Text

Commonwealth Edison Bnps Unit 1 Cycle 9 Startup Rept
	ML20248K736
Person / Time
Site:	Byron
Issue date:	05/31/1998
From:	; COMMONWEALTH EDISON CO.
To:	;
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ML20248K733	List: ML20248K731; ML20248K736;
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	NUDOCS 9806100239
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r Comed Byron Nuclear Power Station Unit 1 Cycle 9 Startup Report i

May,1998 1

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Table of Contents Lis t o f Ta b l es............................................................................ iii L i s t o f Fi g u re s............................................................................ iv i

1 1.0 I n t ro d u c t i o n..................................................................

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2.0 Co re Tes t i n u...................................................................... 2 i

2.1 Control Rod Drop Time M easu rem en t...................................... 2 2.2 Zero Power Physics Testin g................................................... 2 2.3 Powe r Escala tio n Tes t in g...................................................... 2 2.4 Co re Power Dis t rib u tio n...................................................... 2 2.5 Full Power Loop Delta-T Determination................................... 3 3.0 Steam Generator Replacement Related Testine........................... 10 3.1 Containment Pressure Test (CPT)(SPP 9 7-0 4 2)............................ 10 3.2 Steam Generator Blowdown Flowrate Measurement.................... 1I (SPP 97-043) 3.3 SGR Recirculation Pump Performance Tests (SPP 97-44,66.67,68)... I1 3.4 Auxiliary Feedwater Flowpath Verification (SPP 97-045).............. 12 3.5 SGR Thernaal Expansien Test (SPP 97-046)............................... I2 3.6 La rge Load Red u ction (SPP 97-048)......................................... 13 i,

3.7 10 % Load Decrease (SPP 9 7-0 4 9).......................................... 1 4 3.8 Steam Generator Level Control (SPP 9 7-050)............................. 15 l

3.9 Moisture Carryover Test (SPP 9 7- 0 51 )...................................... 16 3.10 Feedwater System Test (SPP 9 7- 0 5 2 ).......................................

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Table of Contents (cont.)

3.11 Steam Generator Thermal Performance (SPP 97-053)................... 18 3.12 RCS Flow Verification (S PP 97-054)......................................... 18 3.13 Plant Performance Baseline Data (SPP 9 7-05 5)........................... 19 3.14 Calibration of Steam Flow Transmitters (SPP 97-056)................... 20 3.15 Loose Parts Monitor Baseline Test (SPP 9 7-0 57)........................ 21 3.16 Feedwater - Steady State Pipe Vibration................................... 21 (inside/outside containment) (SPP 97-061) 3.17 Feedwater-Steady State Pipe Vibration...................

............21 (outside containment) (SPP 97-062) 3.18 Steam Generator Primary IIcad Drain Lines Vibration................. 22 (SPP 97-063) 3.19 Loose Psris Monitoring System (LPMS) llammer Test................. 22 (SPP 97-137) 3.20 Steam Generator Level Instrumentation Tubing /...................... 22 Inservice Leak Testing 3.21 S u rveilla n c e Proced u res.......................................................

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i List of Tables Table 1.1 Byron Unit 1 Cycle 9 Core Design Data.

1 Table 2.1 Unit 1 RCCA Rod drop Time Comparison.

4 Table 2.2 BIR08 Startup Physics Test Results.

6 Table 2.3 Core Power Distribution Results 25% Power.

7 Table 2.4 Core Power Distribution Results 46% Power.

7 Table 2.5 Core Power Distribution Results 60.4% Power.

8 Table 2.6 Core Power Distribution Results Full Power Map.

8 Table 2.7 Full Power Loop Delta-T.

.9 Table 3.1 S/G Blowdown Flow..

24 Table 3.2 Steam Generator Recirculation Flow Rate.

24 Table 3.3 Large Load Reduction Plant Parameters.

24 Table 3.4 10% Load Reduction Plant Parameters.

25 Table 3.5 Steam Generator Level Response - 50% power test plate.

25 Table 3.6 Steam Generator Level Response - 75% power test plateau.

. 26 Table 3.7 Steam Generator Level Error vs. Power Level..

26 Table 3.8 FW / MS DP Error vs. Power..

26 Table 3.9 Main Feedwater Regulating Valve Position vs. Power.

27 Table 3.10 Main FW Pump Speed vs. Power Level 27 Table 3.11 iteam Generator Pressure vs. Best Estimate Predictions.

27 Table 3.12 RCS Flow vs. Acceptance Criteria.

. 28 Table 3.13 Full Delta T Power Indication.

28 Table 3.14 Steam Flow / Feed Flow Mismatch At 100% Power Level..

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List of Figures Figure.1 25% Load Drop - 1 A S/G Level and Reg Valve Demand.. 29 Figure 2 25% Lot 3 Drop - FW Pump Speed.,

.30 Figure 3 25% Load Drop - Auctioneered High Tave..

