are shown l O 3
'y/ - "These figures assume a RCS volumg of 6000 ft rather them the Haddam l Neck RCS volume of about 8400 ft . Other curves in the W study show -
the pressurization rate to decrease markedly with larger RCS volumes. 12
O in Figure 2. ' Based on these relationships, and the SLSV relieving characteristics shown in Figure 1, the following table summarizes the staff calculations: Pressuriza-Initial Allowable tion Expansion PEAK PRESSURE (psig) Temp Pressure Rate Rate 1 SLSV 1 SLSV 2 SLSV's 1 (?F) (psig) (psi /sec) (gpm) (no flashing) (flashing) (flashing) l
~
100 590 33 240 382 408 390 140 680 52 380 387 425 400 180 810 76 570 400 940 415 250 1350 115 860 417 1700 550 Based on the arguments and calculations presented above, the staff concludes that the SLSV's and their assoicated setpoints provide sufficient relieving capacity to mitigate both the design base mass O() addition and heat input events. 3.5 Implementation Schedule The Haddam Neck OPS was fully installed and tested during the fall, 1977 refueling outage. G 13 l
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b 4.0 HPSIP MASS INPUT EVENT , As discussed in Section 2.4 above, the staff required all PWR licensees
.to design and install an OPS which mitigates (i.e., maintains peak RCS pressure below Appendix G limits) the mass addition from the HPSIP.
However, the licensee's OPS has not been designed to mitigate this event. Therefore CYAPC0 was requested to propose hardware fixes that would mitigate the event and to provide a value-impact assessment based on the installation of this hardware. In response to our request, the licensee determined the probability of the HPSIP mass addition event by considering the various operator errors and/or equipment malfunctions which must take place for the event to occur. The expected peak RCS pressure was also calculated based on the existing OPS (two newly installed SLSV's) and revised calculations of the RCS, ECCS and OPS piping frictional losses. CYAPC0 then examined the various equipment changes which, together with the newly installed OPS, would totally mitigate the HPSIP mass addition event. From those various equipment changes, the most viable was selected and its cost and installation schedule were estimated. From this information the licensee concluded that the protection afforded by the most viable equipment fix did not warrant the cost and
;V impact on plant operations. The licensee's assessments and the staff's evaluations are described below.
4.1 Probability Evaluation The probability of a HPSIP mass addition event was estimated by-constructing a fault tree composed primarily of the various operator errors that combine to cause the event. The ifcensee's estimates are based on values used in WASH 1400 (Table II-3 of Appendix III) for the following errors:
- 1. Rack out HPSIP power supply breakers.
- 2. Remove breakers from switchegear.
- 3. Close and lock doors to breaker cabinet.
- 4. Shut HPSIP discharge valves.
- 5. Remove power from discharge valves. -
- 6. Chain-lock shut discharge valves.
- 7. Place HPSIP control switch in " pull-lock" position (in control room).
15
eO V Thelicensee'soverallprobabilj.gyforaHPSIPmassadditionwentwas estimated to be about 1.08 x 10 per cycle. Since Haddam Neck conservatively estimated the number of cold shutdowns in the remaining 26 years of the plants licensed 40 year life to be about 43, the resulting' probability of a HPSIP masg7 addition event during the remaining 26 years is about 4.6 x 10 The staff's probability calculations resulted in higher probabilities. The licensee assumed that during the annual HPSIP surveillance test, the ECCS valves were properly aligned and one SLSV was removed to _ provide a suitable vent path. By including the probability of the operator failing to take these actions, the overall lifetime probabilfgyforaHPSIP_gassadditioneventincreasestoabout 4.6 x 10 , or 1.8 x 10 per year.
- 4. 2 RCS Pressure Transient Analysis The licensee calculated the peak RCS pressure that would be experienced during the HPSIP mass addition transient and presented the results in their Reference 16 submittal. These calculations included the effects of piping frictional losses and therefore more realistically represent the mass addition rate than the calculations assumed in Section 3.4.1.
h(/ The following table presents the licensee's calculations along with the maximum allowable RCS pressure permitted by the 14 EFPY Appendix G Isothermal curve and 10 EFPY Appendix G Hydrostatic Test curve. Peak RCS Pressure Max. Allowable Pressure Backpressure 1 SLSV 2 SLSV Isothermal Hydro-Test 10 psig 930 psig 575 psig 590 psig 1000 psig 100 psig 955 psig 625 psig '590 psig 1000 psig The staff notes that the possible effects of flashing were accounted , for by assuming a backpressure of 100 psig. Further, we note that if both SLSV's are assumed to operate, which is reasonable since they are passive components, the RCS peak pressure exceeds the Isothermal
~
Appendix G curve by 35 psig and is significantly below the maximum pressure _ permitted by the Hydrostatic test curve. 4.3 Description of Additional System Modifications - CYAPCO has reviewed the possible system additions / alternations which in addition to the newly installed OPS, would totally mitigate the HPSIP mass addition event. Each is described along with the staff's O and licensee's evaluations: U 16
d O I
- a. Increasing the capacity of.the existing OPS This modification could be accomplished by the replacement of the newly installed two inch (00) pipes, MOV's and SLSV's with larger pipes, MOV's, and SLSV's. The licensee and staff agree that this proposal is impractical since it would involve extensive rip-out and re-installation. !
- b. Installation of relief devices' in the ECCS piping between the HPSIP and the RCS -
A system composed of safety valves or PORV's could be added to the ECCS piping such that the RCS pressure would be limited by relieving HPSIP pressure. This modification would have to be I accompanied by control circuitry or isolation valves which l insured that the relief devices would not operate when the l HPSIP's are required during a LOCA. l The licensee rejected this alternative since it could effect the ECCS performance and since it would require a more extensive design,-procurement and installation effort (and cost) than the
;- modification described in item (e) below. The staff agrees with v this conclusion, and also notes that this change would have to be accompanied by an ECCS failure modes and effects analyses (FMEA) which could require a re-analysis of the Haddam Neck ECCS LOCA
' performance.
- c. HPSIP Control Circuit The licenses evaluated the viability of ECCS modifications that
.would either limit HPSIP flow or trip the HPSIP in the event of an inadvertent = injection. CYAPCO concluded that the hardware-changes, control circuitry and extra. administrative measures to accompany these changes were such that the ECCS performance could be degraded. The' staff reviewed this alternative and concludes that this modification would also require an_ extensive ECCS FMEA '
since the control systems for LOCA mitigation could be compromised,
- d. ~RHR System Modifications Some PWR licensees are utilizing the RHR system code safety valves for either s part of or as the total OPS. .In Reference -
19, CYAPCO discusses their evalution of this alternative. The RHR safety valve'setpoint would have to be lowered from the present 500 psig to about 380 psig. However, due to the RHR
. system' configuration and pressure limitations, this adjustment in setpoint would compromise the RHR system's ability to provide 17
L I l i v F 1 l continuous core cooling below 300 F. The staff and licensee agree that the RHR system does not present a viable alternative for mitigation of the HPSIP mass addition event.
- e. Additional pressurizer SLSV The installation of another relief piping train, (2 MOV's and SLSV) similar to the ones recently installed would provide enough relieving capacity so that the HPSIP mass addition event would be completely mitigated, (by the operation of all three SLSV's). -
The two inch (00) pipe would tie into the three inch (00) lateral between the pressurizer and the high pressure code safety valves. The new SLSV discharge would be connected to the ten inch (00) discharge pipe as near as possible to the pressurizer relief tank. This addition would provide a redundant and independent relief path which does not compromise the design functions of the ECCS or RHR systems. The licensee has estimated that the total installation cost of the additional relief train and associated control circuitry would be p) ( v about $675,000. This figure does not include any estimate of the cost of replacement power. CYAPCO has also stated that the earliest practical installation of this hardware would be accomplished during the upcoming refueling outage currently scheduled for early 1979. Based on these arguments and the factors listed below, the staff concludes that CYAPCO's omission of the HPSIP mass addition event from the design consideration of the newly installed OPS is acceptable.
- 1. If a HPSIP mass addition event were to occur at a RCS temperature of 100 F, the Appendix G curve (isothermal) would be exceeded by, at most, 35 psig (100 psig back pressure and both SLSV's). The staff' notes that there is a 60 psig and 10*F instrument error included for conservati5rnin the calculation of the Appendix G isothermal curve. Also, if the RCS temperature is above about 120*F, the Appendix G limit increases such that these is no violation during the HPSIP mass addition event. The amount of time spent between 120*F and 100*F is normally quite small (based on staff conversations with other licensees).
- 2. If the HPSIP mass addition event were to occur at a RCS tempera-ture below 120*F, the Appendix G isothermal curve (14 EFPY) would ~
be exceeded. However, the hydrostatic test curve would not be exceeded and the peak RCS pressure would be at least 330 psig below the hydrostatic test curve. The staff is not allowing OPS design based on the Appendix G hydrostatic test curve, but we (n)
,G note that the RCS is allowed to be pressurized once per year up 18-
1 R 1 U !
.to these limits during a slow and controlled test. The HPSIP mass. addition event is certainly not a " slow and controlled" test, nevertheless, we note that the peak pressure of a relatively improbable event is significantly below the allowable pressure of a relatively frequent test.
- 3. Since the present pressure setpoint of the RHR code safety valve is 500 psig, if the RHR and RCS systems are connected, it is probable that the actuation of this valve would reduce the peak RCS pressure during the HPSIP mass addition event to about 600 -;
psig. l
- 4. The most viable addition to the newly installed OPS which would result in an OPS that totally mitigates the HPSIP mass addition event would cost an estimated $675,000 and would not add appre-ciably to the plant safety. The staff notes also that CYAPC0 ,
states they have already spent in excess of $1,000,000 on the ; newly installed OPS.
- 5. 0 @MINISTRATIVECONTROLS O To supplement the hardware modifications and to limit the magnitude of postulated pressure transients to within the bounds of the analyses provided by the licensee, a defense in depth approach is adopted using I procedural and administrative controls. Those specific conditions I required to assure that the plant is operated within the bounds of the analysis are spelled out in the Technical Specifications.
5.1 Procedures A number of provisions for the prevention of pressure transients are conta'ined in the Haddam Neck operating procedures.
'(1) The plant operating procedures for shutdown, cooldown and heatup operations have been modified to reduce to a minimum the time the RCS is in a water-solid condition. ,
1 (2) The plant procedures for RCP stutup have been modified to require ; that when the first RCP is to ne started in a water-solid system, the steam generator and RCS temperatures must be within 20 F, even though the licensee's OPS has been designed to mitigate the ~ RCP startup transient with a 50 F AT. l (3) To reduce'the probability of a RCP start causing a thermal expansion due to temperature asymmetries, at least one RCP is kept running during cooldowns for as long as possible. V 19
R
, , i O
(4) The safety injection logic,is blocked while in'a shutdown condition.
.(5) Additionally, the ECCS components.which are capable of causing an i overpressureeventaredisabledduringplantshutdownandcooldowns when the RCS temperature is below 340 F, and are not re-enabled (unlessreguiredforsurveillancetests),untilRCSstartup(RCS temp > 340 F). Specifically, the following actions are taken:
Open' power supply breakers to the HPSIP's and LPSIP's, and place their control switches.in the " pull-lock" position. , Remove the HPSIP power supply breaker and lock closed the Cover door, c
- Shut, lock shut, remove power and " danger tag" the MOV's between the HPSIP's and the RCS. Also, place their control switches in the " pull-lock" position.
The staff finds that the procedural and administrative control , described are acceptable. However, the staff has determined that certain procedural and administrative controls should be included in 9 the Technical Specifications. These are listed in the following (V section. l l 5.2 Technical Specifications To assure operation of the overpressure protection system (OPS), the licensee has submitted (Reference 15) proposed technical specifications to'be incorporated into-the license for Haddam Neck. These specifications are summarized below.
-(l) The Haddam Neck OPS must be operable whenever the-RCS temprature is below 340?F. Operability of the OPS requires all four MOV's connecting the two SLSV's to the pressurizer to be open'and the q SLSV's setpoint to be 380 psig. The OPS need not be operable if the RCS is depressurized and vented to containment by a three inch (00) opening. If these condition cannot be met, the RCS shall be depressurized and vented in 24 hrs and the inoperable train (s) shall be restored prior to system pressurization.
(2) If the RCS.is in hot standby, startup or power operation, and an OPS train.is discovered to be inoperable, it shall be repaired .. within 7 days (or the staff shall be notified with estimates of the repair date) and the RCS shall not be cooled down and depressurized.to a' Cold or Hot shutdown mode unless pesonnel or plant safety or other Technical Specification mandate such action. 1 20 t , 2 0
l t V l f (3) When starting a RCP with the RCS temperature below 340 F, the secondary side of the steam generator in that loop shall be less than 20*F hotter than the primary side. (4) Whenever the RCS is below 340*F and not vented by a minimum ) opening of three inches (00), the HPSIP's shall be de-energized by racking out their power supply breakers and locking closed the breaker cabinet door and locking closed the HPSIP discharge valves. (5) During the core cooling system periodic tests, the RCS shall be vented by a minimum opening of at least three inches (00) with the OPS operable, or by two openings, each a minimum of three inches ( 00) if both OPS trains are ir.aperable. (6) The OPS shall be tested each refueling outage. The staff has reviewed the licensee's proposed technical Specifica-tions described above and concluded that they are acceptable based on the analyses and methods described in Section 3.4, Setpoint Analysis and Section 4.0, HPSIP Mass Input Event. k_/
6.0 CONCLUSION
S The administrative controls and hardware changes made by CYAPC0 provide protection for Haddam Neck from pressure transients at low temperatures by reducing the probability of initiation of a transient and by limit-ing the pressure of such a transient to below Appendix G limits. The staff finds sufficient justification for the exclusion of the HPSIP as a consideration in the OPS relief capacity design and that the OPS meets the staff criteria and is acceptable as a long term solution to the problem of overpressure transients. However, final NRC acceptance is contingent on the electrical / control systems review. Also, any future revisions of Appendix G limits for Haddam Neck must be con-sidered and the overpressure system setpoint adjusted accordingly with corresponding adjustments in the license. O 21
[ ( Haddam Neck References
- 1. NRC (Schwencer) letter to CYAPC0 (Switzer) dated Autust 11, 1976.
- 2. CYAPC0 (Switzer) letter to NRC (Schwencer) dated September 3, 1976.
- 3. CYAPCO (Switzer) letter to NRC (Schwencer) dated October 15, 1976. ,
- 4. CYAPC0 (Switzer) letter to NRC (Schwwcer) dated December 3, 1976. -
- 5. NRC (Schwencer) letter to CYAPC0 (Switzer) dated January 10, 1977.
- 6. NRC (Schwencer) letter to CYAPC0 (Switzer) dated February 14, 1977. l
- 7. CYAPCO (Switzer) letter to NRC (Schwencer) dated March 3, 1977.
l
- 8. CYAPC0 (Switzer) letter to NRC (Schwencer) dated March 21, 1977.
I
- 9. NRC (Schwencer) letter to CYAPCO (Switzer) dated April 1, 1977.
- 10. CYAPCO (Switzer) letter to NRC (Schwencer) dated April 26, 1977. i O CYAPC0 (Switzer) letter to NRC (Schwencer) dated June 1, 1977.
\g- 11.
- 12. CYAPC0 (Switzer) letter to NRC (Schwencer) dated September 7, 1977.
- 13. NRC (Schwencer) letter to CYAPC0 (Switzer) dated November 1, 1977.
- 14. CYAPCO (Switzer) letter to NRC (Schwencer) dated November 30, 1977.
- 15. CYAPCO (Switzer) letter to NRC (Schwencer) dated January 30, 1978,
- 16. CYAPCO (Switzer) letter to NRC (Schwencer) dated March 6, 1978.
- 17. " Staff Discussion of Fifteen Technical Issues listed in Attachment G, November 3, 1976 Memorandum from Director NRR to NRR Staff" NUREG-0138, November, 1976.
- 18. " Pressure Mitigating System Transient Analysis Results" prepared by Westinghouse for the Westinghouse user's group on reactor coolant system overpressurization,' July 1977, (submitted as Attachment 1 to reference 12 above). ..
- 19. " Specific Plant Report, Low Temperature RCS Overpressure Protection for Connecticut Yankee," August, 1977 (submitted as Attachment 2 to Reference 2 above).
O O 22
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+ ..a MEMORANDUM FOR: -andon R. Nichols, Technical Assistant, 00R FROM: Thomas A. Ippolito. Chief, Operating Reactors Branch #3, 00R
SUBJECT:
USE 0F WASH-1400 IN THE LICENSING PROCESS - VERMONT l YANKEE - REF: Memo, V. Stello to Branch Chiefs, "Use of WASH-1400 In the Licensing Process", dated October 31, 1978 In response to the referenced memo, for Vermont Yankee (VY) two 1 instances of the use of WASH-1400 in the licensing process are known. l Copies of the instances are enclosed.
- 1. Safety Evaluation for the Order allowing continued operation of p* VY for 30 days until torus hold-down devices are installed i (February 13. 1976). Category 1. No action recommended. This l U
period has now passed and hold-down devices are installed.
- 2. Safety Evalation for the Fire Protection License Amendment No. 43 I (January 13, 1978). Category 2. No action recommended. Conclusion .S(
remains valid that continued operation of the plant presents no lete items: undue risk pending resolution of incomp/ ,.. lf I. s, L ,; & JW- 4
^Tfiomas A. IppoJito, Chief Operating Reac't ors Branch #3 Division' of Operating Reactors cc: B. Grimes V. Rooney
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.,,o' Docket. No.: 50-271
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. (> Y W Yankee Atomic Electric Company u,
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3j ATTN: A!r. Robert H. Groce p]a , , . 6' " eJ
-Licensing Engineer ,
20 Turnpike Road i g .J /' 7 'Y Westhoro, 5!assachusetts , 01531 (j' 'l v
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(\ Gentlemen: f"
> \lW Enclosed is L signed. original ~of the " Order for h!odification of License" and our Safety Evaluation issued by the Comission for the Vermont Yankee Nucicar Power Station.
The Order adds requirements needed to assure the continued safo operation of the Vermont Yankee Nuclear Power Station in the event of the lou likelihood, but worst case, loss of coolant accident. A copy of the Order is being filed with the Office of the Federal Register V( ) for publication. Sincerely, ,
/
A/ .' f '- Robert W. Reid, Chief Operating Reactors Branch #4 Division of Operating Reactors
Enclosures:
- 1. Order.for b!odification of License
- 2. Safety Evaluation ec: See next page O ;
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.._ EThe licensee has limited stresses in critical sections to vs:ues-permitted by 1963 AISC Specification for the Desigu FabricaLon and Erection of Structural Steel for Buildings as indicated in Table 12,2.1 of the FSAR. The stressclimits permitted by the AISC specific:. tion cem-
. pare. conservatively with respect to those permitted by the ALE B & FV l Code, Section III, Division 1, Subsection NF, 1974 for Class 2 and Class 1 MC Component Supports for normal loading conditions.
The fabrication, installation,'and construction of the torus hold down system will be performed in accordance with the requirements of the ASME B & PV Code, Section III,-Division 1, Subsection NF or similar-provisions provided for in the FSAR. "l
'it is our conclusion, based on our review of the above, that the ,
l structural modification preposed by the licensee is acceptable, In addition, we conclude that the torus holddown system in conjunction with the differential pressure mode of operation will provide additional assurance'that the torus is capable of withstanding the uplift loads due to the unlikely occurrence of a LOCA. In this regard, we will evaluate the need to continue the AP mode of operation after completion of the tie-down installation. We may conclude some relaxntion of the requirements of operation with the AP mode could be made as our O. ; evaluation continues; however pending our further review, operation following instaliation of the tie downs shall be with both the LP ( j/, mode of operation and the tie downs. Inservice Inspection and Pipe Failure Probabilities The ~11censea has performed a recent in-service inspection (ISI) and has presented a probabilistic analysis of large breaks in primary piping systems which will have a significant consequence on the corus integrity. One hundred and two (102) welds in the primary system piping have been identified _which have a nominal pipe size of greater than 18" and,have the postulated break =crea exceeding the critical value'of 1,77 fe'. Within the last month, visual liquid penetrant,,and ultrasonic examina-tions conducted in accordance with the 1974 edition of the ASME Section XI Code 1were performed onf51 of these welds. No unacceptable indications were found by ultrasonic examination. One unacceptable , indication was-found by surface examination which was subsequently l removed.by sucface' grinding. '
\ The licensee use'd'an estimate of:the fa'11ure probability of these pipe welds based'on the ex ~
yearasgiven'in-WASH-1400gpptednumberofpipefailuresperplantper Starting with the median probability of ' 10-4 for pipe fatiures per plant year and'taking into account the relev:n information related to-the Vermont Yankee torus' problems, such as the number of. pipe welds. involved, the pipe size, and the number of days expected until the coepiction d stre a r J. e.edifica'.Jona, _. . - h ; '. ; -- L O) tss- j l l n I
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g concluded by the licensee that the probability of a pipe failure which ~ could impose high loadings on the torus is approximately 8.7 x 10 ' based on a sixty (60) day completion schedule for the structural modification. We believe that the licensee's probability calculations have not been adequately supported in all respects. However, we do believe that the licensee's calculations provide an indication of the general order of magnitude of'such failures. j The referenced _ WASH-1400 values are for piping greater than six inches in diameter which could initiate a pipe rupture in light water reactors of the type now in operat The appropriate median value given in WASH-1".00 _ forthispipingis10~gon.per year with an uncertainty spread of from 10' ~ to 10~) .per y' ear; - -
, Eecause of the lower failure probability for-large pipes and taking into consideration the fraction of pipes'in a nuclear. facility that are very large (>18" in diameter),
largepipesapproaches10~jebelievethatamedianfailureprobabilityfor per plant year. To further reduce the likeli-hood of a major pipe failure, all licensees are required to perform periedic in-service inspections. The recent inspection (within the last month) of half ! the welds in large primary system piping is in addition to such periodic inspections and provides additional assurance concerning piping integrity.
; j In addition, the short period of. time (30 days) that the facility will U operate prior to'the installation of hold-down devices will significantly reduce the likelihood of an unacceptable event.
We sonclude that the probabi,11ty of large pipe.failureJ uring the eration rior to installation of hold-down devices is,on 30daysofop'onechin_p[e"in'onemillion. the Tri:TeV'"E e , The probability of a LOCA which l'estis~tio a containment'_ failure is sigiiificantly lower than this value because of the use of differential pressure to assure containment' integrity. On the basis of these' low probabilities, we conclude ~that with differential pressure; _ the short_ period of operation pr1or to installation of the hold'-- down device is acceptable. Operating Restrictions j The licensee has identified the upward and downward torus loads as significant loads and has proposed plant operating restrictions and structural modifications intended to limit torus movement such that contain-ment integrity is maintained. Our evaluation of the acceptability of operation with the CDpCS and the structural modifications was based on the _ proposed operating restrictions being in effect. Therefore, we conclude c that the operating restrictions identified in Appendix A to this evaluation should be impicmented, p We determined that this acticn does not authorize a chtnce in eff:uert f ' typ e or tota'. n !.n- m is . n 6 m r Le.el end u'11 wt i
\ 1 result in any n;;ni;1ean:. ear rou.tental :ap :.:. '.hving u e :h ia de tu.... l
; tion, we.have further concluded that the action is insignificant from'the
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'i' ;f WE'i!NGT Oil 0. C. MES January 13, 1978 q".Q}l,Ilt
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Docket No.' 50-271 Yankee Atomic Electric Company ATTH: Mr. Robert H. Grace - Licensing Engineer 20 Turnpike Road Westboro, Massachusetts 01581 Gentlemen: The Commission has issued the enclosed Amendment No. 43 to Facility l Operating License No. DPR-28 for the Vermont Yankee Nuclear Power ' Station. This amendment consists of changes to the license and the Technical Specifications and'is in partial response to your submittals n of January 31, March 18, July 14, August 18, September 13, and November 30, 1977. This amendment adds a license condition relating to the completion of facility modifications for fire protection. It also revises the s Technical Specifications to incorporate limiting conditions for opera-tion and: surveillance requirements for existing fire protection systems i and' administrative controls. The enclosed Technical Specifications i have been somewhat modified from those proposed in your November 30,197/ l submittal. These Technical Specifications,-as modified and agreed to by your staff, shall become effective 30 days after the date of issue. One requirement that was not agreed to by your staff relates to the mini:.. . size of the fire brigade. In your submittal of November 30, you recom-mended a minimum size for the fire brigade as three persons. As discussM in our Mfety Evaluation, we have concluded that the minimum size of the fire brigade should be five persons. In order to achieve expeditious
- ( implementation of the fire protection program, the Technical Specifications s.. being issued at this time specify a minimum number of three for the on-site fire brigace members as you proposed, liowever, you are requested to let us know within 20 days whether a requirement of a minimum fire ,.
brigade size of five is objectionable. If you object, you should specify , 1 f3)
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If you have no objection
'your reasons and the technical bases therefor.
to this specific requirenent, it is nonetheless important to let u know within 20 days. will act.to issue the change on the basis that assumes your agreement. 30, 1977, provide Your submittals dated September 13 and Novemberaddition These the Safety Evaluation a,s requiring additional informatio included in a supplement to the enclosed Safety Evaluation afte pletion of our review. 31, 1978. of Section 3.2 of. the Safety Evaluation by January
-our fire protection consultants (BNL-NUREG-2369 Sincerely, m
4 !,4 l Karl R. Go11er, Assistant Director i for Operating Reactors Division of Operating Reactors
Enclosures:
- 1. Amendment flo. 43 to DPP,-28
- 2. Safety Evaluation
- 3. Notice
- 4. BNL-NUREG-23698 See next page cc w/ enclosures:
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1 ps t In the raocrt of th? Special Review Group en %c Cro r.s Forrv Fire e v ~. c - dated Fr:bruary 1976, consideration of the s.alcty of c3x: rat ion o' .si' werm ing nuclear powar plants' pendin0 tho' completion af our daldled t ire rec % tion evaluat. ion was presented. The following quotations f rom the report
- suonarize ti.e tiesis for cur concl% inn that the operstma of the facility,
. ending resolution of the incomplete 'itens an<J the impler.entatinn of ali o
facili*y modificationsf does not present an undue rist to the health end safety of tne public. A probability assessment of public safety or risk in quantitative ter: is given in .the Reactor Safety Study (!! ASH-1400).- As the' result nf W calculation based on the Browns Ferry fire, the study concludtr. th Lt_ t v potential _for'a significant release of radioactivity from such a fire if about 20% of that calculated from all other causes analyzed. This inm
'that W ttted potential accident risks from all caut.es were not great!
affected by consideration of the Browns Ferry fire. This is one of the reasons that urgent action in regard to reducing risks due to potential ! fires is not required. lhe study (WASH-1ASa.)-elso points out that i
'rather straightforward measures, such as may alrecdy exist at other nuclear plants, can significantly reduce the likelihood of a potential l core melt accident that might result from a large fire. 1
" Fires occur rather frequently; however, fires involving equipment unavailability comparable to the Browns Ferry fire are quite infrcouan'.
g (see Section 3.3 of [NUREG-0050]). The Review Group believes that steps already taken since March 1975 (see Section 3.3.2) have reduced this frequency significantly.
" Based on its review of the events transpiring before, during and af tec
'the Browns Ferry fire, the Review Group concludes that the probat.ility of disruptive fires of the magnitude of the Brokns Ferry event is smtil, and' that there is no need to restrict operation of nuclear pnwer punu !
for public safety. However, it is clear that much can and should be done to reduce even further the likelihood of disabling fires and to improve assurance of rapid extinguishment of fires that occur. Cons 11: tion should be given also to features that would increase further the ability of nuclear facilities to withstand large fires without loss of important functions should such fires occur." We have determined that the ~ license amenCment does not authorize a change 1.
. effluent types or total amounts nor an increase in power level and will no result in any significant environmental impact. Having made this deternim tion, we have further concluded that-the amendment involves an action whicr. i
.is insignifical'. from the standpoint of environmental impact and pursuant ,
10 CFR_51.5(d)(4) that an environmental impact statement, or necative declx s-tion and' environmental impact. appraisal need not be prepared in connection with the issuance of- this amendaent. 19 2 1
- - -r
3.s steps already taken since March 1975 (see Section 3.3.2) have reduced [ this frequency significantly. \
" Based on its review of the events transpiring before, during and after the Browns Ferry fire, the Review Group concludes that the probability of disruptive fires of the magnitude of the Browns Ferry event is small, and that there is no need to restrict operation of nuclear power plants for public safety. However, it is clear that much can and should be done to reduce even further the likelihood of disabling fires and to improve assurance of rapid extinguishment of fires that occur. Consideration should be given also to features that would increase further the ability of nuclear facilities to withstand large fires without loss of important functions should such fires Occur."
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We have. determined that the license amendment does not authorize a change in effluent types or total amounts nor an increase in power level and will not result in any significant environmental impact. Having made this determination, we have further concluded that the amendment involves an action which is insignificant from the standpoint of environmental impact and pursuant to 10 CFR 51.5(d)(4) that an environmental impact statement, or negative declaration and environmental impact appraisal need not be prepared in connection with the issuance of this amendment. We have concluded, based on the considerations discussed above, that: (1) because the amendment does not involve a significant increase in the probability or consequences of accidents previously considered and does _ not' involve a significant decrease in a safety margin, the amendment does not involve a significant hazards consideration, (2) there is reasonable assurance that the health and safety of the public will not be endangered by operation in the proposed manner, and (3) such activities will be ; conducted in compliance with the Commission's regulations and the issuance I of this amendment will not be inimical to the common defense and security or to the health and safety of the public. D k_-) m
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W . UNITED STATES p f ; NUCL2AR REGULATORY 00Mf/iiSSiON ussmarca o c.:cm
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.....- y, ;'w MEMORANDUM FOR: Landon R. Nichols, Technical Assistant, Divi sion of Operating Reactors I
.FROM: Paul S. Check, Chief, Reactor Safety Branch, Division of Operating Reactors
SUBJECT:
USE OF WASH-1400 _ RSB has only one instance to report involving the use of WASH-1400 that to our knowledge isn't being reported by others. 1 1 Haddam Neck (50-213) Overpressure Protection ) RSB concluded that the OPS mitigates all credible mass and heat input events with the exception of HPSIP mass input event. RSB's finding that the HPSIP mass addition could be omitted was based primarily on a proba-bility result derived from a fault tree analysis. 1 O i 8 I have classified this usage of WASH-1400 as Category 5 (Denton to I d Directors, October 30, 1978 ). The RSB SER is enclosed. ,
,, 5 ti Paul S. Check, Chief Reactor Safety Branch Division of Operating Reactors
Enclosure:
As stated cc: D. Eisenhut T. Marsh C. Berlinger O
~
AA Rf 0g UNITED STATES g NUCLEAR REGULATORY COMMISSION [ g WASHINGTON, D. C. 20555
- d. . " MAY 9 1978 Docket No.: 50-213 MEMORANDUM FOR: Dennis Ziemann, Chief, Systematic Evaluation Projects Branch, 00R FROM: Robert L. Baer, Chief, Reactor Safety Branch, D0R
SUBJECT:
REVIEW OF HADOAM NECX OVERPRESSURE PROTECTION SYSTEM
~
(TACS #7053) PLANT NAME: Haddam Neck DOCKET NUMBER: 50-213 RESPONSIBLE BRANCH: ORB-2 PROJECT MANAGER: W. Russell OPERATIONAL TECHNOLOGY BRANCH INVOLVED: Reactor Safety REVIEW STATUS: Complete The Reactor Safety Branch Safety Evaluation of the proposed Haddam O has been completed and the Neck results Overpressure are attached._iWeProtection conclude thaiSystem {0PS)e pnp ~osed OPS ~m
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k credible mass-'and heat input events with the exception of the HPSIP mass input event. Based on the arguments and calculations presented in Section 4 of the attached SER, we also conclude that there is suffi-cient justification for the HPSIP mass addition event to be omitted as tan OPS design base transient. / The Electrical, Instrumentation and C5ntVol- System SER for the Haddam Neck OPS will be furnished separately by the Plant Systems Branch. In your letter to Connecticut Yankee Atomic Power Company fomarding the approved Technical Specification Changes relevant to overpressure protection, please inform the licensee that failures to meet the Limiting Conditions for Operation specified in these Changes are 30 day reportable events. Additionally, any pressure transients which cause the OPS to function, thereby indicating the occurrence of a serious pressure transient, is also a 30 day reportable event. Sufficient infonnation should be forwarded by the licensee with these reports to provide a clear picture of the actions of plant personnel and the variation in system parameters during the course of these transients.
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obert L. Baer, Chief Reactor Safety Branch Division of Operating Reactors O V Enciesure: as stated
.cc: V. Stello N. Anderson S. Weiss T. Novak W. Russell D. Eisenhut M. Fletcher G. Lanik D. Tondi P. Shemanski B. Grimes C. Berlinger J.-Rosenthal.G. Zech L. Marsh D. Davis F. Coffman W. Butler D. Ziemann-
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=e SAFETY EVALUATION REPORT OF THE OVERPRESSURE PORTECTION SYSTEM i
FOR 1 1 HA00AM NECX !
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MAY 1978 l l t l 1 _ . , _ , .__j
I I
1.0 INTRODUCTION
By letters dated September 12, 1977, and March 6, 1978 (References 12 and 16) Connecticut Yankee Atomic Power Company (CYAPCO) submitted to the NRC a plant specific analysis in support of the proposed reactor. vessel Overpressure Protection System (OPS) for Haddam Neck Nuclear Power Station. This information supple: tents other documentation submitted by CYAPCO over the past 17 months. (References 2, 3, 4, 7, 8, 10, 11, 14, 15) , 1
~
Staff review of all information submitted by CYAPC0 in support of the proposed Overpressure Protection System is complete and the staff has found that the system provides adequate protection from overpressure transients. A detailed safety evaluation follows.
