ML20203J866

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Application for Amends to Licenses DPR-53 & DPR-69,deleting Tech Spec Table 3.7-4, Safety-Related Hydraulic Snubbers, Per Generic Ltr 84-13.Discussion of Changes & NSHC Encl.Fee Paid
ML20203J866
Person / Time
Site: Calvert Cliffs  Constellation icon.png
Issue date: 07/31/1986
From: Tiernan J
BALTIMORE GAS & ELECTRIC CO.
To: Thadani A
Office of Nuclear Reactor Regulation
Shared Package
ML20203J870 List:
References
GL-84-13, NUDOCS 8608060047
Download: ML20203J866 (25)
v • d • e


Text

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A B ALTIMORE GAS AND ELECTRIC CHARLES CENTER R O. BOX 1475 BALTIMORE, MARYLAND 21203 JosEpN A.TIERNAN

\ et PatsioENT NLcLEAn ENEnGY July 31,1986 U. S. Nuclear Regulatory Commission Office of Nuclear Reactor Regulation Washington, D. C. 20555 ATTENTION: Mr. Ashok C. Thadani, Director PWR Project Directorate #8 Division of PWR Licensing-B

SUBJECT:

Calvert Cliffs Nuclear Power Plant Unit Nos.1 & 2; Docket Nos. 50-317 & 50-318 Request for Amendment

REFERENCES:

(a) NRC Generic Letter 84-13, Technical Specifications for Snubbers, dated May 3,1984 (b) Letter from Mr. 3. A. Tiernan (BG&E), to Mr. A. C. Thadani (NRC),

dated May 9,1986, Request for Clarification, Reactor Coolant Pump Flywheel Integrity (c) Telephone Conference between Mr. D. H. Jaffe (NRC), and Mr. B. E. Holian (BG&E), on June 12,1986 (d) Enclosure to letter from Mr. D. H. Jaffe (NRC), to Mr. A. E. Lundvall, Jr. (BG&E), Docket 50-318, November 21,1985 (e) CENPD-207-P-A, "C-E Critical Heat Flux", Part 2, December 1984 (f) Letter from Mr. A. E. Lundvall, Jr. (BG&E), to Mr. 3. R. Miller (NRC), dated Feburary 22, 1985, Calvert Cliffs Nuclear Power Plant Unit 1; Docket No. 50-317, Amendment to Operating License DPR-53, Eighth Cycle License Application (g) Letter from Mr. C. H. Poindexter (BG&E), to Mr. E. 3. Butcher (NRC), dated August 30, 1985, Calvert Cliffs Nuclear Power Plant Unit 2; Docket No. 50-318, Request for Amendment to Operating License DPR-69 Seventh Cycle License Application 47 860731 DR P kOOCK05000317 g(/ jfg, PDR 90f g[0 Sho g toy

Mr. Ashok C. Thadani July 31,1986 Page 2 Gentlemen:

The Baltimore Gas and Electric Company hereby requests an Amendment to its operating License Nos. DPR-53 and DPR-69 for Calvert Cliffs Unit Nos.1 & 2, respectively, with the submittal of the proposed changes to the Technical Specifications.

CHANGE NO.1 (BG&E FCR 86-122)

Change pages 3/4 7-25, 7-26, 7-26a, 7-26b, 6-20, and B 3/4 7-5 of the Unit I and 2 Technical Specifications; and delete pages 7-27 through 7-61a (Unit 1) and 7-27 through 7-53 (Unit 2), as shown on the marked up copies attached to this transmittal.

DISCUSSION in May 1984, the NRC issued Reference (a) which reassessed the inclusion of snubber listings within the Technical Specifications. This Generic Letter concluded that such listings are not necessary provided the snubber Technical Specification is modified to specify which snubbers are required to be OPERABLE. The Limiting Condition for Operation, Surveillance Requirements, and recordkeeping requirements will be maintained within the Technical Specifications. The snubber listings, when deleted from the Technical Specifications, will be maintained per controlled procedures. Changes in snubber quantities, type, or locations would be a change to the facility and would, therefore, be subject to the provisions of 10 CFR Part 50.59.

This proposed change to the Technical Specifications is being processed to delete Calvert Cliffs' snubber Table 3.7-4, " Safety Related Hydraulic Snubbers," from the Technical Specifications. This change closely follows NRC guidance for implementing this change. However, we have tailored the recommended Limiting Condition for Operation (LCO) wording to more clearly follow existing snubber policy at Calvert Cliffs.

Reference (a) recommended the following:

3.7.9 All snubbers shall be OPERABLE. The only snubbers excluded

! from this requirement are those installed on non-safety related systems and then only if their failure or failure of the system on i

which they are installed would have no adverse effect on any safety related system.

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Our proposed Technic.at Specification would simply state: "All safety related snubbers shall be OPERABLE." All snubbers currently listed in the Technical Specification table

! are safety related. Additio Tally, BG&E Technical Specifications already contain the policy as stated in the second sentence of the NRC-suggested LCO. This statement, concerning snubber failures which may impact safety related systems, is currently l contained in both Unit I and 2 Technical Specification Bases. All future, additional non-

' safety related snubbers that may be proposed for installation will be evaluated according to this criteria stated in the bases. If a non-safety related snubber failure is evaluated as potentially resulting in adverse effect on a safety related system, that snubber would then be categorized as safety related. Therefore, the LCO can be effectively shortened, i

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r-Q Mr. Ashok C. Thadani July 31,1986 Page 3 without altering the intent, by stating "All safety related snubbers . . . ." This LCO will be much easier for plant operators to reference, since snubber listings will be available to them as two listings - safety related s*d non-safety related. The operators need not be concerned with design decisions affecting the make-up of the snubber listings, in addition to deleting the snubber table from Technical Specifications, the following changes are also proposed:

(A) Table 3.7-4: All references to Table 3.7-4 have been deleted since this table has been removed.

(B) Page Footnotes: Two page footnotes have been deleted since they are no longer necessary. Additionally, the page footnotes in Table 3.7-4 were evaluated for applicability to the LCO and have been similarly deleted.

(C) Safety Related: Incorporate the words " safety related" in various locations (prior to the word " snubber")in order to maintain consistency with the LCO.

(D) 18-Month Timeframes: Change the snubber inspection period and Functional Test "18-month" references to " refueling interval."

NOTE: BG&E plans to begin 24-month refueling cycles commencing with the spring 1987, Unit 2 refueling. As such, plant system engineers have been researching the associated 18-month Sur veillance Requirements - evaluating whether the equipment and past operating history justifies extending the surveillance interval to 24 months. A majority of these surveillance interval extension requests will be submitted to the NRC as a package. However, discussion with our Project Manager indicated that where appropriate, 18-month surveillance interval extension requests should be submitted along with related Technical Specification changes covering the same subject.

