ML20196K638

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Forwards Response to NRC 990310 RAI Re TS Change Request 279 Re Core Protection Safety Limit,Previously Submitted in Licensee .B&W Document 32-1203121-01, Fsplit Certification Analysis Also Encl
ML20196K638
Person / Time
Site: Three Mile Island Constellation icon.png
Issue date: 03/26/1999
From: Langenbach J
GENERAL PUBLIC UTILITIES CORP.
To:
NRC OFFICE OF INFORMATION RESOURCES MANAGEMENT (IRM)
Shared Package
ML20196K642 List:
References
1920-99-20088, NUDOCS 9904050023
Download: ML20196K638 (62)


Text

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{ GPU Nuclear. Inc.

( :ioute 44'. south NUCLEAR Post Offee Box 480 Middletown, PA 17057-0480 Tel 717-944-7621 March 26,1999 1920-99-20088 U.S. Nuclear Regulatory Commission Attention: Document Control dea Washington,DC 20555 Ladies and Gentlemen:

Subject:

Three Mile Island Nuclear Station, Unit 1 (TMI-1) l Operating License No. DPR-50  !

Docket No. 50-289 Additional Information - Technical Specincation Change Request No. 279 Core Protection Safety Limit 1

This letter provides the additional information, requested by the NRC in a letter dated March 10,1999, regarding TMI-1 Technical Specification Change Request No. 279 previously submitted to the NRC in GPU Nuclear letter dated December 3,1998 (1920-98-20669).

If any additional information is needed, please contact Mr. David J. Distel, Nuclear Licensing  ;

and Regulatory Affairs at (973) 316-7955.

Sincerely,

'"b James W. Langenbach Vice President and Director, TMI

/DID i

Attachment I - itemized Questions / Responses Attachment II - Be'.V Document No. 32-1203121-01, "FSPLIT Certification Analysis

4 t . cc: Administrator, Region I O D\

TMI-I Senior Project Manager TMI-I Senior Resident Inspector File No. 98195 -

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t 9904050023 990326 PDR ADOCK 05000289 P PDR ,,J

7 Attachment I 1920-99-20088 Page1of52 ATTACHMENTI Reactor Systems Branch

1. NRC Ouestion Please provide the following information for the loss-of-coolant flow, loss of electric power, main steam line break, steam generator tube rupture, large and small break loss-of-
coolant accidents (LOCAs), lo.s of normal feedwater, and anticipated trc'isient without scram events; and the steam generator overfill and natural circulation evaluations in order to allow the staff to conduct its review of the propose  ; hanger is modeled to conservatively remove pump heat only from the RCS.

l Table 2 summarizes the analysis input values used and provides a sequence of events  ;

for the stanup accident. These values are consistent or more conservative than the i S AR values.

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Attachment I 1920-99-20088 l Page 6 of 52 i ANALYSIS RESULTS As discussed above, sensitivity studies determined the most limiting RIR to be  ;

2.1308e-04 Ak/k/s. The peak neutron power for this RIR is about i12% as shown in l Figure 1. The power rise is terminated by the negative Doppler effect. The transient is terminated when the high RCS pressure trip takes effect at approximately 36 seconds.  ;

Figure 2 shows the peak thermal flux is 57.8% for this case, which is significantly less than the thermal flux at rated power. Figure 3 shows the pressure in the lower plenum.

The peak RCS pressure for this event is 2707.7 psia at 38.2 seconds. Figures 4 and 5 show the average fuel temperature and the average moderator temperature for the j transient, respectively. The average fuel temperature for an average rod never exceeds 1015 F. Thus the acceptance criteria for the startup accident are met with considerable margin.

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F Attachment I 1920-99-20088 Page 7 of 52 TABIE 1 I TMI-l FSAR Chapter 14 Event Acceptance Criteria & Analysis Summary Event Acceptance Criteria 20% Average SGTP Analysis Summan*

Stanup Accident 1. Reactor coolant system pressure shall Analyzed using RETRAN02 (GPUN i I

not exceed 110% of design or 2750 Calculation C-1101-224-E610-068). The psig. NRC approved use of RETRAN02 for

2. Fuel pins shall not experience use by GPUN in Reference 1.

departure from nucleate boiling or exceed centerline fuel melt limits. Acceptance criteria met wi@ considerable This is ensured by requiring that peak marga core thennal power does not exceed the design overpower value (112%

rated power).

Rod Withdmwal at 1. Reactor coolant system pressure shall This event was not reanaly2ed. The Rated Power not exceed 110% of design or 2750 pressure response with SGTP is bounded psig. by the stanup accident, and thermal

2. Fuel pins shall not experience power will not be affected since the departure from nucleate boiling or doppler and moderator feedback will exceed centerline fuel melt limits. remain approximately the same.

This is ensured by requiring that peak core thermal power does not exceco the design overpower value (112%

rated power).

Moderator Dilution 1. Reactor thennal power will be limited This event was not reanalyzed. This is a l Event to less than the design overpower, i.e. slowly developing transient, and the ,

less than 112 percent of full power highest rate of dilution with SGTP can be !

(2568 M Wt). handled by the automatic control system.

2. RCS pressure will be limited to less than 110 percent of the design pressure, i.e. less than 2750 psig.
3. A minimum reactor subcritical margin of 1% delta k/k will be maintained.

Cold k'ater Accident 1. Maintain the RCS pressure boundary This event was not reanalyzed. Due to l intact by maintaining the RCS the short duration of the transient (<l5 l pressure below 110 percent of design secs), SGTP will have an insignificant l pressure, i.e. <2750 psig. effect on the results.

2. Protect the core against potential damagingincreasm in cladding temperature by mamtaining the pcom i thermal power below 112 percent of full power and thereby maintaining the departure-from-nucleate-boiling ratio (DNBR) greater than the CHF correlation limit.

7 Attachment I 1920-99-20088 Page 8 of 52 TM1-1 FSAR Chapter 14 Event Acceptance Criteria & Analysis Summan-Event Acceptance Criteria 20% Average SGTP Analysis Sumnun-Loss-of-Coolant Flow The acceptance criteria for these events are RCS Loop flowrates calculated using to minimize or prevent damage to the fuel FSPLIT (FTl Proprietary Document cladding. This is accomplished by 32 1234876-02).

demonstrating that the calculated DNBR Flow coa tdown analyzed using does not decrease below a minimum value. RELAPS-B&W (FTl Proprietary For the four and single pump coastdown Document 32-1269014-00).

transients fuel damage is prevented by DNB analyzed using VIPRE-01 and the p esening a minimum DNBR greater than BWC Correlation (GPUN Calculation 1.18 (BWC correlation). For the locked C-1101-202-E620-365). The NRC approved use of VIPRE-01 and the BWC rotor transient, requiring a minimum ,

DNBR of 1.0 minimizes fuel damage. correlation m References 2 and 3.

Acceptance criteria met with vansiderable margin.

Stuck or Dropped Rod 1. Maintain the RCS pressure boundary This event was not reanalyzed. The peak intact by maintaining the RCS pressure increase in the FSAP * %

pressure below 110 percent of design event is only 100 psi, and the al pressure, i.e. < 2750 psig. power never gets higher than tue initial

2. Protect the core against potentially- value. Large margins to the acceptance damagingincreases in cladding criteria will be maintained with 20%

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temperature by maintaining the peak average tube plugging. i thermal power below 112 percent of l full power and thereby providing DNB protection. )

Loss of Electric Power 1. Maintain the RCS pressure boundary Analyzed Station Blackout using intact by maintaining the RCS RETRAN (GPUN Calculation C-110'.- .

presrare below 110 percent of design 202-E610-069). The NRC approved .nse pressure, i.e. <2750 psig. of RETRAN02 for use by GPUN in

2. Prevent fuel damage from an Reference 1. Acceptance criteria met excessive power-to-flow ratio, i.e. with considemble margin. I demonstrate that the minimum depanure-from-nucleate-boiling ratio (DNBR)is not less than the correlation limit.
3. Maintain the resultant doses within the limits specified in Title 10, Paragraph 100 of the Federal Code of i Regulations (10CFR100).

Main Steam Line Break 1. The core will reu..ain intact for This event was not reanalyzed. The effective '., ore cooling, assuming FSAR analysis assumed a conservatively mininw.m tripped rod worth with a large initial steam generator inventory stuck rod, which bounds the steam generator

2. No SG tube break or separation from secondary mass with a maxhnum of 25%

the tube sheet will occur due to aloss SGTP. Tims, recriticality, tube loads and of secondary side pressure and the dose consequences remain bounded by resultant temperature gradient , the UFSAR analysis.

3. Doses will be within 10CFR100 limits.

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Attachment I 1920-99-20088 Page 9 of 52 TMI-l FSAR Chapter 14 Evem Acceptance Criteria & Analysis Summary Event Acceptance Criteria 20% Average SGTP Analysis Summan' Steam Generator Tube 1. The radiological deses calculated for his event was not reanalyzed. The Rupture the event must be within the limits of cooldown time with SGTP will remain 10CFR100. the same as assumed in the UFSAR, and

2. The event should not result in the offsite dose consequences with an additional tube faihires andloss of average 20% SGTP will remain the same reactor coolant boundary integrity as the UFSAR values.

resulting from effects of temperature gradients (i.e. thermally induced tube loading).