2.0 BACKGROUND
l Over the last few years, incidents identified as pressure transients have occurred in pressurized water reactors. This term " pressure transients," as used in this report, refers to events during which the temperature pressure limits of the reactor vessel, as shown in the O V facility Technical Specifications, are exceeded. All of these incidents occurred at relatively low temperature (less than 200 degrees F) where the reactor vessel material toughness (resistance to brittle failure) is reduced. The " Technical Report on Reactor Vessel Pressure Trnasients" in NREG-0138 (Reference 17). summarizes the technical considerations relevant to this matter) discusses the safety concerns and existing safety margins of' operating reactors, and describes the regulatory actions taken to resolve this issue by reducing the likelihood of future pressure transient events at operating reactors. A brief discussion is. presented here. 2.1 Vessel Characteristics Reactor vessels are constructed of high quality steel made to rigid specifications, and fabricated and inspected in accordance with the time proven rules of the ASME Boiler and Pressure Vessel Code. Steels used are particularly tough at reactor operating conditions. However, since reactor vessel steels are less tough and could possibly fail in ' a brittle manner if subjected to high pressures at low temperatures, - power reactors have always operated with restrictions on the pressure allowed during startup and shutdown operations. At operating temperatures, the pressure allowed by Appendix G limits is in excess of-the setpoint of currently installed pressurizer code 2
O safety valves. However, most operating PWRs were not originally designed to have pressure relief devices to prevent pressure transients during cold conditions from exceeding the Appendix G limit. 2.2 Regulatory Actions By letter dated August 11, 1976,.(Reference 1) the NRC requested that CYAPCO begin efforts to design and install plant :ystems to mitigate 1 the consequences of' pressure transients at low temperatures. It was also requ~ested that operating procedures be examined and administrative -4 changes be made to guard against initiating overpressure events. It was: felt by the staff that proper administrative controls were required to assure safe operation for the period of time prior to installatfor. of the proposed overpressure mitigating hardware. CYAPC0 participated as a member of a Westinghouse (W) user's group which was formed to support the analysis effort required to verify the adequacy of the proposed.0verpressure Protection System. Using input W performed transient analysis data provided (Reference 18) by.the members, applicable to a T1 licensee's in the user's group. O CYAPC0 responded (Reference 2 and 3) with information describing".their interim ~ measures to prevent pressure transients. Based on some scoping" calculations done by Westinghouse for the user's group, the licensee presented, in Reference 4, discussion of the hardware modifications which were to be proposed pending after further analyses. These hardware changes assumed the ability of the existing pressurizer power (air) operated relief valves (PORV), to mitigate all pressure transients. The staff forwarded questions from our review of these submittals in our January 10 and February 14, 1977 letters to the licensee,-References 5 and 6.
' The staff's April 1,1977 letter, Reference 9, requested CYAPC0 to ensure that the likelihood of an overpressure transient as a result of improper RCP operation was minimized. The licensee's April 26, 1977 submittal, Reference 10, addressed the staff's concerns regarding RCP operation.
After meetings, conference calls and detailed RCS pressure transient analyses, CYAPC0 rejected their initial intent to rely on the existing PORV's, and presented a report describing the proposed installation of c new low pressure spring loaded safety valves (SLSV's) and associated - motor operated isolation valves (MOV's).on the pressurizer. The final Overpressure Protection System (OPS) report (Attachment 2 to September 7, 1977 submittal, Reference.19)-indicated, however that CYAPC0 had
;not analyzed the RCS pressure response resulting from the single HPSI O pump mass input event. This was not in accordance with the staff's V'
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1 k O criteria, discussed in Section 2.3 herein, so that staff requested (Reference 13) the licensee to provide.an analysis of the event. If the Appendix G. maximum allowable pressure was predicted to be exceeded with the proposed OPS, CYAPCO was to propose system modifications
= meeting our design criteria, and to provide a value - impact assessment to make these modifications.
7 The staff visited the plant on November 17, 1977 and observed the OPS components and controls being installed and discussed with plant staff the administrative and procedural controls taken to preclude the HPSIP _ mass input transient. The licensee's November 30, 1977 and March 6, 1978 submittals (Reference 14.and 16) provided an analysis of the HPSIP mass input event and the staff requested value-impact assessment. CYAPCO proposed Technical Specifications in support of the Haddam Neck OPS in their January 30, 1978 submittal, Reference 15. 2.' 3 Desian Criteria Through a series of meetings and correspondence with PWR vendors and O licensees, the staff developed a set of criteria for an acceptable overpressure mitigating system. The basic criterion is that the mitigating system will prevent reactor vessel pressures in excess of these' allowed by Appendix G for the design basis events discussed in Section 2.4.. Specific criteria for_ system performance are:
'(1)- Operator Action: No credit can be taken for operator action for ten minutes after the operator is aware of a transient.
(2) Single-Failure: The system must be designed to relieve the pressure transient given a single failure of an active component in addition to the failure that initiated the pressure transient. (3) Testability: The' system must be testable on a periodic basis consistent with the system's employment. (4) Seismic and IEEE 279 Criteria: Ideally, the The system should meet basic objective is seismic Cateogry I and [YEE-779 criteria. l that the system should not be vulnerable to a common failure that-would both initiate a pressure transient and disable the overpres-sure mitigating system. Events-such as loss of instrument air - and. loss of offsite_ power must be considered. Another criterion required by.the staff-in the design of the pressure mitigating' system was that the electrical, instrumentation, and control systems provide alarms to alert the operator to (1) properly enable e i 4 t
IN O the system at the appropriate temperature during cooldowns and (2) indicate if a pressure transient is in progress. In the initial letters to all PWR licensees, Reference 1, the staff also required the installation and use of permanent RCS pressure and temperature recording devices. 2.4, Design Basis Events The incidents that have occurred to date have been the result.of ., - operator errors or equipment failures. Two varieties of pressure I transients can be identified: a mass input type from charging pumps, I safety injection pumps or safety injection accumulators; and a heat addition type, which causes thermal expansion, from sources such as steam generators, reactor coolant pumps (RCP), pressurizer heaters or decay heat. On Westinghouse designed plants, the most common cause of the over- l pressure transients to date has been isolation of the letdown path, l Letdown during low pressure operations is via a flowpath through the RHR system. Thus, isolation of RHR can initiate a pressure transient , O if a charging pump is left running.* Although other transients occur with lower' frequency, those which result in the most rapid pressure increases were identified by the staff for analyses. The most limit- ) ing mass input transient identified by the staff is inadvertent injec- ; tion by the largest safety injection pump. The most limiting thermal expansion transient is the start of a reactor coolant pump with a 50 degree F temperature difference between the water in the reactor vessel and the water in the steam generator (secondary). The largest safety injection pump at Haddam Neck is the high pressure safety injection pump (HPSIP) which has a flowrate above 2100 gpm at a discharge pressure of 500 psig (from Figure 4, Reference 19). This is more than double the maximum flowrate of the HPSIP in other plants desired by Westinghouse ** Due to the very large relieving capacity
/necessary to mitigate the Haddam Neck HPSIP mass input event, and other plant specific considerations described and evaluated in Section 4, the licensee has designed A recent RCS pressure excursion was caused by the securing of the _
RHR pumps.while the RCS was in a cold, shutdown and water-solid condition. The RCP's were left operating (heat input of about 4.2 MW) and the core was generating about 13.6 MW of decay heat. The loss of the low temperature heat removal capability, plus the possible partial loss of letdown, caused the pressurization. t sn
+ From figure 2.3.2 of Reference 18, other HISIP's in W designed plants (witn the exception of Yankee-Rowe and San Onofre) have flowrates ranging from 500 to 900 gpm at 500 psig.
5
l O U l i i the OPS to mitigate all credible mass and heat input events with the i exception of the HPSIP mass inptit. l 3.0 SYSTEM DESCRIPTION AND EVALUATION 1 Based on calculations performed by CYAPCO using RCS pressure transient sensitivity studies (furnished by Westinghouse) and using Haddam Neck i plant specific data, the licensee rejected their initial proposal of an OPS utilizing the existing pressurizer PORV's.* CYAPC0 elected to l design, purchase and install low pressure spring loaded safety valves I (SLSV's) and motor operated isolation valves (MOV's) on new piping to be added to the pressurizer. The system is described below. l A three inch (00) pipe penetrates the pressurize steam space and branches into two two inch (00) pipes containing the PORV's and their MOV's. Downstream of the PORV's (discharge) the lines join and are routed to the pressurizer relief tank (PRT). The licensee has added two more two inch (00) pipes, each connected to the three inch (00) pipe leaving the pressurizer. Each line contains two MOV's upstream ofaSLSV,andthedischargepipesarejoinedtothePORVcommon discharge pipe. Both SLSV s are set to open at 380 psig, and when all four MOV's are open, a pressure transient is terminated below the O(
*) Appendix G limit by opening of one or both SLSV. During RCS cooldowns, the four MOV's are electrically opened, and to ensure proper OPS lineup, an enabling alarm annunciates (audible and visual) when RCS pressure is below 380 psig, temperature.is below 340*F, and any of the four OPS MOV's are closed.** To ensure the MOV's are not prematurely opened, the MOV's are electrically interlocked so that none can be opened unless RCS pressure is below 400 psig and RCS temperature is i below 340*F. To preclude erroneous MOV closure the licenses will remove all power from the MOV operators once the valves have been opened. During RCS startup and heatups, power is manually reinstated to the MOV's when RCS temperature is above 340 F and the four M0V's are shut. Additional assurance that the MOV's are shut prior to system pressurization is provided by an alarm which annunciates whenever RCS temperature is above 340 and the MOV's are open. The staff finds the use of redundant SLSV's and associated MOV's an acceptable concept for the mitigation of the design base events discribed in Section 2.4. Our discussion and evaluation of the system proposed by CYAPC0 follows:
~
" The calculations are discussed in Reference 19 and in Section 3.4 herein.
**This alarm is supplemented by an "RCS pressure transient" alarm that annunciates when pressure is above 400 psig and temperature below
['T 340 F. These~two alarms work in conjunction with administrative V procedures in. ensuring the CYAPC0 OPS is properly aligned. 6 l l
i f G 1 3.1 Electrical Controls , (Plant Systems Branch input) ; 3.2 Testability Testability will be provided. The licensee has stated that the four OPS MOV's will be mechanically tested in accordance with the require- - ments specified in Section XI of the ASME code, and will be electrically l tested by confirming proper motor and-valve movement in response to an input signal (e.g., opening or closing). A channel functional test associated with the MOV interlocks and controls will be conducted once per refueling shutdown. The SLSV's setpoint will also be verified each refueling outage by either a bench test, (removal of the SLSV for test at a testing facility), or by an in place test done by pressurizing the RCS up to the SLSV setpoint with alternate sets of MOV's open so that each SLSV can be checked. The licensee's testing requirements are further clarified in the technical specifications proposed in p their reference 15 submittal and discussed in Section 5.2 herein, and g are acceptable. 3.3 Appendix G The Appendix G curve submitted by CYAPC0 for purposes of overpressure transient analysis is based on fourteen (14) year period of full power operatio'n. The licensee has utilized the zero degree heatup curve (isothermal curve), which is acceptable since most pressure transients have occurred during isothermal metal conditions. Margins of 60 psig and 10*F are included in the curves to account for possible instrument inaccuracies. The Appendix G limit at 100 F according to the 14 EFPY isothermal curve is 590 psig. The staff finds that the use of the isothermal, 14 EFPY Appendix G curve is acceptable for OPS performance design. 3.4 Setpoint Analysis RCS overpressure transient analyses were performed by Westinghouse for the members of the owner's group. The one loop version of the LOFTRAN code (Reference WCAP 7907) was used for the analysis of mass input .. type transients and the four loop version was used for the heat input transients. Both versions required some changes to the input modeling and initialization. LOFTRAN is currently under review by the staff and is judged to be an acceptable code for treating problems of this p type. I U 7 up e- -
1 1 The Westinghouse generic analyses (Reference 18) provided sensitivity i studies that enabled PWR licensees to calculate the pressure overshoot (P -P for both types of transients (mass and heat input) with a biety b)3 plant parameters. The pressure overshoot is due to the j effects of PORV delay and stroke times. CYAPCO used the sensitivity ; studies to evaluate the OPS performance using their existing PORV and specific plant parameters (pump flowrate, system volume, PORV stroke , time and S/G heat transfer area). The CYAPCO calculations (shown in Appendix A of Reference 19) demonstrated the inability of the existing PORV's'to mitigate the design base events because of their relatively _ slow stroke time. Therefore, the licensee designed and installed an OPS utilizing passive SLSV's. Since the Westinghouse sensitivity studies were performed assuming the j use of a PORV to relieve system pressure and since the time dependent l flow characteristics of the PORV and SLSV differ,* the licensee could not use these studies directly to affirm OPS performance without making additional assumptions (see Section 3.4.1). However, the l portion of the RCS pressure transient prior to PORV opening is I applicable to Haddam Neck, and the licensee and staff used this part I e of the analyses in verifying the proposed OPS performance. Certain f h assumptions in the Westinghouse transient analysis are conservative V relative to the actual Haddam Neck RCS and associated system parameters. ' Some of these are listed below:
- 1. The RCS was assumed to be rigid with respect to metal expansion.
- 2. No credit was taken for the reduction in reactor coolant bulk modulus at RCS temperatures above 100 F (constant bulk modulus at all RCS temperatures).
- 3. No credit was taken for the shrinkage effect caused by low temperature SI water added to higher temperature reactor coolant.
- 4. The entire volume of water in the steam generator secondary was assumed available for heat transfer to the primary. In reality, the fluid immediately adjacent and above the tube bundle would be the primary source of energy in the transient.
~
"The PORV and SLSV relief rates depend on upstream pressure and. flow area. Both the PORV and SLSV upstream pressures are pressurizer pressure. The PORV flow area is independent of upstream pressure once the setpoint has been reached, and depends only on the air operator's m stroking characteristics whereas the SLSV flow area varies directly with upstream pressure until the value is fully open at 110% of PSET' 8
1 1 l l 0 l J
- 5. The overall steam generator heat transfer coefficient was I assumed to be the free convective heat transfer coefficient !
of the secondary side. The forced convective heat transfer j coefficient of the primary side, and the tube metal resistance l have been ignored thus resulting in a conservative (high) i coefficient. )
- 6. The RCP flowrate assumed in the heat input analysis was 95,000 gpm whereas the actual Haddam Neck RCP flow is about 62,000 gpm.
The staff agrees that these assumptions are conservative. Another i significant conservatism associated with the determination of the OPS i performance is the assumption that only one SLSV is available for l pressure relief. Unlike the PORV, the SLSV is free of actuating l circuits and pilot valves and is considered a passive device. The I upstream isolation valves are opened during plant cooldown and have their power removed, and are therefore also passive devices. Verification of the licensee's proposed OPS is described below with respect to each of the limiting design base events. 3.4.1 Mass Input Case V The mass addition from a' single centrifugal charging pump (CCP) with a concurrent total loss of letdown and the RCS in a water-solid condition was identified by CYAPC0 as the most limiting mass input case requiring mitigation by a SLSV.* Based on this event, the licensee calculated the required SLSV setpoint such that the Appendix G limits are not exceeded. The staff verified the licensee's calculations and performed independent checks. Both the staff's and the ifcensee's calculations are discussed below. CYAPC0 determined the CCP flow at discharge pressures below about 1300 psig by extrapolating the head-flow curve ** (Figure 5 of Reference 19) then calculated the SLSV capacity using manufacturers data and assuming
- As discussed in Section 2.4, the licensee has not considered the HPSIP mass input event as one of the design base events used to determine the SLSV setpoint and OPS performance acceptability.
** Extrapolation of CCP flow data will give a maximum but possibly unrealistic flowrate. The pump flowrate is limited by the avail-able NPSH and the motor overcurrent trips. CYAPC0 estimates _
that CCP flow can't go above about 640 gpm due to the maximum available suction head. m ~ l \ {O 9
A 7 D the valve to be fully open (Figure 6 of Reference 19). From these curves, CYAPCO estimated that at a RCS pressure of 380 psig, the CCP flow into the system is about 860 gom and the SLSV relieving rate is about 890 gpm, thus showing that the maximum RCS pressure during this event would be below 380 psig. Since the Appendix G pressure limit at 100?F is about 590 psig, this calculation shows that if the SLSV setpoint is sufficiently below 590 psig, the SLSV will mitigate this event. The SLSV setpoint was chosen to be 380 psig and CYAPC0 determined the overall SLSV flow performance (Figure 1, curve for " Single SLSV Without Flashing"). The staff notes that using this curve, the peak RCS pressure for this event is about 418 psig. The staff examined the possible effects of liquid flashing by using data supplied by a SLSV manufacturer for a valve design similar to the Haddam Neck SLSV.* This data indicates that a flow reduction of about 60% could be experienced if 350 F liquid flashed in the SLSV throat.** Using this data, the staff estimated the relief rates from one and both SLSV's, and these curves are shown on Figure 1. Based on these e;timates and the extracolated CCP head-flow curve, the peak RCS pressure is about 1220 psig with a single SLSV and about 625 psig with both SLSV's operating. The maximum allowable pressure at a RCS p temperature of 350 F is above 1220 psig, so the staff concludes that, for a mass addition event, flashing does not compromise the OPS (' performance. l
-As a further check, the staff used the Westinghouse sensitivity studies, Reference 18. Although these studies assume the operation of a PORV rather than a SLSV, the capacities of the reference PORV and SLSV are ,
similar,*** and the opening characteristics of the SLSV are superior.**** Therefore, if the predicted peak RCS pressure using the W studies is acceptable, then the peak pressure with the SLSV will also be acceptable. Crosby, the manufacturer of the RHR safety valve used by Kewaunee supplied this data to Wisconsin Public Service Company, who then submitted it to the staff in support of the Kewaunee overpressure protection system.
** Since the pressurizer liquid temperature is allowed to be as much as 200 F hotter than the RCS, it is possible for the SLSV discharge to be hotter than 350*F. However, the pressurizer is cooled down using spray flow which is at the RCS cold leg temperature. Since the spray nozzle is at the top of the pressurizer, which is where the SLSV penetrates'the pressurizer, the staff considers 350*F a -
sufficiently conservative temperature for estimating flashing etfects.
*** Comparing Figure 1 herein to Figure 2.2.1 of Reference 18, the p)
(J' PORV flow is about 50 gpm greater than the SLSV flow at 380 psig.
****The licensee states that the SLSV " pops" open is less than 500 msee.
l 10 i \
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- UNITED STATES f;. g NUCLEAR REGULATORY COMMisslON
,mj:
v f .q(ik(< c; 3y o a WASHINGTON, D. C. 20555
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..... gy 21 $78 MEMORANDUM FOR: Landon R. Nichols, Technical Assistant, Division of Operating Reactors FROM: Paul S. Check, Chief, Reactor Safety Branch, D0R
SUBJECT:
USE OF WASH-1400 RSB has one additional instance to report involving the use of WASH 1400 that we understood was to be reported by another organization, but was not. Big Rock Point (50-155) ECCS Exemption during Cycle 15 RSB recommended that Consumers Power Company (CPC) be granted a one cycle exemption from the Appendix K single failure criteria applied to the Big Rock Point Nozzle Spray System (NSS). The exemption request was made since CPC could not substantiate the ability of the Ring Spray System (RSS) alone to provide adequate core cooling in light of recent test data. Q RSB's recommendation was based on probability assessments using WASH-1400 Q fault tree techniques. I have classified this usage of WASH-1400 as Category 5 (Denton to Directors, October 30, 1978). The RSB SER is enclosed. ,
*l /
' , Lto G Paul S. Check, Chief, Reactor Safety Branch Division of Operating Reactors
Enclosure:
As stated cc: D. Eisenhut
. C. Berlinger T. Marsh
Contact:
T. Marsh, RS/ DOR g 28172
'N
N
- UNITED STATES g NUct. EAR REGULATORY COMMISSION
[ .D.
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1 g WASWNGTON, D. C. 20555 O g; . s ., ,/ OCT 181977 Docket No.: 50-155 MEMORANDUM FOR: Karl R. Goller, Assistant Director for Operating Reactors, 00R FROM: Robert L. Baer, Chief, Reactor Safety Branch, 00R 1
SUBJECT:
SUPPLEMENT TO SAFETY EVALUATION REPORT - BIG ROCK POINT l PLANT NAME: Big Rock Point DOCKET NUMBER: 50-155 RESPONSIBLE BRANCH AND PROJECT MANAGER: ORB #2, Edward Reeves TECHNICAL REVIEW BRANCH INVOLVED: Reactor Safety REVIEW STATUS: Complete (TACS No. 6461) CONTACT: Tad Marsh (28060) Enclosed is the Operational Technology's evaluation of the Big Rock Point Nozzle Spray System and the. request for exemption regarding the ring spray i system. - '
'O The performance adequacy of the nozzle spray system has been proven. Based on our assessment of the ECCS as a whole, including additional technical specifications giving improved reliability, we conclude that the requested one-cycle exemption should be conditionally granted.
,f.i.u~lYYL'=-m Robert L. Baer, Chief Reactor Safety Branch Division of Operating Reactors
Enclosure:
As stated cc: V. Stello E. Reeves D. Eisenhut P. Shemanski D. Ziemann N. Anderson D. Davis K. Jabbour C. Berlinger R. Woods ! F. Coffman T. Marsh l S. Weiss N- r ., . , , _ - - - - 3., . ,
1 TABLE OF CONTENTS
1.0 INTRODUCTION
2.'O ' EVALUATION 2.1 Nozzle Core Spray System 2.1.1 Minimum Nozzle Flow 2.1.2 Minimum Assembly Spray Flow 2.2 Ring Core Spray System 2.2.1 Feed System Reflood 2.2.2 Probability Assessments 2.2.3 Other Considerations
3.0 CONCLUSION
4.0 REFERENCES
4 4 d i I
-F
i l'h SUPPLEMENT i . SAFETY EVALUATION REPORT l l BIG ROCK P0 INT 1.0 -INTRODUCTION In the Comission Memorandum and Order dated.May 26,1976,(Ref.1), i Corisumers Power Company (Big Rock Point) was granted an exemption until tha refueling outage scheduled for spring,1977, from the single failure criterion in 10 CFR 50.46 and Appendix K as applied to a loss of coolant accident followed by a failure in the ring spray system. CPCo was also granted a lifetime exemption from the same single failure criterion as applied to a LOCA caused by a break in either core spray system. l j e As a condition of the Order, the Commission required CPCo to provide test data showing that the existing nozzle spray system provides adequate spray distribution during expected LOCA conditions or to modify the system to provide the required spray flow. This action was to be complete prior to the Cycle 15 startup. I An inherent assumption in granting both exemptions was the adequate per-fonnance of the ring spray system. The staff has recently received information regarding the steam effects on core spray distribution, (references 2 and 3), which has necessitated a re-evaluation of the Big Rock Point (BRP) ring spray distribution. k v [ l
Therefore, the performance adequacy of both BRP core spray systems was to be fully evaluated prior to the Cycle 15 startup. The staff's . review of each system is discussed below.
- 2.0 EVALUATION i
2.1 Nozzle Core Spray System The CPCo conducted a test program to measure the spray distribution from the nozzle spray system (NSS) in a steam environment. The tests used a full-scale mock-up of the significant portions of the BRP reactor vessel and fuel assemblies and measured the spray flow to a representative 22 of the 84 bundles at the expected LOCA usage conditions. The tests l O
*showed that the existing single nozzle did not provide adequate spray distribution; therefore, a new-multiple nozzle was designed and con-i structed. The new design was then tested and when acceptable spray dis-tributions were measured, the new nozzle was removed from the test vessel and installed at BRP. CPCo submitted a report describing the test program methods, assumptions and results to the staff on August 9,1977, " Big Rock Point Core Spray Test Report, Single Nozzle Test and Development Program,"
reference 2. The two' major aspects of'the staff review of the NSS performance are:
-(l) the ECCS flowrate to the nozzle and (2) the acceptance criteria for bundle spray flow.- Each facet is discussed below.
O - i
-. - - , , - . .- eq ,
.9
. G 2.1.1- Minimum Nozzle Flow Before beginning the nozzle test program, CPCo estimated a minimum flow to the nozzle due to the most limiting ECCS pump and single failure combinatf ori. This minimum nozzle flow CPCo predicted to be 296 gpm. j The new multiple nozzle was constructed and tested assuming this minimum ;
flow. When acceptable bundle flows were achieved the multiple nozzle design was finalized. A hydraulic analysis was then conducted (by MPR, August 1977, reference 4), to affirm the estimated minimum nozzle flowrate. The analysis determined the nozzle flow during bottom break and ring spray line break LOCA's while considering the most limiting. single failure.
,q For the bottom break LOCA, the analysis showed a particular ECCS pump and valve failure combination that resulted in a nozzle flowrate less than 296 gpm. The problem occurs with both ECCS pumpt running, a vessel pressure of 75 psig and an inadvertent opening of the backup containment spray system (CSS) valve. Although the present BRP technical specifications require both the primary and backup CSS to be operable, calculations submitted to the staff concerning the reactor depressurization system (RDS) performance in a LOCA (Special Report #21, May 15,1975,-reference 5) show that the CSS is not necessary to prevent exceeding containment design pressure. (In fact, the plant operating procedures allow manual bypass of the primary CSS valve if the operator decides that ECCS water should not be diverted from the core.) CPCo has proposed to open the power supply breaker to the backup CSS valve, thereby removing the possibility of inadvertent opening. / \ * .i i
gm 6 ,
+
I
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f' U) If necessary, p'wer could be reinstated and the valve opened from inside the control room. Since the containment spray system is not predicted to be necesstry during a LOCA, there is a primary CSS always available that does not degrade the NSS performance, and the backup CSS can ba rapidly made operable if needed, the staff concludes that power may be removed from the backup CSS valve. The Technical Specifications have been modified to allow power removal from this valve, and with this change the staff concludes that the nozzle spray system receives sufficient ECCS flow (e.g.,1 296 gpm) during bottom break LOCA's. The hydraulic analysis for the ring spray line break LOCA showed that d with the most limiting single failure the nozzle flowrate was in excess of 296 gpm
- Therefore, the staff concludes that the nozzle spray system receives sufficient ECCS flow during the ring spray line break LOCA.
"The ring spray line break ECCS analysis takes credit for nozzle spray ccoling at a vessel pressure of about 75 psig, but the hydraulic analysis demnstrates sufficient. nozzle flowrate (1296 gpm) with a vessel pressure of 38 psig. The conflicting vessel pressure assumption was explained by the licensee by referencing a revised blowdown analysis (submitted to the staff on March 26, 1976, reference 6) and fuel heatup-sensitivity studies
(..ubmitted as Attachment 3 to the CPCo submittal dated February 27, 1976, ('N ). , reference 7). These calculations showed that if credit for nozzle spray 5,V cooiing were delayed until ghe vessel pressure had been reduced to 38 psig, the PCT would be about 1700 F which is well below the Appendix K limit.
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\
- 2.1.2 Minimum Assembly Spray Flow CPCo assumed satisfactory performance of the new nozzle design if test data showed that each assembly received at least 1.0 gpm of spray flow at reactor vessel pressures and nozzle flowrates predicted in the ECCS analysis. The staff requested the licensee to provide a detailed justi-1 fication of the 1.0 gpm acceptance criteria.
CPCo and the NRC staff examined numerous reports concerning the Full ; Length Emergency Cooling Heat Transfer (FLECHT) experiments and the i minimum spray flows conservatively predicted to be present in other BWR's of various vintage and the corresponding spray cooling coeffi-cients assumed for those reactors. It was noted that a certain vaporiza-
~
tion" or " evaporation" flow could be' defined for each fuel assembly such V that vaporization of that amount of water would remove the total amount l of heat being produced in the bundle. The bundle' power is a function of the fission product decay heat generation rate at the time of rated spray when the FCCS analysis takes credit for spray cooling. Therefore, the
" vaporization" flow depends on the time of rated spray.*
It was further noted from the FLECHT tests and from conditions present in other operating BWR's that if the minimum spray flow available to each bundle is at least 30% above the " vaporization" flow for that bundle, the convective spray cooling heat transfer coefficients in the 1 .
*The " vaporization" flow will also depend on the vessel conditions at the time of rated spray since the heat of vaporization, hfg, and the specific volume, vy, depend on the system pressure.
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V 1 __.m_. . _ _ _ . -. . _ _ _ _ _ _ _ _ _ . _ _ _ _ _ _ _ _ _ _ . . _ _ _
. -. .. . -=. . - - - -.. ..
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ECCS-LOCA calculations are conservatively justified. The licensee submitted their calculations in a letter to the staff dated September 19, 1977 reference 8. At each core location, the highest bundle peaking factor at any time in Cycle 15 was detennined. The calcu-
. lations also assumed the ANS decay heat fraction for infinite irradiation at the earliest time at which rated spray flow was assumed to occur in the ECCS analysis (i.e., 20.4 seconds for the DBA). These two factors gave the highest power of each bundle at the time of rated spray. The
" vaporization" flow was determined using this bundle power and the vessel 4
pressure at the time of rated spray. Using the bottom plus top steam entry condition flow data, which the
\' '
staff believes to conser'vatively bound the worst LOCA conditian,* the ratio of actual flow to vaporization flow for each bundle was calculated. Both the licensee's and the staff's' calculations show that the ratio is above 1.30 for every bundle. Therefore, the staff concludes that each bundle will receive adequate flow from the NSS.
\
E h
*The licensee discussed the relation of various steam entry conditions used in the nozzle testing program to actual LOCA conditions in their October 5,1977 submittal, reference 9.
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* -r- , , - - - . , - . . . -
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(v ) 2.2 Ring Core Soray System The licensee had no data that defined the ring sparger spray distribution in either an air or stearn environment, so investigating the rirg spray system adequacy would have to be based on conservative estimates. The 4 staff suggested the licensee first estimate the spray distribution in 1 air by the use of a geometric / trigonometric approach. The projected cone angle from each individual nozzle on the ring would be superimposed j on a core map. From that projection, an estimated bundle spray flow 1 in air could be calculated. To account for steam environment effects, i the bundle spray flow should be conservatively reduced. The resulting n estimated flow can then be compared to the " vaporization" flow, described ; / s () in section 2.1.2 herein. The ratio of estimated flow to vaporization ' flow for each bundle could then be used to evaluate the ring spray system performance. The licensee utilized the staff's suggested approach described above, and the results indicated questionable ring spray distribution in an air environment. Although CPCo does not believe the staff's suggested approach accurately predicts the ring spray distribution, no test or design informa-tion or substitute approach was presented that could confirm the system adequacy. Since there was insufficient time to conduct a test program to investigate this question, CPCo has requested a one-cycle exemption from the Ingle failure criterion of 10 CFR 50.46 with respect to any LOCA
) -
J
O l followed by a failure of the redundant NSS. The 1 exemption and supporting calculations were presented to the staff in the licensee's September 15, 1977 submittal (reference 10). CPCo performed two sets of calculations in support of the exemption: (1) the probability (which they call " risk") of all LOCA plus single failure combinations which would result in total core cooling being provided by the ring spray system and (2) for top break LOCA's, the ability of the feedwater system to reflood the vessel and maintain
~ ~ ~ ~~
cladding temperatures within 10 CFR 50 Appendix K limits. The staff's l evaluation of the licensee's calculations is discussed below. The staff's decision regarding the requested one-cycle exemption is not tO ._ . .. . . . . based only on t.he probability assessments or the feedwater system perfonnance appraisal. Rather, these calculations have been used alcng With an evaluation of other ECCS considerations to reach a decision. The other ECCS considerations are also discussed below. 2.2.1 Feedwa_ter System Reflood Since the ring sparger's performance adequacy cannot be substantiated for this cycle, the licensee must rely on the reactor feedwater system for core cooling during the LOCA caused by a break in the nozzle spray line. The ability of the feedwater system to keep cladding temperatures within Appendix K limits had not been previously confinned. l
J _g. U(R - Appendix A of CPCo's letter to the NRC dated March 26, 1976, reference 6, presented a blowdown analysis for the nozzle spray line break LOCA. The analysis predicted the minimum reactor water level would be one foot l above the bottom of the core so the fuel is never completely uncovered. Using these results and taking credit for a feedwater flowrate of 1600 gpm at ten minutes after the LOCA, CPCo analyzed the fuel heatup before reflood was complete and determined the PCT to be below 22000 F. The attachment to CPCo's letter to the staff dated October 12, 1977, reference 11, discusses the performance aspects of the feedwater system so that reflood can be started at ten minutes. The makeup to the hotwell normally comes from the condensate storage tank via two paths: the r makeup line or the fill line. Both lines have automatic control valves that sense the hotwell level and open to keep level within a predetermined control band. The combined makeup and fill valve flowrates under a gravity flow situation was determined and used to calculate the hotwell refill rate.*
*The contents of the hotwell at the time of the LOCA are conservatively assumed lost out the break. The condensate pumps trip on low hotwell level then the
. feedwater pumps trip on low suction pressure. Once the pump;i trip, refilling of.
the hotwell is accomplished by makeup and fill valve flows from the condensate storage tank.
l l r (y\ With the most limiting initial conditions, CPCo calculated that the hotwell will have sufficient inventory for condensate pump restart at about five minutes after the LOCA, and enou;"4 inventory for core reflood ten minutes after the LOCA.** The plant procedures require the operator to restart the feed system once hotwell level has been restored and to initiate reactor reflood at about ten minutes after the LOCA, or when hotwell inventory is adequa te. Operator action soon after a LOCA is normally not desireable; however, the procedure is routine in system startups, the instruments and controls are familiar to the operators, and there is adequate margin in the calcu-lation so slight delays in reflood would not lead to an unacceptable PCT. The staff considers the required operation of the feed system soon after a LOCA acceptable.