This change proposes that with zero inoperable snubbers per inspection period, the subsequent visual inspection period should be " refueling interval" vice 18 months. This administrative change will allow automatic extension of the inspection period when " refueling interval" is officially extended to 24 months. (Currently "R" is defined in Section 1.0 of the Technical Specifications as "at least once per 18 months.") Additionally, the subse-l quent visual inspection period with one inoperable snubber has been extended (by an identical percentage) to 16 months. This particular change is 1 requested due to the scheduling of refueling outages with two units on j

24-month refueling cycles. One unit will be refueled every 12 months; i therefore, this change precludes taking the second unit off-line during this refueling outage time interval. An inspection period of 16 months i 25%

with one snubber inoperable will correspond with our current plans for l

scheduling a " mini-outage" approximately three-quarters through the 24-month refueling cycle. Finally, this change correspondingly proposes that snubber Functional Tests t>e changed from "18 months" to " refueling interval."

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4 Mr. Ashok C. Thadani July 31,1986 Page 4 We recognize the punitive nature of the Snubber Technical Specification and view it as self-correcting. A snubber program with zero or one inoperable snubber per inspection period should not be unduly penalized. Therefore, we request extended surveillance intervals due to:

1. our successful snubber program (since 1973 we have functionally tested over 260 small bore snubbers between both units. There has only been one failure in this time period), and
2. the fact that we are extending our refueling interval to 24 months.

DETERMINATION OF SIGNIFICANT HAZARDS This proposed change has been evaluated against the standards in 10 CFR 50.92 and has been determined to involve no significant hazards considerations, in that operation of the facility in accordance with the proposed amendment would not:

(i) involve a significant increase in the probability or i consequences of an accident previously evaluated; or DELETING SNUBBER TABLE This change is strictly administrative in nature. Safety related snuobers will continue to be controlled and surveilled according to Technical Specifications. Changes in snubber quantities, types, or locations would be a change to the facility and would be adequately controlled per the provisions of 10 CFR 50.59.

13-MONTH TIMEFRAMES Extending the snubber surveillance intervals does not significantly increase the probability or consequences of an accident previously evaluated. The punitive nature of the Technical Specification will force a more frequent inspection schedule if our failure rate per inspection period increases.

(ii) create the possibility of a new or different type of accident from any accident previously evaluated; or DELETING SNUBBER TABLE This change does not add to, or delete from, the total number of plant snubbers available to provide dynamic load support during a design basis seismic event. No new or different kind of accidents from those previously evaluated in the Updated Final Safety Analysis Report are created by this proposed change.

Mr. Ashok C. Thadani July 31,1986 Page 5 18-MONTH TIMEFRAMES This change does not create the possibility for a new or different kind of accident from any accident previously evaluated. The ability to provide dynamic load support during a design basis seismic event remains as is. The justification for extending the present inspection intervals is based on our successful snubber program.

(iii) involve a significant reduction in a margin of safety.

DELETING SNUBBER TABLE The NRC has concluded that snubber listings are not necessary provided the snubber Technical Specification specifies which snubbers are required to be OPERABLE. The snubber Limiting Condition for Operation (LCO) has been clarified to show that all safety related snubbers must be OPERABLE. This change does not

! involve a significant reduction in a margin of safety since: i) the LCO clearly specifies which snubbers are required to be operable, and 2) the snubber listing will be maintained via controlled procedures.

18-MONTH TIMEFRAME

- Extending the Functional Test interval, and the visual inspection interval for zero or one inoperable snubbers does not significantly reduce a margin of safety. Past operating experience indicates that our current snubber program is more than adequate in minimizing snubber failures.

l CHANGE NO. 2 (BG&E FCR 86-124)

Change pages 3/4 4-28 of Unit 1, and 3/4 4-29 of Unit 2 Technical Specifications as shown cn the nprked up copies attached to this transmittal.

DISCUSSION Technical Specification 3/4 4.10, Structural Integrity, states that " . . . each Reactor Coolant Pump flywheel shall be inspected per the recommendations of Regulatory

Position C.4.b of Regulatory Guide 1.14, Revision 1, August 1975." Item C.4.b.(2) states that inservice inspection should be performed fer each flywheel as follows

l "A surface examination of all exposed surfaces and complete ultrasonic i volumetric examination at approximately 10-year intervals during the plant l shutdown coinciding with the inservice inspection schedule as required by Section XI of the ASME Code."

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9 Mr. Ashok C. Thadani July 31,1986 Page 6 i

We requested, per Reference (b), concurrence with our particular program for meeting the requirements of the above regulatory position. We initiated a voluntary Reactor

- Coolant Pump (RCP) motor overhaul program three years ago. This program utilizes a spare motor to enable quick motor changeouts and longer motor inspection and evaluation int 6rvals. it is our present intent to perform the flywheel examinations as each RCP motor is removed for overhaul. The two-piece bolted flywheel design used at i

Calvert Cliffs makes in-place ultrasonic examination difficult to perform. Tying the flywheel examinations to the RCP motor overhaul schedule will therefore:

1. Ensure an accurate examination is performed, and
2. Maximize the utilization of resources by combining the required flywheel inspections with our voluntary RCP motor inspection program.

The current schedule for the completion of RCP flywheel exams was provided in Reference (b). The Commission has completed a preliminary review of our previous submittal and has requested, per Reference (c), that we submit a Technical Specification change. This change will clarify Surveillance Requirement 4.4.10.1.1 by providing a footnote to specify the expected date of completing the requirements of the initial ISI interval for the RCP flywheel examinations. The completion of the first 10-year ISI interval for both units is scheduled for April 1987. The proposed Surveillance i Requirement footnotes provide dates of June 1990 (Unit 1), and June 1991 (Unit 2), for completing the initial ISI flywheel inspections. Our current plan is to complete the inspections in conjunction with the RCP motor overhaul program; however, these footnotes do not preclude us from completing the inspections at an earlier date should plant down time allow. We will continue to evaluate methods for in-place flywheel

testing to satisfy 20-year inspection requirements.

DETERMINATION OF SIGNIFICANT HAZARDS i

This proposed change has been evaluated against the standards in 10 CFR 50.92 and has been determined to involve no significant hazards considerations, in that operation of the facility in accordance with the proposed amendment would not:

(i) involve a significant increase in the probability or consequences i of an accident previously evaluated; or The results of our RCP flywheel inspections performed to date, as of industry inspections in general, have been satisfactory. RCP flywheel integrity is expected to last throughout the entire plant lifecycle.