Rod Ejection Accident 1. Maintain the RCS pressure boundary This event was not reanalyzed. DNB intact by maintaining the RCS occurs within the first 2 seconds, amt the pressure below 110 percent of design SGTP will not contribute to the amouct of pressure, i.e. <2750 psig. fuel in DNB. The small break LOCA

2. Prevent fuel fragmentation and aspect of this event is bounded by the loss cladding rupture, and thus maintain of coolant accident analysis.

coolable core geometry by limiting the fuel enthalpy to <280 cal /gm.

Loss-of-Coolant 1. The calculated peak cladding Reanalyzed using NRC approved Accident temperatures (PCTs)areless than RELAP5-B&W Evaluation Model(EM) 2200 F. (FTI Proprietary Document BAW-

2. The maximum calculated local 10222P). The calculation was performed cladding oxidation isless than 17.0 in accordance with BWNT Proprietary percent. Document BAW-10192PA-00. j
3. The maximum amount of core-wide oxidation does not exceed 1.0 percent Acceptance criteria met.

of the fuel cladding. l

4. The cladding remains amenable to cooling.

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5. Long-tenn cooling is established and j maintained after the LOCA. _

Loss of Main Feedwater 1. The pressurizer shall not go solid. Analyzed using RETRAN02 (GPUN

2. Reactor coolant system pressure shall Calculation C-1101-224-E610-070). The not exceed 110% of design or 2750 NRC approved use of RETRAN02 for psig. use by GPUN in Reference 1.
3. Fuct pins shall not experience Acceptance criteria met.

departure from nucleate boiling.

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Attachment I 1920-99-20088 Page 10 of 52 TMI-l FSAR Chapter 14 Event Acceptance Criteria & Analysis Summary Event Acceptance Criteria 20% Average SGTP, Analysis Summan-ATWS 1. The maximum RCS pressure shall not This event was not reanalyzed. The exceed 3250 psiain order to maintain diverse scram system install.d in component stress within Senice Level response to the ATWS Rule significantly l C limits, as defined in Section 111, reduces the probability of the event j Division 1 of the ASME Vessel Code. occurrence, and also significantly

2. For events in uhich fuel pins mitigates the consequences of the event. ,

experience depanure from nucleate boiling (DNB), the cladding temperature shall be less than 2200 F; and, the extent of fuel failure slus: be small, so as to not significantly distort the core, impede core cooling or prevent safe shutdown.

3. The calculated radiological consequences shall be within the guidelines set fonh in Title 10, Code -

of Federal Regulations, Part 100 (10CFR100).

4. The calculated containment pressure shall not exceed the design pressure of 1 the containment structure.
5. The reactor shallbe capable of being shutdown and the core maintained amenable to core cooling. i Events Not AfTected Uncomhnsated Operating Reactivity Changes Fuel Handling Accident Waste Gas Tank Rupture Fuel Cask Drop  !

Maximum 11ypothetical Accident 1

References:

1. NRC Letter from Bart C. Buckley, NRC, to James Knubel, GPUN, " Review of Topical Report TR-078, Resision 0, Entitled TMI-1 Transient Analyses Using the RETRAN Computer Code (TAC No. M92167)", dated February 10,1997.
2. NRC Letter from Jan A. Nonis, NRC, to James Knubel, GPUN, "Resiew of Topical Repon TR-087 Entitled TMI-l Core Thermal-Hydraulic Methodology using VIPRE-01 Computer Code for Three Mile Island Unit 1 (TAC No.

M92168)", dated December 19,19%.

3. NRC Letter from Bart C. Buckley, NRC, to James W. Langenbach, GPUN, " Review of Topical Report TR-092 Entitled "TMI-l Reload Design and Setpoint Methodology" for the Three Mile Island Nuclear Power Station. Unit No.1 (TAC No. M94908)", dated April 22,1997.
4. NRC Letter from James E. Lyons, NRC, to J. H. Taylor, IT1, " Acceptance for Referencing of Topical Report j BAW-10192-P, "BWNT Loss-of-Coolant Accident Evaluation Model fer Once-Through Steam Generator Plants"(TAC .

No. M89400)", dated Febmary 18,1997. l

5. BWFC Document 32-1218686-00, " Maneuvering Analysis inputs: 92J", dated 2/24/93. '
6. FSPLIT Qualification Report - B&W Document No. 32-1203121-01, dated September 20,1991.  !

7, NRC Letter from C.O. Thomas, NRC, to Dr. T. W. Scimatz, " Acceptance for Referencing of Licensing Topical Reports l EPRI CCM-5, "RETRAN-A Program for One Dimensional Transient Thermal Hydraulic Analysis of Complex Fluid l Flow Systems," and EPRI NP-1850-CCM, "RETRAN-02-A Program for Transient Thermal-Hydraulic Analysis of I Complex Fluid Flow Systems," dated September 2.1984.

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z Attachment I 1920-99-20088 Page11of52 TABLE 2

SUMMARY

OF STARTUP ACCIDENT ANALYSIS INPUT VALUES PARAMETER FSAR VALUE ANALYSIS VALUE 20% SGTP HZP BOC Moderator Temperature 0.0 9.0 Coefficient, pcmfF HZP BOC Doppler Coefficient pcm/ F -1.17 -1.17 HZP Delayed Neutron Fraction, per 0.007 0.007 PSV Capacity Ibm /hr/ valve 300,600 297,846 PSV Setpoint Drift, % 0 3 Initial Core Power, Wt 2.535 2.568 High Flux Trip, percent full power 112 112 High Flux Trip Delay Time, sec 0.3 0.4 High Pressure Trip, psia 2400 2402 High Pressure Trip Delay Time, sec 0.5 0.6 RCS Inlet Temperature, F 540 525 Initial RCS Pressure, psia 2170 2170 Sequence of Events Startup Accident Event Time, seconds Reactivity insertion intiated 0.001 Power rise terminated due to Doppler effect 32.5 RCS high pressure trip setpoint reached 36.15 Peak Thermal power reached (57.8%) 36.8 PSV setpoint reached 37.77 Peak RCS pressure reached (2707.7 psia) 38.2 End of transient 40.0 l

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'Attachm:nt I

- 1920-99-20088 Page 12 of 52 '

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Figure 1: Neutron Power For Startup Accident at 2568MWt om Om .

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a00 0.0 10A 240 JOA 4CA Tne (t)

Figure 2: Thermal Power for Startup Accident at 2568MWt 1

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1920-99-20088 Page 13 of 52 Moo.o voon .

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o.0 10.o 2o.0 30.0 4cA Time (s)

Figure 3: Lower Plenum Pressure For Startup Accident at 2568MWt 12 cob 11ooA -

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Figure 4: Average Fuel Temperature For Startup Accident at 2568MWt l

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Attachment I 1920-99-20088 Page 14 of 52

=0 C

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04 10.0 20.0 30.0 40A

  • = M Figure 5: Average Core Moderator Temperature for Startup Accident at 2568MWt

Attachm:nt I 1920-99-20088 Page 15 of 52 i

B. LOSS OF COOLANT FLOW DISCUSSION OF LOSS OF COOLANT FLOW ACCIDENTS The loss of coolant flow (LOCF) accidents are the most limiting for minimum DNBR.

The three most DNB-limiting transients that are directly fependent on the lower reactor coolant system (RCS) flow rate resulting from steam generator tube plugging include:

1. Four Pump Coastdown (4-+0)
2. One Pump Coastdown (4-+3)
3. Locked Rotor (4-+3)

A reduction in the reactor coolant flow rate occurs if one or more of the RC pumps fail (four and single pump coastdown events). A pump failure can occur from mechanical failure or from a loss of electrical power. With the reactor at power, the coolant flow j reduction results in a reduction in heat removal capability which will increase the RCS j temperature. The safety criterion of these two events is the DNB protection. Reactor  !

protection for the four pump coastdown accident is provided by the power / pump monitors trip function of the reactor protection system, while the single pump coastdown event is terminated by the flux / flow setpoint. The power / pump monitor produces a reactor trip if(1) two RC pumps are tripped in one coolant loop, and (2) power level is higher than or equal to 55% of rated power when one pump is operating in each coolant loop.  :

The locked rotor event occurs when one of the RC pump rotors seizes and no longer provides forced flow to the reactor coolant. When the notor seizes, total RCS flow is assumed to decrease to 73% of full flow in 0.1 second. Reactor protection for this i accident is provided by the flux / flow trip.

i AN'ALYSIS ASSUMPTIONS ,

The initial power level for both four pump coastdown and locked rotor accident is 102% of 2568 MWt, and incorporates a 2% heat balance error required by Regulatory Guide 1.49. The single pump coastdown is not a FSAR Chapter 14 event. However, the analysis was performed to evaluate the applicability of the flux / flow trip setpoint in the existing Technical Specification. The initial core inlet temperatures include 2 F instrument error. The RCS flows used in the FSAR Chapter 14 Accident Analysis are conservatively based on 100.0% of design flow. The average measured RCS flow rates for TMI-1 are 110 % of design flow, and 106.5% of design flow has been conservatively used for recent analysis. In order to re-analyze these events for 20%

tube plugging, analyses were performed to determine RCS loop flow rates and pump coastdown flow rates. As described in the Technical Specification Change Request (TSCR) No. 279 submittal, a minimum flow of 102% of design flow is used and includes a 2% instrument error and an additional 1.8% flow reduction for conservatism.

The RCP flow coastdown was based on conservative RELAP coastdown predictions.

The initial conditions for the LOCF events are summarized in Table 3.