**The most limiting initial condition for the hotwell is a high level since this delays condensate pump trip (on low hotwell level). The condensate pumps are removing hotwell water at about 2200 gpm, so the sooner these pumps trip the sooner the makeup flow can begin to increase the hotwell level.
The licensee has calculated that about 1815 gallons are needed to completely cover the core, so about 6.7 minutes of hotwell makeup are required. Y O] ix,
i l l k-The staff and licensee noted that several components in the feedwater system if failed, would disable the system's ability to provide adequate core reflood. Accordingly, the staff has added technical specification limiting condition for operation and surveillance requirements on these components to, better ensure their operability in the event of a Aozzle spray line break LOCA. These components are the condensate pumps, the hotwell fill valve
- and the condensate storage tank.
Based on the fuel heatup calculations, the reflood calculations and the added technical specifications regarding the feed system, the staff
~
concludes that the feedwater system provides adequate reflood in a nozzle p) N_. spray line break LOCA.
*The makeup valve is a solenoid operated butterfly valve and the fill valve is an air operated (solenoid actuated pilot) gate valve. The makeup valve line provides little flow under a gravity drain situation
'because a section of this line is only slightly below the CST water level. The fill valve line, however, provides the majority of the gravity flow to the hotwell since the entire line is much lower than the CST water level.
t j V '
. .- l 2.2.2 Probability Assessment CPCo evaluated all combinations of break location and component failure which would result in the reliance on the ring spray system alone for core cooling. Two LOCA scenarios of importance were identified:
(1) unrefloodable LOCA's (caused by bottom breaks), coupled with a i failure of the nozzle spray system, and (2) the refloodable LOCA (caused by a break in the nozzle spray system), coupled with a failure j of the feedwater system. l The probability of each LOCA scenario was calculated by CPCo and reported to the staff in the September 15 submittal, reft ence 10. The staff noted that CPCo had omitted the effects of operator error,* the component O unavailability due to testing and/or maintenance, and the possible common i 'Q mode failures. These facets were addressed by CPCo in their October 12, 1977 submittal (reference 11). The revised ;:robability calculations took these factors into account, and slightly different scenario probabilities resulted. , t
*The operator errors the staff identified that were omitted by the licensee are (1) the erroneous isolation of the nozzle spray line during a bottom break LOCA, (2) the improper restarting of the feedwater and condensate punps or systems, (3) the failing to initiate hotwell makeup from either the firemain (ECCS) or the condensate storage tank, and (4) the improper manual control of an inoperative feed control valve or its bypass.
The most significant of these errors is considered by the staff to be the first since it totally disables the only proven core cooling system for this
~ ~ ~
break location. ~This error appears to have a relatively high probability since the operator has a complicated procedure to perform within a fairly
,q short time after the LOCA. The procedure (described in the staff's BRP f 1 -
Supplement SER dated June 21, 1976, reference 12) isolates the broken V core spray line by comparison of ECCS flows.
The staff did not agree with the licensee's calculations so we conducted a separate probability study. The staff's calculations showed the inadvertent NSS isolation potentiality to be a major contributor to the overall failure probability. Therefore, the staff and licensee discussed possible tech-niques to improve the operator reliability, or to remove the required isolation procedure. As a result of these discussions and a detailed review of the original bases for the requirement,* the staff and licensee agreed that this pro-cedure is no longer required and should be deleted. The other operator errors are not as significant and do not contribute appreciably to the nozzle spray system or feedwater system failure probabilities d However, in evaluating the potential operator errors in initiating hotwell makeup, the staff noted that opening the ECCS to hotwell makeup line could result in a nozzle flow rate less than the minimum 296 gpm required. This flowpath was not evaluated in the hydraulic analysis so CPCo has deleted the procedure to initiate ECCS to hotwell makeup. Instead, makeup to the hotwell is allowed only from the condensate storage tank.
*The ring spray system MOV's were located at a height such that within two hours after the worst LOCA, containment flooding would render them inoperable.
Since long term cooling required isolation of the broken spray line, the operator had to evaluate the spray system flows and locate, then isolate the break. This had to be done before the RSS valves were flooded. The RSS valves have been raised and are no longer subject to filooding, so isolation for long term cooling can be done long after the LOCA. U
p l The staff's probability study was altered to reflect these changes in required operator action. The results indicate that the dominant failure mode in the nozzle spray system is the failure of the in-series MOV's to open. The major failure mode in the feedwater system is the failure of off-site power, a condensate pump or the hotwell fill valve. Thus, the staff has added technical specification limits and surveillance require-ments for these components (except off-site power). Since the staff's and licensee's probability studies used different indi-vidual failure rates, the overall system failure probabilities differed. However, the results were not appreciably different and the staff concludes that the probability of a LOCA and failure combination resulting in the p) (V ring spray system alone having to provide core coolin; is sufficiently low. 2.2.3 Additional ECCS Considerations Several other factors have been considered by the staff in reaching its decision on the requested one-cycle exemption. These factors when combined give the staff an overall assessment of the BRP ECCS. The staff and CPCo have conservatively assumed that the ring sparger's performance is totally inadequate. Although the geometric /trigometric approach used to estimate the spray distribution in air indicated question-able performance, neither the staff nor CPCo believes that the ring's spray pattern provides no spray cooling. The effects of spray cone mixing, reflection off vessel internals and updraft have not been accounted for and can_only be adequately detennined by a rigorous test program (similar to (/ the single nozzle test and development program just completed by BRP). The assumption of ring spray total inadequacy is justified, the staff
A U feels, in light of the i.1 formation available but is probably overly I conservative. CPCo's calculation of the fuel heatup before the completion of core reflood during the nozzle line break LOCA takes no credtt for any spray cooling afforded by the ring sparger. Unlike the feedwater that refloods from the bottom, the ring sparger flow is from above the core and must afford some cooling as it travels down the assembly to the lower plenum. This l l extra cooling has not been considered by CPCo. l l The water in the hotwell at the time of the LOCA has been conservatively assumed to be totally lost out the break. The blowdown analysis does not l take credit for the pressure reduction afforded by this flow, and the heatup analysis ignores this flow in lowering fuel temperatures. The nozzle spray system is a fully tested system that provides more than adequate flow to each fuel assembly in the anticipated LOCA steam environ-ment. The calculations used to substantiate the system adequacy are quite conservative. Also, there is significant spray flow before the ECCS code takes credit for spray cooling heat transfer. The plant operating procedures require restart of the feed and condensate systems and initiation of reactor feedwater flow as soon as possible after the LOCA (see section 2.2.1). If a bottom break LOCA occurs, the feedwater will eventually be lost out the break, but some of the feedwater added to
i j l l l bm the steam drum may, depending on break location and size, flow down the l steam riser or 'the reactor coolant recirculation lines and provide some core cooling. If the LOCA is caused by a break in the ring spray line, CPCo 1 has shown that the nozzle spray system alone provides adequate spray cooling,
)
however, the procedures require the restart of the feed and condensate pumps ! l and initiation of feed flow regardless of break location. The extra coolant inventory provided by the feedwater is significant and has not been considered. ) The ECCS reliability has been increased by the correction of several items discussed in the staff's cycle 14 SER dated June 4,1976, (reference 13) and in the Commission Order, dated May 26,1976,(reference 1). The staff's evaluation of these items is discussed in the BRP cycle 15 SER dated O October 4,1977, reference 14, and summarized below. 1 1 The emergency diesel generator and diesel driven fire pumps have been made , more reliable by making improvements in their trip circuitry. Inadvertent i 1 diesel trips caused by erroneous signals have been virtually eliminated by I the addition of coincident trip logic, t The ECCS has been modified to allow complete on-line testability of the i actuation sensors, (low water level and low primary pressure sensors). Also, technical specification changes have been proposed by CPCo and approved by the staff that incorporate increased on-line ECCS testing. t v
(a CPCo has modified several ECCS annunciation and indication circuits to j 1 remove their susceptability to certain single failures. Since the ' operator must have these circuits to assess ECCS performance during the LOCA, the correction of the defects significantly improves the system reliability. l l The position of the ring spray line isolation valves has been changed l so that these components are no longer subject to flooding during a LOCA. As a result of this alteration, a relatively complicated procedure that required operator action soon after a LOCA has been eliminated. Since the likelihood of operator error during high stress and infrequent situations is high, the deletion of this requirement is an important I
/"
(N addition to the reactor's safety, i l The reliability of those parts of the ECCS required for long term cooling has been improved by the addition of flexible hose that can bypass the underground portion of the fire system. Technical Specification surveillance requirements have been added to ensure the availability and operability of the hose. l 1
3.0 CONCLUSION
S The staff concludes that the nozzle spray system receives sufficient ECCS flow with the most limiting single failure and produces an acceptable spray distribution during expected LOCA conditions. Further, to ensure the adequate nozzle spray system performance, the removal of power from i V '
bi
.\ j the backup containment spray. system valve is acceptable.
The staff concludes. that granting the requested exemption and thereby ! I permitting Big Rock. Point to resume operation, subject to the conditions l specified below, is warranted in view of the staff's assessment of the overall ECCS performance and reliability. l l Prior to the BRP Cycle 16 startup, CPCo must provide an evaluation of the ring spray system demonstrating acceptable performance at the i anticipated LOCA environments, or modify the ring spray system such that acceptable performance is achieved. If a new sparger design is developed, the hydraulic characteristics of b the ECCS must be evaluated to ensure adequate performance of both spray s'ystems considering the most limiting single failure. I 1 I
,s. ,
REFERENCES
/
l. BTg kock Point, dated 26, MayMemorandum 1976. and Order, by the Commission 2. Big Rock Point Core Spray Test Recort, Single Nozzle Test and Development Program, NUS-3005, NUS Corporation, August 1977. (Included as attachment to the letter from W. S. Skibitsky, CPCo to Samuel J. Chilk, Secretary to the Comission, NRC, dated August 9,1977). 3. Effects of Steam Environment on BWR Core Soray Distribution, Amendment #3 to NE00-20566, April, 1977. 4
- Hydraulic Evaluation of the Big Rock Point Plant Emergency Core Cooling System, MPR Associates Inc., August, 1977.
5. Responses *to Additional Information Requested ve rbally May 13, 1975 Regarding Big Rock Point Plant, Special Reporc No. 21, May 15, 1975. 6. Attachment 1 to the letter from Ralph B. Sewell, CPCo to Samual J. Chilk, Secretary to the Commission, NRC dated March 26,1976 (subject: additional information on the BRP ECCS adequacy report).
) ,7.
V Report on Evaluation of Adequacy of Emergency Core Cooling System, Consumers Power Company February 27, 1976.
'8.
Letter from David A. Bixel, CPCo to Director of NRR, NRC, dated September 19, 1977 (subject: verification of nozzle spray flow rates). 9. Letter from David A. Bixel, CPCo to Director of NRR, NRC, dated October 5, 1977 (subject: blowdown phenomena). comparison of top entry steam data with predicted LOCA 10. Letter from David 'A Bixel, CPCo to Director of NRR, NRC, dated September 15, 1977(subject: request for one-cycle exemption). 11. Letter from David A. Sixel, CPCo to Director of NRR, NRC, dated October 12, 1977 (subject: Addendum to exemption request). 12. Memo from Oarrell G. Eisenhut, NRC, to Karl R. Goller, NRC, Supplement SER - Big Rock Point, dated June 21, 1976 (subject: evaluation of selected items prior to cycle 14 startup). 13. Memo from Darrell G. Eisenhut, NRC, to Karl R. Goller, NRC, SER for Big Rock Point dated-May 20,1976 (subject: cycle 14 reload review) 14. Memo from Robert L. Baer, NRC, to Karl R. Goller, NRC, SER for Big Rock Point dated October 4,1977 ~ (subject: cycle 15 reload review). g -
- *er
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Cff UMTED STATES \, m)*/
'A f*. NUCLEAR REGULATORY COMMISslON C' ,#
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- 3. :ce 69,Q ., ,j WASHINGTON, D. C. 20665 ,gj
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/ October 17, 1977 Docke To o
Consumers Power Company ATTil: fir. David Bixel Nuclear Licensing Administrator - 212 West liichigan Avenue Jackson, Michigan 49201 , Gentlemen: The Commission has issued the enclosed Amendment No.15 to Facility ) Operating License No.' DPR-6 for the Big Rock Point Plant. The amendment i is in response to your application dated December 17,1976 (supplemented ; by letters of February 9 and August 17, 1977) and your application l dated April 15,1977 (supplemented by letters dated April 21, August 12 I and 24, and September 26, 1977). This amendment also includes changes l to the Technical Specifications iA resoonse to vour reauest for exemotion ; from the failure criterion reauireunts imposed _by 10 CFR _50.46 and.. p Appendix K. Paragraph _InD.1. ae Annlied to a Loss-of-Coolant Accident t i followed by concurrent sinale failure in the redundant core spray l V sWtem for the 1978 operating fuel cycle. ~ Our Safety Evaluation of '
'the requestec exemption is enclosed. Based on our evaluation, we have to provide time to complete full-determined scale testing that the needed and any limited modificat exemption, ion of the core ring spray system, is acceptable.
The amendment also authorizes operation of the facility (1) with additional uranium 235 fuel assemblies identified as Reload G-3 for Cycle 16 as replacement for the spent fuel assemblies, and (2) with modified limiting l conditions of operation and surveillance requirements based upon the Commission's review of' the licensee's applications and based upon the licensee having complied with the requirements of condition III.d of the' Commission's Memorandum and Order dated flay 26, 1976. Our Safety Evaluation of this amendment is enclosed. . Our review of your applications resulted in minor modifications to your proposed changes which have been discussed with and agreed to by your staff.
\
t
October 17, 1977 Consumers Power Company A copy of the Notice of Issuance of the amendment also is enclosed. Si ncerely, . (t V \ ps b L Don K. Davis, Acting Chief Operating Reactors Branch #2 Division of Operating Reactors
Enclosures:
- 1. Amendment No.15 to .
License No. OPR-6
- 2. Safety Evaluation Regarding Exemption Request
- 3. Safety Evaluation Regarding
- 1978 Operating Cycle
- j 4 .- Notice l
cc w/ enclosures: .
~
See next page l I i i I t l 1 l o v k
'e 4
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re - l
J ,* . s 1 Consumers Power Company - 3- October 17, 1977
,/_ l V) '
l cc w/ enclosures: Mr. Paul A. Perry, Secretary Consumers Power Company 212 West Michigan Avenue
- Jackson, Michigan'.49201 Charles F. Bayless Of Counsel Consumers Power Company 212 West Michigan Avenue Jackson, Michigan 49201, George C. Freeman, Jr., Esquire Hunton, Williams, Gay and Gibson 700 East Main Street Richmond, Virginia 23212 Peter W. Steketee, Esquire '
505 Peoples Building - Grand Rapids, Michigan 49503 Charlevoix Public Libra'y r C\ 107 Clinton Street ty Charlevoix, Michigan 49720 Mr. W'illiam R. Rustem (2) Office of the Governor Room 1 - Capitol Building - Lansing, Michigan 48913 l Chairman County Board of Supervisors Charlevoix County 1 Charlevoix, Michigan 49720 ! Chief, Energy Systems Analyses Branch (AW-459) Office of Radiation Programs I
. U. S. Environmental Protection Agency Room 645, East Tcwer 401 M Street, S. W.
Washington, D. C. 20460 U. S. Environmental Protection Agency Federal Activities Branch Region. V Office
' ATTN: EIS COORDINATOR O 230 Sduth Daarcorn Mree' 'j Ch1:o p.'111in @ lu6t. .
l l e e op e 'n>=
4e UNITED STATES y'.
- NUCLEAR REGULATORY COMMISSION u, WASHINGTON, D. C. 20665 y
5
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CONSUMERS POWER COMPANY l DOCKET N0. 50-155 . j BIG ROCK POINT PLANT 1 - AMENDMENT TO FACILITY OPERATING LICENSE Amendment No. 15
- License No. OPR-6
- 1. The Nuclear Regulatory Commission (the Commission) has found that:
A. The applications for amendment by the Consumers Power Company (the licensee) dated December 17,1976 (as supplemented by letters dated February 9 and August 17, 1977) and April 15, ' l 1977 (as supplemented by letters dated April 21, August 12 and 24, and September 26, 1977) comply with the' standards and requirements of the Atomic Energy Act of 1954, as amended (the Act), and the Commission's rules and regulations set forth in 10 CFR Chapter I; Q I B. The request for exemption from ECCS failure criterion of
\ 10 CFR 50.46, Appendix K, Paragraph I.D.1 dated September 15, 1977 (as supplemented by letter dated October 12,1977) is authorized by law and will not endanger life or property or the common defense and security and is otherwise in the public interest.
C. The facility will operate in conformity with the application,
~ the provisions of the Act, and the rules and regulations of the Commission;
- 0. There is reasonable assurance (i) that the activities authorized by this amendment can be conducted without endangering the health and safety of the public, and (ii) that such activities will be conducted in compliance with the Commission's regulations; E. The issuance of this amendment will not be inimical to the common defense and security or to the health and safety of the public; and O
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l a 1 L) F. The issuance of this amendment is in accordance with 10 CFR f Part 51 of the Commission's regulations and all applicable requirements have been satisfied. , j
- 2. Accordingly, the license is amended by changes to the Technical '
Specifications as indicated in the attachment to this license amendment and paragraphs 2.C(2) and (3) of Facility License No. DPR-6 are hereby amended to read as follows: (2) Technical' Specifications The Technical Specifications contained in Appendix A, as revised through Amendment No.15, are hereby incorporated in the license. The licensee shall operate the facility in accordance with the Technical l Specifications. l (3) Exemption from 10 CFR %50.46, Appendix K, Paragraph I.D.1 Pursuant to 10 CFR 150.12 the licensee is granted an exemption from the ECCS failure criterion of 10 CFR n 550.46, Appendix K, Paragraph I.D.1 as applied to a l f 1 Loss-of-Coolant Accident followed by concurrent V single failure in the redundant core spray system for the 1978 operating fuel cycle. s
- 3. This license amendment is effective as of the date of its issuance.
I FOR THE NUC R, ATORY COMMISSION V ctor s lo, ., Director Division of Operating Reactors Office of Nuclear Reactor Regulation
Attachment:
Changes to the Technical Specifications Date of Issuance: October 17, 1977 l l' ,
a S ATTACHMENT TO LICEt!SE AMENDMENT NO. 15 FACILITY OPERATING LICENSE fl0. OPR-6 DOCKET N0. 50-155 The Technical Specifications attached to Facility Operating License No. OPR-6 are changed as follows:
- 1. Add the following column to Table 5.1 for Reload G-3:
11 x 11 3 0.577 Zr-2
~ 113 0.034 0 0.449 4
91.5 4 . 1 70 . 3 Helium >95%
- 2. Add new Figure 5-8 attached.
- 3. Replace the following revised tables in Section 5.2.1(b):
Table 1 and Table 2
- 4. Add new Figure 1 and Figure 2 following Table 2.
- 5. Replace Table 8.2 with the revised Table.8.2.
- 6. Replace Section 11.3.1.4 with the following revised pages:
11-1 through 11-5
- 7. Delete Page 11-6 of Section 11.3.1.4.
- 8. In Paragraph 4.1.2(b) revise the first sentence to read: "A minimum of one reactor recirculating ~ loop or its equivalent shall be used during all reactor power operations."
- 9. Replace pages 11-14 and 11-16 of Section 11.3.3.4 with attached revised pages.
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TABLE 1 g' N , Reloads: Reload "elead (
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) Modified F & J-2 Reload G G-1U G-3 __
i Minimum Critical Heat Flux Ratio at Normal Operating Conditions
- 3.00 3.00 3.00 3.00 Minimum Bundle Dry Out Time ** Figure 1 Figure 2 Figure 2 Figure 2 Maximum Heat Flux at Overpower, Btu /h-ft2 500,000 395,000 407,000 392,900 MaximumgteadyStateHe,atFlux, 324,000 333,600 322,100 Btu /h-ft 410,000 Maximum Average Planar Linear Heat Generation Race, Steady State, Table 2 Table 2 Table 2
~
kW/ft*** Table 2 Stability Criterion: Maximum Measured zero-to-Peak Flux Amplitude, Percent of Average Operating Flux 20 20, 20 20 bbximum Steady State Power Level, MWt .. 240 240 240 .240 D \ -( Maximum Value of Average Core Power
\s / Density @240 MWe, kW/L 46 46 46 46
( Nominal Reactor Pressure During . Steady State Power Operation, psig 1335 1335 1335 1335 Minimum Recirculation Flow Rate.-Lb/h 6 x 106 6 x 10 6 6x106 6x10 6 Rate-of-Change-of-Reactor Power During Power Operation: Control red withdrawal during power operation shall be such that the average rate-of-change-of-reactor power is less than 50 MWe per minute when power is less than 120MWg, less than 20 MWt per minute when power is between 120 and 200 MWe, and 10 MWe per minute when power is between 200 and 240 MWe . . l3
- The bundle Minimum Critical Heat Flux Ratio (MCHFR), (based on the Hench-Levy correla-tion as described in " Design Basis for Critical Heat Flux Condition in Boiling Water Reactors," by J. M. Healzer, et al, September 1966, AFED 5266 and APED 5286, Part 2; using actual bundle parameters must be above this value.
f- s ** The actual dryout time for each bundle (based on the General Electric Dry Out Correlation for Wonjet Putp Rollir3 Wrer Reactors. NEDE-20566) should be (1 above the ryout
- t t.e 31..vn in
;un or 2, r nprepriate.
*** To be determined by linear ext rapolat ion f rom Table 2. ;
. Amendment No. J@, 15
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V TABLE 2 MAPLHGR (kW/Ft) LIMITS Planar Average Exposure Reload Reload (!Nd/STM) Modified F , F,J-2 . Reload G Reload G-lU Reload G-3_ o - - 6.453 6.h91 6.55h l 200 . 95 9.h - alk - - 6.750 6.758 - l 216 - - - - 6.807 h37 -- - 6.887 6.888 - kh3 - - .
- 6.973 88k - - - 6.960 -
885 - - 6 978
- - - - 7 033 4 893 - -
1,758 - - 6 929 1,769 - - - - 6.970 - 1,773 - - - - 6 98h 3,49h - - 6.885 - 6.913 3,509 -. . .- p 3,5h5 - -
- 6.983 -
5,000 99 9.T -
't#t 6,939 - - 6.838 -
- 6.865 6,970 - - -
7,085 - - - 6.978 - 10,000 99 97 - - 10,422 - - 6.8hT - - 10,h82 - - - - 6.882 10,690 - - - T.019 - 13,938 - - 6.867 - - 1h,019 - - - - 6.90h .i 14.355 - - - 7 069 - 15,000 98 96 - - - 20,000 8.T. 8.6 - - - 21,022 - - 6.905 - 21,19h' - - - - 6.958 21,843 .- - - 7 171 -
- l 25,000- 8.h 8.3 - -
27,778 - - 6.8h3 - - 28,035 -
- - - 6.903 ;
29,08h - - - T.161 - 34,013 - - 6.703 - - 35,1h7 - - - - 6 923 , 35,322 - - - 6.958 - jl' l I
.U Amendment No. IO, 15 4
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-N 900 700 800 TOTAL BUNDLE PEAK LINEAR HEAT C-ENER ATION RATE. Q (KW / FT)
O Figure 1 FUNCTION T(Q) FOR ENC 11X11 FUEL "'" 15
^"*"d**"'
POWER VOlO RELATION
2.5 4
. 3 2.0 ,
o- . 5 s e m - I , l g - M w , .- 1.5 0 0 - C 0 - U Q = MAPLHGR LIMIT X
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NUMBER OF ACTIVE FUEL RODS I um 1.0
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A 600 700 800 TOTAL BUNDLE PEAK LINEAR HEAT GENERATION RATE. Q ( KW/ FT) l Figure 2 FUNCTION TCQ) FOR GE 9 X 9 FUEL POWER' VOID ' RE LhTION i Aniendmen t No. IE
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1 Cent ermelt
;, M UO 2- Inter- ,
0 Advanced NFS-DA 2 mediate ] Core Burnout Ratio at Overpover - 1 5* 1 5" 1.5* 15 Minim Transient Minimum Burnout Ratio in Event 1.5 15 of Loss of Recirculation Frem Rated Power 15 15 Maximum Heat Flux at Overpower, LO2,000. 500,000 - - l Btu /h-Ft2 I
-Maximum Steady State Heat Flux, 500,000 329,000 41o,o00 500,000 Btu /h-Ft2 Maximum Average Planar Linear Heat ** ** **
l Generation Rate, Steady State, kW/Ft
-l Stability Criterion: Maximum Measured Zero-to-Peak Flux Amplitude, Percent - 20 of Average Operating Flu,x 20 -
Q-
- MaximumSteadyStatePowerLevel,.lWf 240 - - 240 Nominal Reactor Pressure During 1,335 Steady State Power Operation, psig 1,335 - -
Minimum Recirculation Flov Rate, Lb/h (Except During Pump "' rip Tests 'or #- Natural Circultion Tests as Outlined in 6 x 10 6 - - 6 x 10' Sec 8) Number of Bundles:
- 1 3 Pellet Uo2' .
- 1 2 -
Power UO2 Rate-of-Change-of-Reactor Power During Power Operation: Control rod withdrsval during power operation shall be such that the average rate-of-change-of-resctor power is less than 50 W, per minute when power is . less than 120 W:, less than 20 W per minute whed power is between 120 and 200 W:, and 10 Wg per minute when pcVer is between 200 and 240 Wt .
- Based upon critical heat flux correlation, APED 5286.
**No unrer used in ree.etor.
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' Amendment 'To.10. 15 n .
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! . :--ev Surveillance Requirement
- i. miting Conditions for Operation
~11.3.1.4 11.4.1.4 EMERGENCY CORE COOLING SYSTEM
'.K.MGENCY CORE COOLING SYSTEM Applicability:
ppplicability:
':, plies to the operating status of the emergency Applies to periodic testing requirements for the.
-ore cooling system.- emergency core cooling systems.
Objective: . Objective: 2 .
~o assure the capability or the emergency To verify operability of the emergency core s or .+ cooling system to cool reactor fuel in cooling systems. ,
, the event of a Loss of Coolant Accident. Specification:
Each month the following shall be performed: fipecification: A. A. The two core. spray systems (original and Verify the operability of-MO-7051, -7061, -7070, t redundant) shall be operable whenever the
-7071 and -7066 by remote manual actuation.
plant is in a power operation condition. The original core spray system shall also ,c Leak testing of the core spray heat exchanger. be operable during refueling. operations. Aornmaric actuation of both fire pumps.
- 6. the cote uptay teciaculatica spatc= chall bc operable whenever'the plant is in a power Verify that valve MO-7069 is locked or sealed i operation condition. in open position. l C. The core spray recirculation heat exchanger Verify that the fire system transformer delugt .!
shall not be taken out of service during valve is shut and its upstream isolation valve ' power operation.for periods exceeding four is locked or sealed in the shut position. (4) hours. The hcat exchanger shall be considered inoperable and out of service if tube bundle leakage exceeds 0.2 gpm. Verify that the hose required for backup cooling water to the core spray recirculation heat exchanger is installed on a designated rack in , the screen house. Verify operability of the condensat e fill .
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valve to the condenser hotwell. t-u
. Amendu.ent ?Jo.' /0.15
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Surveillance Requirement- .-g I.imiting Conditions for Operation 1 -
!3.1.4: EMERGE".', CORE COOLING SYSTEM (Contd) 11.4.1.4 EMERGENCYCORECOOLINGSYSTEM(Contb Bot h . fire _ pumps - (electric and diesel) and B. At.each major refueling outage,-the-
'IN following shall be performed:
the piping system- to the -core spray system - tie-ins shall be operable whenever the plant Calibration of core spray systen' actuation is in a power operation condition and refueling. and pressure and flow-instrumentatinn. E. 11' vecifications.A, B, C, and.D are not met, - a 6.nwal orderly shutdown"shall'be initiated Verify that the~two core spray system con-
- within.24 hours and the reactor shall be tainment isolatica check valver are nat.
- stuck shut. 1 wb:. down as described in Section 1.2.5(a)
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- I: A' W hin twelve (12) hours and shut down as - Calibration of fire system hasket: strainer .
\ deteribed in Section 1.2.3(a) -and (b) within dif ferential pressure switches. -
- ths tollowing 24 hours. No work shall be - .[
performed on the reactor or its connected ; Operability check of the core sprav t systems when irradiated fuel is in the reactoi ' vessel which could result in lowering tna recirculation system through the test- _l flow tank flow path. l i reactor water level below elevation 610'5". Verify manual- and automatic actuat ion or h F. Unril such time as the spray effectiveness of the core spray system valves M0-7051, ' primary core spray nozzles have been proven: -7061, -7070 and -7071 with wat er flow n rmally blocked. (1) two condensate pumps must be operating ourtug powet upet ilua. (2ccpt d -1:; .,. . ., l startup and whem power is <50%, Verify that the hose used for backup tne concensate storage tank level shall cooling water to the core spray recircu-(2) . larion-hear exchanger is operable and free ne 2651 during power operat.lun, ar.d of obvious-defects. ! (3) the condensate fill valve to the con- Perform a leak check and flow check of the denser hotwell is operable.- [. backup cooling water hose when connected i. If (1), (2) and (3) cannot be maintained, a between the screen house fire watei ' l connection and the core spray recirculation normal orderly shutdown shall be initiated:with- heat exchang'er. } j in one '(1) hour and the reactor shall be shut
- de..n as described in Section 1.2.5(a) within C. Instruments sha11 be checked, t%ted, and ~
t 'ee (12) hours and shut down as described in calII. rated at least as frequently as
- ion 1.2.5(a) and (b) wi t hin t.he following curs.
listed in Table 11.4.1.4(as. j !! - un. .n t set p..ints shati 1.e as speyifica in , 3 _ .. g,,,3,, g , g , n,
- _ _ _ - _ _ _ _ _ _ _ _ _ . _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ = _ _ _ _ _ _ _ _ _ _ _ _ _ .
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.g; t TABLES 11.3.1.ha AND 11.h.1.ha, * .]' . Instrumentation That Initiates Core Spray -
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- j. 11.3.1.ha Limitinit Conditions for Operatioh 11,b.1.ha Surveillance Requirement.s_
- Trip System . Limiting Conditions ' for Instrument' Instrument Nrumeter Logic Set Point.,. _ Operabili_ty_ Trip Test Calibration Cg; ' re Spray Val.
.Lov : Lor Unter - One of Two for >610'5" Elev Power Oper& tion Quarterly : Each Maj..r - ,
Lev i (a) - Lch of Two and Refueling - Refueling
- Valven in Series Operations (b)
Pri::.m j Pressure - One of Two for >200-Psig Power Operation -Quarterly. Each Major-Inu I.: ) Euch of Two and Refueling Refueling Valves in Series- Operations (b) - Notes for Table 6 11.3.1.1.a und 11.k.1.ka i I (a) Initiation of valve operation requirea both low reactor water level coincident with low primary system . l ^ pressure. (b) The primary core spray system shall be available for use during refueling operations. The " redundant core l * , ;. ray system shall be inoperable during refueling operations with the valves blocked or otherwise defeated < (while Lhe piping section from the valves to the reactor head is dismantled). '
-i l
_a l l . . ^l l ( 11-3 Amendment No. 16.15
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- i Y nases:
The cure spray system consists of two autodatically a.ctuated independent double capacity piping headers cap-I i able .d cooling reactor fuel for.a range of foss of Coolant Accidents. _ Either system by itself is capable' of poividing adequate cooling for postulated large breaks in all locations. When adequate depressurization k rates are achieved in the postulated small-break situation, either core spray system provi, des adequate cool-itut. For the ' largest, possible pipe break, a flow rate of approximately IsOO gpm is required after about 20
. ee. n..
Each core spray system has 100% cooling capacity from ench spray header and each pump set. Thus, specifying
- both systems to be fully operational will assuref to a high degree -l j core cooling if the core spray system is -
re*ieu r ui. In addit. ion, the-primary core spray is rdquired to be operable during refueling operations to i pret + a ruel cooling in the 'unlikely event of an inadvertent draining of the reactor vessel.
. The core spray syst. ems receive - their water supply frem the plant fire system. The plant fire system supply is ~.-.m Luke Michid an via two redundant 1,000 gpm fire pumps, one electric and one diesel driven. These pumps start untomat.ically on decayin6 fire system pressure. If a passive failure of underground fire main' ptping should occur during the long-tenn. cooling phase, the capability exists to bypass the affected. portion of pip-ing ni.iiizing a fire huse to ensure t.he continuation Of long-terre 1:'.CCS cooling. .
The core spray recirculation system is provided to prevent excessive water buildup in the containment sphere and to provide for long-term, post-accident cooling. The system consists of two pumpn (3:00 gpm each) and a i heat exchanger. The pumps take a auction from the acuer levels of containment and discharge to t.he core spray ' heude r.i . The synt.em la actuat.ed manually when the water level in the containment rises to. elevation S87 feet. The $87-foot, elevation will be achieved between 6 to 21s hours operation of one core spray and.one' containment spray system.