Extending the initial ISI flywheel inspection interval does not involve a

. significant increase la :ne probability or consequences of an accident previously evaluated.

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.t-Mr. Ashok C. Thadani July 31,1986 Page 7 (ii) create the possibility of a new or different type of accident from

, any accident previously evaluated; or ,

This proposed change only clarifies the BG&E flywheel inspection 4 program. No modifications to the intent of the Technical Specifications are being made; therefore, no new accident previously unanalyzed will be created by this proposed change.

(iii) involve a significant reduction in a margin of safety.

4 The two-piece bolted flywheel design used at Calvert Cliffs makes in-place ultrasonic examination difficult to perform. Tying the flywheel examinations to the RCP motor overhaul schedule will ensure accurate examination results are obtained. The change is administrative in nature since it clearly defines (for our initial ISI interval) the regulatory I

position that states flywheel inspections are to be performed at approximately 10-year intervals. The proposed change, therefore, does not involve a significant reduction in a margin of safety.

CHANGE NO. 3 (BG&E FCR 86-125)

Change pages 3/4 6-17 and 6-18 of the Unit I and 2 Technical Specifications as shown on the marked up copies attached to this transmittal.

DISCUSSION l This proposed change requests that the provisions' of General Technical Specification

! 3.0.4 be exempt from Technical Specification 3/4.6.4, Containment Isolation Valves.

Additionally, in support of BG&E's future 24-month refueling schedule, this submittal

proposes to change the 18-month surveillance interval to "at least once per refueling interval."

l Because the provisions of Technical Specification 3.0.4 are not currently exempted from

. Technical Specification 3.6.4.1, a unit cannot be started up following a MODE reduction

! while an inoperable valve is secured closed (whereas the current Technical Specification Action Requirements allow continued operation with an inoperable valve secured closed). By stating that the " provisions of Technical Specification 3.0.4 are not applicable," entry into an OPERATIONAL MODE could be made while relying on provisions contained in the Action Requirements. The Action Requirements for the

! containment isolation valve specification require that with an inoperable isolation valve, either:

a) Restore the valve to OPERABLE status within four hours, or b) Isolate each affected penetration within four hours by use of at least l- one deactivated automatic valve secured in the isolation position, or i _ - _ . _ . _ . _ , _ _ - . _ _ _ _ . - ,, . . , . .. _ .__ - _ _ _ .

O Mr. Ashok C. Thadani July 31,1986 Page 8 c) Isolate the affected penetration within four hours by use of at least one closed manual valve or blind flange, or d) Be in HOT STANDBY within tha next six hours and in COLD SHUTDOWN within the following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />.

These Action Statement provisions ensure that the purpose of the containment isolation valve (i.e. to provide isolation for the containment penetration) is satisfied. Since unlimited operation is allowed while in compliance with the Action Statements, there is no increment in safety to be gained by restricting upward MODE changes once the penetration has been secured. Also, similar Technical Specification 3.0.4 exemptions for containment isolation valve inoperability have been previously approved at various other nuclear power plants.

Changing the 18-month Surveillance Requirement wording to state "at least once per refueling interval" will permit testing of the containment isolation valves at the COLD SHUTDOWN or REFUELING MODE coinciding with our new 24-month fuel cycle. Each isolation valve that receives an automatic closure signal is stroked to verify that the valve actuates to its isolation position. This refueling surveillance requirement is largely redundant. OPERABILITY of a majority of the test signals is verified on a monthly basis. Additionally, the isolation time of each power operated or automatic valve is determined to be within its limit on a quarterly basis (during COLD SHUTDOWN for those valves that cannot be exercised during plant operations). The results from past surveillances required by this Technical Specification indicate that the OPERABILITY of the isolation valves should not be adversely affected by extending this surveillance interval to a 24-month timeframe.

DETERMINATION OF SIGNIFICANT HAZARDS This proposed change has been evaluated against the standards in 10 CFR 50.92 and has been determined to involve no significant hazards considerations, in that operation of the facility in accordance with the proposed amendment would not:

(i) involve a significant increase in the probability or consequences of an accident previously evaluated; or The Containment Isolation Valve Action Statements and the Surveillance Requirements will continue to ensure that the purpose of the isolation valve (to provide isolation for the containment penetration) is satisfied.

The addition of the Technical Specification 3.0.4 exemption to Technical Specification 3.6.4.1 and the extension of the refueling surveillance interval do not increase the probability or consequences of an accident previously evaluated.

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4 Mr. Ashok C. Thadani July 31,1986 Page 9 r

(ii) create the possibility of a new or different type of accident from any accident previously evaluated; or

! Exemption from the requirements of Technical Specification 3.0.4 will allow entry into an OPERATIONAL MODZ. According to current Action Statements, unlimited operation may continue with an inoperable isolation valve provided that penetration is properly secured. Extending l the containment isolation valve refueling surveillance interval from 18 to 24 months will not adversely impact verifying containment isolation '

capability. The proposed changes to Technical Specification 3.6.4.1 do not create the possibility of a new or different type of accident from any previously evaluated.

, (iii) involve a significant reduction in a margin of safety.

The proposed changes to Technical Specification 3.6.4.1 do not involve a i significant reduction in the margin of safety. No significant decrease in the availability or capability of the containment isolation valves is involved.

I CHANGE NO. 4 (BG&E FCR 86-126)

Change page 3/4 7-9 of the Unit I and 2 Technical Specifications as shown on the marked up copies attached to this transmittal.

BACKGROUND The existing Main Steam Isolation Valve (MSIV) actuation system has been a significant contributor to plant down time. In addition to occasionally causing operational problems,

the system has caused maintenance, parts procurement, and design problems. In early 1985, the MSIV Project Team was tasked with evaluating alternative designs. The j decision reached was to replace the existing MSIV internals and acutation system. The i new MSIV internals (supplied by Rockwell International) will be of the bi-directional l design, which requires a much smaller closing force. The MSIV actuation system will be
replaced with a Rockwell Type A, valve mounted, gas-hydraulic, stored energy actuator. Energy for closure of the valve is provided by high pressure nitrogen contained
in a spherically shaped chamber above the hydraulic piston. Closure of the valve begins
when the hydraulic fluid from the actuator cylinder is released through two hydraulic l manifolds. The opening of two solenoid valves, through input from separate electrical signals, initiates flow of the hydraulic fluid through the manifolds to a reservoir. The
fluid velocity is controlled by restricting flow through the use of pressure-compensated flow control valves, to ensure uniform valve closure speed.