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Attachment I 1920-99-20088 Page 16 of 52 ANALYSIS RESULTS Figure 6 shows the minimum DNBR results for 4-01oss of coolant flow accidents. As shown on Figure 6, a minimum DNBR of 1.669 occurs at 1.5 seconds for the 4-0 pump coastdown transient. As desc.ibed in the Technical Specincation Change Request (TSCR) No. 279 submittal, the locked rotor event is analyzed as a single state point at 73% full flow and 102% rated power. This resulted in a minimunt DNBR of 1.276.

The results show that acceptable minimum DNBR exists for the loss of coolant flow accidents and there will be no fuel damage resulting from 20% average steam generator tube plugging.

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Attachment I 1920-99-20088 Page 17 of 52 Table 3

SUMMARY

OF L OSS OF COOLANT FLOW ANALYSIS INPUT VALUES System Parameters Locked Rotor Four Pump Trip Reactor Power (%) 102 102 RCS Flow (gpm) 359,040 359,040 Inlet Temperature (F) 556.21 556.21 Minimum DNBR Results 1.276 1.669 Reactor Trip function flux / flow trip (=1.08) power / pump monitor Trip Delay Time (sec) 2 0.62 f

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Attachment I 2920-99-20088 Page 18 of 52 Hgure 6 i Four Pump Trip (4-to4)) DNBR Result for 20% average UFSG

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2.5 20' g h0NBR= 1.669 g

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at t= 0.62 semnd D N n ~ "(*4) ,

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0.5 0.0 0.5 1.0 1.5 2.0 line (second) After Four (4-t04) Pung Trip

T-Attachment I 1920-99-20088 Page 19 of 52 C. LOSS OF FEEDWATER ACCIDENT j DISCUSSION OF LOSS OF FEEDWATER ACCIDENT A loss of feedwater may result from abnormal closure of the feedwater isolation valves, abnormal control valve failure or main feedwater pump failure. A loss of normal flow through the secondary system will result in a reduction in secondary heat removal, causing the reactor coolant system (RCS) temperature to increase. Due to this temperature increase, the reactor coolant begins to expand causing the RCS pressure to l merease.

Increasing RCS temperature and pressure could result in the RCS filling solid, a failure 4 of the RCS, or a fuel cladding failure. Reactor protection for these events is provided by the high RCS pressure trip function of the reactor protection system (RPS). When the RCS pressure reaches the high RCS pressure setpoint, the reactor is tripped.

Shortly after reactor trip, only decay and pump heat are added to the reactor coolant.

Initially, the emergency feedwater (EFW) flow rate is not able to keep up with decay and pump heat. Therefore, the reactor coolant will continue to expand until the EFW heat removal matches decay and pump heat. Subsequent to this point in time, RCS pressure will decrease and the reactor coolant will contract.

ANALYSIS ASSUMPTIONS The initial power level is 2619.34 MWt which is 102% of the rated power level. A heat balance error is required by Regulatory Guide 1.49, which states that the accident analysis calculations must be performed at a power level 2% greater than rated power to account for uncertainties in the determination of power level through the heat balance calculation. Starting the event at a power level higher than nominal is conservative.

The analyses are performed using beginning-of-cycle (BOC) kinetics since these  ;

conditions are the most limiting for this event. A smaller (less negative) Doppler coefficient and a larger (more positive) moderator temperature coeflicient (MTC) are conservative for a loss of feedwater analysis. Since this accident is analyzed from rated power, a 0.0 pcm/ F MTC was used. TMI-1 Technical Spec rications require that the MTC shall not be positive at power levels above 95% rated power.

Reactor trip is modeled to occur when the neutron power reaches 112 percent of rated power of 2568 MWt or when the primary system pressure reaches 2402 psia (2355 psig

+ 32 psi error + 15 psi to absolute) at the hot leg pressure tap. The high pressure trip setpoint includes 32 psi string error.

A trip delay of 0.4 seconds is used for the high flux trip. The high RCS pressure trip delay is modeled as 0.6 seconds. These values represent the delay from the time the trip condition is reached to the time the control rods are free to fall and bound the actual delays for TMI-1.

Attachment I q 1920-99-20088 j Page 20 of 52 The percent of reactivity insertion versus time curve is for 2/3 insertion at 1.4 seconds afler reactor trip. A minimum tripped rod worth (MTRW) of 2.36% Ak/k is used. The MTRW is comprised of a power deficit of 1.2%, a maximum allowable inserted rod worth of 0.16%, and a shutdown margin of 1.0%. This MTRW corresponds to a required minimum shutdown margin of 1% Ak/k and provides for the maximum worth stuck rod.

The initial pressurizer liquid level is set to 232 temperature-compensated inches, which is the typical hot full power (HFP) pressurizer level of 220 inches plus 12 inches error  ;

allowance . The initial cold leg temperature was assumed to be 555.7 F and the initial RCS pressure was 2170 psia in the hot leg, which are the approximate operating values with 20% tube plugging.

The analysis was run with an assumption of 20% average tube plugging in the once-through steam generators (OTSGs). Both loops were adjusted to account for a reduction in the coolant flow area in the primary and a 20% reduction in the heat transfer area between the primary and secondary. Since the Loss-of-Feedwater is a symmetric transient (i.e. feedwater is lost to both OTSGs) and the reactor coolant

, pumps remain operational for this event, an asymmetric tube plugging of 25%/15%

(10% asymmetry) will show the same results as the 20% average tube plugging. The smatter heat removal from the steam generator with the higher tube plugging will be compensated by the larger heat removal through the steam generator with less plugging, resulting in heat removal equivalent to 20% average tube plugging.

The RCS flows used in the FSAR Chapter 14 Accident Analysis are conservatively based on 106.5% of design flow. The average measured RCS flow rates for TMI-l are  ;

110 % of design flow. In order to re-analyze these events for 20% tube plugging, '

analyses were performed to determine RCS loop flow rates and pump coastdown flow rates. As discussed in the TSCR No. 279 submittal, a minimum flow of 102% of design flow or 133.8 Mlbm/hr was used.

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Attachm:nt 1 1920-99-20088 Page 21 of 52 l

The initial steam generator inventory provides a measure of the heat removal capability of the secondary system. For a LOFW, a smaller initial secondary system inventory in the steam generators will lead to a smaller integrated heat removal. The smaller the heat rev. oval, the higher the resultant reactor coolant pressure. The inventory predicted for a steam generator with a level at 50% of the operating range has been calculated to be approximately 39,000 pounds per steam generator. TMI-l normally operates at 60%

of the operating range. In addition, the mass of feedwater between the isolation valves and the affected steam generator (approximately 35,500 lbm) was conservatively not modeled and not available to cool the affected steam generator.

The EFW system is initiated by a low OTSG level signal. The OTSG low level initiation signal of 10 inches is measured by the startup range instruments with an assumed instrument enor of 10 inches. The EFW system was conservatively assumed to deliver flow to the steam generators starting at 43 seconds after the initiation signal with any combination of EFW pumps (1 TDP or 2 MDPs or 1 TDP and 1 MDP). One EFW pump is assumed to have failed which is the worst single failure. EFW is provided at a constant flow of 275gpm to each steam generator 43 seconds after initiation signal. The distribution of flow to each OTSG is less important than having a ,

total flow of 550 gpm. j 1

The flow rate through the pressurizer power operated relief valve (PORV) is 100,000 lbm/hr/ valve at 2450 psig. The flow rate through the pressurizer safety valves (PSVs) is 297,846 lbm/hr/ valve at 2575 psig (the setpoint includes a 3% lift tolerance). The pressurizer spray set point is 2205 psig in the hot leg. The spray capacity is 190 gpm.

Table 4 summarizes the analysis input values to be used. These values bound the TMI specific values.

Two separate transients were analyzed. First, with no credit taken for the PORV or pressurizer sprays to determine peak RCS pressure. The second, with PORV and spray active to determine a worst case pressurizer level. The pressurizer power operated relief valve (PORV) is a non-safety grade component. Therefore it is not usually modeled in safety analysis. However, in the case of a LOFW, actuation of the PORV to control system pressure would aggravate the liquid insurge to the pressurizer.

Consequently, the PORV was included in this analysis to provide a conservative prediction of pressurizer liquid level. Similarly, pressurizer spray is a non-safety grade l pressure control system. However, actuation of pressurizer spray flow could worsen the l pressurizer liquid level response during the event by condensing the pressurizer steam bubble. Consequently, the LOFW accident was analyzed with pressurizer spray to provide a conservative prediction of pressurizer liquid level. l l

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Attachment i 1920-99-20088 Page 22 of 52 ANALYSIS RESULTS The loss of feedwater is conservatively assumed to be initiated by a closure of the feedwater control valves. The feedwater control valves are conservatively assumed to close in 7 seconds. The rapid loss of flow to the OTSGs causes an immediate reduction in OTSG secondary mass as shown on Figure 7 and a consequent reduction in heat transfer, Reduction of primary-to-secondary heat transfer causes Tw and Ta in both loops to increase because OTSG heat transfer is inadequate to remove primary system heat (Figures 8 and 9).

Increasing RCS temperatures increase RCS liquiJ volume and therefore pressurizer level (Figure 10). Increasing level compresser the pressurizer steam bubble, increasing RCS pressure (Figure 12) until the reactor tr:ps on high pressure at 17 seconds (Figure 11). The trip of the reactor and the resultant, momentary drop in average RCS temperature causes a shrink of RCS inventory and a decrease in RCS pressure. Reactor trip also initiates a turbine trip, so thn steam flow out of the OTSGs is reduced, as is heat removal. Reactor power stays at the initial va'ue of 102% of 2568 Mwt until reactor trip, and so thermal power will not exceed this value. EFW flow is maintained constant for the duration of the transient, as no level setpoint for EFW throttling was reached in the OTSGs up to the point of transient termination.