+ A test t.ank and appropriate valving is provided in the core spray' recirculation system so the pump suction '
condi tions and the flow characteristics of the system can be periodically tested.
. One core spray recirculation pump hun adequate capacity to provide fuel cooling at anytime following a Loss of .
Coolant. Accident. Cont.inuous containment spray operation is not required during the post-accident recircula-tion phase if only one recirculation pump is available. 1 Amendment No.10, 15
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l _.ll Bases: (Contd) -L. The , c _rable status of the various systemis and component,s is to be demonstrated by periodic tests. Some of t the1, t ests will be per formed while the reactor is operating in- the power range. If a component is found to be L. verable, it will be possible in most cases to effect repairs and restore the system to full operability with .. a relatively short time. For a single component to be inoperable does not negate the ability of the syst<n to perform its function, but it reduces the redundancy provided in the reactor design and thereby limits
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the 4.t.! Lily to tolerate additional equipment failuren. If it develops that (a) the inoperable component is us.t c%. aired within the specified allowable t.ime period; or (b) a second component in the same or related sys-ter. . Found to be inoperable, the reactor will initially be removed from cervice which will provide for a rea . an of the decay heat from the fuel and consequential reduction of cooling requi rements after a postu-lateu t.oss of Coolant. Accident. If the malfuncti ..n e ame't be rapidly corrected, the rebetor will be cooled to 1 i uhutdown condition'usind normal cooldown procedures. In this condition, relense of fission products'
- or a age of the fuel elements is not considered possible. ' .
The i. lent operating procedures require immediate action to effect repairs of an inoperable component and, ths . e Nre , in most cases, repairs will be completed in less than the specified allowohle repair times. The limiting timca to repair are intended to: (1) Assure that operability of the enaponent will be restored prm.pt ty and yet, (?) Allow sufficient time to effect repairs using safe and proper procedures. The Ic..kage rate limit for the core spray reelreulation syster heat exchanger han been established to assure detection of any degradation of the integrity of the heat exchanger. By Commission Memorandum and Order dated May 26, 1976, Consumers Power Company was granted a plant life exemp- ! tion from the single failure criterion requirements of 10 CFR Part 50, 50.46 and Appendix K, Paragraph I.D.1 for I
' the specific case of a Loss of Coolant Accident (LOCA) caused by a break in either core spray line. This exemption 8 was based on conditions specified in the Memorandum and Order and supporting NRC staff documents with which I
Consumers Power Company had complied.
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Consumers Power Company has requested an exemption for Cycle 15 operation from the single failure criterion i Paragraph I.D.1, Appendix K to 10 CFR 50.46. The NRC staff has granted the exemption for one cycle of operation ' pending completion of tests of the original ring spray nozzles.
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*Jurveillance Requirement Limiting Conditions for Operation ll.h.3.k CONTAIM4ENT SPRAY SYSTB4 11.3.3.h CO rrAIm4ENT SPRAY SYSTE4 l ! Applicability: Applicability:
Applies to the operating status of the con- Applies to the testing of the containment tainment spray system. spray system. Objective: Objective: To assure the capability of the containment To verify the operability of the containment spray system to reduce containment pressure. spray system. in the event of a Loss of Coolant Accident. Specification: 71 Specification:
'A. Once each operating cycle, the following shall be performed: .,- A. During power operation each of the two cnntainment spray systems shall be operable, except that the power supply 1. Automatic actuation of the contain-breaker.(52-2B45) must be locked open to ment spray valve MO-706h (with water preclude inadvertent operation of M0-7068. flow manually blocked).
I
- 2. Calibration of flow instrumentation.; , ,
B. If Specification A is not met, a normal. orderly shutdown shall be B. At least once every six (6) months, . initiated within 24 hours and the except for periods of continuous l reactor shall be shut down as des- shutdown when the following shall i cribed in Section 1.2.5(a) within be. performed prior* to startup: i 12 hours and shutdown as described in Section 1.2.5(a) 4 (b) within the . Verify operability of power-operated '
- following 24 hours. valves required for proper system ,
8 actuation. C. Operability of the fire water supply Surveillance of fire water supply and and recirculation systems is governed C. by Specification ll.3.1.k. recirculation systems is governed by ~ Specification 11.4.1.4. ' p, Instrument channels shall be tested and
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calibrated as listed in Table 11.4.3.h(a) E. Each month verify that liower supply breaker ' 52-2H45 for MO-7068 is locked open.. 11-14 ,] Amendment No. l9, 11
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- Bases
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The containment spray systems are provided to reduce pressure in the containment following a Loss of Coolant Accident. They are initially supplied from the fire water system and later by the core spray recirculation system. They are not required to be in service .et reactor coolant temperatures of 212*F or below because the resultant Loss of Coolant Accident pressure is not sufficient to pressurize the containment. The specified Operation of only one system is sufficient to provide the required containment spray flow. flow of approximately. h00' gpm is sufficient to remove post-accident core energy releases including a substan-tiul chemical reaction involving hydrogen generatioh 'o below design values. If a component is The operable status of these systems and components is demonstrated by periodic tests. l fc.in 1 to be inoperable, it will be possible in most cases to effect repairs and restore the system to full or..r".bility within a relatively short time. If a single system becomes inoperable, a redundant system has j been provided with the ability to perform the spray function, but it reduces the redundancy provided by plant design and limits the ability to tolerate additional equipment failures. Initiation of the containment spray system assures that containment design Itpressure has been vill not be exceeded conservatively calcu- due to hydrogen generation assuming the core spray systems do not function. ~ 1:.ted that the energy release following a complete core meltdown (assuming no containment spray systems or c..ce spray systens operate) would bring the containment pressure to approximately the design value (27 psig) J out 15 minutes after the postulated accident had occurred. Subsequent LOCA analysis system modifications
- .! regulations have limited H2 generation such that it is no longer significant and calculations show Thus, that the ec.e.ninment sprays are not required to prevent containment design pressures from being exceeded.
u.tamatic actuation time of the primary containment apray system has been established if system operation isatnot 15 required. minutes soThe as to allow-the operator adequate time to evaluate and block actuation, spray backup containment spray valve (which may be normally operated upon failure of the primary containment
- valve) is disabled to preclude a single failure or inadvertent opening during a LOCA.
References:
- 1. FHSR, Section 3 17, 1966. i Additional information in support of Proposed Technical Specification Change No 8 dated March )
- 2. !
'. Safety Evaluation by the Research and Power Reactor Safety Branch, Division of Reactor Licensing, Consumers Power Company, Proposed Change No 8 dated April 1k, 1966.
11-16 3 Ame n.ime n t No. fd, i$
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l _fC#$;I*p UNITED STATES y: - - NUCLEAR REGULATORY COMMISslON g r, j WASHINGTON, D. C. 20666 V ..... SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION SUPPORTING A LIMITED ECCS EXEMPTION FOR THE 1978 OPERATING CYCLE CONSUMERS' POWER COMPANY BIG ROCK' POINT PLANT DOCKET NO. 50-155
1.0 INTRODUCTION
In the Commission Memorandum and Order fatad $ y 26, 107A . (Reference 1), Consumers Power Company w'ai granted an exemption for dig Rock Point (BRP) until the refueling outage scheduled for spring,1977, ' from Lhe-single failure criterion in 10 CFR 50.46 and Appendix' K as applied to a loss of coolant accident followed by a failure in the ring spray system. _CPCo was also granted a lifetime m emation_ from the same single faRure criterion as applied to a LOCA caused
, bT a ureak irr&Tther core spray system.
['As a condition-of the Order, the Commission required CPCo to provide ytest data showing that the existing nozzle spray system provides adequate spray distribution.during expected LOCA conditions or to modify the system to, provide the required spray flow. This action was to be complete prior to i.he Cycle 15 startup. An inherent assumption in granting both exemptions was the adequate performance of the ring spray system. The staff has recently received information regarding the steam effects on core spray distribution, 2 (references 2 and 3), which has necessitated a re-evaluation of the BRP ring spray distribution. Therefore, the perfonnance adequacy of both BRP core spray systems was to be fully evaluated prior to the Cycle 15 startup. The staff's review of each. system is discussed below. 1 4' (
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2.0. EVALUATION l 2.1 Nozzle Core Spray System , CPCo conducted a test program to measure the spray distribution from the nozzle spray system (NSS) in a steam environment. The tests used a full-scale mock-up of the significant portions of the BRP reactor vessel and fuel assemblies and measured the spray flow to a representative 22 of the 84 bundles at the expected LOCA usage conditions. The tests showed that the existina sinale nonleSd .not.. provide .adequaWspray listributior; therefore, a_ new-multiple nn"le e M igned_andd
' constructed. After the new design was tested and an acceptable spray
~ distribution measured, the new nozzle was removed from the test vessel and installed at BRP. CPCo submitted a report describing the test program methods, assumptions and results to the staff on August 9, 1977, " Big Rock Point Core Soray Test Report, Single Nozzle Test and Development Program," reference 2. ,
Thejiomajoraspectsofthestaffreviewoft)eNSSperformanceare: l (1) the ECCS flow rate to the nozzle and (2)dhe acceptance criteria .j for bundle spray flow. Each aspect is discussed below.
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V 2.1.1 Minimum Nozzle Flow
'Before beginning the nozzle test program, CPCo estin'ated a minimum flow to the nozzle due to the most limiting ECCS pump and single failure combination. CPCo predicted the minimum nozzle flow to be 296 gpm.
The new multiple nozzle was constructed and tested assuming this minimum flow. When acceptable bundle flows were achieved the multiple nozzle design was finalized. A hydraulic analysis was then conducted (by MPR, August,1977, reference 4), to confirm the estimated minimum nozzle flowrate. The analysis determined the nozzle flow during bottom break and ring spray line break LOCA's while considering the most limiting single failure. For the bottom break LOCA, the analysis showed a particular ECCS pump and valve failure combination that resulted in a nozzle flowrate less than 296 gpm. The problem occurs with both ECCS pumps running, a vessel pressure of 75 psig and an inadvertent opening of the backup containment spray system (CSS) valve. Although the present BRP technical specifications require both the primary and backup CSS to be operable, calculations submitted to the staff concerning the reactor depressurization system (RDS) perfonnance in a LOCA (Special Report #21, May 15,1975, reference 5) show that the CSS is not necessary to prevent exceeding rh k
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p U , containment design pressure. (In fact, the plant operating procedures allow manual bypass of the arimary CSS valve if the operator decides that ECCS water should not 3e diverted from the core.) CPCo has proposed opening the power supply breaker to the backup CSS valve, thereby eliminating inadvertent valve opening. If necessary, power could be reinstated and the valve opened from inside the control room. Since the containment spray system is not predicted to be necessary during a LOCA, the primary CSS is always available without degrading t'ne NSS performance, and the backup CSS can be rapidly made operable if rieeded, the staff concludes that oower should_be_ removed from the backup CSS valve. The Technical Specifications have been
'mocittea to require power removal from this valve. With this change the staff concludes that the nozzle spray system receives sufficient ECCS flow (e.g., > 296 gpm)-during bottom break LOCA's.
' The hydraulic analysis for the ring spray line break LOCA showed that with the most limiting single failure the nozzle flowrate was in excess of 296 gpm.* Therefore, the staff concludes that the nozzle spray system receives sufficient ECCS flow during the ring spray line break LOCA.
p 2.1.2 Minimum Assembly Soray Flow CPCo assumed satisfactory performance of the new nozzle design if test t data showed that each assembly received at least 1.0 gpm of spray ficw at reactor vessel pressures and nozzle flowrates predicted in the ECCS analysis. The staff requested the licensee to provide a detailed justification of the 1.0 gpm acceptance criteria. CPCo and tha NRC staff examined numerous reports concerning the Full Length Emergencv ' feat Transfer (FLECHT) experiments and the minimum spray 1 ...../atively predicted to be present in other BWR's of various uasigns and the corresponding spray cooling coefficient assumed for those reactors. It was noted that a certain " vaporization" or " evaporation" flow could be defined for each fuel assembly such that vaporization of that amount of water would remove the total amount of power being produced in the bundle. The bundle power is a function
*The ring spray line break ECCS analysis takes credit for nozzle spray cooling at a vessel pressure of about 75 psig, but the hydraulic
>296 gpm) with a analysis vessel pressure of 38 psig. The conflicting vesse (T pressure assumption demonstrates sufficient nozzle flowrate was explained by the licensee by referencing a revised blowdown analysis (submitted to the staff on March 26, 1976, reference 6) and fuel heatup sensitivity studies (submitted as Attachment 3 to the CPCo submittal dated February 27, 1976, reference 7). These calculations showed that if credit for nozzle spray cooling were O '
delayed until the versel w. sum nu been reduced to 30 nsi.;, V the PCT would be about ik. i w.cn is call below . a to; r ' .' . limit. g.
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p b of the fission product decay heat generation rate at the tine of rated spray when the ECCS analysis takes credit for spray cooling. Therefore, the " vaporization" flow depends on the time of rated ,
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spray.* - It was further noted from the FLECHT tests and from conditions present in other BWR designs that if the minimum spray flow available to , each bundle is at least 30% above the " vaporization" flow for that I bundle, the convective spray cooling heat transfer coefficients in the ECCS-LOCA' calculations are conservatively justified. , The licensee submitted their calculations to the staff in a letter dated September 19,1977 (reference 8), which determined the highest bundle peaking factor at any time in Cycle 15 for each bundle location. The calculations also assumed the American Nuclear Society decay heat fraction for infinite irradiation at the earliest time at which rated spray flow was assumed to occur in the ECCS analysis (e.g., 20.4 seconds l for the DBA). These two factors gave the highest power of each bundle at the time of rated spray. The " vaporization" flow was determined l using this bundle power and the vessel pressure at the time of rated spray. . The actual flow delivered to each bundle was determined from the full (A] N scale tests using the minimum predicted nozzle flow of 296 gpm at 75 spsig vessel pressure or higher flows at lower vessel pressure consistent with the pump lead flow performance. Using the bottom plus top steam entry condition flow data, which the staff believes to conservatively bound the worst LOCA condition,* the ratio of actual flow to vaporization flow f or each bundle was calculated. Both the licensee's and the staff's calculations show that the ratio is above 1.30 for every bundle. Therefore, the staff concludes that each bundle will receive adequate flow from the NSS.
*The " vaporization" flow will also depend on the vessel conditions at the time of rated spray since the heat of vaporization, hfg, and the specific volume, vf, depend on the system pressure.
*The licensee discussed the relation of various steam entry conditions used in the nozzle testing program to actual LOCA conditions in their October 5,1977 submittal, reference 9.
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l 1 b(3 2.2 Ring Core Spray System _ ! The ring core spray system is redundant to the nozzle spray system. Its performance is required to satisfy the single failure criterion of 10 CFR 950.46, Appendix K. Paragraph I.D.1 for postulated failures in the NSS concurrent with all LOCA's except a postulated break in the NSS. For postulated breaks in spray systems, the Commission has previously evaluated the likelihood and consequences of breaks in either spray system with concurrent failures in the other (i.e., intact) spray system and granted a lifetime exemption based partly on the expected performance of the reactor feedwater system. However, at that time the spray distribution in a steam environment was only thought i to adversely affect the single nozzle spray system. As discussed l earlier, the staff requested CPCo to reevaluate this aspect of BRP l l ring spray system performance. The licensee had no data that defined the ring sparger spray distribution in either an air or steam environment, so investigating the ring spray system adequacy would have to be based on conservative estimates. l The staff suggested the licensee first estimate the spray distribution in air by the use of a geometric / trigonometric approach. The projected cone angle from each individual nozzle on the ring would be b superimposed on a core map. From that projection, an estimated
'V bundle spray flow in air could be calculated. To account for steam environment effects, the bundle spray flow would be conservatively s
reduced. The resulting estimated flow could then be compared to the " vaporization" flow, described in section 2.1.2 herein. The ratio of estimated flow to vaporization flow for each bundle would then be used to evaluate the ring spray system performance. The licensee utilized the staff's suggested approach described above, and the results indicated questionable ring spray distribution in an air environment. Although CPCo.does not.believe the staff's suggested approach accurately predicts the ring spray distribution, no test or design information or substitut_e approach was available t_o confirm the system adequacy.150 ailow sufficient time to conduct a test reyram Lu~ investigate this question, CPCo requested a one-cycle exemption from the single failure criterion of 10 CFR 50.46 as applied to a LOCA followed by a concurrent s%1e failure of the redundant NSS.
/ The exemptiorQ37r3 suppor~ ting calculations were presented to the staff in the licensee's September 15, 1977 submittal (reference 10).
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6-b CPCo performed two sets of calculations in support of the exemption: (1) the probability (which they call " risk") of all LOCA's plus single failure combinations which would result in total core cooling s being provided by the ring spray system and (2) for top break LOCA's, the ability of the feedwater system to reflood the vessel and maintaint cladding temperatures within 10 CFR 50 Appendix K limits. The staff's T evaluction of the licensee's calculations is discussed below. The staff's decision regarding the requested one-cycle exemption is not based only on.the probability assessments or the feedwater system ; performance appraisal. Rather, these calculations have been used along with an evaluation of other ECCS considerations to reach its decision. The other ECCS considerations are also discussed below. 2.2.1 Feedwater System Reflood Since the ring sparger's performance adequacy cannot be substantiated for this cycle, the licensee must rely on the reactor feedwater system for core cooling during the LOCA caused by a break in the redundant NSS line. The ability of the feedwater system to keep cladding temperatures within Appendix K limits had not been previously confirmed for the redundant NSS break. Appendix A of CPCo's letter to the staff dated March 26, 1976, refercace 6, presented a blowdown analysis for the NSS line breal LOCA. The analysis predicted the minimum reactor water level would be one foot above the bottom of the core, thus the fuel is never completely uncovered. Normally, core cooling is accomplished by both spray systems (two are required to satisfy the single failure criteria). Because of the uncertainty in the ring spray distribution, consideration was given to the performance of the feedwater system, even though it is not a principal safety system. Taking credit for a feedwater flowrate of 1600 gpm at ten minutes after the LOCA, CPCo analyzed the fuel heatup before reflood was complete and determined the PCT to be well below 22000F. The attachment to CPCo's letter to the staff dated October 12, 1977, reference 11, discusses the performance aspects of the feedwater system so that reflood can be started at ten minutes. Water makeup to the hotwell nonna11y comes from the condensate storage tank via two paths: the makeup line or the fill line. Both lines have automatic control valves that sense the hotwell level and open to keep level within a O V
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predetermined control band. The combined makeup an fill valve ; flowrates under a gravity flow situation was determined and used ' to calculate the hotwell refill rate.* For the most limiting initial conditions, CPCo calculated that the j hotwell will have sufficient inventory for condensate pump restart at about five minutes after the LOCA, and enough inventory for core I I reflood ten minutes after the LOCA.** The plant _precedures'would require the operator to restart the feed system once hotwell level has been restored and to initiate reactor reflood at about ten minutes after the LOCA, or when hotwell inventory is adequate. Operator action soon after a LOCA is normally not desireable; however, the procedure is routine for BRP startups, the instruments and controls are familiar to the operators, and there is adequate margin in the calculation so that slight delays in reflood would not lead to an unacceptable PCT. Additionally, the operators ' will be informed and trained to restart the feedwater system to assure adequate reflood capability following a LOCA. The staff donsiders the required operation of the feed system soon after a LOCA acceptable for the next operating cycle. O h While not normally a safety related system, given its important ECCS function for the next operating cycle, the feedwater system was reviewed to improve its reliability. The staff and licensee noted that several components in the feedwater system, if failed, ' would disable the system's ability to provide adequate core reflood. Accordingly, the staff has added Technical Specification
*The contents of the hotwell at the time of the LOCA are conservative 1yr assumed lost out the break. The condensate pumps trip on low hotwell level then the feedwater pumps trip on low suction pressure. Once the pumps trip, refilling of the hotwell is accomplished by flow through the makeup and fill valves from the condensate storage tank.
**The most limiting initial condition for the hotwell is a high level since this delays condensate pump trip (on low hotwell level). The condensate pumps are removing hotwell water at about 2200 gpm, so that the sooner these pumps trip the sooner the makeup flow can begin to increase the hotwell level.
The licensee has calculated that about 1815 gallons are needed to completely cover the core, thus about 6.7 minutes of hotwell makeup are required.
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G' limiting conditions for operation and surveillance requirements to better ensure feedwater system operability in the event of a liSS line break LOCA. These components are the condensate pumps, the hotwell fill valve
- and the condensate. storage tank.
Based on the fuel heatup calculations, the reflood calculations and the added Technical Specifications regarding the feedwater system, the staff concludes that the feedwater system provides adequate reflood in a nozzle spray line break LOCA. 2.2.2 Probability Assessment - CPCo evaluated all combinations of break location and component failure which would result in the reliance on the ring spray system alone for core cooling. Two LOCA scenarios of importance were identified: (1) unrefloodable LOCA's (caused by bottom breaks), coupled with a failure of the redundant NSS, and (2) the refloodable LOCA (caused by a break in the redundant NSS line), coupled with a failure of the l feedwater system. .
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The probability of each LOCA scenario was calculated by CPCo and ,# r reported to the staff in the September 15 submittal, reference 10. , The staff noted that CPCo had omitted the effects of operator error \**
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the component unavailability due to testing and/or maintenance, ) l and the possible common mode failures. These facets were addressed } j
*The makeup valve is a solenoid operated butterfly) valve and t valve is an air operated (solenoid actuated pilot gate valve.
The makeup valve line provides little flow under a gravity drain situation because a section of this line is only slightly below the CST water level. The fill valve al re, however, provides the majority of the gravity flew to the notwellIfsince the entire the solenoid, line is much lower than the CST water level. the level switch or the air supply should fail the fill valve is inoperative and cannot be manually opened.
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l
**The operator errors the staff identified that were omitted by the licensee are (1) the erroneous isolation of the redundant NSS ;
during a bottom break LOCA, (2) the improper restarting of the feedwater and condensate pumps or systems, (3) the failing to initiate hotwell makeup from either the firemain (ECCS) or the condensate storage tank, and (4) the improper manual control of an inoperative feed control valve or its bypass. f The most significant of these errors is considered by the staff to be the first-since it totally disables the only proven core n cooling system for this break b a'Ntien. This -% error op appears m tor has a V}
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to have a relatively high v"- complicated procedure to pertU
, . L. , a 4 m m y snur. t.i w 0 ter the LOCA. The procedure isolates the broken core spray line by comparison of ECCS flows through each spray line.
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e 4 4 i by CPCo in their October 12, 1977 submittal (reference 11). The ! revised probability calculations took these factors into account, and slightly different scenario probabilities resulted. ' 1 t c;rc; ;;ith the 14mnsee's__ calculations so we f L The' staff did
" conducted an independent stLd y, The staff's calculitiohs showed the inadvertent NSS isolation potentiality to be a major contributor to the overall failure probability. Therefore, the staff and licensee discussed possible techniques to improve.the operator reliability,
' or to remove the required isolation procedure. .
As a result of these discussions and a detailed review of the original bases for the requirement,* the staff and licensee agreed that the NSS isolation procedure is no longer required and should be deleted. The other operator errors are not as significant and do not contribute appreciably to the redundant NSS or feedwater system failure proba-bilities. However, in evaluating the potential operator errors in initiating hotwell makeup, the staff noted that opening the ECCS fire system to hotwell makeup line could result in a redundant NSS flow rate 41ess than the minimum 296 gpm required. This flowpath was not evaluated in the hydraulic analysis so CPCo has deleted : the procedure to initiate.ECCS fire system to hotwell makeup. ( Instead, makeup to the hotwell would be allowed only from the condensate storage tank. The staff's independent study was altered to reflect these changes in required operator action. The results indicate that the.. dominant.' e
.LailuraJnode in the redundant TISTTs7fie fail _ure_of_the_in-s .ri.es M0V's to open. The major failure mode in the feedwater system i's "eitner se fi'ilure of off-site power, a' condensate pump or the hotwell fill valve. Thus, the staff has added Technical Specification I limiting conditions of operation and surveillance requirements l for these components (except off-site power which was already subject to the Technical Specifications). l,
*The ring spray system M0V's were located at a height such that within two hours after the worst LOCA, containment ficoding would render them' inoperable. Since long term cooling required isolation of the broken spray line, the operator had to evaluate the spray system flows and locate, then isolate the break. This had to be done before the.RSS valves were flooded. However, the RSS valves have been raised and are no longer. subject to flooding, so u ' isolation for long term cooling can be done long after the LOCA where operator errors have less effect on ECCS performance.
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O Since the staff's and-licensee's probability studies use'd different 1 individual failure rates,'the overall system failure probabilities 1 differed. However, the overall results were not appreciably different and the staff conclude, + hat the probability of a LOCA and failure combination resulting in tia ring spray system alone having to pmvide. core cooling is suffic' tly low such that there N is reasonable assurance that operation duilng the 1978 fuel cycle \ will not endanger. life or property. 2.2.3 Additional ECCS Considerations Several other factors have been considered by the staff in reaching . its decision on the requested one-cycle exemption. These factors 1 when combined give the staff an overall assessment'of the BRP ECCS performance. 1 The staff and CPCo have' assumed that the ring sparger's performance is totally inadequate. 'Such an assemption is very conservative. Although the geometric /trigometric approach used to estimate the i spray distribution in air indicated questionable performance, neither the staff nor CPCo believes that the ring. spray pattern provides no spray cooling. The effects of spray cone mixing, reflection off vessel internals and updraft have not been accounted O, for and can only be adequately determined by a rigorous test program (similartothesinglenozzletestanddevelopmentprogramjust 1 completedbyBRP). The assumption of ring spray total inadequacy was necessary, but very. conservative,. since the staff did not have information available to judge its effectiveness. CPCo's. calculation of the fuel heatup before the completion of core reflood during the nozzle line break- LOCA takes no credit for any spray cooling afforded by the ring sparger. Unlike the feed-water that refloods from the bottom, the ring sparger flow is from above the. core and must afford some cooling as it travels down the assembly to the lower plenum. This extra cooling has not been considered by CPCo.
' The water in the hotwell at the time of the LOCA has been conservatively
, assumed to be totally lost out the break. The blowdown analysis
'does not take credit for the pressure reduction or vessel inventory
. afforded by this flow, and the heatup analysis ignores this flow in lowering fuel temperatures.
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U The redundant NSS is a fully tested system that provides more than adequate. flow to each fuel assembly in the anticipated LOCXTteam environment. The calculations used to substantiate the system adequacy are quite conservative. Also, there is significant spray flow before the time that the ECCS model assumes spray cooling heat transfer. The plant operating procedures require restart of the feed and condensate systems and initiation of reactor feedwater flow as soon aspossibleaftertheLOCA(seesection2.2.1). If a bottom break LOCA occurs; the feedwater till eventually be lost out the break, but some of the feedwater added to the steam drum may, depending on break location and size, flow down the steam riser or the reactor coolant racirculation lines and provide some core cooling. If the 1 LOCA is caused by a break in the ring spray line, CPCo has shown that the redundant NSS alone provides adequate spray cooling; however, the procedures at BRP require the restart of the feed and condensate pumps and initiation of feed flow regardless of break locations. The extra coolant inventory provided by the feedwater is significant,
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yet has not been considered. . The ECCS reliability has been increased by the correction of several , items discussed in the staff Safety Evaluation Report for Amendment l h No. 10 dated June 4, 1976, and in the Commission Order, dated l [V May 26, 1976 (reference 1). The staff's evaluation of these items s is discussed in the attached Safety Evcluation. The emergency diesel generator and diesel driven fire pumps have been made more reliable by making improvements in their tri) circuitry. Inadvertent diesel trips caused by errcneous signals have been virtually eliminated by the addition of coincident trip logic. The ECCS instrumentation has been modified to allow complete on-line testability of the actuation sensors, (low water level and low primary pressure sensors). Also, Technical Specification changes have been' proposed by CPCo and approved by the staff that require increased on-line ECCS testing. CPCo has modified several ECCS annunciation and indication circuits to remove their susceptability to certain single failures. Since the operator must.have these circuits to assess ECCS performance during the LOCA, the correction of the defects significantly improves the system reliability,
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1 O C/ The position of the ring spray line isolation valves has been changed so that these components are no longer subject to flooding during a LOCA. As a result of this alteration, a relatively coc.pli-cated procedure that had required operator action soon after a LOCA has been eliminated. Since the likelihood of operator error is high during a high stress condition and for an infrequent situation such as a LOCA, the deletion of core spray isolation requirements is an important addition to the reactor's safety. The reliability of portions of the ECCS required for long term cooling has' been improved by the addition of flexible hose that can bypass the underground portion of the fire system. Technical Specification surveillance requirements have been added to ensure the availability and operability of the hose. Continued operation of the facility during this period will provide electric power for the surrounding community. The licensee has provided information demonstrating that continued operation results in savings of significant quantities of fuel oil that would otherwise
- be consumed.
3.0 CONCLUSION
S fn The staff concludes that the redundant NSS provides sufficient ECCS cooling water flow with the most limiting single failure and produces an acceptable core spray distribution during expected LOCA conditions and this provides reasonable assurance that operation during the next refueling cycle will not endan,;rr life or property. To ensure the adequate redundant NSS core spray performance, removal of powsr from the backup containment spray system valve has been required. The staff concludes that granting the requested short-term exemption, to permit BRP to resunfe operation, subject to the conditions specified below, is warranted in view of the staff's assessment of the overall ECCS performance and reliability:
- 1. Prior to the BRP Cycle 16 startup, CPCo must provide an evaluation of the ring spray system demonstrating acceptable performance at the anticipated LOCA environments, or modify the ring spray system tuch that acceptable performance is achieved, and D.
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- 2. If a new core spray sparger design is developed, the hydraulic characteristics of the ECCS must be evaluated to ensure adequate
< performance of both spray systems considering the most limiting single failure. We have concluded, based on the considerations discussed above, that the exemption is authorized by law and will not endanger life or property or the common defense and security and is otherwise in the public interest. l Date: October. 17, 1977 ' d 1 , I i
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/ REFERENCES t
L
- 1. Memorandum and Order, by the Commissioners, NRC In the Matter of CPCo, Big Rock Point, dated May 26, 1976.
- 2. Big Rock Point Core Spray Test Report, Single Nozzle Test and Development Program, NUS-3005, NUS Corporation, August 1977. (Included as attachment to the letter from W. S. Skibitsky, CPCo to Samuel J. Chilk, Secretary to the Commission, NRC, dated August 9,1977).
- 3. Effects of Steam Environment on BWR Core Spray Distef 5ution, Amendment d3 to NE00-20566, April, 1977.
- 4. Hydraulic Evaluation of the Bio Rock Point Plant Emergency Core Cooling System, MPR Associates, Inc., August, 1977. ,
i
- 5. Responses to Additional Information Requested verbally May 13, 1975 Regarding Big Rock Point Plant, Special Report No. 21, May 15,1975. l
- 6. Attachment 1 to the letter from Ralph B. Sewell, CPCo to Samual J. Chilk, Secretary to the Commission, NRC dated March 26, 1976 (subject: additional information on the BRP ECCS adequacy report).
- 7. Reyort on Evaluation of Adequac y of Emergency Core Cooling System, j
[ Consumers Power Company, February 27, 1976. (
- 8. L'etter from David A. Bixel, CPCo to Director of NRR, NRC, dated September 19, 1977 (subject: verification of nozzle spray flow rates).
- 9. Letter from David A. Bixel, CPCo to Director of NRR, NRC, dated October 5, 1977 (subject: comparison of top entry steam data with predicted LOCA blowdownphenomena).
- 10. Letter from David A Bixel, CPCo to Director of NRR, NRC, dated September 15, 1977 (subject: request for one-cycle exemption).
- 11. Letter from David A. Bixel, CPCo to Director of NRR, NRC, dated October 12, 1977 (subject: Addendum to exemption request).
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f 4# UNITED 5TATEs yy g 4, NUCLEAR REGULATORY COMMISSION
.f * {, [ WASHINGTON, D. C. 20655 -
e,w*%N o % le v .. ... SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION SUPPORTING AMEN 0 MENT NO.15 TO FACILITY LICENSE NO. OPR-6 CONSUMERS POWER COMPANY BIG ROCK POINT PLANT DOCKET NO. 50-155
1.0 INTRODUCTION
By letter dated December 17, 1976, Consumers Power Company (CPCo) pro-posed changes to the Big Rock Point (BRP) Technical Specifications. In response to staff concerns, CPCo provided supplementary information in letters dated February 9 and August 17, 1977. The proposed changes would modify the fuel heat generation limits approved for Cycle 14 operation. CPCo also proposed Technical Specification changes for the BRP Cycle 15 fuel reload by letter dated April 15, 1977 supplemented by letters dated April 21, August 12 and September 26, 1977. Based on the Commis-( sion Memorandum and Order dated May 26, 1976 and NRC staff concerns x CPCo provided supplementary information for staff evaluation by letters dated January 19 and 20; February 4 and 9; May 5; July 26; August 9, 12, 17, 24 (two letters),.30 (two letters) and August 31; September 14, 19 and 26; and October 5, 1977. The CPCo proposed technical specification changes and related license amendment would:
- 1. authorize operation of BRP with the newly constituted reactor core designated for Cycle 15,
- 2. modify certain surveillance requirements based on CPCo having complied with conditions of the Commission Memorandum and Order dated May 26, 1976,
- 3. add certain limiting conditions of operation and surveillance requirements based on the staff's review of CPCo's Cycle 15 Reload application, anc f' *,"
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g 4. delete a fuel burnup limitation that is no longer required. The staff has revised CPCo's proposed specification enanges consistent
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with this safety evaluation. Modifications have been reviewed and agreed to by the CPCo staff. The NRC staff evaluation relating to the uncertainties in the core ring spray system for which CPCo requested a one-cycle exemption by letter dated September 15, 1977 was included in a separate safety eva'luation report. 2.0 DISCUSSION AND EVALUATION 2.1 Cycle 15 Fuel Reload 2.1.1 Nuclear Characteristics The Cycle 15 core will be composed of 84 fuel assetiblies, (listed in ) Table 1); 22 are fresh 11 x 11 fuel bundles manufactured by EXXON, I including 16 type G-3 and six type G-1U assemblies as shown in Table 1. The G-lu fuel was also used as reload fuei for the Cycle 14 core. The G-3 reload fuel is very similar to the G-lu fuel with three differences:
- 1. The G-3 assembly dtes not have the four cornbr cobalt target rods. Instead, fout low enrichment fuel rods are used.