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Mr. Ashok C. Thadani July 31,1986 Page 10 p

DISCUSSION As a result of this modification, two proposed changes to Technical Specifications are necessary. First, since the existing MSIV hydraulic supply lines are being removed, this

change requires the removal of ten snubbers from Unit 1, and three snubbers from Unit 2 (Unit 1
1-83-30 to 37 and 73, 74; Unit 2: 2-838-1,2,3). Since Change No. I to this request for amendment letter addresses removing the entire safety related snubber listing (Table 3.7-4) from Technical Specifications, this aspect of the change will not be discussed in detail here. Change No. I has been evaluated against the standards in
10 CFR 50.92 and has been determined to involve no significant hazards considerations. .

Removal of these 13 MSIV snubbers is an administrative change since the piping they support will be eliminated during the installation of the new Rockwell, Type A, MSIV actuators.

1 The second proposed change to Technical Specifications resulting from this MSIV actuator replacement deals with Surveillance Requirement 4.7.1.5. This surveillance

, demonstrates MSIV operability by verifying full valve closure when testing pursuant to Technical Specification 4.0.5. As stated in the Technical Specification Bases: "The OPERABILITY of the main steam isolation valves within the closure times of the Surveillance Requ:rements are consistent with the assumptions used in the safety

, analyses." Chapter 14 of the Updated Final Safety Analyses Report (UFSAR) discusses MSIV testing. Section 14.14 provides the design bases allowable closure time: "The main steam isolation valves have been designed to close in less than six seconds under the pressure, temperature and flow conditions applicable to the assumed accident." This j proposed Technical Specification change would word the Surveillance Requirement to read similar to the UFSAR - requiring valve closure in less than 6.0 seconds.

The current MSIV surveillance requires full closure within 3.6 seconds. This time requirement assures MSIV closure within six seconds under all accident conditions. The 3.6 second surveillance time specifically ensures that
1) In a reverse flow accident situation, with steam flow impedi ng valve closure, the MSIV closure time is less than 6.0 seconds, and I 2) With one of the 19 accumulators failed, MSIV closure is approximately 5.7 seconds (once again, less than 6.0 seconds).

The new MSIV actuation system is designed such that valve closure will occur in 3.0 seconds with both hydraulic circuits operating properly. This closure time is independent of steam flow direction because of the new valve's balanced disc, bi-directional design.

Additionally, if one of the hydraulic circuits failed to operate, the other circuit is i designed to close the valve in 5.0 seconds. Therefore, the new valve closure times are shorter than current design.

i In-house evaluations, along with discussions with Combustion Engineering (CE) and

. Bechtel, were conducted to evaluate the need for performing analyses of core response, 1

containment pressure, offsite dose, and mass and energy release to support replacement of the MSIV/ actuator. Shorter MSIV closure times will have no significant effect on core i response due to the conservative licensing methodology used by CE for the Main Steam 4

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Mr. Ashok C. Thadani July 31,1986 l

Page 11 Line Break (MSLB) event. The offsite boundary dose due to a MSLB would be reduced by

a shorter MSIV closure time since a lower mass .and energy release would result.

.  ; Similarly, due to the reduced early mass and energy release, it is estimated that a slight redation in peak containment pressure due to a MSLB could be realized by reanalysis. It was concluded that new core response, offsite dose, mass and energy release, and containment response analyses are not necessary to support the new MSIV/ actuators.

The new MSIV/ actuator promises to be a more reliable, faster-acting valve. Operating Procedures and Surveillance Test Procedures will specifically address the new closure times - 3.0 seconds with both hydraulic circuits operating, and 5.0 seconds with one

circuit. Tolerance limits for these closure times will be included in plant procedures.

i' These limits will provide an acceptance band for test results. Values falling outside of this allowable range will be investigated to determine the possible cause (e.g. potential valve / actuator degradation). The Technical Specification Surveillance Requirement is being changed to match the upper-limit time requirement of the UFSAR. This limit, "less than 6.0 seconds," is the current basis used in accident analyses requiring MSIV closure.

1 DETERMINATION OF SIGNIFICANT HAZARDS This proposed change has been evaluated against the standards in 10 CFR 50.92 and has been determined to involve no significant hazards considerations, in that operation of the facility in accordance with the proposed amendment would not: ,

(i) involve a significant increase in the probability or consequences of an accident previously evaluated; or f The Surveillance Requirement for MSIV testing has been changed to 3

provide the design bases accident time requirement for MSIV closure.

This change does not involve an increase in the probability or consequences of an accident previously evaluated.

(ii) create the possibility of a new or different type of accident from any accident previously evaluated; or The change to the MSIV closure time is bounded by the existing accident f

analyses. No new accident previously unanalyzed will be created by this proposed change.

l (iii) involve a significant reduction in a margin of safety.

The new MSIV/ actuator provides for a faster closure time compared to the existing design. The Surveillance Requirement closure time is being expanded to match that currently in the accident analyses. No new j analyses are necessary due to the shorter, more conservative MSIV closure times. The proposed change does not involve a significant

< reduction in a margin of safety.

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Mr. Ashok C. Thadani July 31,1986 Page 12 CHANGE NO. 5 (BG&E FCR 86-3002)

Change pages B2-1,3,5,6 and B3/4. 2-2 of the Unit 1 Technical Specifications as shown on the marked up copies attached to this transmittal.

DISCUSSION This proposed change requests a reduction in the statistically derived Departure from Nucleate Boiling Ratio (DNBR) limit in Sections B.2.1 and B3/4.2.5 of the Technical Specifications for Calvert Cliffs Unit 1. The Technical Specification change requested herein for Unit 1 is identical to that already approved for Unit 2 (Reference d).

The DNBR limit is being reduced from the value of 1.23 to a value of 1.21. The reduction results from NRC approval in the Safety Evaluation Report (SER)

(Reference e) of a reduced DNBR limit using the CE-1 Critical Heat Flux (CHF)

, correlation for Combustion Engineering 14x14 fuel. At the time the Statistical Combination of Uncertainties (SCU) analysis was approved for the Calvert Cliffs units, NRC review of the applicability of the CE-1 CHF correlation to rods with nonuniform Axial Power Distribution (APD) was incomplete. An interim DNBR limit of 1.19.when using the CE-1 CHF correlation was thus used in the original SCU analysis. In the subsequent SER on CE's nonuniform APD topical report, the NRC reduced the CE-1 CHF correlation DNBR limit from 1.19 to 1.15 for 14x14 fuel. The SCU DNBR limit is being correspondingly reduced from 1.23 to 1.21. This limit corresponds to a 95% probability at a 95% confidence level that DNB will not occur on the limiting fuel rod.