Initially, the EFW flow is not sufficient to remove decay and pump heat, and the system stays pressurized with pressure relief through the pressurizer safety valves as shown on Figure 12. By about 240 seconds, the OTSG heat transfer exceeds the heat generated and the RCS pressure and temperatures start to decrease. The OTSG secondary pressure is maintained at about 1055 psia by the safety valves.

The maximum RCS pressure is predicted to be 2669.4 psia in the lower plenum. In the case allowing for pressurizer spray and PORV, the spray trips on at 10.7 seconds and continues to flow until low pressure signal at 378 seconds. The PSV setpoint is reached once afler 20 seconds and the PORV cycles several times in the first 130 seconds. In the case without pressurizer spray or PORV, the PSV cycles several times in the first 130 seconds. The pressurizer level reaches a maximum 38.7 ft and the pressurizer does not become water solid. The sequence of events for these cases are shown on Tables 5 and 6.

Based on these results, it is concluded that the reactor is protected against a loss of feedwater accident for a power of 2568 MWt with 20% average OTSG tube plugging since the existing UFSAR acceptance criteria are met, This revised discussion of the reanalysis of the Loss of Feedwater Accident supercedes the Loss of Main Feedwater description provided on Page 11 of Enclosure 1 of GPU Nuclear letter 1920-98-20669, dated December 3,1998.

r Attachment I 1920-99-20088 Page 23 of 52 TABLE 4

SUMMARY

OF LOSS OF FEEDWATER ANALYSIS INPUT VALUES PARAMETER ANALYSIS VALUE HFP BOC Moderator Temperature 0.0 Coemcient, pcm/ F HFP BOC Doppler Coemcient, pcmf'F -1.17 HFP Delayed Neutron Fraction, er 0.007 Spray Capacity, gpm 190

  • V Capacity, Ibm /hr/ valve

. 100,000 PSV Capacity, Ibm /hr/ valve 297,846 PSV Setpoint Drift, % 3 i

Initial Core Power, MWt 2619.36 (102% of 2568)

Decay Heat model ANS 1979 (2c uncertainty = 95%) (1.05 multiplier)

High Flux Trip, percent full power 112 High Flux Trip Delay Time, sec 0.4 High Pressure Trip, psia 2402 High Pressure Trip Delay Time, sec 0.6 RCS Inlet Temperature, F 555.7 Initial RCS Pressure, psia 2170 RCS Flow Rate, Mlbm/hr 133.8 EFW Full Flow Rate, gpm 550 EFW Temperature,"F 120

I

'Attachm:nt I - i 1920-99-20088 I Page 24 of 52 l

Table 5 Sequence of Events LOFW with PORV and Spray i Event Time, seconds Main feedwater control valve closure initiated 0.0 Main feedwater flow reaches zero 7.0 Pressurizer spray on 10.72 RCS high pressure trip setpoint reached 17.0 l Turbine trip 17.5 .

l PORV lift (first) 17.63 i 1

Peak RCS pressure reached (2643.8 psia) 20.0 j PSVlift 20.8  !

OSTG low level setpoint reached 50.06 EFW flow initiated 93.06 PORV lift (last) 130.67 Peak RCS temperature reached (613.1l'F) 222.0 Pressurizer spray off 378.71 Peak pressurizer level reached (38.7 ft) 379.0 End of transient 800.0 9

Attachment I 1920 99-20088 Page 25 of 52 i

Table 6 j Sequence of Events LOFW without PORV or Spray _

i Event Time, seconds Main feedwater control valve closure initiated 0.0 Main feedwater flow reaches zero 7.0 RCS high pressure trip setpoint reached 16.94 Turbine trip . 17.44 PSV lift (first) 19.47 Peak RCS pressure (2669.4 psia) 20.J l OSTG low level setpoint reached 50.06 EFW flow initiated 93.06 PSV lift (last) 124.53 Peak pressurizer level (35.0 ft) 233.0 Peak RCS temperature (613.4 F) 236.0 a End of transient 800.0 e

r b

Attachment 1

-1920-99-20088 Page 26 of 52 40000.0 I

ananoa .

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Figure 7: OTSG A Mass for LOFW at 2568MWt e,u s,as -

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Figure 8: Hot Leg RCS Temperature for LOFW at 2568MWt i

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- Attachment I 1920-99-20088 Page 27 of 52 nos

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Figure 10: Pressurizer Level for LOFW At 2568MWt 1

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7 Attachment I J 1920-99-20088

'i Page 28 of 52 e

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Figure 11: Percent of Rated Power for LOFW at 2568MWt l

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E 1 l

)

Attachment I i 1920-99-20088 Page 29 of 52 D. LOSS OF ELECTRIC POWER DISCUSSION OF LOSS OF ELECTRIC POWER ACCIDENT l The loss of all ac power (Station Blackout) transient is the hypothetical case where all unit power except the unit batteries is lost. .A loss of power results in gravity insertion 1 of the control rods and trip of the turbine valves. The reactor coolant pumps, main feedwater and condensate booster pumps will also trip. After the turbine stop valves trip, excessive temperatures and pressures in the reactor coolant system (RCS) are prevented by natural circulation with excess steam relief through the main steam line safety valves and the atmospheric dump valves (turbine bypass valve steam reliefis lost due to loss of power to the condenser cooling water circulating pumps). Excess steam is relieved until the RCS temperature is below the pressure correspor. ding to the set point of the atmospheric dump valves. Thereafter, the atmospheric dump valves are  !

used to remove decay heat. The turbine-driven emergency feedpump (TDP) provides feerlwater for decay heat removal. The TDP takes suction from the condensate storage tanks and is driven by steam from either or both steam generators. Decay heat removal after coastdown of the reactor coolant pumps is provided by the natural circulation characteristics of the system.

ARALYSIS ASSUMPTIONS The initiating event for a station blackout (SBO) ts. olent is the loss of all ac power, and results in a trip of the reactor, the reactor coolant pumps and main feedwater pumps. The analysis assumptions are the same as for a Loss cf Feedwater Accident, described earlier, and summarized in Table 7. Table 7 also provides a sequence of events for SBO. The natural circulation cooldown with increased tube plugging was analyzed for the SBO analysis in GPU Nuclear Calculation C-1101-224-E610-069, Rev. O, using the RETRAN-02 Mod 5.2 code. This code is approved by the NRC for use in TMI-l licensing applications (NRC SER dated February 10,1997). The analysis was performed from an intial power level of 2620 MWt, which is 102% of rated power. j Conservative beginning-of-cycle kinetics parameters were used. The model uses a consen atively low initial OTSG mass of 39,000 lb.

For the station blackout (SBO) transient, the emergency feedwater (EFW) system would be initiated by a loss of the reactor coolant pumps signal. With a loss of ac power the motor driven EFW pumps (MDP) are unavailable and only the turbine driven EFW pump (TDP) are assumed to provide flow. Subsequent to the EFW initiation i signal, the steam admission valve (MS-V-13 A/B) to the turbine driven pump (TDP)  !

receives an immediate open signal and is fully open in 24 seconds. 'Iurbine testing  !

shows the TDP is at full speed in 11 seconds after the steam admission valves are full  ;

open. An additional 8 seconds for flow coastup is modeled resulting in TDP flow  !

delivery at 43 seconds, when valve MS-V-13 A is available. MS-V-13A/B valves l provide motive power to the turbine driven EFW pump from the ' A' and 'B' once-l l- )

r Attachment I 1920-99-20088 Page 30 of 52 through steam gen rators (OTSGs) respectively. The EFW system is desip.ed so that MS-V-13A receives an immediate open signal as described above, while MS-V-13B has a delay timer that is set between 40 and 60 seconds to avoid lining of the EFW steam line relief valve (MS-V-22).

Thus TDP flow delivery begins at 103 seconds aner the initiating signal, when

! MS-V-13A is unavailable. This delivery time can conservatively be applied for the SBO, as this represents the worst single failure for this event.

No credit is taken for the pressurizer power operated relief valve (PORV) or pressurizer i sprays and the turbine bypass and atmospheric dump valves are conservatively assumed to be unavailable.

ANALYSIS RESULTS

' A loss of power results in gravity insertion of the control roc's and trip of the turbine j stop valves. Since the event is initiated by a reactor trip, thermal power never exceeds

the initial value. The reactor coolant pumps, main feedwater and condensate booster L pumps will also trip. Consequently, the transient proceeds in a mostly symmetric

, manner and the results for one loop are presented in Figures 13 through 18 and are

! representative of the other loop.

l l The feedwater pumps are conservatively assumed to coastdown from 100% to 0% flow l

in 10 seconds due to rotational inertia as shown in Figure 13. An almost instantaneous EFW signal is initiated on loss of RCPs, and EFW will try and control level at 50% of the operating range. ARer reactor trip and turbine stop valve closure, the main steam l safety valves (MSSV's) open to relieve excess steam. The MSSVs cycle several timer during the first 200 seconds of the transient.