- 2. The removal of the four target rods has necessitated a change in the enrichments of the G-3 fuel rods. The overall bundle enrich- i
,V ment in the G-lu as!embly is 3.88%, whereas the G-3 bundle enrich- l s ment is 3.14%, (U-2:15) . .
- 3. The gadolinia pois(n pins have been relocated for better peaking i characteristics. This new arrangement is shown in Figure 3-2 of I reference 23.
LABLE1 CYCLE 15 CYCLES NUMBER OF INITIAL ENRICH BOC
, TYPE SIZE IN CORE ASSEMBLIES U Pu BURNUP G-3 11x11 1 16 3.14 0 0 G-lu 11x11 1 6 3.88 0 0 G-1U 11xil 2 14 3.88 0 5,863 G 11x11 2 8 3.08 0.90 6,518 l
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TABLE 1 (Continued) CYCLE 15 CYCLES NUMBER OF' INITIAL EURICH BOC SIZE IN CORE ASSEMBLIES U Pu BURNUP TYPE G 11x11 3 18 3.08 0.90 13,828 F-MOD 9x9 4 12 3.51 0 13,711 G 11x11 5 2 3.08 0.90 22,851 F-MOD 9x9 5 2 3.51 0 16,703 F 9x9 5 6 3.52 0 16,641 The new fuel will generally be loaded on the core periphery with the i more exposed fuel located in the center of the core. The Cycle 15 l loading pattern has been designed to incorporate 180 rotational symmetry throughout the core. The core' loading maps are shown in Figures 3-1 and 3-3 of reference 23, and in reference 34. O The nuclear parameters of the Cycle 15 core are described in the CPCo r.eload submittal. The current Technical Specification minimum shut-Q down margin limit is 0.30% ak/k, at the most reactive time in core
' life with the most reactive rod fully withdrawn. The Cycle 15 core meets this requirement with a beginning of cycle (B0C) shutdown margin of 2.21% ak/k and an end of cycle (E0C) margin of 6.2% ak/k. .The Technical Specification maximum reactivity for in-sequence rod drop worth is 2.05% ak/k. The Cycle 15 value at BOC is 0.77% ak/k and at E0C is 0.57% ak/k.
Cycle 15 nuclear parameters are listed in Table 2. TABLE 2 PARAMETER BOC EOC
-5 -5 D0PPLER COEFFICIENT -7.06x10 ak/k/%P -7.65x10 6k/k/%P VOID COEFFICIENT -0.1663ak/k/uv -0.1127ak/k/uv OELAY FRACTION 0.00606 0.00588 l
(N L)
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l l l O TABLE 2 (Continued) PARAMETER BOC E0C
~4 -5 MODERATOR COEFFICIENT (102.5 F) -5.496x10 ak/k/ F -2.4274x10 Ak/k/*F SHUTOOWN MARGIN 2.'212k/k 6.212k/k MAX IN-SEQ R00 WORTH 0.772k/k 0.572 k/k MAX OUT-OF-SEQ R00 WORTH 2.032k/k 1.732 k/k l CPCo indicated in reference 37 that calculations performed to determine the Cycle 15 Standby Liquid Control System (SLCS) worth show that the reactivity inserted by a 2000 ppm boron concentration at 68 F, in a xenon free condition, is 26.992k/k. Therefore, the SLCS satisfies the alternate shutdown requirement specified in General Design Crite_
ria 26. l l The Cycle 15 core power distributions, reactivities, reactivity co- i efficients, fuel burnup and margin to thermal limits were calculated l using the computer code GROK. GROK is a three dimensional coarse mesh l reactor simulator with thermal-hydraulic feedback and is a derivative (s g of the FLAR program (D.L. Delp, et al, " FLARE, A THREE DIMENSIONAL BOILING WATER REACTOR SIMULATOR," GEAP-4598, July 16, 1964). CPCo has agreed to provide additional description of GR0K prior to the Cycle 16
' reload.
Based on the information presented in by CPCo and on the staff's previous review of the nuclear design of G-lU fuel, the nuclear characteristics and performance of the reconstituted core for Cycle 15 operation at BRP are satisfactory. 2.1.2 Mechanical Design The mechanical design of type G-3 fuel is essentially the same as the G-lu fuel. The only difference in the mechanical designs between the G-lO and G-3 fuels is an alternation in the latter's upper tie plate. Since G-3 fuel does not have the four corner cobalt rods that G-lu fuel had, the upper tie plate was modified to provide standard fuel rod location holes replacing the locking slots used in the G-lu design. CPCo has'provided description of the mechanical design of type G and G-lu fuels in letters dated June 6,1972 and October 13, 1975. The G-3 fuel components, their purpose and composition are described in Table 4.2-1 of the Cycle 15 reload submittal. p
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' Based on the.succesful operation of types G and G-lU-fuels, and the minor difference between these fuels and tne G-3 design, we conclude D" that the, mechanical design of the G-3 fuel is acceptable.
2.1.3 . Thermal-Hydraulic Design 2.1.3.1 General The hydraulic design and performance of the G-3 fuel is identical to that of the G-lu fuel. However, the thermal performance differs due to the replacement of the four ccbalt rods with low enrichment fuel
. rods which. results in increased bundle enrichment. The average G-3 fuel rod power will be maintained slightly less than the G-lU fuel rod, resulting in lower clad and fuel temperatures. Table 6-1 in reference 23 compares the thermal and hyrdraulic performance of the G-10 and G-3 fuels.
2.1.3;2 Transient Analyses Transient analyses are presented by CPCo in reference 1, reference 2, i and the Final Hazards Summary Report (FHSR) for BRP, dated 1962.
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In ! I general, the peak power, heat flux or minimum burnout ratio (MBR) are compared for each transient analyzed to determine the " worst case" transient. For BRP the " worse case" transient was identified as the loss-of-recirculation pump transient. CPCo also analyzed the design I I overpower condition and calculated the MBR assuming all plant variables (- at the design value with the exception of core power waich'was assumed s to be at 122%*. Each cycle, CPCo recalculates the MBR, (also the minimum critical heat flux ratio (MCHFR) since the Hench-levy correlation is being used) for th'e loss-of-recirculation pump transient and the design overpower condition. The present Technical Specifications require the MBR (or MCHFR) to be greater than 1.50. The staff reviewed the analyses and tests discussed in references 1, 2 and the FHSR. In addition, CPCo met with our staff on August 18 and l September 7, 1977 for further discussions of the transient analyses. I l The. staff concluded that the modsis and methods utilized were not ! acceptable. Since the techniques are used as a bases for setting fuel thermal limits, the staff required CPCo to define and substantiate MCHFR limits using presently acceptable techinques. , 1*The 122% of rated power was determined by assuming an initial power of 105%, (hi-flux alarm), 5% for instrument errors, and 12% for a transient heat-flux allowance' determined in a turbine-trip without bypass test presented in
< reference 2. /'-
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( V 2.1.3.3 Discussion of New MCHFR Safetv Limit and Operating Limit CPCo used the Hench-levy correlation to determine the MCHFR limits. Since the transient analyses were unacceptable, as noted above, the staff required CPCo to calculate a MCHFR limit using the Hench-Levy correlation (MCHFR -such that a MCPR of 1,32 would not be exceeded The value of usingthestaffapkbv)edXN-2 correlation (MCPR1.32 limit in.other BWR plants. Exxon Nuclear Corporation (ENC) performed the sensitivity studies for CPCo and submitted the results to the staff (reference 35), THe ENC sensitivity studies varied the plant parameters (inlet . enthalpy, power and axial peaking f actors) in the Hench-levy correla- l tion over a narrow range until the highest MCHFR t corresponding to a 1,32 MCPR was found. CPCoreportedthisvaldetobe2.15. Since thisvalubN$rrespondstothe1,32MCPRsafetylimit,the2.15MCHFRH-L c l is a safety limit. The staff reviewed transient analyses of several BWR's which used the l Hench-Levy correlation in an attempt to determine the worst case In the Turbine Trip Without Bypass (TTW/0BP) transient, AMCHFR which $ . staff believes to be the limiting transi-ent for BRP, the l largest aMCHFR of the other plants analyzed was about 0.50. How- i ever,foraddikibnalconservatism,thestaffdeterminedthelargest AMCHFR in the other BWR analyses for all transients (not only the onebeYibyedtobethelimitingtransieniforBRP). This value is 0.70 and was reported in the Duane Arnold Energy Center (OAEC);FSAR Q for the dual loss-of-recirculation pump transient. The staff added t this AMCHFR to the CPCo's proposed 2.15 MCHFR safety limit. For additional $observatism and to account for any eNIbting plant differ-ences between DAEC and BRP or inaccuracies in the analyses used to calculate the 2.15 MCHFR safety limit or the 0.70 AMCHFRTherefb, factor. a ' to ta l transien allowance, the staff add $d a 0.15 6MCHFR ,kn operating limit for MCHFR g of3.00,hasbeenestablisheda$ g The staff is confident that this value conservatively bounds all transients for BRP. CPCo has committed to perform re-analysis of the BRP transients prior to the Cycle 16 reload to justify any reduc-tion of the MCHFR limit below 3.00 which the licensee believes to ' beunnecessarilyNobservative. 2.1.4 Accident Analysis 2.1.4.1 ECCS, Appendix K Analysis The original ECCS analy' sis for BRP was performed in two parts, one for General Electric (GE) fuel, (reference 8) and the other for Exxon fuel (refere~nce 9). The Exxon analysis was accomplished using GE blowdown data as input to the approved Exxon, Non-Jet Pump, Fuel Heatup Model p)g Q n F
L r A This combination was reviewed and approved by the staff ( (XN-NJP-FHM). in reference 13. A licensee event report, (LER) was issued by CPCo on October 28, 1976, stating that certain revisions made to XH-NJP-FHM resulted in a shift in the limiting break and changes in the maximum average planar linear heat generation rate (MAPLHGR). The utility r6stricted plant opera-tions to the most limiting MAPLHGRs pending completion of staff re-view.
' CPCo's request for Technical Specification changes (reference 17)
- briefly described seventeen revisions to the ECCS code. Three addi-tional submittals (references 21, 22 and 30) clarified the changes and discussed the effect on the break spectrum. By letter dated April 15, 1977, and supplemented by the Exxon report (reference 22), CPCo proposed MAPLHGR limits for the Cycle 15 fuels (G-10 and G-3).
As a result of the seventeen ECCS code revisions, the MAPLHGR limits for type G and G-lu fuels increased (less limiting) during the first portion of the cycle and dropped slightly (more limiting) during the latter portion. theDBA,3.926ft}helimitingbreakpriortothecoderevisionswas After the code revisions, the limiting break for the G, G-10 an G-3 fuel types was predicted to be the intermediate break, 0.25 ft O The staff has evaluated the input updates and has determined that five ("/ of the seventeen changes constitute model changes and were reviewed in
' that context. The remaining twelve revisions have been categorized as input changes. Each change was evaluated considering its effect on the peak clad temperature (PCT) and break spectrum. These are discussed below. The item number in parentheses after each item refers to the listing in the addendum to reference 22.
2.1.4.1.1 ECCS Evaluation Model Changes
- 1. HUXY Time Stop Size (Item #5)
The time step used in the. m u (ref.10) calculation was reduced over a portion of the transient time interval to insure solution convergence. This change resulted in a 1 F change in the cal-culated peak cladding temperature (PCT) and is acceptable.
- 2. Yamanouchi Canister Quench Algorithm (Item #9)
This correlation is used in HUXY to determine the quench time for the fuel element canister. The algorithm was previously hard p U
.m e
o f'N E coded in the computer program.so that tne quench time was calcu-lated at a fixed plane of interest. The computer program has been modified so that the quench time can now be determined .2t However, the Yamanoucni correlstion has any horizontal plane.This change results in no change in PCT since not been modified. the previous code version calculated thefinds The staff canister quenchacceptable. the change time at the proper elevation of BRP.
- 3. Inert Pin Modeling (Item #12)
The inert zircaloy rods in'the fuel assemblies were previously modeled as solid rods. These rods are actually zircaloy clad The modeling of these rods has zircaloy bars wi.th a radial gap. This change been modified to reflect the actual configuration. The staff resulte'd in an approximate increase of 5 F in PCT. finds this change acceptable. l
- 4. Increased Radial Noding of Inert Rods _ (Item #13)
The number of radial nodes in the inert Thisrods changewas increased has no effect from 3 ) to 12 to insure solution convergence. I The staff finds this change acceptable. on the calculated PCT. f f.s
- 5. Quench Plane for Active and Inert Rods (Item #14)
! T The BRP fuel is cooled after the LOCA by the core spray system V which injects water from above the core. During this cooling ,
' period, the inert zircaloy rods in the fuel assemblies function l as a heat sink. The quench plane for the active and inert rods in the BRP core was previously calculated at an elevation three- ,
quarters of the way down from the top of theThis core, whereas delayed the quench l PCT was calculated at the core'mid plane. time was inconsistent and represented a large conservatism. The quench planes for the active and inert rods have been changed to be consistent with the elevation of interest for the PCTtimecalcula-tion. This modification results in calculating a quench For the large break for the inert rods before PCT is calculated. This change provides a analysis, the PCT was reduced by 150 F. more consistent calculation and is acceptable to the staff. 2.1.4.1.2 ECCS Evaluation Model Input Changes and Updatej
- 1. Reduction of Axial Peaking in GAPEXX (Item #1) l The axial peaking factor in GAPEXX (reference 4) has been reduced from 1.50 to 1.40. GAPEXX is used in the FHM to determine the gap heat transfer coefficient due to the presence of fill and o
9 E
' * (*
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. fission gas. The'. quantity of fission product gas released from the. fuel depends on LHGR, fuel type, fuel temperatures and burnup.
A reduction in axial peaking causes the' axial heat prafile to become flatter, thereby raising the fuel. temperature, fission product production and release; hence a lower gap conductivity. The change was also made for consistency with the fuel heatup calculation model, HUXY. The staff concludes.that the change is conservative, establishes consistency with HUXY, and is acceptable. t
- 2. Reduction in Convective Heat Transfer Coefficient in GAPEXX .
(Item #2) The coolant convective heat transfer coefficient-is utilized by GAPEXX .in .the determination of the fuel pin radial temperature profile. Since a lower coefficient results in less energy transfer, l
'the radial temperature profile increaseg. The coefficient was ;
reduced from 28,365 to 21,000 BTV/hr-ft 'F and was done for consistency.with HUXY. . The staff finds this change acceptable since it establishes ~ consistency and is conservative. b .3. Changes in MOX Weight Fractions in GAPEXX (Item #3) i Based on actual weight gactions f the fabricated material, the weight fractions of Pu 2 and Pu 2 were' changed in GAPEXX. Pu from 0.2131 to 0.2054 Pu from 0.0569 to 0.0729 1 As discussed in_section 3.4.2.8 of " Final Generic Environmental Statement on the Use of Recycle Plutonium in Mixed 0xide Fuel in i Light Water Reactors" (reference 14) the fission product release I from a-MOX fuel is essentially the same as from a U0,, fuel. Exxon reported that this update resulted in no PCT variation although there was a minor change in the predicted power depres-stori. Since the change reflects actual rather than estimated fuel parameters and since the PCT was.not effected, the staff finds.this revision acceptable.
- 4. Increased Points in h g and Hot Gap size vs. LHGR (Item #4).
;The gap heat transfer coefficient (h ), gap size and associated LHGR calculated by GAPEXX are inputs96to HUXY. The table of
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l b l V values has been increased to give improved solution convergence and is acceptable.
- 5. Switch from NSSS Normalized Power Curve to ANS Shure Curve at 40 sec (Item #6)
In previous ECCS analyses, CPCo used Nuclear Steam Supply System (NSSS) vendor supplied normalized power data for time after l
- shutdown. In section 4.1.2.2 of reference 7 the staff evaluated l and approved this method.
In the current ECCS analysis, CPCo uses NSSS data during the first 40 seconds after shutdown and is thereafter using 1.2 times the Shure curve, (reference 5), plus a constant 0.31% power for actinide decay energy. In reference 7 the staff reviewed and I approved the use of 1.2 times the Shure curve. Also, the staff concluded that the use of a constant 0.31% power for actinide decay was conservative since the techniques discussed in refer-ence 5 permit the decay of this energy during the LOCA. However, the evaluation made in reference 7 and the calculations made in reference 5 were based on UO 2 fuels. . The staff performed check calculations that showed the 0.31% actinide decay energy to be conservative for M0X and UO fuels. AlthoughtheShurecurveisstatedtobeapplicabletob0 fuels,
.Q GESMOstatesthattgfissionprogtdecayheatissever$1 percent less for Pu than for U due to the different fission product yields. For the reasons stated above, the use of 1.2 times the Shure curve plus 0.31% power for M0X fuel as well as UO 2 fuel is acceptable.
- 6. Use of New Power Depression Table in HUXY (Item #7)
If the fuel (M0X or UO,) enrichment is greater than 4%, GAPEXX is not able to calculate the radial power depression in the fuel, and the user must input this information to both GAPEXX and HUXY. If the enrichment is less than 4%, GAPEXX calculates the radial depression, uses it in its own calculations, and supplies it to HUXY. CPCo has used, for both M0X and U0,, fuels having enrichments greater than 4%, a table of radial' depression representing the MOX fuel. The depression in a M0X fuel is larger than a UO fuel, as described in section 3.4.2.6 of reference 14. Al$rge depression results in less stored energy, since the average fuel temperature is less. Thus, overestimating the power depression underestimates the fuel stored energy.
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I O) (' CPCo has proposed using a power depression value of 9% rather than 14%, indicating a flatter radial power profile. This value l- represents the power depression in the UO, fuel, but will oe utilized for both types. The use of 9% pcwer depression is conservative when predicting M0X fuel performance. CPCo utilizes the 9% power d' epression throughout the fuel pellet life, although it is known that the flux depression in the fuel will increase with burnup due to Plutonium accumu-lations at the fuel pellet edge. Therefore, the use of this value throughout life is conservative. Radiant heat transfer reverses the clad temperature transient after the inert rod has been quenched by the core spray system. For all breaks, this occurs well into the period when decay heat is more significant than the initial stored energy. Thus the change in power depression has essentially no effect on PCT, and for all the reasons stated, the change acceptable.
- 7. Thermal Conductivity Penalty (Item #8) .
The thermal conductivity of MOX fuel is slig'htly less than UO 7 fuel, as reported in WASH-1327. As stated in Section 2 of staff safety evaluation report for Cycle 14 fuel reload (ref. 13), CPCo (N reanalyzed G and G-lU fuel heatup during a LOCA assuming a reduced fuel thermal conductivity. The new MAPLHGR limits were slightly (]' different. CPCo had applied this reduction in conductivity to s both M0X and UO fuel. In the present analysis, CPCo has applied - 2
. this penalty to only M0X fuel rods. Since the intent of the change of thermal conductivity was to represent the M0X fuel more accurately, the staff concludes that this penalty need not be applied to the UO2 fuel and finds this change acceptable.
- 8. A Correction in Canister size (Item #10)
In the previous ECCS calculations,'the value of the canister inside width used was 6.453 inches, instead of the actual 6.543 inches. This value was corrected in the present analyses and is acceptable.
- 9. A Correction in the Initial Zr0 Thickness 2 (Item #11)
Section 4.1.2.3 of reference 7 discusses the metal-water reaction rate prediction used by Exxon and the importance of the initial oxide thickness. In essence, the thinner the initial Zirconium oxide thickness at the time of the onset of the Zirconium-water reaction, the faster the reaction rate and hence the greater the energy release, n .e1 +. . . ,.
, j
l [ \ -5 V CPCohasredugedtheinitialZr03 thickness from 3.25 x 10 incn to 2.10 x 10 inch to be consistent with the most recent shop l data. 'This change is conservative, more accurately represents the actual fuel and is acceptable. , 10. Enlarging Ellion film-boiling HTC look-up table (Item #15) The Ellion Film Boiling correlation gives the heat transfer coefficient (HTC) after dryout but before midcore uncovery. HUXY uses a tabular form of the Ellion correlation for different values of coolant pressures, In previous calculations, this table did not cover a wide enough range of pressures; thus, extrapolations were necessary. CPCo has extended the range of pressures to avoid extrapolations, resulting in a more accurate value for the HTC. The staff finds this change acceptable.
- 11. A Correction in the End-of-Life Local Peaking Factors In previous ECCS analyses, the value of the local peaking factor (LPF) used at the end of cycle (E0C) was an average of the LPF's throughout life. CPCo has corrected this so.that the value of the LPF used for the EOC ECCS calculation is the actual value at that time. The staff concludes that this is an acceptable change.
O 12. A Correction in the Burnup Calculation at each MAPLHGR (Item #17) The technique used to determine the fuel burnup in previous calculations was to use a nominal MAPLHGR and the number of days of operation to give a " nominal" burnup. The " nominal" burnup value was then used in the ECCS calculation, which yielded a MAPLHGR limit. CPCo modified this technique such that once the MAPLHGR limit is determined at the " nominal" burnup, a more precise burnup is determined by using the calculated si uiGR. The calculational loop could be carried on again until an exact MAPLHGP and burnup pair were determined; however, the staff considers that further refinements are not necessary. The change improves the method to calculate burnup and is acceptable. 2.1.4.1.3 BRP Break Spectrum The seventeen changes CPCo made to the approved ECCS evaluation model have altered'the break spectrum, as shown in Figure 5-1 'of the Exxon report XN-NF-76-55 (ref. 22) and in Figure 1 belqw. The limiting breakforBRPgasshiftedfromthe08A(3.926ft')totheintermediate Since CPCo calculated the PCT at only four break break (0.25 ft ). fm : g.
g - FIGURE *1 - l 4 3 1 3 5 5 I IE 3 3 4 5 4 5 5 4 8 E 5 5 I I & I 33 PCT g . - RELOAD G 2200 .
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c.s s . ~ . ~_ . . ...... I - t u. TIME OF CORE UNC0VERY ~- -- -. . --- --- - 1 E R R 9 1..{ M ., t t t I t I lit 1 ,_t a A i t I f_ lo.tj I.0 0.01 0.1 2 Died Area, f t f { , 3
;t h t _ _ - - - _ _ _ _ _ _ -
G ( "' ) areas and a shift in the limiting break was predicted, the staff requested a justification of the break spectrum shape and a detailed explanation of the shift in the limiting break. CPCo identified two parameters that are significant in calculating the break srectrum: the time of mid-core uncovery (t") and the adiabatic heatup time (t -t . During the time interval from LOCA initiation tomid-coreunbbveryy)thefueltemperaturesaredroppingduetothe energy removal by the coolant still present in the core. The cladding l temperature initially increases up to slightly less than the fuel temperature, then decreases due to heat transfer to the coolant, until the time of core uncovery. Therefore, t represents a fuel cooling timeandisanindicationofthecladdindcoolingtime.* During the time interval from mid-core uncovery until rated spray, (tg), the fuel is undergoing adiabatic heatup since no coolant is present and no credit is taken for radiative heat transfer; therefore, I the clad temperature is rising. The ratio of the adiabatic heatup I time,(t - t ) to the cooling time, t , is used by the licensee in u u explainiktheBRPbreakspectrumshape. .
~
Each event time, t and t depends on the break area,** and was calculated by GeneF31 elecVr,ic and presented in the ECCS submittal for GE fuel (ref. 8). In general, tu and t increase with decreasing break size, as shown in Figure 1. The$kfferencebetwgenthesetimes l l I
!(v ]j (the adiabatic heatup time) is greatest at the 0.25 ft break.
\
l *To be more precise the cladding cooling interval is the time from cladding-fuel approximate temperature equilization (described above) until the time of core uncovery. Since the equalization time is constant for all break sizes, the difference between the real cladding cooling time and the time of core uncovery is a constant, and t is representative of the cladding cooling time. u
**For large breaks, the reactor quickly depressurizes and the ECCS is activated by the low reactor water level signal (< 610 ft) and the _
low reactor pressure signal (1 200 psi). For small breaks, the pressure of the reactor and steam drum remain essentially constant, and the reactor water level drops. The Reactor Depressurization system (RDS) acts to reduce the pressure to a point where ECCS water injection is possible. The RDS relief valves vent steam to containment 2 minutes after the low reactor water level, low steam drum level and high fire main pressure signals are receiveo.
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l O (' The ratio of adiabatic heatup time to the. time of uncovery gives an indication of the cladding temoerature at the time of rated spray. If the ratio is large, there has been either a long heatup time or short cooling time. The PCT of the hot rod is mainly determined by the clad temperatures at t
- The spray cooling heat transfer coefficients assumed,onceratN. spray flow is reached, are not a function of break size or clad temperatures. Therefore, the variation of the time ratio,(t w of PCT win -breNk t )/t sYz,e.ith break size will be similar to the variation CPCoexaminedthetimgratiovagiationin,,
three brea less than 0.25 ft , 0.25 ft to 1.0 ft", and1.0ft)sizeintervals: to DBA.
- 1. For break sizes smaller than 0.25 ft2 , the RDS is significant in l determining the adiabatic heating period. The parameter t- -
increases with smaller break sizes due to the reduction in" blow- l down rate. The_ parameter t also increases with smaller breaks, but not as fast as t . TheNfore,theadiabaticheatingtime dropsforsmallerbrWaks. The time ratio also drops for smaller break areas indicating a reduction in the clad temperature at t RS'
- 2. For breaks of creas between 0.25 2 ft and1.0dft,theadiabatic 2
heating time and time of mid-core uncovery both drop with increas-ing break size; however, the heating time drops mure rapidly than the cooling time. The RDS is not significant for these break I areas since the reactor depressurizes rapidly through the break. I (G]
' The t drops more rapidly than t due to the more rapid depres-
' surizNiongivinganearlierECCS" initiation. The t remains
, essentially constant with increasing break areas, and since the adiabaticheatingtimeisdjopping,thetimeratiodropsfor larger breaks above 0.25 ft indicating a lower clad temperature at t RS' a
The quenching of the inert rods and cannister walls plays a significant
, role in the PCT for each break size since these components form a -
radiative heat sink for the hot rod. The quench front velocity does depend somewhat on the local temperatures. Therefore, the higher the temperatures at the time of rated spray, the slower the quench front can cool the inert rods and cannister wallc, and the longer the heatup of the not rod. This effect is evident, but not signifi-cant since the quench front velocity does not vary appreciably over the range of component temperatures of interest. 15 - bi V I oww mv, we . .n , , y
A 2 y .3.- For breaks of area from 1.00 ft to the DBA, the t and t drop slowly, but at about the same rate, therefore the Niabatid heating time is relatively constant. For large breaks, the t occurs before the fuel and cladding temperatures equalize, thds there is a very short cladding cooling time. This effect is not 1 evident when observing the time ratio and tends to increase the
' PCT above that indicated (by the time ratio). The t and t drop at the same rate since the t occurs at about tN time 8f the ECCS actuation signal, thus tHe a time between t R and t represents the ECCS delay time. Sincetheadiabaticbeating" time is constant, but the cooling time drops, the time ratio increases .
for larger break sizes. I The change in the break spectrum was caused primarily by the change in the quench plane of interest (see section 2.1.4.1.1). Sensitivity studies performed by Exxon for CPCo and reported in reference 30 showed that the other sixteen changes % eed negligible changes in the break spectrum. In changing the quench plane of interest, the center inert and corner I cebalt rods are quenched earlier and are available as a radiant heat , sink sooner. The time of cannister quench did not change. In pre- l vious ECCS analyses, the cladding temperature transient was reversea l by convective spray cooling and the radiant heat transfer to th'e l ( cannister wall before inert rod quench. In the new ECCS analysis, tne ( ]- . cladding temperature trtansient is reversed by radiant heat transfer to the center inert and corner cobalt rods, which occurs about 1 second before PCT, as well as by convective spray cooling . The PCT for all break sizes, except the 02 25 ft 2break, dropped by about 100-150 F. The PCT for the 0.25 ft break dropped by only 20 F. The drop in PCT's for all breaks is due to the earlier availability of the inert rods as radiant heat sink; the varying A PCT is due to the effects of time and temperature for each break size.
"Since the licepsee didn't recalculate the PCT's for break sizes between 1.0 ft and the DBA, a comparison of the new break spectrum with either the old break spectrum or the time-ratio cannot be done in this break size interval,,(Note: a straight line has been drawn between the PCT's at 1.0 ft' and the DBA on Figure 1). Two facts have led the staff to conclude that the new break spectrum shape
-would be similar to the time ratio shape in this break size interval.
First, the time-ratio and old break spectrum shapes correlate in this - intervti; secondly there have been no reactor system or evaluation model changes made that would cause the new and old break spectrum shapes to differ significantly. J i ie um , 5- ,
- p. . - . .. -
4 is 4 O Q. Figure 1 demonstrates the degree of correlation between the old and new break spectrum shapes
- and the tima ratio' parameter. Based on-the staff's evaluation of the variation of the time ratio with break area, and the degree of correlation between the break spectrums (old and new) with the time ratio, the staff concludes that the cycle 15
. fuel' reload break spectrum shape.has been justified.
'2.1.4.1.4 Minimum Oryout Time Limd _
Nucleate boiling is assumed to occur in the time interval from LOCA initiation until the time of dryout, (i.e. , departure from nucleate l boiling). This cooling interval is significant since the lower the clad and fuel temperatures can be made prior to core uncovery, then the lower the PCT once the temperature transient is reversed. There-
. fore, the time of dryout (t0RY) is a significant parameter in the ECCS analysis. .
I The t uried in the ECCS analyses is determined for GE fuels (F and l F-modNied)usingthebundledryoutcorrelationdiscussedinNED0-20566 l and for EXXON fuels f , G-lO and G-3) using the dryout correlation discussed in the fuel heatup model description, HUXY.(ref. 10). The j voiri fraction (i.e., fraction of bundle' coolant volume occupied by steam voids) is a-significant quantity in-the determination of t y. ,l Sincetheactualbundlevoidfractioncandifferfrcmthatassum0 din ECCS analyses, the actual bundle t 0RY could be less than that
' Since BRP has both GE and ENC fuel types and each fuel vendor utilizes its own dryout correlation, CPCo has plotted a minimum dryout time versus maximum bundle power for each vendor fuel type based on the appropriate correlation using oundle parameters at their design value.
The' actual bundle dryout time, determined using the GE correlation and actual bundle parameters, must be greater than or equal to the minimum t BRP ensures the actual-t is greater than or equal to the mkkYm.um0RY t freverybundleuN[gthe.off-lineplantcomputer. In a submittal dated September 26, 1977.(ref. 38), CPCo proposed
. Technical Specification limits to' ensure the actual t is greater than or equal to that assumed in the ECCS analyses. kNstaffsligntly modified the proposed Technical Specifications and CPCo has agreed to the altered version.
2.1.4.-l.5 Summary The staff has reviewed the tive model changes and twelve input revi-sions made to the. approved ECCS evaluation code, and the resulting break spectrum presented by CPCo showing a shift in the limiting-
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. _ , __ :. _1.. . . . , , - -
break. The staff has also reviewed the supporting arguments for the limiting break size shift along with the explanation of the O Q break spectrum shape. Based on our evaluation of this material, we conclude that the ECCS model as modified by the changes described above is an acceptable ECCS model for BRP. Also, the break spectrum shape and the limiting break size have been acceptably justified. The MAPLHGR limits generated in the ECCS analysis, and presented in Table 2 of the reload submittal, reference 23, are acceptable. Based on the correlations and methods used in the determination of-the minimum and actual bundle dryout times, the staff considers the modified Technical Specifications acceptable. The use of the GE blowdown data in, conjunction with the Exxon fuel heatup model to predict the Exxon fuel performance in the postulated LOCA was-reviewed and approved by the staff for the Cycle 14 fuel reload (ref. 13). The staff feels that this technique, however, is less preferable than a unified ECCS evaluation model using a blowdown analysis and fuel heatup calculation concurrently developed. Therefore, CPCo is required to develop and submit for staff review an ECCS analysis for BRP using a coupled blowdown and fuel heatup analysis based on acceptable techniques. The models, techniques and results should be submitted prior to the Cycle 16 startup. . 2.1.4.2 Rod Drop Accident , CPCo submitted a p1' ant specific analysis of the predicted Rod Drop (~N Accident (RDA) fuel response as an attachment to the Cycle 11 reload Q submittal, reference 6. Basec on an in-sequence rod worth of 2.1% Ak/k, the analysis at that time predicted a peak fuel enthalpy of 340 cal / gin in the G-1 type fuel (M0X) and 350 cal /gm in the J-1 fuel i (VO,3).
- The staff reviewed and accepted the analysis and cycle il prebicted fuel response.
"The licensee calculated the 2.1%ak/k maximum in sequence rod worths by assuming that an unwithdrawn rod is ejected from the core. The scenario normally assumed by BWR and accepted by the staff in calculating in-secuence rod worths is the following: .