The 1.21 SCU DNBR limit includes the following penalties, the first two of which were imposed by the NRC in their review of the SCU analysis:

- Critical Heat Flux (CHF) correlation cross validation penalty (5% increase in standard deviation of CHF correlation uncertainty distribution)

- Thermal-Hydraulic computer code uncertainty penalty (5%, equal to two standard deviations)

- Rod bow penalty which accourits for the adverse effects of rod bowing on CHF for 14x14 fuel with burnup not exceeding 45 GWD/T (0.5% DNBR).

. Thus, the revised SCU DNBR limit accounts for all uncertainties addressed in the SCU analysis and includes all penalties that were imposed by NRC in their review of the SCU methods. The reduction in the SCU DNBR limit is based solely on the NRC's generic approval of allowed DNBR limit for the CE-1 CHF correlation applied to C-E's 14x14 l fuel design.

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l Mr. Ashok C. Thadani July 31,1986 Page 13 DETERMINATION OF SIGNIFICANT HAZARDS The proposed change has been evaluated against the standards in 10 CFR 50.92 and has been determined to involve no significant hazards considerations, in that operation of the facility in accordance with the proposed amendment would not:

(i) involve a significant increase in the probability or consequences of an accident previously evaluated.

The reduction in the DNBR limit results from the application of an NRC approved correlation concerning the Critical Heat Flux for Combustion Engineering 14 x 14 fuel. There are no plant equipment modifications made as a result of, or in conjunction with, this reduction to the interim DNBR limit. The proposed change does not involve a significant increase in the probability or consequences of an accident previously evaluated.

(ii) create the possibility of a new or different type of accident from any accident previously evaluated.

The proposed DNBR reduction is a change to the existing interim limit.

This change does not result in modification to plant equipment and does not create the possibility of a new or different type of accident from any previously evaluated.

(iii) involve a significant reduction in a margin of safety.

The proposed change establishes the DNBR limit to ensure, to a 95/95 probability / confidence level, that the hot rod in the core does not experience DNB during normal operation or Anticipated Operational Occurrences. Hence, the proposed change does not involve a significant reduction in a margin of safety.

CHANGE NO. 6 (BG&E FCR 86-3003)

Change page 3/4.1-5 of the Unit Nos. I and 2 Technical Specifications, as shown on the marked-up copies attached to this transmittal.

DISCUSSION As a result of the increased RCS dissolved boron concentrations required to accomodate 18-month cycles and 2/00 MWt operation, Beginning-of-Cycle (BOC) Moderator Temperature Coefficients (MTCs) at Calvert Cliffs Units 1 and 2 have become more positive, at times approaching the Technical Specification Limits on MTC. This poses an operational constraint during power ascensions, particularly at the 70% power plateau.

3 Mr. Ashok C. Thadani July 31,1986 Page 14 At this power levgl, the current Technical Specification limit on MTC changes abruptly from 6 +0.7x10- delta Rho / F (at and below 70% power) to +0.2x10- delta Rho / F (above 70% power). To satisfy the more restrictive limit it has been necessary to hold power at 70% while xenon builds up. The buildup of xenon adds the negative reactivity necessary to reduce the critical boron concentration, which in turn reduces the MTC, maintaining it below the Technical Specification limit. To avoid such time consuming and costly delays -in power ascension, we propose to revise the current Technical Specification limit to provide more operatingglexibility. The desired change is to permig ,

the MTC limit to ramp down from +0.7x10- delta Rho / F at 70% power to +0.5x10- '

delta Rho / F at 100% power.

I An increase in the positive Moderator Temperature Coefficient (MTC) limit has an 1 impact primarily on the heatup transients and the peak reactor coolant system pressure resulting from such events. The more positive MTC limit may also affect the reactivity insertion as c. function of moderator density input to the LOCA evaluations. Of the non-LOCA transients potentially affected it was determined that only the Feedline Break (FLB) transient required reanalysis due to the increased positive MTC limit. Other events which could potgntially be affected by a more positive MTC have been evaluated for an MTC of +.7x10- delta Rho /cF during the Unit 1 Cycle 8 and the Unit 2 Cycle 7 reload effort. Reanalysis of the events whose results were judged to be adversely affected by the more positive MTC were presented in the Unit 1 Cycle 8 and Unit 2 Cycle 7 analyses, docketed in References (f) and (g). In addition, physics analyses showed that the reactivity insertion versus moderator density curve used in the Unit 1 Cycle 8 i

and Unit 2 Cycle 7 LOCA analyses described in Referegces (f) and (g) conservatively bounded the one calculated for a po'sitive MTC of +0.7x10 delta Rho / F.

The FLB is not a Design Basis Event for Calvert Cliffs plants. The high elevation of the steam generator feedwater nozzles minimizes the loss of steam generator water inventory and the resultant heat-up and pressurization effect that the FLB event is

! analyzed for. However, an analysis of this event conservatively assuming a feedwater

! nozzle located near the bottom of the steam generator is submitted (Attachment 1) to illustrate the consequences of extreme heat-up of the primary. Reanalysis of the FLB event demonstrated that the peak RCS pressure for this event meets its analysis

criteria. The basis for the subject Technical Specification (i.e., Technical Specification 4

3.1.1.4), therefore, is unchanged by changing the positive MTC limit. The new Technical l

. Specification limit continues to ensure that the assumptions used in the accident and l transient analysis remain valid throughout each fuel cycle.

1 DETERMINATION OF SIGN!FICANT HAZARDS CONSIDERATIONS

, This proposed change has been evaluated against the standards u.10 CFR 50.92 and has l been determined to involve no significant hazards considerations, in that operation of the facility in accordance with the proposed amendment would not:

i

Mr. Ashok C. Thadani July 31,1986 Page 15 (i) involve a significant increase in the probability or consequences of an accident previously analyzed.

The proposed change to the MTC limit is an input parameter in various transient and accident analysis. Allowing the operating MTC to be more positive does not influence whether or not the transient is more or less likely to occur. As described above, safety analyses have been performed to demonstrate that any transients or accidents whose results

+

would be affected by a more positive MTC limit do not have consequences that are significantly worse than previously evaluated. In addition, the analyses, incorporating the proposed change in MTC limit continue to demonstrate that all appropriate analyses criteria reported in the Reload Analysis Report (References f and g) are met. In particular, the change does not increase previously calculated site boundary doses and the resultant peak RCS pressures are withm the limits established by the analyses criteria. Therefore, the proposed change in the Technical Specification MTC limit does not involve any significant increase in the probability or consequences of an accident previously evaluated.

(ii) create the possibility of a new or different type of accident from any accident previously analyzed.

The proposed change does not involve a change to any component system alignment, or operative procedure and would not create the possibility of a new or different type of accident.