Following loss of power to the reactor coolant pumps, the reactor. coolant system flow i decays (Figure 15). Decay heat removal aRer coastdown of the reactor coolant pumps L is'provided by the natural circulation characteristics of the system. Only the TDP l provides emergency feedwater for decay heat removal. This pump is assumed to stait l delivering 175 gpm/SG at 103 seconds after reactor coolant pump trip as shown on l Figure 14. ,

l

[

m

. Attechment I

-1920-99-20088'

' Page 31 of 52 The RCS system pressure decreases to post-trip values as shown on Figure 16. There is l no challenge to the pressurizer relief or safety valves and pressurizer level shows a gradual increase following the post-trip value as seen on Figure 17. Figure 18 shows a temperature difference ofgreater than 20*F exists between the hot and cold legs at the end of the transient. The cold leg tempe:ature wrresponds to the saturation temperature at the lowest MSSV setpoint. As decay heat decreases, the energy removed by the EFW will exceed the core decay heat and RCS temperatures, pressure and level will be reduced. Similar results were achieved with asymmetric steam generator tube plugging of 25%/15%.

(

l Attachment i 1920-99-20088 Page 32 of 52 TABLE 7

SUMMARY

OF LOSS OF ELECTRIC POWER - SBO ANALYSIS INPUT VALUES PARAMETER ANALYSIS VALUE )

HFP BOC Moderator Temperature 0.0 Coeflicient, pcm/ F HFP BOC Doppler CoeGicient, pcm/ F -1.17 HFP Delayed Neutron Fraction, p,tr 0.007 PSV Capacity, Ibm /hr/ valve 297,846 PSV Setpoint Drift, % 3 Initial Core Power, MWt 2620 (102% of 2568)

High Flux Trip, percent full power 112 High Flux Trip Delay Time, sec 0.4 High Pressure Trip, psia 2402 High Pressure Trip Delay Time, sec 0.6 ,

j RCS Inlet Temperature, F 555.7 Initial RCS Pressure, psia 2170 RCS Flow Rate, Mlbm/hr 133.8 Sequence of Events for Station Blackout Event Time, seconds ;

Reactor trip 0.001 RCS pumps trip 0.001 Main feedwater pump coastdown intiated 0.001 Turbine trip 0.5 MSSV setpoint reached (first) 1.81 Main feedwater flow reaches zero 10.0 EFW TDP flow initiated 103.0 MSSV setpoint reached (last) 121.08 End of transient 1000.0

u Attachm:nt I 1920-99-20088 Page 33 of 52 l

2000.0 l

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! Figure 13: Feedwater Flow to OTSG A for SBO At 2568 MWt With 20% Average SGTP aos 1

1 l

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t- Figure 14: TDP EFWto OTSG A For SBO At 2568MWt With 20% Average SGTP i

p I

Attachm:nt 1 1920-99-20088 Page 34 of 52 10000.0 , j N00.0 I

4000.0 E-E =0 .

2000.0 .

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Figure 15: Loop A RCS Flow For SBO At 2568MWt With 20% Average SGTP 2300.0 m 2200.0 1

i i i ,, 0 l I

E a000.0 )

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l Figure 16: RCS Hot Leg Pressure For SBO At 2568MWt  !

With 20% Average SGTP l l

l

i Attachm:nt I 1920 09-20088 Page25 of52 24.0 L

no .

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Figure 17: Pressurizer Level For SBO At 2568MWt With 20% Average SGTP

.mo l

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Figure 18: RCS Temperatures For SBO At 2568MWt With 20% Average SGTP l

I

Attachm:nt I 1920-99-20088 Page 36. of 52 -

E. LOSS OF COOLANT ACCIDENT DISCUSSION OF LOSS OF COOLANT ACCIDENT The large and small break LOCA were re-analyzed with increased once-through steam

, generator (OTSG) tube plugging and reduced RCS flow. The calculations were l

performed by Framatome Technologies Incorporated (FTI) using the NRC approved RELAP5-based Evaluation Model(EM), described in BAW-10192PA. FTI prepared RELAP5/ MOD 2-B&W, REFLOD3B, and BEACH input models that represent the TMI-l plant. The analyses were performed in compliance with the EM methods ' and the limitations and restrictions stated in the NRC Safety Evaluation Report (SER) on :

BAW-10192PA at a conservative power level of 2772 MWt. These reanalyses have been revised to address the previously identified nonconservatisms in the RCP modeling by FTI.

ANALYSIS ASSUMPTIONS The inputs and assumptions for this set of LOCA analyses are shown on Tables 8,9, and 10. The LOCA analyses were performed to support 20% tube plugging for TMI-I and another B&W plant. The largest change to the existing UFSAR inputs was the change in high pressure injection (HPI) flow for the HPI line break. The analysis was done to support a plant that does not have HPI line cavitating venturis, which would require manual operator action at 10 minutes to balance HPI flows. TMI-l has HPI line cavitating venturis and does not require this manual operator action. Therefore, the analysis'is conservative for TMI-1. There were minor changes to the low pressure injection (LPI) and HPI flow versus pressure values to accommodate both plants.

Other important changes include 20% tube plugging and lower RCS flow, which is

, directly related to the proposed increased tube plugging. The Low RCS Pressure

- Reactor Trip Setpoint and the ECCS delay time were conservatively reduced to

- accommodate both plants.

1 A single failure of one emergency diesel generator is assumed for the LOCA analyses i consistent with the TMI-1 UFSAR. This is the worst case active single failure because  !

it reduces the available injection to one HPI pump and one LPI pump. Tables 9 and 10 - !

present the flow injected into the RCS from only one LPI and one HPI pump, respectively.

ANALYSIS RESULTS I

' The results of the LOCA analyses demonstrate compiiance with the acceptance criteria l

for breaks up to r.d including the double-ended severance of the largest primary
coolant pipe for the TMI-l plant with 20% average steam generator tube plugging.

i i

g

. Att:;chm:nt I

-1920-99-20088 Page 37 of 52 '

The results of the LOCA analysis are similar to the existing UFSAR Chapter 14 analysis, which conservatively assumed 15% tube plugging. UFSAR Table 14.2-15 provides a sequence of events for the break spectrum analysis performed for that analysis, and is essentially unchanged for 20% tube plugging.

I The peak clad temperatures and LOCA Linear Heat Rate Limits provided in Table 2 in the original TSCR No. 279 submittal, dated December 3,1998, have been revised to reflect the FTI reanalysis (FTI Document No. 86-5002073-01, dated March 17,' 1999) for TMI-l to address the previous nonconservative RCP modeling concerns as reported in FTI letter to the NRC dated February 4,1999, and GPU Nuclear letter to the NRC dated February 5,1999. The revised values are shown on Table 11. These fmal values remain well within acceptance criteria. The pressure, liquid level and clad temperature responses are shown in Figure 19 for the spectrum of SBLOCA cases perfonned, including the core flood tank (CFT) line break and the HPI line break. '

I i

l o

p--.

Attachment I '

i 1920-99-20088 l Page 38 of 52 Table 8 l LOCA ANALYSIS ASSUMPTIONS

' Initial Reactor Power 2827 MWt (102% of 2772 MWt)

Decay Heat 120% ANS 5.11971 Standard With ANS 5.11979 Actinides Time of full rod insertion (SBLOCA only) 2.3 sec Low RCS Pressure Reactor Trip Setpoint' 1780 psig Low RCS Pressure Reactor Trip Delay Timei 0.6 sec ESAS Setpoint HPI: 1480 psig LPI: 340 psig ECCS Delay Time' HPI: 35 sec LPI: Later of 35 sec after HPI Signal or 10 sec after LPI signal EFW Delay Time (SBLOCA only) 120 see Core Flood Tank Pressure 565 psig i Liquid Volume 985 ft l Temperature 140F j l

BWST Temperature 120F SG Level Setpoint (SBLOCA only) 0 - 20 min: 50% OR

>20 min: 65% OR 2

Main Feedwater Pump Coastdown 14 sec OTSG Tube Plugging' Broken Loop: 25%

Intact Loop: 15 %

Total RCS Flow' 133.9e6 lbm/hr includes instrument delay, trip module delay, breaker opening time delay, and CRDM unlatch time delay, 2

!, Loss of offsite power (LOOP) is assumed coincident with reactor scram. The LOOP is assumed to cause the reactor coolant pumps and main feedwater pumps to trip.

Parameter changed from previous analysis.-

i Attachment I 4 1920-99-20088 l l

I Page 39 of 52 TABLE 9 4

LOW PRESSURE INJECTION FLOW VERSUS CORE FLOOD /LPI NOZZLE PRESSURE Large Break LOCA 3 I

Pressure At Low Pressure Centerline Core Injection Flow Flood /LPI Nozzle (perloop) )

(PSIG) (GPM) )

0 3150 I I

109 2700 145 1830 l 160 1350 I 169 900 178 0

' Parameter conservatively changed from previous analysis.

Small Break LOCA' Pressure At Low Pressure Centerline Core Injection Flow Flood /LPI Nozzle (per loop)

(PSIG) (GPM) l 0.0 3150 i 98 2700  !

133 1830 l 148 1350 157 900 163.9 0 l

' Parameter conservatively changed from previous analysis.

I

Attachment 1

-1920-99-20088 Page 40 of 52 TABLE 10 HIGH PRESSURE INJECTION FLOW VERSUS .

HPI NOZZLE PRESSURE LOCA on RCS Piping' '

Pressure AtIIPI Nozzle

. (PSIG) Total Flow?

(GPM) 0 438 600 431 1200 380

!$00 346 1600 335 1800 310 2400 190 Breaks other than Cold Leg Pump Discharge (CLPD) break and HPI Line break.