.31 Figure 4 25% Load Drop - Pressurizer.

.32 Figure 5 25% Load Drop - Load and Power.

.33 Figure 6 10% Load Decrease-1 A S/G Level and Reg Valve.

.34 Demand Figure 7 10% Load Decrease-Feedwater Pump Speed.

.35 Figure 8 10% Load Decrease-Pressuri7er.

.36 Figure 9 10% Load Decrease Data - Load and Power.

. 37 Figure 10 10% Load Decrease-1 A RCS Average Temperature.

38 Figure 11 SG 1 A Step Down at 50%.......

.39 Figure 12 SG 1 A Step Up at 50%,.

40 Figure 13 SG 1 A Step Down at 75%....

41 Figure 14 SG 1 A Step Up at 75%..

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l 1.0 Introduction i

l Commonwealth Edison conducted a comprehensive test program following replacement l

of the Unit 1 Steam Generators (S/Gs) that demonstrated that modified structures, systems, and components perform satisfactorily in service. The test program outlined in this report summarizes events and testing performed during the first heatup and increase to 100% power with Byron 1 Replacement Steam Generators (RSGs). The testing scope

' included sequencing of special tests (SPPs) and station surveillance to satisfy requirements of the modification.

The Byron Unit 1 Cycle 9 core includes a feed batch of 76 fuel assemblies manufactured by Westinghouse. The new fuel region incorporates Integral Fuel Burnable Absorber (IFBA) rods with a B-10 loading of 1.5X with a 100 psig backfill pressure. The 1.5X IFBA rods have been used in previous cycles, but unique to Cycle 9 is the reduction of I

backfill pressure from 200 psig to 100 psig. In addition, enriched annular blankets are used on all feed assemblies (6" top and bottom). Table 1.1 contains characteristics of the Byron Unit 1 Cycle 9 core design.

The Cycle 9 reactor core achieved initial criticality 3/8/98, at 0150 hours0.00174 days 0.0417 hours 2.480159e-4 weeks 5.7075e-5 months .

The Unit 1 Main Generator was synchronized to the grid 3/9/98 at 0609 hours0.00705 days 0.169 hours 0.00101 weeks 2.317245e-4 months .

1 Power escalation testing, including testing at full power, was completed 4/4/98.

l Table 1.1 Byron Unit 1 Cycle 9 Core Design Data 1.

Unit 1 Cycle 8 burnup:

433 EFPD i

2.

Unit 1 Cycle 9 design length:

410.2 EFPD Region Fuel Type Number of Enrichment Cycles Burned Assemblies w/o U-235 9A VANTAGE +

24 4.0 2

9B VANTAGE +

16 3.6 2

10A VANTAGE +

36 4.4 1

10B VANTAGE +

40 4.2 1

llA VANTAGE +

44 4.0 0

llB VANTAGE +

32 3.8 0

llc VANTAGE +

1 1.6 0

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2.0 Core Testine 2.1 Control Rod Drop Time Measurement This test is performed prior to each fuel cycle with T,y greater than 550 degrees F and with all reactor coolant pumps in operation (per Technical Specification 3/4.1.3.4). Due to the potential for marginally increased reactor coolant system 110w impacting control rod drop times, a verification of acceptable rod drop times was required as part of replacement steam generator test ig. The individual full-length shutdown and control rod (RCCA) i drop time from the rully withdrawn position is required to be less than 2.7 seconds from the beginning of decay of the stationary gripper coil voltage to dashpot entry.

All BIR08 RCCA drop times satisfied this acceptance criteria. TLble 2.1 summarizes the results of drop time measurements from BIR08. In addition, a comparison of drop times l

to previous cycles is provided. Based on this information, there where no changes in the I

RCCA drop times due to Steam Generator Replacement.

2.2 Zero Power Physics Testing Zero Power Physics Testing (ZPPT) is performed at the beginning of each cycle as specified by ANS/ ANSI-19.6.1, " Reload Startup Physics Test for Pressurized Water Reactors." A summary of the Startup Physics Test results is contained in Table 2.2. All test results were determined to be acceptable.

2.3 Power Escalation Testing i

Power Escalation Testing is performed during the initial power ascension to full power for each cyr'e and is controlled by 1/2BVS XPT-3. Tests are performed from 0% through 100% with major testing plateaus at approximately 30%,75%, and 100% power.

Significant tests included:

Core Power Distribution at 25%,46%,69%, and 98% power.

Reactor Coolant Delta-T Measurement at 60% and 100% power.

Hot Full Power Critical Boron Concentration Measurement (100%).

Reactor Coolant System Flow Measurement at 69% and 100% power.

2.4 Core Power Distribution Core power distribution measurements were performed during power escalation at low power (<30%),' intermediate power (40 '/5%), and full power. Measurements are made to verify flux symmetry and to verify core peaking factors are within limits. Data obtained during these tests are used to check calibration of Power Range NIS channels and to calibrate them if required. Measurements are made using the Moveable Incore Detector System and analyzed using the INCORE 3-D computer code.