- a. A rod in the normal withdrawal sequence becomes disconnected fr:m its drive and stuck in the core.
- b. Normal withdrawal sequence continues, despite the uncoupled and stuck rod, with the operator failing to notice erroneous indications.
- c. At the worst time in rod withdrawal, the stuck rod frees and drops to its drive mechanism position.
The maximum in-sequence rod worth of 0.77% Ak/k was calculated using the above scenario. The control rod giving the max in-sequence wortn is an interior, Group D rod. G f l-U g e e-
O Q The maximum in-sequence rod worth during cycle 15 is 0.77% ok/k at BOC and 0.57% ok/k at EOC. Cycle 15 reload fuels (Exxon types G-10 and G-3) differ from those used in the Cycle 11 RDA analysis; however, the key nuclear parameters for the 00 fuel types are similar (section 7.2.2oftheCycle15reloadsubm$ttal,ref.23). As a check the staff compared the Cycle 11 RDA predicted fuel performance to that predicted by GE for their 8 x 8 BWR fuel assemblies shown in Figures 3-1 and 3-2 NE00-10527. Several parameters important in the analysis were dissimilar due to different vintage plants and fuel vendors. In both analyses, the fuel enthalpies for rod worths less than 1% was less than 100 cal /gm. Even though the significant parameters differeo in the compared analyses, the predicted fuel response to RDA's involv-ing low worth rods was similar. Based on the low in-sequence Cycle 15 rod worth and the Cycle 11 analysis that adequately predicts RDA fuel response for low rod worths, the staff concludes that, the Cycle 15 l fuel response to the in-sequence RDA is acceptable. i l BRP does not have hardware installed into the system that assists the j operators to keep the proper rod withdrawal sequence.* Therefore, an I
$ out-of-sequence RDA may be more probable at BRP than at other BWR l facilities that have this hardware. The staff requested CPCo to l evaluate the maximum out-of-sequence rod worth and the probability of l an out of-sequence RDA at Big Rock Point during Cycle 15 operation. ,'
O l Calculations performed with the GR0K code predicted a maximum out-of- 1 ( sequence rod worth of 2.03% ok/k at BOC and 1.73% Ak/k at EOC. These I values were reported by CPCo in a submittal dated September 14, 1977
' (ref. 36).
In response to the staff's concerns relating to the Cycle 15 RDA
- probability, CPCo referenced and made slight modifications to an analysis performed in support of a proposed Technical Specification change in 1967, reference 3. The study calculated the probability of each event that must occur for an RDA that would give significant excursions (greater than 280 cal /gm fuel enthalpy). The individual eventprobabilitieswerethe90 combined to give an overall maximum probability of about 4 x 10 per year.
The staff performed in-depth calculations of the probability of RDA's resulting in fuel enthalpies greater than 280 cal /gm while studying
*The Rod Worth Minimizer (RkM) is an off-line computer program that aids the operator in maintaining the established rod sequence but has no direct control function; whereas the Rod Sequence Control
. System (RSCS) is a hardwired system that assures the operator keeps to the established rod sequence.
1
/^\
V the margin of safety that would be afforded by the installation of the RWM or RSCS into the older BWR-2 and -3 class reactors. The study was presented as an attachment to a memo to the Advisory Committee on Reactor Safeguards (ACRS) in June 1976 (ref.12). Although the Big Rock Point facility was not analyzed, the study concluded that the probabilities might well be similar dye to comparable systems. The probability per year of an RDA resulting in Tud enthalghs above 280calfgmcalculatedbythestaffrangesfromabout1x10 to 1 x 10 . Based on these figures, the study concluded that the instal-lation of the RWM or RSCS was not required. The results calculated by CPCo and the staff differ due primarily to the number of control rods moved per startup. The staff's study assumed 10 startups/ year and 200 control rods /startup giving a total number of rod movements (during startups) of 2000 per year. i
', The original CPCo study assumed 1 startup per year and 16 rod move-ments of interest per startup. However, in the September 14, 1977 submittal, the licensee modified the assumptions to 10 startups per year and 40 rod movements of interest per startup. The'40 rod motions per startup was calculated by assuming 20 rods are moved in an approach
- to criticality, and a factor of two was applied to account for multiple
. steps in full withdrawal of any single rod.
D (Q The staff study assumes an average of 178 rods per reactor studied, and 200 rods per reactor.was conservatively assumed for the analysis. To account for the fewer control rods in the BRP reactor, the staff's results were altered and the resulting maximum probability of ag8RDA causing fuel enthalpies greater than 280 cal /gm is about 2 x 10 per e year. Based on the CPCo modified analysis and the staff's independent calcu-1ations, the probability of an out-of-sequence RDA is acceptably low. 2.1.4.3 Main Steam Line Break, Refueling Accident The LOCA aspects of the main steain line break (MSLB) accident are analyzed in the General Electric (GE) and the Exxon ECCS analyses, reference 8 and 9 respectively. These calculations have previously been reviewed and accepted by the staff. The radiological aspects of the MSLB accident are discussed in section 12.5.16.1 of the Final Hazards Summary Report (FHSR). The radiological consequences of a MSLB into the turbine building are less severe than the Maximum Credible Accident (MCA). As above, these results have been previously reviewed and accepted by the staff.
- p. V
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im Refueling Accident CPCo submitted information to the staff on March 21 (V) and June 28,19? Tin response to our January 17, 1977 request for an evaluation of the consequences of a postulated fuel handling accident inside containment. We have not completed our review and evaluation of this information. However, because CPCo, in response to an earlier staff requirement (see the February 6, 1976 safety evaluation of a cask drop accident into the spent fuel storage pool), has installed radiation monitoring circuitry which automatically isolates the containment. We conclude that no additional restrictions on refueling operations inside the containment are needed while our review is underway. After we complete our evaluation of the potential consequences of this postulated accident, we will, if necessary, revise the refueling Technical Specifications to reflect the assumptions of this postulated accident. We will require Technical Specifications which will provide reasonable assurance that the containment isolation system will isolate the containment during a refueling accident. ' Fuel Loading Error 2 1.4.4 . In reference 32 CPCo discussed the worst fuel misloading error for Cycle 15 in their response to staff questions. Eight possible inde-pendent fuel loading error cases were studied, and the resulting
-(ov'
) MCHFR's at 122% overpower were compared. The lowest MCHFR determined the worst fuel loading error. CPCo determined that of the eight cases i i studied, the worst was the interchange of a fresh G-3 bundle (G303) l with an exposed (2nd cycle) M0X type G bt.ndle (G207). With the mis-loaded bundle, the MCHFR at 122% overpower is 2.477; without the error ,
(e.g. all bundles properly loaded), the MCHFR at 122% overpower is ! 2.663. The worst AMCHFR, therefore, for the fuel loading error is 0.186. Since the staff imposed AMCHFR of 0.70 transient allowance is more restrictive (see section 2.1.3.3), the staff concludes that the consequences of the worst case fuel misloading error have been bounded and are therefore acceptable. 2.1.5 Thermal-Hydraulic Stability. Analysis In' reference 32 CPCo addressed the thermal hydraulic stability analyses for BRP in response to staff questions on the Cycle 15 reload. In generci, CPCo reviewed the stability of the reactor as a whole based on analytical calculations and tests. They conclude that the system is stable if operated within the prescribed limits. However, at BRP operation in the natural circulation mode has been allowed. This mode is one of least stability for BRP operations; therefore, CPCo has agreed to discontinue operation with natural circulation flow. 21 - t (
** m se gan= =
a
O Since the stability calculations and tests described in reference 32 l
+k ') were based on SRP fuel in the core at that time and weren't representa-tive of present fuel design, CPCo analyzed the' hydraulic stability of the current Exxon fuels. The results of this analysis, as well as the i analyses performed for the reactor as a whole, showed.that the reactor l core decay ratios are well within the operational design guide decay j ratio. These results are acceptable to the staff.
The staff has expressed generic concerns regarding the least stable reactor condition allowed by Technical Specifications. This condition could be reached during an operational transient from high power where the plant sustains a trip of all recirculation pumps. The concerns are motivated by increasing decay ratios as equilibrium fuel cycles are approached and as fuel designs improve. The staff concerns relate to both the consequences of operating at an ultimate decay ratio and the capacity of analytical methods to accurately predict decay ratios. GE is addressing the-staff concerns through meetings, topical reports and a test program.
- A reactor core stability test program has been carried out at Peach Bottom Unit No. 2 at the end of their Cycle 2. The test program is expected to be a significant aid in the resolution of generic staff concerns on stability. The testing was performed during April 1977, ,
and the results will be provided to the staff by the GE. I
) Based on the restriction of BRP plant operation to other than natural
(./ circulation flow, the analyses presented in support of the Cycle 15 . s reload stability, and the satisfactory operation of the plant during l the previous fourteen cycles with essentially the same core design, I the staff concludes tnat the thermal-hydraulic stability of BRP is acceptable. 2.1.6 Physics Startup Testing The proposed physics startup test program for BRP has been reviewed. The_results of this program will be reported within 90 days after startup. Based on our review, we find the physics startup test pro-gram and reporting schedule.to be acceptable. l l
- 2. 2 Conditions to be Met Prior to Cycle 15 Startup l The Commission's Memorandum and Order, dated May 26, 1976, (reference
- 11) and the Staff issued Amendment 10 (reference 13) specified several i conditions that CPCo was to meet prior to the Cycle 15 startup. Most of these items arose during .he ECCS review prior to the Cycle 14 startup.
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(n) v 2.2.1 Underground ECCS Piping Discussion: The BRP ECC system is shown in Figure 1 of reference 8. A portion of the system piping is buried, 6" diameter, cast iron pipe with limited inspectability and repairability. This part of the system is essential for long term cooling following all LOCA events and is vital'in achieving safe shutdown for many other conditions. The NRC Commissioners stated in paragraph 31, page 17 of their Memor-andum and Order:
" Prior'to return to operation following the refueling outage presently scheduled for Spring 1977, Consumers Power Company shall... i) Modi.fy the fire protection system such that long term cooling can be accomplished without relying on the undergrounc piping."
Evaluation: In a letter to the Commissioners, dated February 4, 19'77, reference 20, the licensee documented completion of the requirement. Fittings were added to the post incident heat exchanger inlet for hook-up of 2-1/2" hose to bypass the underground piping. CPCc , advised that the 275 feet of fire hose would be k.ept in protected racks. CPCo performed flow tests after hose installation to ensure acceptable performance of the core spray portion of the ECCS. The test yielded a (o) v flow rate 21% greater than the minimum flow required for adequate cooling of the core spray heat exchanger. The staff has added surveii-t lance requirements in the Technical Specifications to ensure the fire hose is available for use and is 'kept in good condition. Based on these considerations the staff concludes that the alternate flow-path during long' term cooling following a LOCA is acceptable. 2.2.2 Emergency Diesel Generator / Diesel Driven Fire Pump Trigs Discussion: The Commission's Memoranduin and Order, dated May 26, 1976 directed CPCo to: Modify the emergency diesel generator and diesel driven fire water pump protective trips to bypass the protective trips during accident conditions except for retention of the engine overspeed and generator ' differential current trips, unless additional bypass trips are approved by the Director, Nuclear Reactor Regulation. Evaluation: 'In a letter dated July 26, 1977 CPCo advised of proposed modifications being implemented to the emergency diesel generator. 23 - V I
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,The staff.has-reviewed the modifications to'our currently accepted positions.
Our Branch Technical' Position (BTP) EICSB-17 (Diesel-Generator Protec-tive Trip Circuit Bypasses) specifies that the design of standby diesel generator systems should. retain only the engine overspeed and ,I the generator differential current trips and bypass all other trips under an accident ~ condition. All those trips that are bypassed for an accident condition may be retained for the diesel generator routine tests. This concept will: reduce the probability of spurious trips during accident conditions and will also reduce the exposure of the-
. equipment to damage from malfunctions durirg routine tests. If other .;
L' trips,.in addition to the engine overspeed and generator differential current, are retained for accident conditions, an acceptable design should provide.two or more independent measurements of each of these
' trip parameters. Trip logic should be such that diesel generator trip would require specific coincident logic. ,
1 Based on BTP EICSB 17, CPCo modified the emergency diesel generator l trip circuitry to retain those trips associated with low lube oil , j pressure, high cooling water temperature and generator overcurrent, utilizing two independent sensors and coincident logic, while main-
.taining the engine overspeed trip as designed. No modifications were incorporated or planned for the' diesel driven fire water pump, since the only parameter that will cause a trip is engine overspeed.
(' Based on our review,.the modifications to the emergency diesel generator- , t _\ are acceptable because they: (1) satisfy the criteria of BTP EICS8 17, (2) significantly enhance the reliability of the onsite power system, and (3) comply with Section (3)(iii) of the Memorandum and Order, i dated May 26,.1976. . i 2.2.3 ECCS Indication / Annunciation Circuitry Discussion: The Commission'.s Memorandum and Order, dated May 26, 1976, directed CPCo to: Protect the controls irdication and annuciation circuitry associated with the' ECCS, including the core spray valves, against the consequences of flooding following a LOCA which affects the ' ability of the ECCS to perform properly or the plant operator to
' take corrective action during the course of a LOCA.
i By letter dated May.S, 1977 CPCo summarized the ECCS indication / annuciation circuitry modifications made at BRP. kJ p+ ;,. .. ar
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s Q t / Evaluation: The ECCS indication / actuation functions susceptible to V failure due to flooding from a LOCA are listed below:
- 1. Station service annuciator panel (includes ECC5 indication and j alarms); ,
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- 2. Nuclear steam supply annuciator panel;
- 3. Fire system annuciator panel; j
- 4. Containment isolation valve indication; and l S. Core spray valves control and indication.
Items one through four above have been corrected through the use of selective fusing. The time-current characteristics of the fuses are ! such that the individual load fuses will clear before the supply circuit breakers trip. The newly added fuses are installed in the back of the control panels such that they are easily accessible for inspection. A blown fuse is readily detectable by observing the fuse pin indicator in the extended position. Item five above was corrected for Cycle 14 operation by a procedural change. Within the first one and one-half hours following a LOCA, i A the operator was required to observe the core spray flow indication, j ('j appropriately isolate one core spray line and open the circuit 1 breakers to all four core spray valves. This action assured that !
' the co're spray valves would be properly positioned for long-term cooling before being flooded. This action would no longer be required since during the Cycle 15 fueling outage the valves were relocated to be above the flooding level (see 2.2.6 below).
In addition to the changes required by the Commission Order, the ! staff, by letter dated June 4, 1976, directed CPCo to: (1) install ; and calibrate flow recording instruments for the core nozzle spray i flow and the core ring spray flow; and (2) provide electrical switch-ing circuitry outside of containment to enable connecting either the ring spray flow transmitter or the nozzle spray flow transmitter to either spray line flow instrument channel. The modifications have 1 been completed. The new core spray flow recording instrumentation provides the operator with a continuous recording of core spray flow during a LOCA. The electrical switching provides a means of identify-Ing a failure in either flow recording channel exclusive of the flow transmitter. These changes eliminate electrical single failures which could disable the core spray systems indication and annuciation channels, Thus, the changes substantially increase the reliability of information neces-sary for operator review during a LOCA. The staff considers the p) V requirements of the Commission Ord:r of !1ay 26,1976 and staff cenr- -
)f the June 4,1976 letter tie brui utisf actorily ammd w X.
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l L ( 2.2.4 ECCS Cn-Line Testability Discussion: The Commission's Memorandum and Order, dated May 26, 1976, directed CPCo to: Provide complete on-line testability at the ECCS, including testability of the acutation system. Evaluation: Automatic actuation of the ECCS primary and redundant l core spray systems isolation valves requires a low reactor water level I signal coincident with a low reactor pressure signal. The BRP design had no means.available to test the sensors operability while at power. This was primarily due to the lack of two-valve isolation. protection between the sensors and the nuclear steam supply equipment and due to I the lack of test connections which would allow controlled bleed-off I and test equipment installation. CPCo has not completed piping modifications to the ECCS low water l level and low primary pressure sensors which corrected the deficien-cies noted above. The design now provides the capability for on-line ECCS sensor testing. CPCo proposed Technical Specifications requiring l on-line testability surveillance of the ECCS actuation circuitry.
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The staff has reviewed the modifications to the ECCS which now provide (N complete on-line testability of the system. We conclude that the ( ) modifications are acceptable and comply with the conditions required ' by the Commssion Order of May 26, 1976. s Nuclear Characteristics
2.2.5 Discussion
The staff's review of the Cycle 14 nuclear design is summarized in the staff safety evaluation report for Cycle 14 reload, reference 13. The staff found no serious deficiencies, but considered it desirchie to update all physics information. The staff concluded that prior to startup following the next refueling, CPCo should provide more definite nuclear design information. Evaluation: CPCo provided a description of the Cycle 15 nuclear design in section 5.0 of the Cycle 15 reload submittal. This informa-tion was reviewed and found acceptable in section 2.1.1 above. We conclude that the requirement to provide updated physics character-istics has been satisfactorily completed. 2.2.6 Ring Spray Isolation Valves Location Discussion: The two motor-operated ring spray isolation valves, MOV-705) and 7061, were located inside containment at an elevation of n k y-.
I 586 feet. Since the water level in the containment may rise to the G 586 foot elevation about two hours after a LOCA the valves and valve operators would be flooded. Therefore, the ring spray isolation valves would be considered inoperable. I Since positioning of these valves may be necessary following the LOCA, l CPCo implemented procedures during Cycle 14 operation to assure that the valves were properly positioned prior to two hours after the LOCA. l The staff concluded that reliance on continued prompt operator action ' l was not desirable for long term operation as stated in the staff safety evaluation report for Cycle 14 reload, (ref.13). Thus CPCo agreed to relocate the core ring spray valves above the . flooding level prior to return to power following the 1977 refueling l outage. 1 Evaluation: The two ring spray valves were relocated by CPCo during i the Cycle 15 refueling outage. The valves are now located at the 596 1 foot elevation, significantly above the level which would flood the J valves. Since the maximum water level inside containment following a LOCA is about 586 ft. relucm,Ing the ring spray isolation valves at 596 feet ensures their operability following the LOCA. The staff concludes that this change is acceptable. Q 2.2.7 900# Class Valves Discussion: The NRC staff comments to the Commission dated April 19,
' 1976, entitled " Staff Views Regarding Consumers Power Company Report on Evaluation of Adequacy of ECCS for Big Rock Point," identified a concern regarding the use of 900 lb class valves in the ring spray line. Although the downstream ring spray isolation valve is a 1500 lb. class motor operated gate valve, two 900 lb class valves are located immediately upstream. The staff concluded that a modified overpressure protection analysis of the reactor pressure boundary was required. However, the staff considered the existing safety margins adequate assurance of the integrity of the valves for the period of time required-for CPCo to obtain and for the staff to review the modified analysis.
Evaluation: In a letter dated August 24, 1977 (reference 31) CPCo states that the most limiting overpressurization event for Big Rock Doint is the safety valve sizing event (turbine trip without bypass) as specified in the General Electric Report " Anticipated Transients Without Scram Study for Big Rock Point Power Plant" (NEDE-21065 dated October 1975). This assumed event results in a peak reactor vessel pressure of 1587 psig for approximately three seconds and a transient peak temperature of 604 F. CPCo states that the temperature at the p U r '#
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p l O h valves for the peak. reactor pressure is 140 F. The pressure-tem::eratura ratings for the 900# class valves are 1640 psig at 600 F or 2135 psig I at 140 F. Based on our review, we conclude that these valves can withstand the effects of.the most limiting overpressurization event and therefore are acceptable. , i 2.2.8 Nozzle Spray System Performance Discussion: In'the' Commissioners' Memorandum and Order of May 26, 1976, CPCo (BRP).was granted a one cycle exemption from the single failure requirements of-10 CFR 50, para 50.46 and Appendix K, paragraph I.D.1 for any LOCA followed by.a single failure in the ring spray system. CPCo (BRP) was.also granted a lifetime exemption from the same criterion as' applied to a LOCA caused by a break in either core spray system. These exemptions were granted by the Commission subject to several conditions, some having to be satisfied prior to the cycle 15 startup. In paragraph d3 of the Order, the Commission stated: ,
" Prior to return to operation following the Yefueling outage currently scheduled for Spring 1977, Consumers Power Company shall: ., ,
O (ii) Provide test data showing the adequacy of the nozzle spray system to provide adequate spray distribution during expe::ted
, usage conditions, or modify the nozzle spray system to provide adequate spray distribution."
Evaluation: CPCo stated in a letter to the staff dated January.19, 1977 (ref.'18)', that the nozzles used in the BRP nozzle spray and ring spray systems provide course spray (large_ diameter droplets) and should not be significantly affected by the presence of a steam environ-ment. However, to verify the adequacy of the nozzle spray system, as required by the Commission Order, CPCo conducted a test program to measure experimentally the spray distribution in a steam environment. The. tests showed that the existing single nozzle did not provide adequate spray distribution;'therefore, a new nozzle design was construc-ted and tested. The-results were presented to the staff in a report,
" Big Rock Point Core Spray Test Report, Single Nozzle Test and Develop-
. ment Program," August 1977 (ref. 27).
The' staff has evaluated the performance of the BRP nozzle spray system, as described ~in the CPCo.submittals dated August 1977 (ref. 27) and September 15,-1977 (ref. 37). Based on our evaluation, as discussed in the supplementary Safety Evaluation Report, the staff concludes that the BRP nozzle spray system is acceptable. 28 - s
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! l V 2.3 Deletion of Maximum Allowable Burneo Limit Current Technical Specifications limit the maximum burnup of eacn bundle to 23,500 mwd /T of contained uranium. The burnup limit of 23,500 fMd/T was applicable to the original Cycle 1 fuel, but not to I any subsequent fuel design. In the Cycle 15 reload submittal (ref. 23) ,
CPCo proposed removal of the maximum burnup limit, (MBL) for two main j reasons: i
- 1. The fuel performance during the ECCS calculations (peak cladding temperature (PCT) and MAPLHGR) and at the design E0C calculation ,
(maximum fuel centerline temperature and peak pin pressure) are l acceptable, even with the staff-imposed enhanced fission product release fraction.
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- 2. The offsite dose contributions from nuclides affected by increased fuel burnup are negligible relative to the total maximum credible accident (MCA) doses.
2.3.1 Fuel Performance Aspects The existing MBL of 23,500 mwd /T is below the design burnup of the fuels in the Cycle 15 core. All BRP fuels must meet the performance - requirements of 10 CFR 50, paragraph 50.46 and AppendixAlso, K forthe postu-fuel OV lated LOCA's, at all burnups up to the design burn,up. and clad must be designed in conformance with the staff's Standard Review Plan (SRP), section 4.2. The SRP requires that the cladding and fuel perform within the guidelines contained there in at burnups up s to the design burnup which is in excess of the MBL (23,500 mwd /T). I J In a letter to CPCo deted November 23, 1976 (ref.15) the staff request-ed sensitivity calculations showing the effects of enhanced fission product release rates for exposure above 20,000 mwd /T and up to the design burnup. CPCo was asked to calculate the change 'in PCT and , MAPLHGR's (ECCS calculations) and the maximum pin pressure and peak l fuel centerline temperature (fuel design calculations) using a staff- ' l supplied enhanced fractional release formula. CPCo's response of January 20, 1977, (ref. 19) showed that the E0C peak pin pressure had about doubled (34.0 to 62.0 psig) The but was fuel still average significantly less than system pressure (1350 psig). temperatures had o,nly slightly increased (AT = 42 F). The PCT in thelimitingbreakLOCAincreasedamaximumbb32FfortheG-10 fuel type and less for the other types. Based on these results, CPCo concludes and the staff agrees that the performance of the fuel above the MBL and up to the des /gn burnup is acceptable, even with enhanced fission product release ti rtions. o 4 n s q-
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t O Radiological Ascects V 2.3.2 CPCo performed an analysis of the fission prcduct6inventory change for fuel burnups to a hypothetical maximum of 15 x 10 mwd /T. The analysis showed that radiation dose increases due to increased fission product inventory were insignificant (less than 1% of. total dose). Further, all radioactive nuclides, except Kr-85 and I-129, which are significant in the radiation dose contribution have achieved steady state equilibrium at the lowest fuel burnups. For exposure of four years or less of fuel in BRP, radioactive Kr-85 and I-129 contribute insignificantly (less than a few tenths of one percent) to calculated accidental radiological consequences of design basis accidents relative to the other noble gases and halogens. Hence, the contribution due to these nuclides can be ignored. Therefore, CPCo's proposal to delete existing fuel burnup restrictions is acceptable. 2.4 Ring Spray System Performance l The adequate performance of the ring spray system at BRP was an inherent assumption in the Commission's granting the lifetime exemption discussed in Section 2.2.8 above. However, information recently suomitted to the staff regarding steam effects on spray distribution, including the report on the performance of the BRP nozzle spray system (references O 24 and 27), led the staff to request CPCo to investigate the ring spray
) performance in a steam environment.
' As'a result of scoping calculations that indicated questionable ring sparger performance, and the lack of sufficient test or design data to prove the ring sparger adequacy, CPCo requested an exemption until the 1978 Cycle 16 startup from the failure criterion requirements of I 10 CFR 50.46 and Appendix K as applied to the nozzle spray system.
The exemption requested under the provisions of 10 CFR 50.12 by CPCo I letter dated September 15, 1977, would allow sufficient time for CPCo to complete testing of the ring sparger, system. The staff's evaluation of the exemption request was provided in a separate Safety Evaluation Report. Environmental Consideration We have determined that the amendment does not authorize a change in effluent types of total anounts nor an increase in power level and will not result in any sigaificant environmental impact. Having made this determination, we have further concluded that the amendment involves an action which is insignificant from the standpoint of environmental impact and, pursuant to 10 CFR 951.5(d)(4),that an
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4 environmental impact statement or negative declaration and environ-mental impact appraisal need not be prepared in connection with tne issuance of the amendment. Conclusion .
.We have concluded, based on the considerations discussed above, that:
(1) because the amendment does not involve a significant increase in. the probability or consequences of accidents previously considered and does.not involve a significant decrease in a safety margin, the amena-ment does not involve a significant hazards consideration, (2) there is reasonable assurance that the health.and safety of the public will not be endangered by operation in the proposed manner, and (3) such activities will be conducted in compliance with the Commission's regulations and the issuance of the amendment will not be inimical to the common defense and security or to the health and safety of the ! public, i Date: October 17, 1977 .
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' b< . REFEREllCES
- 1. Transient Analysis, Consumers Power Company, Big _ Rock Point Plant, General i Electric, APED-4093, October 1962. l
- 2. Consumers Power Comoany Application for Reactor Construction Permit and
_0perating License, Amendment 14, Attachment to letter from H. P. Graves, ! CPCo, to Director of Licensing and Regulation, AEC, November 15, 1963. l
- 3. Additional Information Required in Sucoort of Proposed Chance No. 13.
Included as an attachment to a letter.from Robert L. Haueler, CPCo to Director of Reactor Licensing, AEC, dated November 10, 1967.
- 4. GAPEXX: A Comnuter Prooram for Predicting Pellet-to-Cladding Heat Transfer Coefficient, XN-73-66, Exxon Nuclear Company, Inc., August 13, 1973.
- 5. " Decay Energy Release Rates Following Shutdown of Uranium-Fueled Thermal Reactors," ANS-5.1, October 1973.
- 6. Letter from Ralph B. Sewell, CPCo to Orector of Licensing, AEC, dated '
June 20, 1974 (subject: Cycle 11 reload submittal).
- 7. Report Regarding the Exxon Nuclear Company ECCS Non-Jet Pump BWR Fuel Heatuo Model, Of fice of Nuclear Reactor Regulation, NUREG 75/016, March 6 f7 1975.
b 8. " Big Rock Point Plant Loss-of-Coolant Accident Analysic for General Electric Fuel in Conformance with 10 CFR 50, Appendix K," (Non-Jet Pump Boiling Water Reactor) July 11, 1975 (Submitted as Appendix A to a technical specification change request from Consumers Power Company to the NRC, dated July 25, 1975.
- 9. "Heatup Analysis for Exxon Nuclear Company, Inc. G Fuel in the Big Rock Point Piant in Conformance with 10 CFR 50, Appendix K." July 26, 1975 (submitted with letter from Thomas W. Craig (ENC) to NRC, dated July 28, 1975).
- 10. H0XY: A General Muitorid Heatuo Code with 10 CFR 50 Appendix K Heatup Option - User's Manual, XN-CC-33(A), Revision 1, November 14, 1975.
- 11. Memorandum and Order, by the Commissioners, NRC In the Matter of CPCo, Big Rock Point, dated May 26, 1976.
- 12. Generic Item II-42, Control Rod Drop Accidents (BWRs), Bernard C. Rusche, Director.of NRR, NRC to R. Fraley, Executive Director, ACRS, dated June 1, 1976.
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\ 13. ." Safety Evaluation by the Office of Nuclear Reactor Regulation Supporting
. Amendment No. 10 to Facility License No. OPR-6, Consumers Power Company, Big Rock Point Plant, Docket-No. 50-155," dated June 4,1976; (included as enclusure in letter from D. L. Ziemann of the NRC to R. B. Sewell of Consumers Power Ct any, dated June 4, 1976).
- 14. Final Generic Environment-Statement on the Use of Recycle Plutonium in Mixed 0xide Fuel in Light Water Reactors, NUREG-0002, USNRC, August 1976.
- 15. Letter from Dennis L.' 'Ziemann, ORB #2, NRC to Ralph B. Sewell, CPCo, dated November 23, 1976 (subject: required calculations due to enhanced fission product release)/
- 16. Letter from Dennis L. Ziemann, ORB #2, NRC to Ralph B. Sewell, CPCo, dated December 15, 1976 (subject: request for information relative to nozzle and ring spray system),
- 17. Letter from Ralph B. Sewell, CPCo to Director of Licensing, NRC dated December 17, 1976 (subject: proposed Tech Spec MAPLHGR changes for G and G-it! fuels).
- 18. Letter from David A. Bixel, CPCo to Director of NRR, NRC dated January 19, '
1977 (subject: Core Spray Testing).
- 19. Letter from David A. Bixel, CPCo, to the Director of NRR, NRC dated January 20, 1977 (subject: required calculations due to enhanced fission i product release).
- 20. Letter from David A. Bixel CPCo to Samuel J. Chilk, Secretary to the i Commission, NRC dated February 4, 1977 (subject: Fire hose to bypass underground piping portion of ECCS).
Letter .from David A. Bixel, Consumers Power Company to Director of Nuclear Reactor Regulation, NRC dated February 9,1977 (subject: Response to NRC l questions on-MAPLHGR changes). i
- 22. ECCS Analysis for Exxon Nuclear Comoany G-3 All Uranium No Cobalt Fuel for Big Rock Point (including Reanalysis of Reload G and G-lu Designs), l XN-NF-76-55, February 1977.
- 23. Consumers Power Company Request for Change to the Technical Specifications, Attachment to letter from David A. Bixel, CPCo to the Director of NRR, NRC, dated April 15, 1977 (subject: Cycle 15 reload submittal).
- 24. Effects of Steam Environment on BWR Core Spray Distribution, Amendment #3 l to NE00-20566, April 1977.
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O O 25. Letter from David A. Bixel, CPCo to Director of NRR, NRC dated May 5, 1977 (subject: Modification made to ECCS instrumentation).
- 26. Letter from David A. Bixel, CPCo to Samuel J. Chilk, Secretary to the Commission, NRC, dated July 26,1977~(subject: Modification of diesel trips). ,
- 27. Big Rock Point Core Spray Test Report, Single Nozzle Test and Development Program, NUS-3005, NUS Corporation, August 1977 (Incluced as attachment to the letter from W. 5. Skibitsky, CPCo to Samuel J. Chilk, Secretary to the i Commission, NRC,* dated August 9, 1977).
- 28. Letter from W. S. Skibitsky, CPCo to Director of NRR, NRC, dated August 12, 1977 (subject: Change in BRP tech specs relative to ECCS).
- 29. Letter from W. S. Skibitsky, CPC0 to Samuel J. Chilk, Secretary to the Commission,'NRC dated August 12, 1977 (subject: ECCS on-line testability).
- 30. Letter from David A. Bixel, CPCo to Director of NRR, NRC dated August 17, 1977.(subject: Exxon explanation of BRP break spectrum shape).
- 31. Letter from David A. Bixel, CPCo to Director of NRR, NRC dated August 24, 1977 (subject: 900# Class Core Spray Valves).
(> 32. Letter from David A. Bixel, CPCo to Director of NRR, NRC dated August 24, 1977 (subject: Response to NRC request for additional information on Cycle l 15 reload).
- 33. Letter from David A. Bixel, CPCo to Director of NRR, NRC dated August 30, .
1977 (subject: corrections to NUS report, reference 27). l
- 34. Letter from David A. Bixel, CPCo to Director of NRR, NRC dated August 30, 1977 (subject: Cycle 15 core load map).
- 35. Letter from David A. Bixel, CPCo to Director of Nuclear Reactor Regulation, NRR, NRC dated August 31,1977 (subject: Exxon Report on MCHFR and MCPR sensitivity study).
- 36. Letter from David A. Bixel, CPCo to Director of NRR, NRC dated September 14, 1977-(subject: further information for cycle 15 reload).
- 37. Letter from David A. Bixel, CPCo to Director of NRR, NRC, dated September 19, 1977 (subject: adequacy of redundent spray system (nozzle)).