2 Total Flow is evenly distributed between all four HPI lines.

Parameter conservatively changed from previous analysis.

CLPD Break' Pressure At HPI Nozzle (PSIG) Flow to Intact Legs' (GPM) 0 306.6 600 301.7 1200 266.0  ;

1500- .242.2 1600 234.5 1800 217.0 l 2400 133.0 No credit is taken for HPI flow to the broken Cold Leg.  ;

2 Parameter conservatively changed from previous analysis.

HPl Line Break2 j Pressure At HPI NouJe (PSIG) Flow to Intact Legs' (GPM)

Before 10 minute )

0 272.09 600 272.09 j 1200 197.97 i 1500 156.56 i 1600 138.96 1800 104.22 After 10 minute 0 308.96 l 600 308.%

1200 230 1500 182 1600 165 1800 130 l I

No credit is taken for HPI flow to the broken Cold Leg. l 2

Parameter conservatively changed from previous analysis. l l

r Attachment I )

1920-99-20088 J Page 41 of 52 TABLE 11  !

Summary of Mk-B9 LHR Limits  !

TMI-l LBLOCA 20% Tube Plugging LOCA LHR Limit, kW/ft LOCA LHR Limit, kW/R LOCA LHR Limit, kW/R j (PCT, F) (PCT, F) (PCT, F) {

Elevation BOL MOL (40000 MWD /mtU) EOL (60000 MWD /mtU) l i

0.0 ft. 15.9 15.9 12.0 j 2.506 ft. 16.8 (2046) 16.8 (1845) 12.0 (1535) 4.264 ft. 16.8 (2006) 16.8 (1859) 12.0 (<l 700) 6.021 R. 17.0 (1959) 17.0 (1842) 12.0 (<1700)

' 7.779 fl. 17.3 (1955) 17.3 (1872) 12.0 (<1700) )

9.536 ft. 16.8 (1918) 16.8 (1775) 12.0 (<l700) 12.0 f1. 15.9 15.9 12.0 Notes: 1. Linear interpolation for LHR limits is allowed between 40000 MWD /mtU and 60000 MWD /mtU. i

2. For the BOL and MOL columns, the LHR limits below 2.506 feet are reduced linearly to 0.95*LHR .506 2 at 0.0 feet. The LHR limits above 9.536 feet are reduced j linearly to 0.95*LHR9.s36 at 12.0 feet.  !

1

3. Analyses at BOI_ .nd MOL used a steady state energy deposition factor (EDF) of l 0.973 for initial core energy deposition and a transient EDF of 0.973. The EDF is used to relate nuclear source power (used in maneuvering analyses) to thermal source power (used in LOCA analyses).

LHR 3wermat = LHRuua .,

  • EDF Analyses at EOL used a steady state EDF of 1.0 and a transient EDF of 1.1. To I report the LHR given above on a basis consistent with the BOL and MOL LHRs, it was necessary to divide the EOL LHR of 11.7 kW/R by an EDF of 0.973 to obtain a reported LHR of 12.0 kW/R. Therefore, all of the LHRs given above are based on nuclear source power with an EDF 0f 0.973.
4. LHRs are valid for fuel enrichments of 5.1 weight percent (maximum) and pin prepressures of 355 psia.

I

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2000 I LEGEND 1750 0.07-FT2, CLPD SBLOCA, Seg 19 ,


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Figure 19-1 0.15 - 0.75 FT2 CLPD SBLOCA BREAKS FOR 20% SGTP COMPARISON OF PEAK CLADDING TEMPERATURES.

2 LEGEND 1750, 0.15-FT2, CLPD SBLOCA, Seg 20

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Figure 19-J 0.44 FT2 CFT-LINE SBLOCA BREAK FOR 20% SGTP COMPARSION OF SYSTEM PRESSURES.

LEGEND ,160 Hot Leg 2000 - - - Intact SG Secondary


Broken SG Secondary CFT 120 1600-E &  !

2 I 1200-80 0 0 E \ E I 800-40 400-

=~%g%.,.=.-m. urum am. w. mum aau.,

0 0 0 500 1000 1500 2000 2500 3000 3500 4000 l

TIME. SECONDS j

Figure 19-K 0.44 FT2 CFT-LINE SBLOCA BREAK FOR 20% SGTP REACTOR VESSEL COLLAPSED LIQUID LEVELS.

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Figure 19-L O.44 FT2 CFT-LINE SBLOCA BREAK FOR 20% SGTP HOT CHANNEL PEAK CLADDING TEMPERATURES.

2000 LEGEND 1750 Seg 21,11.2 - 12.0 FT

- - - Seg 20,10.4 - 11.2 FT 1200 Seg 19, 9.6 10.4 FT 1500- ----------

Seg 18, 8.8 - 9.6 FT Seg 17, 8.0 8.8 FT 1000

"" 1250-I N E E g1000- 800 g r r 750-h 600 500-

.A ae ,

250- 400 0

0 500 1000 1500 2000 2500 3000 3500 4000 TIME. SECONDS Figure 19-M O.44 FT2 CFT-LINE SBLOCA BREAK FOR 20% SGTP COMPARISON OF HOT CHANNEL MIXTURE LEVELS.

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. j

Figure 19 N HPI-LINE NO OPERATOR ACTION SBLOCA BREAK FOR 20% SGTP COMPARSION OF SYSTEM PRESSURES.

LEGEND 160 Hot Leg 2000 - --- Intact SG Secondary Broken SG Secondary CFT 120 1600-I f E 2

1200' 80 g - - . - =

E ~ E 800- '

................................................................ 40 400-0 0 0 1000 2000 3000 4000 5000 6000 7000 8000 TIME, SECONDS Figure 19 0 HPI-LINE NO OPERATOR ACTION SBLOCA BREAK FOR 20% SGTP REACTOR VESSEL COLLAPSED LIQUID LEVELS.

- 20 LEGEND 8.0 Downcomer 24-

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i Figure 19-P HPI-LINE NO OPERATOR ACTION SBLOCA BREAK FOR 20% SGTP HOT CHANNEL PEAK CLADDING TEMPERATURES.

O LEGEND 1200 Seg 21,11.2 12.0 FT '

1500< -.---- Seg 20,10.4 - 11.2 FT Seg 19, 9.6 - 10.4 FT I

--- ------ Seg 18, 8.8 - 9.6 FT 1000 1250-7 ..Qr Qg 17, 8.0 8.8 FT

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O O 1000 2000 3000 4000 5000 6000 7000 8000 TIME, SECONDS l

Figure 19-Q 0.44 FT2 CFT-LINE SBLOCA BREAK FOR 20% SGTP COMPARISON OF HOT CHANNEL MIXTURE LEVELS.

20.0 LEGEND l

5.6 17.5, M CMnnel

=---- Average Channel 4.8 15.0-12.5- .

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O 1000 2000 3000 4000 5000 6000 7000 8000 TIME, SECONDS l

a Attachment I 1920-99-20088

.Page 42 of 52

2. NRC Ouestion Provide a discussion including the information requested in 1. above for the limiting main steam system pressure event. (General Design Criterion [GDC] 15 as described in SRP sections to include protection of the main steam system).

Response

A Turbine Trip without Bypass event would generate the maximum secondary system pressure and is limited by the Main Steam Safety Valves (MSSV). However, the energy from the primary system (i.e., core thermal power and RCP heat) is not increased as a result of the tube plugging. The MSSV system flow capacity is not reduced in any way and the MSSV setpoints are not affected. Additionally, the feedwater temperature is not increased as a result of the plugging. The only effect of reduced steam generator heat transfer to the secondary side resulting from the tube plugging would be to delay the pressure build-up on the secondary side, but this would not increase the resulting peak pressure. Therefore, increased tube plugging would not cause secondary system pressure to exceed the ASME

- Code requirements. This is valid with a unit average tube plugging of 20% with a maximum of 25% in a single OTSG and a maximum asymmetry of 15%.

3. NRC Ouestion

' For the main steam line break, you stated that the Updated Final Safety Analysis Report (UFSAR) analysis assumption of 55,000 lbm per steam generator bounds the steam generator mass inventory with 20% tube plugging. How would the limit of 25% tube plugging affect this assumption? (SRP Section 15.1.5)

Response

The OTSG normal mass inventory is conservatively estimated to be less than 45,000 lbm for a 20% average tube plugging or a 25% maximum tube plugging. The mass inventory based on the current ICS high level alarm setpoint of 70% operating range with 25% tube plugging is estimated to be 47,000 lbm. Both of these conditions are well below the 55,000 Ibm assumed in the FSAR analysis. Therefore, the results of the MSLB analysis remain conservative for the 25%/15% tube plugging case.

4. NRC Ouestion For the steam generator tube rupture analysis, you stated that the assumption of 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> for cooldown remained conservative with respect to the requested steam generator tube plugging limit. Please provide furtherjustification for this statement. Please consider the tube plugging asymmetry in yourjustification. (SRP Section 15.6.5)

I I

j

p>

-Attachment IL

1920-99-20088 Page 43 of 52.

Response

LThe initial evaluation of the impact of tube plugging on the primary-to-secondary heat transfer indicated that the reduction in heat transfer area could slightly increase the cooldown time, but was expected to remain less than the 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> assumed in the UFS AR analysis. Further evaluation has indicated that the capacity of the turbine bypass valves for rejecting steam from the steam generators and the cooldown rate limits are more limiting than the ability to transfer heat from the primary to the secondary. Therefore, the cooldown rate would not be affected by the reduction in heat transfer surface area. . Given the same cooldown time the dose consequences would not change from those in the UFSAR.