(iii) involve a significant reduction in margin of safety.

Safety analysis calculations showed that incorporation of the more positive MTC limit does not have a significant impact on the results; and, that the results are still within the acceptance criteria. Therefore, the operation of the facility in accordance with the proposed change involves no significant reduction in margin of safety.

SAFETY COMMITTEE REVIEW These proposed changes to the Technical Specifications and our determination of significant hazards have been reviewed by our Plant Operations and Off-Site Safety Review Committees, and they have concluded that implementation of these changes will not result in an undue risk to the health and safety of the public.

Mr. Ashok C. Thadani July 31,1986 Page 16 tet:ti uETERMINATION Pursuant to 10 CFR 170.21, we are including BG&E Check No. (1063885) in the amount of

$150.00 to the NRC to cover the application fee for this request.

Very truly yours, 9

STATE OF MARYLAND

TO WIT:

CITY OF BALTIMORE  :

Joseph A. Tiernan, being duly sworn states that he is Vice President of the Baltimore Gas and Electric Company, a corporation of the State of Maryland; that he provides the foregoing response for the purposes therein set forth; that the statements made are true and correct to the best of his knowledge, information, and belief: and that he was authorized to provide the response on behalf of said Corporation.

WITNESS my Hand and Notarial Seal: bLv1 s T

// otary Pubifc My Commission Expires: I -- / - / /)

3AT/BEH/PA: /3ES/dlm Attachments cc: D. A. Brune, Esquire

3. E. Silberg, Esquire D. H. Jaffe, NRC T. Foley, NRC T. Magette, DNR

l ATTACHMENT 1 Feedline Break Event Introduction The Feedline Break (FLB) event was analyzed for Calvert Cliffs Units 1 and 2 to assure that the integrity of the RCS pressure boundary is maintained and that the site boundary doses do got exceed 10CFR100 guidelines when the MTC limit is increased from

+0.2 x 10- delta Rho / F for powers between 70% and ig0% to a limit which ramps down from +.7x10 4 delta Rho / F at 70% power to +0.5x10- delta Rho / F at 100% power.

The event was analyzed 1) with loss of AC power on reactor and turbine trip and compared to the RCS pressure criterion of 12096 of design (3000 psia) and 2) with AC power available following reactor and turbine trip and compared to the pressure criterion of 110% of design (2750 psia). A spectrum of break sizes were considered and the results of the limiting break sizes for the above cases are presented herein.

Identification of Event and Causes The FLB event is initiated by a break in the Main Feedwater System (MFS) piping.

Depending on the break size and location and the response of the MFS, the effects of a break can vary from a rapid heatup to a rapid cooldown of the Nuclear Steam Supply System (NSSS). In order to discuss the possible effects, breaks are categorized as small if the associated discharge flow is within the excess capacity of the MFS, and as large if 4 otherwise. Break locations are identified with respect to the feedwater line reverse flow check valve. The reverse flow check valve of concern is located betiveen the steam 4

generator feedivater nozzle and the containment penetration. Closure of the check valve, to prevent reverse flow from % etmm generator, maintains the heat removal capability of that steam generator la me , .esence of a break upstream of the check valve.

~

Feedwater line breaks upstream of the reverse flow check valve can initiate one of the following transients. A break of any size, with MFS unavailable, will result in a Loss of j Feedwater Flow (LOFW) event. A small pipe brear; with MFS available will result in no reduction in feedwater flow. Depending on the break size, & iarge break with MFS available will result in either a partial or a total LOFW event. Since FLBs upstream of the reverse flow check valve result in transients no more severe than a LOFW event,

these FLBs were not analyzed.

In addition to the possibility of partial or total LOFW, FLBs downstream of the' check valve have the potential to establish reverse flow from the affected steam generator back to the break. Reverse flow occurs whenever the MFS is not operating subsequent to a pipe break, or when the MFS is operating, but without rufficient capacity to maintain

} pressure at the break above the steam generator pressure. FLBs which develop reverse flow through the break are limiting with respect to primary overpressure. Thus, only

, these FLBs were considered in the analysis.

FLBs downstream of the check valve with reverse flow may result in either a RCS heatup or a RCS cooldown event, depending on the er.thalpy of the reverse flow and the heat transfer characteristics of the affected steam generator. However, excessive heat removal through the feedwater line break is not considered in the analysis because the coo!down potential is less than that fcr the Steam Line Break (SLB) event. This occurs because SLBs have a greater potential for discharging high enthalpy fluid due to the location of the steam piping which is located above the feedwater pipjng within a steam generator. In addition, the maximum break area for a FLB is 2.2 f t in comparison to 6.305 f t2 for a SLB.

I L

- . . , m. _.

Unlike SLBs, FLBs cause a decrease in feedwater flow, resulting in lower steam generator liquid inventory which reduces the heat removal capacity. The reduced heat transfer capability results in a rapid RCS overpressurization and thus, it is the heatup potential of a FLB which was analyzed.

A general description of the FLB event downstream of the check valves, with the MFS unavailable and with low enthalpy break discharge, is given below. The loss of subcooled feedwater flow to both steam generators causes increasing steam generator temperature, decreasing ' liquid inventories and decreasing water levels. The rising secondary temperature reduces the primary-to-secondary heat transfer, which results in a heatup and pressurization of the RCS. The hea' tup i .comes more severe as the affected steam generator experiences a further reduct9 in its heat transfer capability due to decreasing liquid inventory. The heatup the RCS and the depletion of liquid inventory in the steam generator will initiate a teactor trip on either high pressurizer pressure or steam generator water level. The heatup can continue even after a reactor trip, due to a total loss of heat transfer in the affected steam generator as the liquid inventory is completely depleted. The rise in RCS pressure causes the pressurizer safety valves (PSVs) to open. The rise in secondary pressure is limited by the opening of the Main Steam Safety Valves (MSSVs). The opening of the PSVs and the MSSVs, in conjunction with the reactor trip (which reduces core power to decay level), mitigates the RCS overpressurization.

The reduction of liquid inventory in the unaffected steam generator in conjunction with low S.G. level signal initiates AFW flow to the unaffected steam generator. Automatic initiation of AFW is sufficient tn provide a continued heat sink for the removal of decay heat.

Analysis Assumptions and Initial Conditions The following is a discussion of the conservative assumptions and initial conditions chosen to maximize RCS pressure. Blowdown of the steam generator nearest the feedwater line break is modeled assuming frictionless critical flow as calculated by the ,

Henry-Fauske correlation (Reference A). The Feedwater Line Break location is conservatively modeled to be near the bottom of the steam generator, even though, in

^

reality, the feedwater line nozzle is at a much hi' gher elevation within the steam generator. The analysis assumes that saturated liquid is discharged through the break ,

until the feedwater nozzle is uncovered, at which time saturated steam discharge is assumed. This assumption maximizes the liquid inventory discharge through the break, minimizes the energy removal from the primary by the steam generator, and thereby maximizes the RCS overpressurization.