- 38. Letter from David A. Bixel, CPCo to Director of NRR, NRC, dated September 26, 1977 (subject: proposed technical specification on minimum bundle dryout time).
O V 4 l
a UNITED STATES NUCLEAR REGULATORY COMMISSION DOCKET ti0. 50-155 CONSUMERS POWER COMPAtlY NOTICE OF ISSUANCE OF AMENDMENT TO FACILITY OPERATING LICENSE ; 1 The U. S. Nuclear Regulatory Commission (the Conmission) has issued Amendment No.15 to Facility Operating License No. OPR-6, issued to the 'Cohsumers Power Company (the' licensee), which revised i
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the license and Technical Specifications for operation of the Big Rock Point Plant (the facility) located in Charlevoix County, Michigan. The amendment is effective as of its date of issuance. The amendment: , (1) granted an exemption from the emergency core cooling system p (ECCS) failure criterion of 10 CFR Section 50.46, Appendix K, Paragraph I.D.1 as applied to a Loss-of-Coolant Accident
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followed by a concurrent single failu're in the redundant core spray system for the 1978 operating fuel cycle, (2) authorized operation of the facility with additional uranium 235 fuel assemblies identified as Reload G-3 for Cycle 15 as replacement for the spent fuel assemblies, and (3) modified limiting conditions of operation and surveillance requirements based upon the Commission's review of the licensee's applications and based upon the licensee having complied with the requirements of condition III.d of the Commission's Memorandum and Order dated May 26, 1976. O V
4 O The applications for the exemption and amendment comply with the
'Q standards and requirements of the Atomic Energy Act of 1954, as amended (the Act), and the Comissien's rules and regulations. The Comission has made appropriate findings as required by the Act and the Comission's rules ' and regulations in 10 CFR Chapter I, which are set forth in the license amendment. In connection with item (1) above, Notice of Request for Exemption from Requirements Concerning Emergency Core Cooling System Performance was published in the Federal Register for coments on September 26,1977 (42 F.R. 48951). No comments were received on this item. Prior public notice of items (2) and (3) above was not required since these actions do not involve a significant hazards consideration.
The Comission has determined that the issuance of this amendment will not result in any significant environmental impact and that pursuant [] V to,10 CFR 951.5(d)(4) an environmental impact statement or negative declaration and environmental impact appraisal need not be prepared in connection with issuance of this amendment.
.For further details with respect to this action, see (1) the application for exemption dated September 15,1977 (as . supplemented by letter dated October 12,1977),(2) the applications for amendment dated December 17, 1976 (as supplemented by letters dated February 9 and August 17,1977), and April 15,1977 (as supplemented by letters dated April 21, August 12 and 24, and September 26,1977),(3) Amendment No. 15 to License No. DPR-6, (4) the Comission's related Safety Evaluations, and (5) the Comission's Memorandum and Order dated May 26, 19 76~ . All of these items are available for public inspection at the Commission's Public Document Room,1717 H c
Street, N. W., C. and at the Charlevoix Public Libr1ry, Q Washington, D p-
[ - 3-107 Clinton Street, Charlevoix, Michigan 49720. A single copy of items (3) and (4) may be obtained upon request addressed to the U. S. Nuclear Regulatory Commission, Washington, D. C. 20555, Attention: Director, Division of Operating Reactors. Dated at Bethesda, Maryland, this 17th day of October,1977. FOR THE NUCLEAR REGULATORY COMMISSION y i
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Don K. Davis, Acting Chief Operating Reactors Branch #2 Division of Operating Reactors W ., T
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UNITE D STATES { .* 4 - NUCLEAR REGULATORY COMMISSION G 5~_ . WASHINGTON, C. C. 20555
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~ " November.2ff, 1978
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MEMORANDUM FOR: Landon Nichols, Technical Assistant, D0R THRU: D. K. Davis, Chief, Systematic Evaluation Program Branch, D0R FROM: N. R. Anderson, Systematic Evaluation Program Branch, D0R
SUBJECT:
USE OF WASH-1400 IN THE LICENSING PROCESS
REFERENCES:
- 1. Memo, Harold Denton to Division Direccors, dated 10/30/78, "Use of WASH-1400 in the Licensing Process".
- 2. Memo, Victor Stello, Jr. to Branch Chiefs, 00R dated 10/31/78, "Use of WASH-1400 in the Licensing Process".
O) t This memorandum is in response to references 1 and 2 and represents input from the SEP Branch and Operating Reactors Branch #2. All members of both Branches were asked to provide infomation on any licensing actions they were involved in which used or referred tn WASH-1400. I found that there was some duplication and also that some identified actions were being reported by other organizations who had lead responsi- l bility or more direct involvement. ' The following items are believed to be the sum total, often deleting items covered by others. 1
- 1. Big Rock Point Licensing Exemption from ECCS Single Failure Criterion (Category 5) 1 In a Commission Memorandum and Order dated May 26, 1976, Consumers l Power Company was granted an exemption for Big Rock Point (BPP) until ;
(L the refueling outage scheduled for Spring,1977, from the single failure criterion in 10 CFR 50.46 and Appendix X as applied to a loss M of coolant accident followed by a failure in the ring spray system. CPCo was also granted a lifetime exemption from the same single failure criterion as applied to a LOCA cause by a break in either core spray system. U
l 1 , d Landon Nichols November 20, 1978 l l As a condition to the Order, the Commission required CPCo to provide l test data showing that the existing nozzle spray system provides adequate spray distribution during expected LOCA conditions or to , modify the system to provide the required spray flow. This action l was to be complete prior to the Cycle 15 startup. The initial licensing exemption (May 26, 1976) was reported by Robert L. Baer whose memo to Herbert Berkow is attached. A 7: =::::- OaAWL m..i of the limited exemption following fuel Cycle 14 was made which 4 ;e, cff ; al so referenced WASH-1400. The safety assessment attached to Amendment 15 to Big Rock Point justifies monu,c,9 the exemption for o4
= cddi tic-9 fuel cycle. !
l The following statement, extracted from that safety assessment, explains the use of WASH-1400 in the evaluation: l "The staff's decision regarding the requer+ed one-cycle exemption is not based only on the probability assessments or the feedwater system perfonnance appraisal. Rather, 9 these calculations have been used along with an evaluation l [V of other ECCS considerations to reach its decision." l
- 2. San Onofre Limited Time Exemption to ECCS Single Failur'e Criterion I (Category 1)
Page 2.2-8, Section 2.2.5.2 of the SER for Amendment 25 to DPR-13 I states that probability numbers extracted from WASH-1400 were the lC basis for a limited exemption from the ECCS single failure criteria until October 1977. This is a Category 1 usage per reference 1.
- 4. ..dr,,s 5,w i However, thef, single failure criteria has subsequently been corrected I so that consideration of reassessment in view of the Lewis report is '
I not necessary. Amendment 25 is attached. O
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r I Landon Nichols - 3- November 20, 1978 4
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- 3. Task Action Plan.Asr, Revision 1, dated May 1978 (Category 3)
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\ Probabilities of pipe failure from WASH-1400 and used to' support conclusions or continued operation of operating reactors pending sending completion of Task A-12. Arguments are presented on i Pages 3 and 4 of the attached TAP-12 Action Plan.
i I Newton Anderson
. Systematic Evaluation Program Branch Division of Operating Reactors Attachments:
As stated cc w/ attachments: D. Davis a D. Ziemann b
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l % UNITED ST ATES 3N ,0*4 NUCLEAR REGULATORY COMMISSION
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MEMORANDUM FOR: Herbert Berkow, Program Assistant to the Director, Division of Project Management FROM: Robert L. Baer, Chief, Light Water Reactors Branch No. 2, DPM
SUBJECT:
USE OF WASH-1400 IN THE LICENSING PROCESS This memorandum is written in response to Roger Boyd's and Harold Denton's I memoranda of October 30 and November 1,1978 on the same subject. I have been involved in three regulatory actions that have made some use of the results and/or methodology of WASH-1400. These are discussed individually below.
- 1. Big Rock Point (Category 5)
In 1976 Consumers Power Compang (CPCo) requested an exemption from the ECCS single failure criterion of 10 CFR Part 50.46, and Appendix K, Paragraph I.D.l. As one aspect of the staff's review, we requested CPCo to provide estimates of failure O probabilities for the combination of LOCA events and various postulated failures in which the single failure criteria was not fully satisfied by of the design of the big Rock Point Nuclear Power Plant. The staff evaluated the information provided by CPCo and also performed on independent assessment using methodology similar to that employed in WASH-1400. This effort would be designated to be in Category 5 in accordance with Mr. Denton's memorandum. A discussion of the staff's review is contained in Enclosure 1. The specific discussion of probabilistic analyses is presented on pages 3 through 7 of that Enclosure. It should be noted that the staff's recommendation to the Commission regarding
. granting of an exemption to Big Rock Point considered many '
aspects of the issue, not only the probabilistic analyses performed by CPCo and the staff. Enclosure I contains the following paragraph:
"Although the staff has based it recommendation upon technical judgment relating to the perfor-mance capability of the entire ECCS and existing design margins at Big Rock, it has also performed an independent assessment of the reliability of certain systems installed at Big Rock to provide core c.ooling in the event of a LOCA resulting I
p) t V-from a break in one'of the core spray lines. As part of this assessment, the staff estimated the failure probability of the valves in the core 1 i
O Hcrbert Berkow t, , ( spray lines, combined with estimates of spray l line break probability and failure probability } of other portions of plant systems that can provide core cooling. The use of failure estimates was one aspect of the staff assessment used to provide a better understanding of system reliability and plant safety."
- 2. Branch Position on Residual Heat Removal (Category 2)
The results of WASH-1400 showed that transient events were a major contributor to the probability of core melt. For PWR's, transient j events represented a major contributor to the probability of I core melt for release Categories 2 and 7.* In both of these f categories, failure to remove decay heat after successful reactor trip was calculated to be a more probable cause of core melt than failure to trip the reactor. Transient events for BWR's represented the major contribution to i core melt probability for release Categories 1 through 3.** l For Category 2 releases, the probability of core melt as a result (AU j of the failure of decay heat removal systems was calculated to be greater than the probability due to failure to render the reactor suberitical. For Category 1 and 3 releases, WASH-1400 calculated the two probabilities to be within a factor of two of each other. Based on the results discussed above, it appeared to me that the design requirements for systems that remove decay heat in nuclear power plants should be evaluated to determine whether additional requirements should be imposed. A task group was formed and this eventually lead to a position on residual heat remo' val systems that was approved by R t. It should be noted that neither the numerical data or methodology of WASH-1400 was used to develop the position. Rather, the results of WASH-1400 showed a potential need for increased requirements in this area. Of the categories listed in Attachment 1 of Mr. Denton's me..o, Category 2 is the most appropriate.
*There were eight release categories associated with PWR core melt events with l with Category 1 being the most severe.and Category C being the least severe. ]
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**There were four release categories associated with BWR core melt events )
with Categery I being the most severe and Category 4 being the least severe. 1
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- 3. Allowable Outage Times for ECCS Components (Category 2 or 5)
The allowed outage times for compnnents in safety systems are l included in the plant technical spec!fications that are part of l the plants operating license. These have been based largely on i engineering judgment. ; In order to help determine whether reliability and probabilistic l techniques, such as those used in WASH-1400, could be extended to establish allowable outage times on a quantitive basis, two contracts were awarded to Science Applications, Inc. (SAI). The first contract was awarded in February 1975. The first phase of this contract was completed and a final report on this effort issued on August 1975. The second phase of the contract was l completed and a report issued in July 1977. The second contract was awarded in March 1977 and a report was isseed in June 1978. The contracts were limited in scope to investigating the feasi- i bility of extending WASH-1400 techniques to the quantification I of allowable outage times for ECCS components. ~ The first phase of the initial SAI contract addressed the Peach (J Bottom and Surry Nuclear Power Plants which were the two plants analyzed in WASH-1400. The fault trees for safety systems involved in a LOCA, were reviewed for their modeling complete-ness and quantitive adequacy with regard to their 6pplication to allow outage times. As a preliminary basis for these evaluations, conditional systems unavailabilities were calcu-lated in which one component was assumed to be down for servicing. The second phase of this contract extended the application for conditional unavailabilities to a RESAR-3 Pressurized Water Reactor (Trojan). Fault trees were drawn for the LOCA safety systems for the Trojan Nuclear Power Plant and conditional '
. availabilities were again calculated for every major component in the system.
The final SAI contract was an extension of the initial contracts and involved investigating possible ways system unavailabilities could be used.in establishing allowable outage times. Information and data requirements were investigated and theoretical approaches were reviewed for possible specification of values and ranges of allowable outage times. p V
Herbert Berkow -
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1 Th'e only direct use of the results of the SAI studies in the licensing process that I am aware of is report in Enclosure 2. I This memo recommends relatively slight increases in allowable outage times for some _ECCS components and has been implemented in the' standard technical specifications. As noted in this document, the results of the first SAI contract were used as one input that led to slight revisions of the allowable outage times. An equally important input was a survey of the . actual frequency of ECCS outages during the period from about January 1, 1974 to about September 30, 1975. This effort could be placed in either Category 2 or 5. f) /0>r f D he." *3 Robert L. Baer, Chief Light Water Reactors Branch No. 2
,- Division of Project Management
Enclosures:
As Stated T cc w/o enclosures: D. B. Vassallo P. Check / N. Anderson / C. Berlinger T. Novak C. Graves L. Nichols l e
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[ t s Samuel J. Chilk, Secretary of the Commission m 7 STAFF VIENS RECARDING CONSU.'IERS POWER CO.'4PANY REPORT ON EVALUATION OF ADEQUACY OF,ENERGENCY CORE COOLING SYSTE.\1 FOR BIG ROCK POINT - DOCKET NO. S0-155 Transmitted herewith for submission to the Commission are " Comments by the Director, Nuc car Reactor Regulation Itclating to the Request for lixemption of the Big llock Point Nucicar Pov;cr Plant from the Itcquirer.cnts of 10 CPR Section 50.46." These cor=ents are provided in response to the Commi'ssion's " Notice of Request for Exemption from Requirements Concerning Emergency Core Cooling System l'orformance" dated April 5, 1976.
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;) L v E ..c c.<.c L Ben C. Rusche, Director '
Office of Nucicar Reactor Regulation
Enclosure:
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UNITED STATES OF AMERICA 6 NUCLEAR REGULATORY COMMISSION -- gy p g ,; r i i , . . . . ,;,.y l
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In the Matter of 8"""
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) D y NTL C0t!SUt1ERS POUER C0!!PANY ) Docke t No. 50-15 l
) l (Big Rock Point Huclear Power Plant) l C0!E!ENTS BY THE DIRECTOR, NUCLEAR-REACTOR REGULATIO'.! nELATING TO Tile REOUEST FOR EXE!!PTIO.'1 0F TilC BIG POCF. POINT NI' CLEAR POLT.!: PLA"T FRO:t ,
Tile: REQllIltEtISi!TS OF 10 CFR SECTIO:1 50.46 l l 4 On, December 31, 1975, the Commission granted two linited excoptions from ; the Commission's ECCS Acceptanco Criteria in 10 CFR Part 50, 50.46 and Appendix K., e to Comsumers Power Company-(CPCo) for its Big Rock Point Huc1 car Power Plant, subject to certain specified conditions. The first exemption. permitted reactor operation until March 1,1976,' pending completion of the installation of the Reactor Depressurization System. The second exc,ption allowd Connuaces Pouer Company (CPCo) until March 1,1976 to provide more information supporting its request. for an exemption from the ECCS singic-failure criterion of 10 CFR Part l 50.46 and Appendix K, Paragraph I.D.1, as applied to a loss-of-coolant accident (LOCA) caused by a break in a core spray line and a concurrent singic failure in the remainhsg co're spray system. In addition, the Commission requested additional staff comments concerning a possible further exemption from the Comnission's ECCS l single-failure criterion. l The staff comments submitted on January 7,.1976, by the Director of Nucicar 1 Reactor . Regulation, outlined - certain additional analyses that should be performed il O . by CPCo and possible system modifications to enhance operating reliability.
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i V - On February 27, 1976, in response to opportunity provided by Commis-
- i sion Memorandum and Order of December 31, 1975, CPCo submitted f urther !
l information to support its exemption request in a report entitled " Report on Evaluation of Adequacy of Emergency Core Cooling System" and requested i further consideration of its life-time exemption request. The Commission
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published notice of this additional exemption request in the Federal Register and provided an opportunity for public comment (41 F.R. 10969, March 5, 1976). Af ter obtaining additional information from CPCo, on
!! arch 26,19 76, the Director of Nuc1 car Reactor Regulation submitted certain additional staff comments on the pending exemption request and j requested an extension of time until April 19, 1976, in which to complete s
the review of all ECCS related issues for Big Rock Point.(1) The Commission granted this request on April 51976. CPCo's original request for exemption from the singic failure require-monts of 10 CFR Part 50, Appendix K, Paragraph I.D.1, identified the case of a core spray line break and the failure of a valve in the redundant core; spray system as the specific instance of nonconformance with singic failure requirements. Further analysis carried out by CPCo (1) " Additional Comments by the Director, Huclear Reactor Regulation and Request for Extension of Time for Staff to Respond to the Request for Exemption of the Big Rock Point Nuclear Power
,_ Plant From the Requirements of 10 CFR Section 50.46"
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U - 3 . pursuant to the Commission's December 31, 1975 Memorandum and Order identified additional equipannt which would not conform to the single failure criterion in the case of a core spray line break. During the course of the staff's review of the Big Rock facility, the staf f ' identified additional aspects of ECCS perfornance which required further evaluation. These items were identified in the staff's liarch 26, 1976 Additional Comments. Further, in the course of providing more information CPCo has very recently (on April 15,1976) identified areas which have required additional staff evaluation of the ECCS ['~' performance capability for the Big Rock facility.
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The various ECCS related issues are as follows:
- 1. CPCo's Exemption Request Relatin?, to Single Failures of Core Spray Valves As noted in the Staf f's !! arch 26, 1976 Additional Comments, CPCo's cctimates of the failure probabilitics for the combination of events resulting in a core spray line break and a failure of the other core spray system, were approximately 2 x 10
-0 por year for a break in the
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nozzle spray line and 4 x 10 per year when the break is in the ring spray line. t Although the staff _ has based its recommendation upon technical j udgenents I belating to;the performance capability of the entire ECCS and existing
/'~') design margins at Big Rock, it has also performed an independent assess-acnt of the reliability of certain systems installed at Big Rock to
, provide core cooling in the event of a LOCA resulting from a break in i
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one of the core spray lines. As part of this assessment, the staff estimated the failure probability of the valves in the core spray lines, combined with estimates of spray line break probability and failure probability of other portionc of plant systems that can provide core coaling. The use of failure estimates was one aspect of the staff assessment used to provide a better undecstanding of system reliability and plant safety. Staff failure probability estimates are generally higher than those used by CPCo. These higher values give more appropriate s consideration to service conditions, to test and- maintenance
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programs, and to operating experience at Big Rock. For pipe breaks in the nozzic spray line the ~ staff has used the value of i 9 x 10-5 por year. For a break in the ring core spray line, the l failure probability used is 10-3 por year. This higher value I reflects the existence of four uninspectabic welds in this system. l In the event of a break in one core spray line, wate'r can be supplied to the core through the other core spray line. Since each of the redundant core spray lines (the ring spray and nozzle spray) has two actuating valves in series' , the singic failure of one of these valves would render the system inoperative.
' The failure probability in the core ring spray system is approxi-
's ; mately 0.02 per demand with the CPCo proposed annual testing of the
- valves . JThe valves in the ring spray system are powered from the de -
station battery bus. The valves in the nozzle spray system are not o- -
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ccnnected to the station battery. They are poucred from the emergency dicsc1 generator or by off-site power. The f ailure probability of
, these valves is also about 0.02 per demand since the failure proba-bility is dominated by valve failure when of f site power is considered.
Using these values, the probability for a nozzle spray line break and failure 'of a valve in the ring spray system is about 2 x 10 per year (with annual testing). The probability for a ring spray line break and a failure of a vpve in the nozzio spray system is about
-5 7 x 10 per year if off-site p wer is assumed unavailabic and about
, 2 xl10 -5 per year with off-site power availability (all with annual k,
te s t ing) '. More frequent testing or other enhanced surycillance, would increase reliability. Independent of the core spray systems, adequate cooling capacity is availabic for core spray breaks by use of the feedwater system. I The supply of water to the foodwater system, when used for this purpose,' is the stored condensato.
- This supply is supplemented by a six inch if,ne from the fire protection system. The feodwater system, in conjunction with adequate water sources, can provide cooling for an extended period until the containment core spray recirculation system i
is- placed in operation to cool thc core. The feedwater system i is powered by'the offsite power systems. As discussed in item 6, offsite power has a high reliability and therefore the failure ( 4 , probability for the feedwater system is dominated by necessary operator actions and the operability of the valves which must function to provide a _ _ _ _ ~ . _ . _ _ _ _ . _ _ _ _ _ _ _ _ _ . _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . _ _ _ _ _ _ _ _ _ ._ _ _ _ _ _ _ . _ . _ _ _ _ _ _ _ _ _ _ . _ _ _ _ _ _ .
( l . (<- g . water source to the feedwater system. Since neither the staff nor CPCo has explicity evaluated the perfonnance of this system, , it is not clear what failure probabilitics can be assigned to this course of events. However, since this system is used during normal operation, its failure probability for tuo short period of time it would be required is believed to be small. However, it is clear that this alternative source of cooling water supply in the event of a spray line break enhances overall ECCS reliability so that failure to provido adequate cooling to the core as a result of a break in one core spray line and a single f ailure in the other spray system. is acceptab1v low. Accordingly, the staf f believes that the requested lifetime axcmp-tion from the singic-failure requirements of the Comnission's ECCS Acceptance Criteria in 10 CFR Part 50, 50.46 and Appendix K, Paragraph I.D.1 for the case of a pipe break in one spray line 6 system, should be granted. For other reasons which are discussed in the items below, the execptions should be conditioned. 2 For example, the staff evaluation discussed above is based on adequate spray perfossance by the spray nozzle. However, as discussed in item 5, recent information has raised some question as to the adequacy of. nozzle spray performance. For this reason, the i U l t >}:
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4 c) exemption requested by CPCo should be conditioned as set forth in item 5. Other conditions which should be imposed as part of the exenptions, are set forth in cach appropriate item and the conclusion. These conditions set fo rth certain requircaents which must be met prior to the return of Big Rock to power operacion and other requirencnts which nust be mot prior to its return to operation af ter the refueling shutdown presently scheduled for the Spring of 1977.
- 2. Use of 900 lb Class Valves in the Ring Spray Line As discussed in the staff's !! arch 26, 1976 Additional Comnents, two valves in the ring spray system are 900 lb class valves. Since the pressure which these valves can withstand is related to service temperatures, the staff investigated the adequacy of these valves to withstand the expected normn1 operating pressure of the reactor coolant system of 1335 psig at 600 F. Our review has verified that these valves, the core spray valve (MOV-7051) and check valvo (CV-7) have an allowable pressure-temperature of 1640 psig at 600 F. Since 1640 psig is 300 psi above the reactor coolant system normal operating pressure of 1335 pais, we have concluded that an adequate safety margin is availabic relative to CPCo's ECCS exemption analysis. Existing safety margins provide adequate O assurance of the integrity of these valves for the period of time
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required for CPCo to obtain and for the staff to revicu the-
r modified overpressure protection analysis of the reactor pressure boundary to consider the lower operating pressure rating of the valves. CPCo has agreed to furnish this information within six months. No Commission action relating to CPCo's ECCS ; exemption request is required for resolution of this matter.
- 3. ECCS tlater Supply System The staff has reviewed the potential for both active and passive :
failure of the fire protection system, which for Big Rock Point is a vital portion of the ECCS, as well as other safety systems, used for dissipation of heat from the core. The active portions of the fire protection systec. are either redundant or are adequately : 1 protected against singic f ailurcs. Passive piping failures have been considered for both the short term cooling requirements associated with injecting water into the core and for long term cooling, requirements for removing core decay heat. For short term cooling requirements, up to 24 hours follouing a LOCA, the probability of both a LOCA and an unrelated passive failure of the piping in the fire protection system during this limited period of time is sufficiently lou to be acceptable. An important factor in p reaching this conclusion is the short period of time during which the fire water system is required to operate.
l Thie situation for long term core cooling is quite different. As the
. plant is currently designed, the fire protection system is needed for !
l an indefinite period during the long term cooling mode to provido l cooling water for the containment heat removal heat exchanger. Since this cooling water is needed almost continuously, the resultant failure probability can be related directly to t.he failuro probability of the fire system piping. That failure probability of l that piping .alone has an upper bound value of 2.6 x 10-3 per year i
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I and a median value of 9 x.10-5 per year. Because of the limited inspectability due to the inaccessability of the underground piping of the fire protection system, the staf f believes that its evaluation should be based on the upper bound value. Since this system is an essential component of the ECCS system cooling water supply for long term cooling for all LOCA events, not solely those involving a coro spray line break, and the system is vital in achieving safo shutdown for many other conditions, the staff believes that this annual failure proba-bility is not neceptabic for a period covering the ronnining life
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N of the plant. !!ovever, for a period of another fuel cycle, sono 12 to 16 months, the probability of a LOCA or other event requiring the fire protection system and concurrent failure of the fire protection system is sufficiently low to permit operation with the current design. Wilile assessment of the adequacy of the fire protection system as part of the ECCS is not limited to the case of single failure events involving the requested exemption, the staff believes that fire system reliability has a vital hearing on the overall safety of the plant. This in turn is of primary importance in assessing the effect of deviations from the Comnission's ECCS performanco require-ments.
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, Consequently, the staff recommends that granting of the cxemption requested by CPCo be conditioned to require, prior to startup following the refueling outage scheduled for Spring 1977, modification of the facility such that long term cooling can be accomplished without relying on the underground portion of the fire protection system.
- 4. ECCS Performance Evaluation Model With respect to other aspects of the ECCS performance evaluations submitted by CPCo for Big Rock Point, the staff review has uncovered no y other outstanding issues and no issues relating to the subject matter
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of CPCo's requested exemptions other than those discussed in these Staff Comments. Consequently, no Commission action is required with respect to other aspects of the ECCS performancc cvaluations for Big Rock Point.
- 5. Effectiveness of Nozzle Core Spray The single overhead spray nozzle in the nozzle spray system at Big Rock Point' is a Spraying System's Company "Distribojet," Catalog No. 4R80160. It is a one piece cast type nozzle with non-removable internal vancs. The nozzle, 5" in diameter by 8 1/8" high, is to distributes cooling water to all the fuci bundles in the core should the core becoue uncovered. The spray characteristics are described by the manufacturer as "Large capacity, f ull flow deluge type sprays.
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Nozzles designed to pass a large liquid volume in a full cono pattern." Heither the General Electric Company (GE) nor its overseas partners have tested the spray distribution of this type nozzle under expected usage conditions. However, GE has tested a Type VNC nozzle without a deflector which is somewhat similar in configuration although of much smaller diameter (1 inch) . Reported test data show that such a nozzic "cxhibits a spray width reduction of approximately 50% when spraying into atmospheric proosure saturated steam." Such conditions (atmosphere pressure and saturated secam) are typical of those under ( which the nozzio spray system is required to operato at Big Rock. Thus, a width reduction of this magnitude at Big Rock Point would result in incomplete core spray coverago. Imcomplete core spray coverage could af fect the ability of the nozzle spray system to adequately cool the core should it become uncovered. Without representative tests on an, identical nozzic_ confirming full core spray coverage under expected usage conditions, there is inadequate assurance that the core spray nozzle system would cool the core. GE agrees that a test on the 4R80160 nozzle'in a steam environment would be desirable. However, the GE test facility does not have a sufficiently large steam supply to perform such a test. GE is surveying other domestic and foreign companies in an attempt to find an adequate test. f- s facility. L i.
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The spray nozzle is a vital element for adequate ECCS performance. For a large number of the potencial LOCA break sizes and locations, the core could be uncovered. Cooling is provided in these cases by spray cooling, ' from either the core ring spray system or the core nozzle spray system which ucro each designed to provido adequate spray cooling for the entire core, thus providing redundant spray capacity. For a break in the core - ring spray system, the staff believes the core can be reflooded by the incomint feedwater system and by the water from the nozzle. Consequently, in this case, even though the spray nozzle distribution alonc may not be sufficient to provide adequato core cooling, the combination of flooding from the V' fecdwater system and spray from the nozzle spray system nay be suf ficient to adequately cool the core. However, a specific evaluation has not yet been performed to rcrify the adequacy of feedwater system reflood capability. For breaks at locations for which reflooding of the core is not possible, the ability to provide adequate core cooling depends on the reliability of the core, ring spray system if the nozzic spray system does not perform as designed. Specifically, the reliability of the valves in l the core ring spray system becomo limiting in terms of LOCA protection for such breaks. While the reliability of the core spray lino valves is' sufficient in' the case where both spray systems cach provido .adequato spray ec: ling, as designed, we do not believe the reliability of the l core, ring spray valves is presently sufficient in the event that only the l ring spray system provides adequato cooling. I I l l i _ _ . . _ . _ . - _ _ _ . _, , . - . _ - , m.. _. _, ,. ,, , _..
k Augmented surycillance of the core ring spray valves can enhance reliability suf ficiently for a linited period of operation such as l the next refueling period. Ilowever, for the longterm operation the staf f believes that redundant spray cooling systems should be provided to protect against failures in the.in-core spray cooling sparger. For the foregoing reasons, unicas the adequacy of the nozzle spray distribution has been demonstrated, the staf f recommends that the excmption be granted for the Big Rock ECCS system only on the follow-ing conditions: G 1. Ucfore return to operation, CPCo shall provide the staff with an analysis of ECCS performance which properly denonstrates that in the event of break in a core ring spray line, the feedwater system and the flow through the core spray nozzle will reliably provide suf ficient cooling water to the core so that the peak clad temperature does not execed the Commission's Acceptance Criteria set forth in 10 C FR >50. 46.
- 2. Before return to opetation, provision will be made for enhanced reliability of the core ring spray system by augmented surveillance of the valves and valvo actuating circuits, or by other modifications or procedural changes which provide reasonabic assurance that the
,O core ring spray system can, by itself, provide reliable and adequate core cooling in the event of a LOCA at a location where reflooding does not provide adequate core cooling.
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- 3. Modify the nozzle spray system to provide adequate spray distribution, prior to return to operation af ter the 4
refueling shutdown presently scheduled for the Spring of 1977.
- 6. Electric Power Supply The Fire Protection Sys tem has redundant pumps availabic to
, provide short term core cooling. One -pump is an elecric driven.
pump powered from offsite pmeer or from the onsite emergency diesel generation; the other pump is driven directly by a i separate diesel engine. Ilowever, for long term cooling, in addition to the proper operation of the fire protection system, operation of c]cetrically driven recirculation water pumps is required to supply water to the core and remove heat f rom the , cont ainment. Several older plants such as Big Rock Point vero constructed with redundant offsite power circuits but only one onsite emergency diesel. Consequently, a single failure of the only emergency diesel generdtor would leave the station without
.. onsite power for long-term or recirculation mode core cooling.
Such cooling is required within 24 hours af ter the LOCA. CPCo has advised the staff that a suitable portable diesel generator could be obtained and made operable within the required time interval. D
Without reliance on of fsite power supplies , the singic failure of the onsite diesel benerator adversely affects the performance of the ECCS system. This circumstance also deviates from the Commission's ECCS performance requirements in 10 CFR Part 50, 50.46 and Appendix K. CPCo indicates that an exemption for the failure of the diesel generator is encompassed within their pending request which applies to all single failure in onc core spray system which do not conform to ECCS perf romance 1 requirements in the event of a break in the ot:ter spray system. ! 1 Although singic failures in the dicsc1 generator, in the absence of offaite power, can adversely affect systems performance for a number of events, the staff agrees that this single failure is encompassed in CPCo's pending request. To aid in reaching the staff recommendation in this area, it investi8ated the reliability of the existing offsite and onsite power sys tems. The offsite system consists of two of fs tte power circuits originating at the same substation. 'Ihese circuits share the same right-of-way from the substation to a point about a mile from the plant where the circuits separate and enter the plant on separate rights-of-way. Generally, two types of events can' cause loss of offsito power, trips of the plant due to internal causes and external events such as ice storms. The staff has assessed the offsite power unavailability res"Iting h-v from plant trip to be 1 x 10 -3 per event. This appears
a I l I conservative in view of the relatively small size of this plant (70 WMc) compared with' the system capacity. In addition, operating experience confirms that the unavailability is small since none of the 11 plant trips from above 25 Mit have resulted in loss of offsite power. The plant has experienced one complete loss of offsite power in eight yours. This was due te severe ucather conditions. Therefore, based on this experience, the unavailability of offsite power due to causes external to the plant is equal to 1/8 year or about 0.125 per year (this is consistant w!.th the WASH 1400 ? . Repo rt) . l'
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Offsite power is required as a redundant ECCS power source for the
' LOCA resulting from a break in the spray ring line only for l the. time required to open the nozzio spray valves , i.e. , probably less than a minute..
i Thus, assuming a time fraction of six hours for availability of offsite power is conservative. For this time period, the unavaila-bility of offsite.pover reduces to: 0.125. X 6 hours = 8.6 X 10 -5 year 8760 hours / year Thus, the controlling or larger of the two offsite power unavailabilitics immediately follwoing a LOCA is that' associated with a plant trip, i.e., x 10~3 per event and not that assc,eiated with external ~ events. This is ! the yklue used in the staff's independent reliab'ility analysis described in item 1. l l
A In reviewing the existing onsite power system, the staff observed that some of the emergency dicsci generator protective trips are set to shut down the unit, even in an emergency, for conditions which may result in economic loss but would not of themselven cause a loss of power. Since such trips could significantly reduce the avail- l ability of the diesel generator during a LOCA removal or reviston of I these trips would significantly enhance the reliability of the onsite power system. Based on the high availability of offsite power and the conditions which are noted below for the onsite power system, the staff believes that , the probability of a LOCA at this facility coincident with a sustained loss of of fsite power is sufficiently low to be acceptable for long torn l core and the exemption should be granted subject to the following conditions: 1
- 1. Prior to plant startup from the current refuellug outage CPCo i modify the emergency procedures (a) to assure that in the un-likely event of a LOCA a second dedicated emergency diesel .(
generator can and will be obtained expeditiously as a backup to the existing plant diesel generator can and will be obtained , expeditiopsly as a backup to the existing plant die =e1 u nerator l and-(b) required that such dedicated emergency dicsc1 generator ! must be fully operational at Big Rock Point within 24 hours after the LOCA.