5. NRC Ouestion In your submittal, you stated that the Mk-B9 fuel design was used in the loss-of-coolant analyses. For the loss-of-coolant flow analyses you stated that the Mk-10 fuel design was used. You also stated that a core consisting ofMk-8, Mk-9, and Mk-10P will be used for Cycle 13. Please provide justification for the fuel type used in each of these analyses with j respect to the fuel mix that will be loaded for Cycle 13. Please discuss the thermal i hydraulic effects of the mixed core on the analyses. (SRP Sections 15.6.5,15.3-1-15.3.2)

Response

GPU Nuclear is not requesting approval for mixed fuel assembly cores. The Mk-B8, Mk-B8V, Mk-BIO (Mk-B9 design with cruciform holddown spring) and Mk-BIOP fuel designs, which will be loaded into TM1-1 Cycle 13 are all hydraulically and geometrically similar. All designs have zircaloy intermediate spacer grids and the fuel rods have the same outside diameter. The BWC CHF correlation is applicable to all the designs. The  !

fuel design changes have been shown to have an insignificant impact on DNB performance in a conservative configuration of mixed fuel designs and no mixed core penalty was warranted. Therefore, these fuel design differences are not considered a mixed fuel assembly core. Cycle specific reload analyses are performed assuming a fuel design that will produce the most conservative DNB results. NRC approval of FTI fuel design changes )

is obtained in accordance with the criteria contained in the NRC SER dated March 13, 1993, for FTI Topical Report BAW-10179P-A, " Safety and Methodology for Acceptable Cycle Reload Analyses". The above fuel design changes were not within the scope of this NRC approved criteria. These fuel designs have been incorporated in each of the TMI-I

. cycle specific core reload designs based on the criteria contained in BAW-10179P-A since -

mid-Cycle 9, July 1993.

L_r_u ..

i i

' Attachment I '. j

1920-99-20088 Page 44 of 52 j With regards to LOCA analyses, these analyses are primarily dependent upon overall j system response rather than reload core characteristics. Therefore, the mixture of fuel designs in the core will not impact the system response to a LOCA. A separate set of LOCA-limited maximum allowable linear heat rates are determined for each fuel rod l design to be loaded in the core based on stored energy and peak clad temperature.  !

TMI-l Cycle 13 will also contain four (4) Westinghouse lead test assemblies that will be undergoing their third. cycle ofirradiation. A limited number oflead test assemblies i located in non-limiting core regions is provided for in TMI-1. Technical Specification l Section 5.3.1.1.. While these assemblies do not constitute a full reload batch, evaluations - l were performed to verify they have no adverse impact on neighboring MK-B assembhes.

6. NRC Ouestion Provide a description of the FSPL1 f computer code used in the loss-of-coolant flow analyses. (SRP Section 15.3.1-15.3.2)

Response

The FSPLIT code calculation certification analysis is contained ir 3&W Document l

. No. 32-1203121-01, which is provided as Attachment II. A discussion of FSPLIT code  !

benchmark cases and the results of benchmark cases are provided in this document. The  ;

code input portion of this document is proprietary and has not been included in  ;

' Attachment IL i 7.' NRC Ouestion l

'An acceptance criteria for the loss of main feedwrer event is that the pressurizer not go water solid. In your submittal you indicated that Ge analysis s! owed that the pressurizer would go water solid. You further suggested that the intent of this acceptance criteria was  !

to assure that liquid is not passed through the pressurizer safety or relief valves and that this ,

intent is met because at the time that the pressurizer goes solid, the pressure is below the l setpoints of these valves. It is not clear from your submittal that you had considered the ,

most limiting event with respect to water diaharge through the relief and safety valves.

Typically, analyses are performed in or der to demonstrate that under the most limiting conditions, the acceptance criteria are .iot violated. With regard to water discharge through  !

the pressurizer safety and relief valves, showing that the pressurizer does not go water solid under the most limiting level transient provides the necessary assurance to conclude that j there will not be water discharge through the valves. However, when the limiting level  !

transient shows that water solid conditions can be reached, this poses the question of the  !

. potential for an event where the pressurizer level and pressure achieved can lead to water discharge through these valves. Please' provide an analysis that meets your licensed acceptance criterion of not going solid in the pressurizer. (UFSAR Section 14.2.2.7, SRP

' Section 15.3.1-15.3.2) l

Attachmmt I 1920-99-20088 Page 45 of 52

Response

The reanalysis of the Loss of Feedwater Accident as described in response to Question 1 demonstrates that the acceptance criteria of not going water solid in the pressurizer is satisfied with 20% tube plugging. This was achieved by re-analyzing the transient which was submitted for the original Technical Specification Change Request (TSCR) No. 279, dated December 3,1998, with a higher emergency feedwater (EFW) flow rate (275 gpm vs.

240 gpm per OTSG). The higher EFW flow rate capability is achieved by removal of overly conservative assumptions used in modeling the EFW system hydraulics and pump performance cmves as explained below.

The RETRAN thermal-hydraulic (T-H) analysis establishes the EFW flow required to two pressurized OTSGs to meet the acceptance criteria for the accident. The EFW pump head

]

1 required to achieve this flow is based on a RELAP5 model of the EFW system which is benchmarked against recent surveillance test data.

The EFW flow analysis prior to the 12R refueling outage was performed in the following manner:

a) the vendor pump head capacity curve was reduced by a constant percentage so that EFW pumps delivered the RETRAN T-H analysis required flow to two pressurized OTSGs (the RETRAN T-H analysis required flow is approximately mid-range of

'the pump curve) b)' with this adjusted pump head capacity curve the flow rate from each EFW pump to a depressurized OTSG under surveillance fest' conditions was determined c) this flow rate was specified as the acceptance criteria for the pump surveillance $ st.

Figure 20 illustrates the results of this methodology as it was applied to EFW pump EF-P-2A. This methodology was overly conservative as applied to the EFW surveillance test acceptance criteria for the following two reasons:

a) decreasing the pump head by a constant percentage at all flow rates resulted in too j high a head requirement at surveillance test conditions, which then required i excessive pump flow rates b) specifying an EFW flow rate only for surveillance testing (i.e. no head was specified) 2 i

E 1 l

Attachment I 1920-99-20088

  • ' Page 46 of 52 The current EFW flow analyses are performed in the following manner:

l a) The RETRAN T-H analysis flow is input to the RELAP5 system model for two -

pressurized OTSGs. EFW pump pc;formance is determined for all pump combinations (e.g.,1 TDP,1 TDP and 1 MDP, etc.) to develop the most limiting pump performance requirement.

b) A revised EFW surveillance will require acceptance criteria for each pump as the ,

most limiting performance determined in a).

Figurr~~. .austrates the results of this methodology as applied to EF-P-2A. As can be seen .

from Figure 21, the new methodology demonstrates that the EFW pump is capable of providing more flow than required to meet the acceptance criteria for the event.

i i

i I

1 l

I 1

L Attachment I 1920-99-20088 Page 47 Of 52 FIGURE 20 EFW PUMP EF-P-2A WITH 11R DATA & 12R TEST REQUIREMENTS l 3500 00 3300.00 - l l

1100.00 VENDOR TDH

]

2900.00 VENDL,R TDH 87% VENDOR TDH 2700.00 0 12R TEST REQMT

~ 2500 00 87% OF VENDOR TDH

  • 12R ACCIDENT REQMT 12R ACCIDENT REQMT # 11R TEST DATA 2300.00 2100fl0 1900.00 12R TES ACCEPTANCE l 1700.00 CRITERION j 2

l 1500.00 l 0 100 200 300 400 500 600 700 j TOTAL PUMP FLOW (GPM) l l

FIGURE 21 EFW PUM P EF-P-2A WITH TEST DATA & NEW ACCIDENT REQUIREM ENT 3500.00 3300.00 ,  !

3100.00 - [

2900.00 CURRENTTDH CURRENTIM g VENDOR 1DH

( 2700 00 +

z CURRENTTDH 2500.00 e 11R TEST DATA E

2300 00 A 12RTEST DATA 2 NEWACCIDENT REQUIREfENT AtNT ANAE NON

  • 2100.00 -

1900.00 1700.00 -

1500.00 l 0 100 200 300 400 500 600 700  ;

TOTAL PUMP FLOW (GPM)

. Attachment I 1920-99-20088 Page 48 of 52 Mechanical Engineerina Brancli p -

8. NRC Ouestion 1

On Page 15, you indicated that the resulting Lws and temperatures based on a parametric study of tube plugging in the TMI-l steam generators (Reference FTl Proprietary Document 32-1234876-02) have been assessed for any potential impact on the existing structural analysis bases. Provide a summary of the evaluations (including analytical methodology, assumptions, and maximum stress and fatigue usage factors) for the effects of resulting flow and cold leg temperatare reduction on the structural and pressure boundary integrity of the reactor vessel and internals, reactor coolant system (RCS) piping, control rod drive mechanisms and housing, pressurizer spray nozzles, SGs, feedwater nozzles, reactor coolant pumps, and pressurizer power-operated valves and safety valves. Identify changes (if any) in maximum stresses and fatigue usage factors (at critical locations) from your evaluation.

This information is needed for the staff to review the affected ASME Code Class 1.2. and 3 l components, component supports, and Class CS core support structures, in accordance with ASME Section III, Subsection NB, to meet the requirements of 10 CFR Part 50, Appendix A,

.GDC 1.