I The analysis also assumes that the effective heat transfer area is decreased linearly as l . the steam generator liould mass decreases. The mass intarval over which the rampdown is assumed to occur was conservatively chosen to model a rapid loss of heat transfer in the affected steam generator.

To maximize RCS pressure, the analysis conservatively credits only the high pressurizer pressure trip. This assumption maximizes the rate of change of pressure at the time of trip, and thus the peak pressure obtained following the trip. The analysis does not credit i either the high containment pressure trip or the steam generator low water level trip.

Table 1 presents the initial conditions chosen to maximize the RCS pressure. A Moderater Temperature Coefficient of +0.5x10~ delta Rho / F corresponding to 100%

power at beginning of cycle conditions is assumed. This combination of MTC and power

(.

~r -- - + , , - - _ _ , . , - - - _ , _ .--m- ----,--.-m _ -

w ,,,_.y -

_ - --.- -. ---.-e---. -.y--

results in the most severe primary heatup and pressurization since the increased heatup due to more positive MTC limits at powers below 100% is more than compensated for by lower initial powers. The positive MTC, in conjunction with increasing coolant temperatures, adds positive reactivity, and thus maximizes the rate of change of heat

. flux and pressure at the time of trip. A Fuel Temperature Coefficient ~ (FTC) corresponding to beginning of cycle conditions is used in the analysis. This FTC causes the least amount of negative reactivity feeoback, allowing higher increases in both the heat flux and RCS pressure. An uncertainty factor of 15% is applied to FTC.

An initial RCS pressure of 2154 psia is used in the analysis to maximize the rate of change of pressure at time of trip, and thus the peak pressure obtained following a reactor trip. An initial steam generator pressure of 815 psis is assumed in the analysis.

This pressure delays the opening of the Main Steam Safety Valves (MSSVs) and maximizes the peak RCS pressure.

The Steam Dump and Bypass System (SDBS), the Pressurizer Pressure Control System (PPCS), the Pressurizer Level Control System (PLCS) and the Power Operated Relief Valves (PORV) are assumed to be in the manual mode of operation. This assumption enhances the RCS pressure increase, since the automatic operation of these systems

mitigates the RCS pressure increase. The analysis also assumes that the steam generator feedwater flow to both steam generators is instantaneously reduced to zero at initiation of the event.

This analysis conservatively assumed no automatic initiation of auxiliary feedwater. This assumption increases the RCS heatup and pressurization following the trip in the FLB event. Credit was taken for manualinitiation of auxiliary feedwater 10 minutes into the event. A conservative delay time of 58 seconds was assumed for the auxiliary feedwater to reach the steam generator. The flow to the unaffected steam generator is 434 gpm.

No auxiliary feedwater flow to the affected steam generator was assumed.

The assumptions made to maximize the boundary site dose are given in Table 2. During the event, two sources of radioactivity contribute to the site boundary dose: (1) the initial activity in the steam generator and (2) the activity associated with primary to secondary leakage. The leakage through the steam generator tubes is assumed to be the Technical Specification limit of 1.0 GPM. The initial. primary and secondary activities are assumed to be at the Technical Specification limits of 1.0 uCi/gm and 0.1 uCi/gm, respectively. The analysis assumes that all of the initial activity in the steam generators and the primary activity due to the tube leakage are released to the atmosphere with a decontamination factor of 1.0, resulting in the maximum site boundary dose.

i Results The FLB Went with Loss of AC (LOAC) power on reactor trip results in the maximum RCS pressum. This occurs because loss of AC power causes the Reactor Coolant Pumps

to coastdown. The reduced core flow decreases the rate of heat removal and thus maximizes the primary heatup and over-pressurization. However, the results of the FLB event with LOAC power on reactor trip and with AC power available following trip are presented herein since the latter case has a closer approach to its respective pressure criterion.

Figure 1 presents the results of a parametric study to determine the break size which leads to the highest RCS peak pressure that was performed in the Calvert Cliffs Unit 2

. Cycle 5 FLB event analysis. The trend and conclusions of this parametric study are valid in this analysis. Figure 1 shows that, initially, as the break size increases, so does the

-3_

peak RCS pressure. This is due to faster water drainage out of the ruptured steam

i. generator, which will cause a more rapid primary to secondary heat transfer rampdown.

However, as the break size increases further, the greater steam relieving capacity of larger breaks (once the ruptured stearn generator feedwater nozzle uncovers) will offset the faster heat transfer rampdown and will result in lower peak pressure. The highest peak pressure was obtained for a break size or u.m it- for both the LOAC power on reactor trip and the AC power available following trip cases.

The sequence of events for the 0.325 f t2Feed Line Break downstream of the reverse flow check valve are given in Tables 3 for LOAC on trip and in Table 4 for AC power available following trip. Figures 2 through 7 present the transient behavior of core power, core average heat flux, RCS temperatures, RCS pressure, steam generators pressures and steam generators liquid inventories, respectively, for 1800 seconds for the case with LOAC at reactor trip. Figures 8 through 13 present the same parameters for the case with AC power available following reactor trip.

A 0.325 ft 2break in the main feedwater line is assumed to instantaneously terminate feedwater flow to both steam generators and establish critical flow from the steam generator nearest the break. During the first 22.2 seconds of the event, the absence of subcooled feedwater flow causes the secondary pressure and temperature to increase, which reduces the primary to secondary heat transfer. This causes the primary pressures and temperatures to increase and results in a power. increase in the presence of a positive MTC. At 22.5 seconds, the liquid inventory in the ruptured steam generator is sufficiently depleted to cause a further rampdown in the heat transfer rate. This causes

~

the primary pressure and temperature to rapidly increase and at the same time causes the secondary pressure to decrease.

The rapid increase in primary pressure initiates a High Pressurizer Pressure Trip at 25.0 seconds. At 25.6 seconds, the pressure reaches 2525 psia, at which time the Pressurizer Safety Valves (PSVs) open to mitigate the increase in primary pressure. At 26.2 seconds, the turbine stop valves close, increasing the secondary pressure. At 26.2 seconds, the CEAs begin to drop into the core, inserting negative reactivity which mitigates the primary heatup. .