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- 2. Before return to power after the refueling scheduled for Spring 1977 CPCo provide modifications to the emergency diesel generator protective power circuitry to allow bypassing protective trips during the demand for emergency power except for the retention j of'the engine overspeed and the generator differential trips, or ]
( as an acceptable alternate CPCo may make modifications to provida ( at_least two independent measurements for any other protective ; ( trips considered necessary by CPCo. Trip logic for any other protective trips retained would require specific coincidence logic. Similar design changes should also be made to improve the reliability of the diesc1 driven fire pump.
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- 7. Other Electrical Failures The staf f has continued its review of the electrical singic failures identified by CPCo in its February 27, 1976 submittal and in the staf f comments dated !! arch 26, 1976. Additionally, we have reviewed the CPCo comments of !Mrch 26, 1976, relating to other staff identified cicctrieni singic failurcs and cicctrical system operational concerns.
CPCo has initiated action to correct all cicctrical singic failurec which would have a direct consequence during a LOCA except those discussed in item 1 above. This includes reconnection of the Emergency Diesci Concrator starting circuit from the station battery to an
,< n t ) independent uninterruptabic power source thus making these two CCCS V
power cources truly independent. CPCo'o actions will rectify the identified cicctrical singic failures prior to return to operation. CPCo has also identified other cicctrical singic failurcs which do not directly affect ECCS actuation but which could disahic indication and annunciation channels required for, accident and post-accident monitoring. Although these channels do not result in a failure of automatic controls, the indication and annunciation functions are of importance to the operator in monitoring conditions in the facilicy in the event of an accident. For this reason, the staff has informed CPCo that those failures must be corrected prior to return to power from the next' refueling outage scheduled for the Spring of 1977. ,A,
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N No action is required by the Comnission on those items in connection with the pending exemptions request.
- 8. Surveillance Testability of ECCS The present design does not provide on-line ECCS actuation systen testab ility. The staff has concluded that complete ECCS testability is necessary to substantiate the reliability analysis dcoc ribed in item 1 above. Therefore, the grant of the requested exenprion should be conditioned to require:
- 1. Prior to startup, modifications or procedural changes, acceptabic to the staff, should be made to augment surveillance of ECCS availability including tt.c ECCS actuation system, and the Technical
- Specifications shall be revised to require such surveillance.
- 2. Prior to return to operation after the next refueling outano scheduled for Spring 1977, modifications shall be made to the ECCS system to provide complete on-line testablity of the ECCS including the actuation system.
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- 9. Submerged Components Affecting ECCS There has been a series of correspondence between CPCo and the staff on the subject of potentially flooded CCCS equipment l
without any recent indication by CPCo that f urther problems exist.U ) { l I _______________________ ,__________________________________________ l l
- 1. In a letter dated April 1,1975, the staff required the submis-sion of the results of ECC instrument tests and analyses. On !!ay 2, 1975, CPCo submitted Special Report 20.21 in response to that letter.
Item III D of that report addressed the of fcets of containment
~O flooding due to LOCA on the core spray systen notor-operated volves.
No mention was made of other possibic safety consequences of such flooding. On Ifarch 17, 1976, the staff specifically requested identification of all electrical equipment that might be submerged as a result of a LOCA. On March 26, 1976, CPCo responded that " Submerged ECCS equipment was identified and corrective actions taken as appropriate during the five-month. plant shutdoun in 1975." In that letter, CPCo also identified a 125 Vdc motor control center l'25 Vdc distribution bus and a 480 Vac bus, all of which were stated to have adequate tripping devices for the loads that could be submered such that the center and the two buses would not be lost (~- . duc to a fault on subocrged circuits. We found this to be acceptable.
4 j 22 - l However, the staff was informed only recently in the course of its review of CPCo's exception request of the existence of additional control, indication and annunciation featurcs, at least some of which are ECCS related, that can be lost due to containment flooding. On April 15, 1976, representatives of CPCo orally informed the staff that the following five additional functions or panels could bc loot due to containment flooding.
- 1. Station Servico Annunciator Panci O 2. Nucicar Gtcas Supply Annunciator Panci
- 3. Fire System Annunciator Panci
- 4. Containment Isolation Valve Indication
- 5. Core spray valves control and indication l
The fifth item affcces the controls for the valves discussed in item 1 above and must be rectified prior to return to operation. j l l I i
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. I Similarly, all other items which would adversely affect the control of the ECCS system must be rectified prior to return to operation.
For those items which affcet only indication and annunciation, but provide the only intelligence to the plant operator needed to take appropriato corrective actiona during the course of a LOCA, rectification also must be nado prior to the .rcturn to power. For this reason, the granting of the requested exemption should be conditioned to require the following prior to return to operation:
- 1. The core spray valves control and indication circuitry must bc D
b) + protected against the consequences of flooding as a result of a LOCA, during the entire courco of events for which they may be required to function.
- 2. All other CCCS control circuits which may be required to f unction must be protected against the consequences of flooding as a result of a LOCA during the entire course of events.
- 3. All ECCS indication and annunciation circuits the failure of which could adversely affect the ability of the plant operator to take corrective action during the course of a LOCA, as determined by the staff, shall be protected against the consequences of flooding as a result of a LOCA, during the entire course of events.=
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- 4. Resolution of the foregoing itens shall be proponed by CPCo and approved by tho staf f prior to power operation of the Big Rock facility.
Conclusion In connection with its assessment of the exemption requested by CPCo from the Commission ECCS performance requirements set forth in 10 CFR Part 50, 550.46 and Appendix K, the staff has carefully assessed the capability of the entire ECCS installed at Big Rock Point to provide adequate cooling water to protect the core in the event of a LOCA. V As discussed in items 1 through 9 above, this evaluation has used certain failure probability e< nates as a valuable tool to aid in understanding I certain aspects of system performance. These estimates, when coupled with our overall assessment of additional protection afforded by multiple backup systems, and the margins provided by conservative analytical techniques, assumptions and performan.ce requirements provide reasonable assurance that the ECCS will perform adequately as discussed above. In response to the Commissioners Memorandum and Order of October 31, 1975, CPCo has estimated in its October 27, 1976 submittal the various costs involved in modifying the facility for full compliance with the single failure requirements of 10 CFR 50.46. These estimates appear reasonable. I Since~the staff concludes.that the present system, under the conditions I set forth herein, provides a high degree of safety, we believe that there 1 is ' good . cause to warrant the exemption requested. s l
25 - s ' Accordingly, the staff concludes that in accordance with 10 CFR 50.46 the Commission should grant an exemption from the singic failure require-ments of 10 CFR Part 50 550.46 and Appendix K, Paragraph I.D.1 as applied to a LOCA caused by a break in a core spray line and a concurrent single failure in the remaining core spray system including the failure of the onsite diesel generator subject to the following conditions:
- 1. Prior to return >peration, CPCo shall:
a) Provide an 4tysis of the ECCI performance which properly l demonstrates taat in the event of a break in core ring spray I line, the feedwater system and the flow through the core spray nozzle will reliably provide sufficient core cooling water unless adequate spray discribution of the nozzle has been - d*nonstrated.
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b) Enhance the reliability of the core ring spray system by augmented surveill,9cc to provide reasonable assurance that the core ring spray sy.c em can, by itself, provide reliabic and adequate core coolite or a LOCA not allowing reflooding unless adequate spr. distribution of the nozzle has been demonstrated. . c) ModiC, the emergency procedures to assure a second emer,e- e diesel will be obtained and operational within 24 hours a. . a LOCA. d) Augment the surveillance of ECCS to enhance its reliabi a method acceptable to the staff. e) Protect the controls, indication and annunciation circuf associated with the ECCS, including the core spray valves, as approved by the staff, against the consequences of floca. following a LOCA which affect the ability of the ECCS or p1s I operator to take corrective action during the course of a LOCA. J 4 5
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- 2. - Prior to return to operation following the refueling outage cutrent.ly I scheduled forL Spring 1977, CPCo shall: ,
a). Modify the fire protection system such that long term cooling can
. be accomplished without relying on .)ortions of its miderground piping.-
b) Provide test data showing the adequacy of the nozzle spray , distribution during expecteel ur.nga conditions or nodify the nozzic spray system to provide r.dequate spray dir.tribution. c) Modify the.' emergency dienel generator and diese) driven fire pump to bypass protective trips during. accident conditionn ; except for retention of engine overnpced and generntor differential i trips unlecs additional trips are approve.d by the ntaff. d) . Provide complete on-line testability of the ECCS including "the actuation ayuten. ,. .
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T g .- /,p" I ,,u % c L.. l.. . - t. % . lien C. Rusche; 'frector
- Office of 1:ue] ear Reactor Regulation
- Dated at Bethesda, Maryland,.
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UNITE 3 5TATES
. EAR REGULATORY COMMISSION
[~ ) E y%;;S WASHINGTON, D. C. 20556 6 C a~ m
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)l Docket No. 50-206 April 1,1977 -/.
!41 Southern California Edison Company ,
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ATTN: Mr. Jack B. Moore N Vice President 2244 Walnut Grove Avenue Post Office Box 800 j Rosemead, California 91770 Gentlemen: , i The Commission has issued the enclosed Amendment No. 25 to Povisional Operating License No. OPR-13 for the San Onofre Nuclear Generating Station, Unit 1 (50-1). The amendment consists of changes to the Technical Specifications in response to your requests dated June 15, 1976 (Proposed Change llo. 46), September 23,1976 (Proposed Change i No. 50) and January 18,1977 (Proposed Change No. 55). The amendment incorporates provisions in the Technical Soecifications, required for operation of S0-1 with the refueled Cycle VI Core, with the new onsite emergency power system, with the modified ECCS features, and with the new sphere enclosure and associated modifications in conjunction with a reduced 50-1 exclusion area boundary. Based on the detemination-discussed in the , enclosed Safety Evaluation, an exemption to the single failure requirement in 10 CFR Part 50, Appendix A, General Design Criterion 35 is hereby granted for 50-1 pursuant to 10 CFR Part 50, Section 50.12 and operation uhrtt October 1,1977 witnout a backup &ir supply for the pneumatic flow % control valves FCV-lll50, E & F is hereby authorized. The amendment also adds a license condition which requires the steam generator to be reinspected within 12 months from the date of the amendment. Copies of the Safety Evaluation and the Federal Register kotice are also enclosed.
- Sincerely,
$ We %
Victor Stello, Jr., Director Division of Operating Reactors Office of Nuclear Reactor Regulation J
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Enclosures:
See next page. e-
Southern California Edison Company April 1,1977 .
Enclosures:
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- 1. Amendment No. 25 to OPR-13
- 2. Safety Evaluation
- 3. Federal Register Notice cc w/ enclosures:
See next page I O 1 - O
authern California t.wison Company -3e April 1,1977' *
, 4 cc: Rollin E. Woodbury, Vice President O and General Counsel Southern California Edison Company Post Office Box 800 Rosemead, California 91770 , , .
Chickering a f. . egory, General Counsel ATTN: C. Has en Ames Esquire San Diego Gas and Electric Company 111 Sutter Street San' Francisco, California 94104 Mission Viejo Branch Library 24851 Chrisanta Drive Mission Viejo, California Mayor City'of San Clemente San Clemente, California 92672 Mr. Irving Goldberg, Chief Environmental Radiation Control Unit l Radiologic Health Section l California Department of Heal th , t 714 P Street, Room 498 Sacramento, California 95814 l Chief. Energy Systems Analyses Branch (AW-459) Office of Radiation Programs U.S. Environmental Protection Agency Room 645. East Tower . 401 M Street, SW Washingtoa, D.C. 20460 U.S. Environmental Protection Agency i Region IX Office ATTN: EIS COCRDIMATOR 100 California Street
- San Francisco, California 94111 i
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j.' e UMTED STATES y ,
. NUCLEAR REGULATORY COMMtsSION y '
f ' WASHINGTON, D. C. 20S55 v, \..v... / . t' SOUTP.EP.H CALIFMNI A EDISOM C0itPANY At:0 SAN DIEGO GAS AND ELECTRIC COMPANY DOCKET H0. 50-?06 SAN'ONOFRENUCLEARGENERATINGSTATION,UNITJ t AMEND!tEHT TO PROVISIONAL OPERATING LICENSE Amendment No. 25 License No. DPR-13
- 1. The Nuclear. Regulatory Commission (the Commicsion) has found that: .
A.- The applications for amendment by Southern California Edison Company and Can Diego Gas and Electric Com?any (the. licensees) dated June-15,~Septender 23, 1975 and January 18, 1977, comply with the standards and reouirements of the Atomic Energy Act of [,
\ 1954, as anendec (the Act), and.the Commission's rules and regulations ~ set forth in 10 CFR Chapter I; B. The facility will operate in conformity with the application, '
the provisions of the Act, and the rules and regulations of the Commission; C. There is reasonable. assurance (i) that the activities authorized by this amendment can be conducted without endangerinp the health and safety of the public, ard (ii) that such activities
.will be conducted in compliance with the Commission's regulations; D. The . issuance of this amendment will not be inimical to the common defense' and security or to the health and safety of the public; and E. The issuance of this amendment is in ace' ordance with 10 CFR Part 51' of the Conmission's regulations and all applicable requirements have been satisfied.
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- 2. Accordingly, the license is amended by adding paragraph 3.E and l a , by changing the Technical Specifications as indicated in the attachment to this license anendment and paragraph 3.B of Facility )
License Ho. DPR-13 is hereby amencted to read as follows: (k) Technical Specifications The Technical Specifications contained in Appendices ! A and B, as revised through Amendment No. 25, are , l hereby incorporated in the license. The licensee - shall operate the facility in accordance with the Technical Specifications. . (E) Steam Generator Insoections In order to perform an inspection of the steam generators, the plant shall be brought to the cold shutdown condition within twelve months of operation from April 1,1977. The scope of this inspection shall provide sufficient data for a reassessnent of the maanitude of inplane expansf or, or I "hourglassing" in the top and bottom tube succort olatas on I the effect of potential continued steam gancrator tube j denting. Nuclear Regulatory Commission approval shall be ( obtained before resuming power operation following this ! inspection. l
- 3. This license amendment is effective as of the date of its issuance.
. FOR THE NUCLEAR REGULATORY C0lVilSSION
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()h 4&*U$'% -
.?Z, Karl R. Goller, Assistant Director for Operating Reactors
, Division of Operating Reactors
Attachment:
Changes to the Technical Specifications Date of Issuance: April 1,1977 O
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- - [D 6. The steam flow is based on the Moody curve with fL/D=0,
- 7. Perfect moisture separation exists in the steam generator.
, 8. The reactor vessel upper. head fluid temperature is initially at - the vessel outlet temperature. With the above assumptions, SCEC has analyzed four combinations { of breaks and initial conditions.
- 1. Rupture of a pipe outside the containment, downstream of the steam flow measuring nozzle, no load conditions, with offsite power available.
- 2. Rupture of a pipe inside the containment, at the steam generator outlet, at no load conditions, with offsite power available.
3, Case 1. above without offsite power available. 'l
- 4. Case 2. above without offsite power available.
x_) For the four cases analyzed, return to criticality does occur. liowe ver, 1 the minimum DNBR remains above 1.30. No departure from nucleate boilina,. occurs and therefore there is no clad damage and no release of fission products to the environment. We find the results of the MSLB accident reanalysis to be acceptable. 2.2.2.5 Emergency Core Cooling System (ECCS) Evaluation 2.2.2.5.1 Submerged Valves I On March 16, 1976, 0 0) SCEC submitted the results of its ') evaluation for valves at 50-1 which could become submerged following a LOCA. Of those valves identified as having the potential for submergence,
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2.2-6 none are safety related, ,or linked to safety related equipment. Therefore, we conclude that there will be no adverse effects on the safety features systems performance due to post LOCA submergence of valves. 2.2.2.5.2 Single Failure SCEC has recently submitted the results of its continuing single failure analysis (16) for the S0-1. SCEC has identified necessary modifications for preventing potential single failures which could impede each of the three post accident phases. The loss of power (LOP) logic requires modification to provide power for all three post accident phases. To provide independent and redundant loss of power logic on an interim basis, the undervoltage relays on the two redundant 4160 volt busses will be modified before startup with Cycle VI, to deenergize to activate. As modified, an interrupted circuit on the contac side of the relay causes the relay to oerform the intended function. This modification is acceptable since it will insure that the inout signals required for emergency diesel generator start and sequencer operation are provided in the event of failure of the undervoltage relays. Permanent
.i Jres to provide independent and redundant loss of offsite power input signals will include installation of a second relay on each of the 4160 volt busses. This work will be accomplished during the next refueling outage.
At present two electrically separate but closely spaced stages on a single safety injection system (SIS) override / block switch are used to send independent signals to each of the two SIS logic / sequencer trains. During next refueling cutage the system will be modifiea by installation of a second SIS override / block switch, thus providing a separate switch for each SIS train. I a l
l 2.2-7 O ' V . Interim' measures to insure that no single failure or inadvertent operator action will block both SIS logic / sequencer trains include j attaching a. stage to the existing stage of the switch, installing i a protective cover over the switch handle on the front of the control l l panel and rebriefing the operators on the proper use of this switch. .. These interim measures are acceptable since they provide added assurance that switch failure or_ inadvertent operator action will not block initiating signals-to the Safety Injection Actuation Systems. 4 The automatic transfer feature is to be eliminated from three transfer switches prior to startup with the Cycle VI Core. This action ; is being taken for (1) transfer switch No. 7 which energizes 120 volt a.c. vital bus No. 4 from Motor Control Center 1 (MCC 1) or MCC 2 (2) the transfer ( switch which energizes the emergency siren from MCC 1 or MCC 2, and (3) l' the transfer switch which energizes the communication power panel from either MCC 1 or. MCC 2. All three of these transfer switches will be locked to one source of power. Transfer switch No. 7 will be aligned to I
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MCC 2 with its feeder breaker closed and MCC 1 feeder breaker fuse block renoved. ^ The emergency siren will be assigned to MCC 1 with the feeder breaker from MCC 1 closed and the MCC 2 feeder breaker fuse block removed. The communication power panel will be assigned to MCC 1 with the feeder breaker from'MCC 1 closed and the MCC 2 feeder breaker fuse block removed.- We conclude that.this elimination of the automatic transfer function will preclude the automatic transfer of a postulated power train. fault and is therefore acceptable, c
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2.2-8 i To insure adequate operation during the safety injection phase, the SIS flow comparator connected to motor operated valves MOV-850 A, 8, & C will be removed before Cycle VI startup. Automatic closing of a ruptured safety injection leg is not a necessary function to assure satisfactory performance of the SIS. Removal of the flow comparator acceptably eliminates a potential single failure within the flow cogarator that could result in the closure of all three safety injection valves. Examination of the system used for the recirculation phase of plant cooldown follwing a LOCA has identified a single failure which could prevent recirculation. Pneumatic flow control valves FCV-11150, E & F are supplied by a common air system and fail in the cicsed position on loss of air. SCEC has committed to install a backup air supply within six months after Cycle VI startup and to modify the valves to be fully single failure proof by the fall 1979 refueling outage. We find these measures acceptable. The addition of a backup air supply provides a suitable redundant feature to assure the proper functioning of the system. For the intervening period of operation of six months without the backup air supply we believe that an exemption from the single failure requirement for this single item is warranted. This is based on the lack of problems with these valves in the past and the low probability that compound failures would occur during that time interval. Using the results of the WASH-1400 Report, SCEC arrived at a compound arobability of failure of 1.1x10-6 by assuming the most probable LOCA (1/2" to 2" break) with a probability of 10-3 per reactor year along with a power cable failure of 3.10-6/ hour. During the 30 day recirculation period this gives a
2.2-9 probability of cable failure of 2.2x10-3 . Thus, for the intervening O i i six month period the compound failure probability becomes 1.1x10"6 U . Further, even if the events should occur, at least minimal flow to the core could be achieved through the hot leg recirculation oath. Thus, there is no substantial effect on the insignificant probability of an accident , with consequences more severe than those considered in the Final Saiety Analysis. In the absence of any safety problem associated with operation of the facility during the period until October 1,1977, there appears to be no public interest consideration favoring restriction of the operation of this facility. Accordingly, an exemotion from 10 CFR 50 Appendix A General Design Criterion 35, pursuant to 10 CFR 50.12, is appropriate. A second potential single failure has been identified which could result in loss of both charging pumps prior to the recirculation phase. p Failure of valve MOV/LCV-1100C to close between the Volume Control Tank Q' and the charging pump suction could result in cavitation of both pumps. . To preclude this from happening SCEC has agreed to install an additional valve in series with MOV/LCV-1100C powered from a separate power train at the next refueling outage. In the interim, one charging pump will be removed from the automatic start sequencers. Thus, failure of valve MOV/LCV-1100C to close would at most damage only one charging pump. Written and approved procedures have been added which require the operator to verify that the valve is indicated to be closed. If it is not, the operator is to close the valve from the control room. If that fails, the operator is to secure the charging pump that is running and dispatch an operator to manually close valve MOV/LCV-1100C. Following termination safety ' injection flow (at least 8.5 minutes after the break) and during (A G 1 recirculation mode (at least 26.5 minutes after the break) at least one charging' pump will then be available to the operator for manual startup i-
s - 2.2-10 l We conclude that sufficient time would be available for an operator to I perform the necessary actions. The analysis which was done on the ECCS performance assumed recirculation flow from only one charging pump. l Therefore, this procedure will provide an acceptable interim resolution l to assure adequate core flow in the recirculation phase. 1 The remainder of the recirculation system has been examined and found to be . free of any potential single failures which could prevent the system from performing its intended safety function. 2.2.2.5.3 Boron Precipitation To prevent buildup and precipitetion of boron in the core in the long term recirculation mode following a LOCA, SCEC has proposed not later than the next refueling outage to use a dual recirculation pattern involving the cold legs and a hot leg injection path. The hot leg injection will require flow through the pressurizer to the loop "B" hot leg. At the present time several single failures could prevent, or at least reduce, flow through an existing intended path. For the interim period until the necessary valves are obtained and installed, SCEC has installed additional piping to provide a secondary hot leg injection path with interim procedures using the recirculation pumps, the refueling water pumps, the resihal heat removal heat exchanger and piping, and the loop "C" hot leg residual heat removal line. While the use of this secondary path is more complicated, there is sufficient time to effect all necessary alignments. The remainder of the system to tc used for hot leg recirculation has been found to be free of any potential single failures which could prevent the system from performing its 1 intended safety function. O so
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Task A-12 4 FRACTURE TOUGHNESS AND POTENTIAL FOR LAMELLAR TEARING OF STEAM GENERATOR AND REACTOR COOLANT PUMP SUPPORTS Lead NRR Organization: Division of Operating Reactors (DOR) Lead Supervisor: Darrell G. Eisenhut, A/D for Systems and Projects, 00R Task Manager: Dick Snaider, SEP/00R Applicability: Pressurized Water Reactors Projected Completion Date: August 1979 O ; !o v i A ,
Task A-12 Rev. No. 1 May 1978 O
- 1. DESCRIPTION OF PROBLEM
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During the course of the licensing action for North Anna Power Station Unit Nos. 1 and 2 a gmber of questions were raised as to the potential for lamellar tearing- and low fracture toughness of the steam generator and reactor coolant pump support materials for those facilities. Two
'different steel specifications (ASTM A36-70s and ASTM A572-70a) covered most of the material used for these supports. Toughness tests, not
- originally specified and not in the relevant ASTM specifications, were made on those heats for which excess material was available. The toughness of the A36 steel was found to be adequate, but the toughness of the A572 steel was relatively poor at an operating temperature of 80'F. 'In the case of the North Anna Unit Nos. 1 and 2, the applicant has agreed to raise the temperature of the ASTM A572 beams in the steam generator supports to a minimum temperature of 225'F prior to reactor coolant system pressurization to levels above 1000 psig.
Auxiliary electrical heat will be supplied as necessary to supplement the heat derived from the reactor coolant loop to obtain the required ~ operating temperature of the support materials. Since similar materials and designs have been used on other nuclear plants, the concerns regarding the supports for the North Anna facil- , ities may be applicable for other PWR plants. It is therefore l necessary to reassess the fracture toughness'of the steam generator and reactor coolant pump support materials for all_ operating PWR plants and those in CP and OL review. Lamellar tearing may also be a problem in those support structures similar in design to North-Anna. This possibility will be inves-tigated on a generic basis. M Lamellar tearing is a cracking phenomenon which occurs beneath welds and is principally found in rolled steel plate fabrications. The tearing always lies within the parent plate, often outside the transfomed (vis-ible) heat-affected zone (HAZ) and is generally parallel to the weld I fusion boundary. Lamellar tearing occurs at certain critical joints usually within large welded structures involving a high degree of stiff-ness and restraint. Restraint may be defined as a restriction of the movement of the various joint components that would normally occur as a result of expansion and contraction of weld metal and adjacent regions during welding ("Lamellar Tearing in Welded Steel Fabrication", The Welding' Institute). O A-12/1
1 Task A-12 Rev. No. 1 May 1978 O V The scope of this program is presently limited to PWR steam generator J and reactor coolant pump supports. Another program, ASY M ETRIC LOCA l LOADS (A-2) will investigate vessel supports as part of its scope. 1 As part of that effort, a review of the need for including BWR vessel supports is being undertaken. As'noted in Section 8 of this report, activity A-12 can be expanded to include BWR supports and other PWR support structures if warranted.
- 2. PLAN FOR PROBLEM RESOLUTION j
- 4 A preliminary survey of operating PWR plants was made in May 1976 to l determine the initial scope of this problem. Results indicate that five units have designs similar to North Anna and that 12 units use l l A36 materials. No plants which were surveyed used the A572 material. j The staff concluded that, depending on the heat treatment of the A36 ,
material, a potential material toughness problem may exist. In j addition, it was determined that other materials used in the design of ,, l steam generator and pump supports have never been tested to determine toughness properties. Therefore, the potential " toughness problem" may exist for operating plants thct did not use A36/A572. As noted O above, the potential for lamellar tearing may also exist for certain Q support structures. ; Based on the above, the continuing action plan for resolution of this concern for operating PWRs is as follows: l
- a. Send a generic letter to all PWR licensees stating NRC concerns and requesting information on the design, materials, fabrication and inspection of the steam generator and reactor ccolant pump supports for each plant. (A follow-on letter to BWR licensees may be necessitated by information in program A-2.)
- b. Based on information supplied by the licensees and with the aid of the consultant, categorize the support design and materials as far as practical and select typical designs for further study.
DSS /MTEB will concurrently review fracture toughness and possi-bility of lamellar tearing for PWRs in the CP and OL stages, based on information gathered from the 00R review.
- c. Complete preliminary review of typical designs and inform each l applicable PWR licensee of the concerns on their particular support system.
- d. Utilizing input from consultant, develop and issue specific guidance for resolution of the problems discovered. This will be a joint DSS / DOR task and will result in the issuance of a g ,
NUREG document and/or other appropriate document. A-12/2 4 _ _ . _m_.___ ._.__ _ _ . _ _ _ _ _ _ _ _ _ _ _ _ _ . _ _ . _ _ _ _ _ _ . _ _ _ . _ _ _ _ . _ _ _ _ . _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . _ _ _ _ _ _ _ _ _ _ _ _ __
Task A-12 Rev. No. 1 May 1978 Subsequent case-by-case resolution (implementation) will involve requiring those applicants or licensees for whose facility (ies) a problem exists to either: (1) demonstrate that safety margins are not lower than anticipated or; (2) propose a solution to the problem in accordance with the criteria developed in step d above.
- 3. BASIS FOR CONTINUED PLANT OPERATION AND LICENSING PENDING COMPLE-TION OF TASK As indicated in Section 2 the staff anticipates that the result of this task will be the issuance of a NUREG document which will delineate guidance and requirements for the selection of materials and the construction of reactor coolant pump and steam generator support structures. The document will also address preservice inspection requirements for plants in the operating license stage and inservice inspection requirements for operating reactors.
A preliminary survey of operating PWRs was performed in late 1976. Based on the results of this survey and the information received to date as part of this task, we have determined that additional O, investigation is prudent. Presently, there is no ASME Code require-ment for inspection of the steam generator supports, although the establishment of such a-requirement is being considered. The ASME Code requires visual inspection once every ten years for reactor coolant pump supports. As noted above, the staff will consider establishing additional guidance and requirements for inservice inspection of these supports as part of this task. Operating stresses in the support structures during normal operation are sufficiently low to preclude failure in either a brittle or ductile mode. In addition, inservice temperatures for the materials used in the support structures are normally high enough to preclude brittle failure under accident induced stress conditions. Primary system component supports in operating reactors are designed to withstand postulated worst-case accident conditions. Even though there are some questions regarding the toughness of some l support materials, as indicated in Section 2, the staff has no reason to expect at this time that any of the support materials for operating reactors will be found to be substandard from a fracture toughness standpc - Further, the staff believes that the likeli- I hood of an initistu.e avant (e.g., a large pipe break) of sufficient I magnitude as to seriously challenge the structural adequacy of tha support members is very low. The probability of the disruptive failure of a reagtor pressure L) . vessel itself has been estimated to lie between 10 8 and 10 7 per reactor A-12/3 l l l
Task A-12 l Rev.-No.~1 i May 1978 year - so low that it is not' considered-as a design basis event. ; The rupture probability of pipes is estimated to be higher. WASH-1400 used a median value of 10 4 for LOCA initiating ruptures per plant-year for. all pipe siges 6" and greater (with r. lower and upper l bound of 10 s and 10 3, respectively). We Niieve that considering { the large size of the pipes in question (up to 50" 0.0. and 4-1/8" i thick), the lower bound is more appropriate since these pipes are ' more like pressure vessels in size. In f.ddition, the quality control of the piping uset. in nuclear power plants is the best available and somewhat better than that of the piping used in the WASH-1400 study. For applications for operating licenses the staff reviews the design of primary system component supports and requests and evaluates information related to the fracture toughness of support materials. Based on the foregoing, the staff has concluded that gontinued operation of operating reactors and licensing of plants in the operating license review stage will not present an undue risk to - the health and safety of the public pending completion of the task. ' Further, based on the anticipated completion date for this task, the task results will be available well in advance of the operation of any plant currently under construction permit eview.
- 4. NRR TECHNICAL ORGANIZATIONS INVOLVED
- a. Engineering Branch, Division of Operating Reactors. Has lead responsibility for review of data generated from licensee responses, control of and coordination with consultant organiza-tion, and will coordinate with 055 in development and issuance of criteria.
- Manpower Estimates: 1.0 man year FY 1978, .6 man year FY 1979.
- b. Materials Engineering Branch, Division of Systems Safety.
Review information received from operating units and problems identified during review. Coordinate with 00R in development and issuance of criteria. Manpower Estimates: .: man year FY 1978, .3 man year FY 1979.
- c. Task Manager, Division of Operating Reactors. Has overall responsibility for coordination of DOR and DSS technical tasks and for the development and issuance of criteria documents. ,
i Manpower Estimates: .1 man year FY 1978, 0.1 man year FY 1979. (
- A-12/4 ye .y.
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- Task A-12 Rev. No. 1 May 1978
- 5. TECHNICAL ASSISTANCE Technical assistance for the D0R program is required to provide expertise in evaluating the potential for lamellar tearing and low fracture toughness of the support materials. The work will include:
- a. Evaluating utility responses to NRC questions.
- b. Performing a literature search for fracture toughness on the materials in question,
- c. Evaluating the brittle failure potential of support materials.
- d. Evaluating the potential for lamellar tearing and assessing its consequences.
- e. Evaluating any proposed solutions as requested by the NRC.
- f. Preparing a topical report. -
The present budget is $100,000, $50,000 of which was carried over from FY 1977. We anticipate Sandia's continued participation in the program D completion in FY 79. 00R has requested a budget allocation of
$35,000 for this effort.
- 6. INTERACTIONS WITH OUTSIDE ORGANIZATIONS Individual licensees of PWR facilities and applicants for PWR licenses. All PWR licensees will be contacted to gather informa-l tion at the commencement of the program. Some licensees will become more involved in this study due to the need for site visits and/or the discovery of material problems at their particular facility (ies). Further interaction will be a function of the results of our review.
! DSS will perform information review during CP and OL stages of review in order to resolve issues prior to licensing.
- 7. ASSISTANCE REQUIREMENTS WITH QTHER NRC OFFICES The Office of Standards Development intends to commence, in FY 1979, work on a program involving Fabrication and Examination of Component Supports. Although an effort is presently being made to incorporate specific guidance in the ASME Code, this new program may result in issuance of a Regulatory Guide.
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