Response

Framatome Technologies, Incorporated (FTI) developed an evaluation approach for determining the potential impact on existing TMI-1 structural design bases consisting of an estimation of the magnitude of the ' expected thermal expansion changes and transient through-wall thermal gradient changes. This approach was applied to the reactor coolant system (RCS) piping and components identified in the above question including the pressurizer spray nozzle. The expected maximum increase in hot leg temperatures and decrease in cold leg temperatures of 1.25 F resulting from the 0-20% tube plugging scenarios evaluated were determined to have a negligible effect on the existing stress and fatigue resistance analyses for TMI-1, as described below. Therefore, the RCS pressure boundary design limits are maintained.

i Thermal Expanlion -

Cold leg stresses will decrease since the' cold leg operating temperatures will be reduced by 1.25 F. Hot leg operating iemperatures will increase by 1.25 F with 20% l

. tube plugging and the FTI evaluation conservatively considered a 2.l'F increase. The  !

resulting hot leg stress increase is negligible since the postulated temperature increase l results in only a 0.4% change in the temperature differential from an initial system temperature of 70 F to the revised hot leg temperature. ". mhange has negligible l effects on the existing stress and fatigue results. Additionally, it is noted that the design basis stress analyses are based on 608 F hot leg temperature which still bounds the conservative postulated 2.1 F hot leg temperature increase due to 20% tube plugging.

Attachment I 1920-99-20088 Page 49 of 52  !

I Transient Tbto_u_gh-Wall Thermal Gradients l l

An assessment of the combined effects of RCS flow reduction, which reduces thermal  !

gradients, and increased hot leg temperatures, which increases thermal gradients, due to l 20% tube plugging has determined that the final resulting temperature change through-  !

wall in the subject RCS piping and components will be smaller. Evaluation of the RCS  ;

functional specifications for normal operating conditions, anticipated transient conditions, and upset conditions shows that the through-wall thermal gradient terms used in the current stress analyses remain conservative. In addition, P 11-1 Technical Specification heatup and cooldown rate limits administratively contro anticipated transients, and these limits are not changed.

Specifically as regards the temperature difTerential that may occur at the pressurizer  !

spray nozzle due to the lowered cold leg temperature; this effect has been determined to be negligible since a minimum bypass flow exists through the spray line which keeps the line and the nozzle at the cold leg temperature. The nozzle body is also protected i by a thermal sleeve. l The potential for localized additional tube wall degradation because of tube plugging in the steam generators, due to moisture and flow induced vibration, is evaluated for regional  ;

areas of the steam generator that may contain a high density of plugging. The criteria for l this assessment is essentially independent of the total plugging limits. This evaluation will i be performed on a cycle specific basis to account for the results of each refueling outage tube inspection.

In summary, the changes in temperature and flow from 0% tube plugging to 20% tube plugging limits have no effect on the bounding design basis stress and fatigue analyses for TMI-1.

9. NRC Ouestion On Page 15, you indicated that a reduction in cold leg temperature (Teoid) can affect the magnitude of pressure waves traveling through the RCS internals during a LOCA, thus i

increasing loads. Also, the reduction in Tcold ncreases the fluid density and thus, increases the loading on the components, changes the fluid flow which would affect tube vibration and transients. Provide a discussion for the efTects of the reduced cold leg temperature that affect the hydraulic forces used in the design basis analysis and the potential for the flow induced vibration.

l This information is required for the staff to review the effects of the proposed changes on the design-based loads and load combinations, for safety-related components to meet the requirements ofGDC 1,4,14, and 15.

i E

Attachm:nt I-

! 1920-99-20088 l Page 50 of 52 -

l-

Response

l Hydraulic LOCA Forces l

L The FTI evaluation consisted of performing calculations that show that the decrease in

( .Tcold from 0% tube plugging to 20% tube plugging scenarios has negligible effect on the -

LOCA loadings for TMI-1. The peak LOCA loadings occur right after the break and are predominantly driven by the magnitude of the pressure waves that propagate through the system. A decrease in Tcold decreases the saturation pressure and thus causes a larger j pressure wave magnitude based on the difference between the operating pressure and the saturation pressure. This increase in pressure differential is about 1.6%, which is

, considered to have negligible effects on LOCA loadings. The increased density of the cold leg water affects the loads later in time (flow / momentum) but the more significant loads due to the pressure waves have decayed by the time the flow responds.

Primary Component Flow hiduced Vibration (FIV)

I

Steam generator tube plugging does not adversely affect primary component flow induced i vibration. Flow induced vibration is a result of the dynamic pressure, or the product of the l density and the square of the velocity in the flow path. In terms of mass flow rate, the dynamic pressure is proportional to mass flow rate squared divided by the density. As steam generator tubes are plugged, the primary flow will decrease, in addition, the primary flow reduction will cause an increase in the primary hot leg-to-cold leg temperature i

difference that will result in a cold leg temperature decrease and a cold leg density increase.

For example,20% tube plugging will result in a flow reduction of approximately 4% while

. the primary temperature will decrease less than 2 F in the cold leg, and increase less than 2 F in she hot leg. A 2 F change in hot leg temperature from, for example,602 F to 604 F results in only a 42.92 lbm/f/ to 42.74 lbm/ft , or 0.4%, decrease in density. In the hot leg

. this density decrease is more than offset by the mass flow rate decrease, and the dynamic l pressure will decrease with tube plugging. In the cold leg, both the primary flow rate L decrease and density increase will cause a slight reduction in dynaniic pressure. Thus, the I susceptibility of primary components to flow induced vibration will not be increased dum to steam generator tube plugging. Also, Babcock & Wilcox Owners Group (BWOG) plants have been operating with flows in the expected tube plugging flow range without FIV problems.-

Tube plugging has a negligible affect on any potential post-LOCA flow induced vibration.  !

Tube plugging affects the initial conditions before the LOCA. During a LOCA, the l

. primary flow rates decrease dramatically, and thus are bounded by the normal flow rates.

Hence, flow induced vibration is controlled by normal condition effects, which as stated above are negligibly effected by tube pluggmg. i 1

I l

1 g

g

. Attachment i 1920-99-20088 Page 51 of 52-Steam Generator Tube Flow Induced Vibration (Secondary Side)

Only t..e secondary side changes have the potential to affect steam generator tube flow induced vibration. The secondary side effects of tube plugging on steam generator tube flow induced vibration are negligible. Of specific interest is the potential for flow induced vibration in the upper span of the steam generator where the superheated steam flows radially and normal to the tubes. As tubes are plugged, the superheated steam temperature will decrease, thus causing a reduction in the steam enthalpy and an increase in steam density. Actual steam temperatures depend on steam pressure, feedwater temperature, power level, and feedwater flow rates; typical values are: (1) 590 F to 595 F for no plugging, and (2) 570 F for 2 20% plugging. To maintain the plant rated power output, the feedwater flow rate would be increased to compensate for the steam enthalpy decrease.

As will be shown below, these changes in ' steam properties and flow rate have a negligible' affect on the flow-induced vibration forcing function (i.e., dynamic pressure). Note: these values are intended to illustrate the independence of the dynamic pressure from steam temperature and are thus representative rather than plant specific.

2 P=pV , ,2/ A2 where P = dynamic pressure p = steam density in upper span V = radial velocity component in the upper span w = steam mass flow rate A = area at the tube ofinterest To evaluate independent of tube location, P oc w2 j For a constant power output, Q w = Q/(hsun - hrw) where hsun.= superheated steam enthalpy brw = feedwater enthalpy E

L Attachment I 1920-99-20088 Page 52 of 52 2

Thus, for the conditions listed below, the dynamic pressure values, w / , were calculated as a function of steam temperature. i At 2584 Mwt (2568 core power + 16 [RC Pump heat, makeup, letdown, ambient losses]),

Trw = 450 F, and Tstm = 590 F

.Q = 2584 Mw

  • 3413 B;u/(kw/h)
  • 1000 (kw/Mw) * (1/3600)(h/s)

Q = 2.45e6 Btu /s i

. On a per steam generator basis, Q = (2.45e6 Btu /s)/2 = 1.225e6 Btu /s

-)

l At P = 915 psia and T = 590 F, h,tm = 1250.019 Btu /lbm and p = 1.773 lbm/R At P = 925 psia and T = 450 F, hrw = 430.4 Btu / ibm j I

w = 1.225e6 Btu /s / [1250.019 - 430.4] Btu /lbm = 1494.6 lbm/s = 5.38e6 lbm/hr l 2 2 w / = (1494.6)2 lbm /s / [1.773 lbm/R

  • 32.2 A lbm/(lbf s2)] = 39,128 lbf A Similarly for other values of steam temperature (neglecting changes in feedwater temperature with steam flow rate and temperature),

2 Steam Steam Density Steam Enthalpy w7 3

Temperature ( F) (Ibm /ft ) (Btu /lbm) (lbr A*)

595 1.755 1254.214 39,127 i

590- 1.773 1250.019 39,128 585 1.791 1245.743 39,142 ,

580- 1.810 1241.378 39,149  !

575 1.830 1236.918 39,150 i 570 1.850 1232.354 39,169 NOTE: Up to seven significant digits are sho'rn and used to demonstrate the dynamic pressure insensitivity to peam temperature changes caused by tube plugging.

2 Since the increase in this dynamic pressure term, w /p, is negligible (as steam temperature i decreases due to tube plugging), it can be concluded that the flow-induced vibration of the i tubes will not be adversely affected by tube plugging.

i