The Reactor Coolant Pumps (RCPs) are assumed to ini.tiate flow coastdown for the case 4

with LOAC power on turbine trip. For this case, the sequence of events following the reactor trip and RCP coastdown is as follows: the rapid decrease in core flow slows down the rate of heat removal from the primary. At 25.8 seconds, the feed nozzle is uncovered and steam is discharged through the break, which mitigates the primary i heatup. These competing effects result in a peak RCS pressure below 2800 psia at 29.1 l seconds.

! At 168.0 seconds the Steam Generator Isolation Setpoint is reached. After appropriate delays, the Main Steam Isolation Valves (MSIVs) fully close at 174.9 seconds. This causes the pressure in the undamaged steam generator to increase and the pressure in the damaged steam generator to continue to decrease through blowdown through the rupture.

The water level in the undamaged steam generator continues to decrease as a result of boil-off. At about 230 seconds the liquid inventory in the undamaged steam generator is sufficiently depleted that there is no heat transfer from primary to secondary. This causes the primary pressure and temperature to increase again. The increase in primary pressures results in the opening of PSVs at 382.5 seconds.

c i

- - , , - --, rvy- - , , - - - . - - - - - -

- -. . . - - . - . -- =. _ - .. .

The analysis conservatively assumes that auxiliary feedwater is initiated manually at 600 seconds rather than automatically by the low steam generator level instrumentation

The sequence of events for the case with AC power available following trip is slightly different due to availability of forced circulation in the primary ard is presented in Table 4.

The resultant site boundary dose calcuated with the assumptiens given in Table 2 is:

Thyroid (DEQ I-131) = 2.2 REM Whole Body (DEQ Xt-133) 0.1 REM Conclusion The results of the FLB event with Loss of AC porter on reactor / turbine trip shows that l

the peak RCS pressure is much lower than its corresponding limit of 3000 psia. The results of the FLB cvent with AC power available shows that the peak RCS pressure does ,

not exceed its corresponding criterion of 2750 psia. The site boundary doses are within 10CFR100 guideline lirnits.

References A. R. E. Henry, H. K. Fauske, "The Two Phase Critical Flow of One Component Mixtures in Nozzles, Orifices and Short Tubes", Journal of Heat Transfer, Transactions of the ASME, May 1971 1

e

+

b 4

)  ;

TABLE 1 KEY PARAMETERS ASSUMED IN THE FEEDWATER LINE BREAK ANALYSIS Parameter Units Value Initial Core Power Level MWt 2754.0 Initial Core Coolant inlet Temperature F 550.0 Initial RCS Vessel Flow Rate gpm 370,000 Initial Reactor Coolant System Pressure psia 2154.0 Initial Steam Generator Pressure psia 815.0 Initial Pressurizer Liquid Volume it 975.0 Moderator Temperature. Coefficient x10-4 delta Rho / F +0.5 Doppier Coefficient Multiplier .

- 0.85 High Pressurizer. Pressure Trip Setpoint psia 2470.0 r

Auxiliary Feedwater Actuation Manual Initiation 600 sec.

CEA Worth at Trip  % delta Rho -5.3 Reactor Regulating System Operating Mode Manual **

Steam Dump and Bypass Steam Operating Mode Manual **

  • Pressurizer Pressure Control System Operating Mode Manual **

Pressurizer Level Control System ' Operating Mode Manual **

    • These modes of control system operation maximize the RCS peak pressure.

l i

n.

l TABLE 2 ASSUMPTIONS FOR THE RADIOLOGICAL EVALUATION FOR THE FEED LINE BREAK EVENT Parameter Units - Value Reactor Coolant System Maximum uCi/gm 1.0 Allowable Concentration Steam Generator Maximurg Allowable uCi/gm 0.1 Concentration (DEQ 1-131)

Partition Factor Assumed for All Doses -- 1.0 2 3 1.80x10-4 Atmospheric Dispersion Coefficient sec/M Breathing Rate M3/sec 3.47x10-4 Dose Conversion Factor (1-131) ' REM /Ci 1.48x10 6

~

1 Tech Spec Limits-2 0-2 Hour Accident Conditions O

)

TABLE 3 SEQUENCE OF EVENTS FOR FEED LINE BREAK EVENT WITH LOAC FOLLOWING REACTOR TRIP Time (Sec) Event Setpoint or value 0.0 Break in Main Feedwater Line .325 f t 2 22.2 Heat Transfer Area Rampdown in LHSG Begins 19691 lbm 25.0 High Pressurizer Pressure Trip Setpoint 2470 psia is Reached 25.6 Primary Safety Valves Begin to Open 2525 psia 26.2 CEAs Begin to Enter Core; LOAC on Turbine --

Trip; RCS Pumps Begin to Coastdown 29.1 Peak'lkCS Pressure 2800 psia 43.8 Maximum Steam Generator Pressure 1026/1039 ridarnaged/ Damaged 44.3 Primary Safety Valves are Closed 2424 psia 168.0 . Main St'eam Isolation Setpoint is Reached 600 psia 174.9 Main Steam Isolation Valves are Fully Closed -

382.5 ~ Primary Safety Valves Begin to Open 2525 psia ,

658.0 Auxiliary Feedwater Flow Established to 434 gpm Undamaged Steam Generator 703.5 :Jndamaged Steam Generator Safety Valves 1050 psia Begin to Open 771.0 Primary Safety Valves are Fully Closed 2424 psia

TABLE 4 SEQUENCE OF EVENTS FOR FEED LINE BREAK EVENT WITH AC POWER AVAIL'ABLE FOLLOWING REACTOR TRIP Time (Sec) Event Setpoint or Value 0.0 Break in Main Feedwater Line .325-22.2 Heat Transfer Area Rampdown in LHSG Begins 19691 lom 25.0 High Pressurizer Pressure Trip Setpoint 2470 psia is Reached 25.6 Primary Safety Valves Begin to Open 2525 psia 26.2 CEAs Begin to Enter Core --

29.0 Peak RCS Pressure 2750 psia 41.4 Primary Safety Valves are Closed. 2424 psia 42.6 Undamaged Steam Generator Safety 1050 psia Valves Begin to Open 45.7 Maximum Steam Generator Pressure 1054/1040 psia Undamaged / Damaged 53.7 Und'amaged Steam Generator Safety 1050 psia Valves are Closed

. -161.3 ' Main Steam Isolation Setpoint is Reached 600 psia .

168.2 Main Steam Isolation Valves are Fully Closed -

. 303.3 Primary Safety Valves Begin to Open 2525 psia 653.0 Auxiliary Feedwater Flow Established to 434 gpm Undamaged Steam Generator 821.5 Undamage.d Steam Generator Safety Valves 1050 psia Begin to Open 901.7 Primary Safety Valves cre Fully Closed 2424 psia

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