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. Following successful completion of the low power flux map, power was increased to the 50% S/G testing plateau (calorimetric power of 46%). At this power level, the maximum corrected Fx> was greater than Fxy"", but less than Fxy""d. This was the result of the core load pattern and INCORE constants, not the result of S/G replacement. This resulted in the allowable power increase limited to 66% power. Reactor power was subsequently stabilized at 60.4% and a core power distribution flux map obtained. The corrected Fxy at this power level was less than Fxy"", and the unit was released for increase to full power.

Results of the core power distribution measurements at 25%,46%,60.4%, and full power are shown in Tables 2.3, 2.4, 2.5, and 2.6. respectively.

l 2.5 Full Power Loop Delta-T Determination 1

The purpose of this test is to determine the full power Delta-T for each Reactor Coolant i

loop in order to recalibrates any loop with significant change. This procedure is applicable in MODE I and is performed above 95% Rated Thermal Power (RTP) after each refueling outage. Results are contained in Table 2.7.

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Table 2.1 Unit 1 RCCA Rod drop Time Comparison B1R06 B1R07 #1 B1R07 #2 B1R08 Startup D-02 1.53 0-02 1.555 D-02 1.520 D-02 1.54 B 12 1.5 B-12 1.530 B-12 1.490 B-12 1.51 M-14 1.535 M-14 1.545 M-14 1.520 M-14 1.55 P-04 1.495 P-04 1.505 P-04 1.495 P-04 1.52 B-04 1.49 B-04 1.510 B-04 1.475 B-04 1.49 D-14 1.53 D-14 1.575 D-14 1.510 D-14 1.55 P-12 1.465 P-12 1.490 P-12 1.475 P-12 1.49 M-02 1.555 M-02 1.580 M-02 1.535 M-02 1.59

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G-03 1.51 G-03 1.535 G-03 1.515 G-03 1.52 C-09 1.475 C-09 1.520 C-09 1.470 C-09 1.5 J-13 1.53 J-13 1.565 J-13 1.520 J-13 1.57 N-07 1.5 N-07 1.510 N-07 1.485 N-07 1.52 C-07 1.475 C-07 1.515 C-07 1.465 C-07 1.51 G-13 1.485 G-13 1.520 G-13 1.485 G-13 1.52 N-09 1.5 N-09 1.525 N49 1.470 N-09 1.5 J-03 1.5 J-03 1.525 J-03 1.490 J-03 1.54 E-03 1.55 E-03 1.585 E-03 1.535 E-03 1.56 C-11 1.515 C-11 1.560 C-11 1.500 C-11 1.52 L-13 1.53 L-13 1.550 L-13 1.520 L-13 1.53 N-05 1.525 N-05 1.520 N-05 1.520 N-05 1.52 C-05 1.485 C45 1.520 C-05 1.495 C-05 1.49 E 13 1.51 E-13 1.575 E-13 1.510 E-13 1.54 j

N 11 1.505 N-11 1.525 N 11 1.490 N-11 1.5

- L-03 1.54 L 03 1.545 L-03 1.535 L-03 1.5S H-04 1.525 H-04 1.530 H-04 1.480 H-04 1.5 0-08 1.495 D-08 1.535 D-08 1.480 D-08 1.51 H-12 1.5 H-12 1.515 H-12 1.490 H-12 1.51 M-08 1.505 M-08 1.525 M-08 1.475 M 08 1.49 H-06 1.5 H-06 1.525 H-06 1.495 H-06 1.5 H-10 1.49 H-10 1.560 H-10 1.480 H-10 1.52 F-08 1.E25 F-08 1.555 F-08 1.505 F-08 1.5 K-08 1.52 K-08 1.535 N-08 1.490 K-08 1.51 F-02 1.55 F-02 1.560 F-02 1.505 F-02 1.52 B-10 1.515 B-10 1.525 B-10 1.490 B-10 1.51 K 14 1.53 K-14 1.540 K-14 1.500 K-14 1.54

~ P-06 1.49 P-06 1.500 P-06 1.480 P-06 1.52 B 06 1.49 B-06 1.505 B-06 1.475 B-06 1.6 F-14 1.55 F-14 1.605 F-14 1.535 F-14 1.59 P 10 1.515 P-10 1.525 P-10 1.495 P-10 1.52 K-02 1.54 K-02 1.580 K-02 1.530 K-02 1.57 H-02 1.51 H42 1.510 H-02 1.510 H-02 1.52 B-08 1.5025 B-08 1.515 B-08 1.485 B-08 1.49 H-14 1.5 H-14 1.520 H-14 1.495 H-14 1.52 P-08 1.515 P-08 1.545 P-08 1.520 P-08 1.56 F-06 1.475 F-06 1.530 F-06 1.505 F-06 1.51 F-10 1.515 F-10 1.580 F-10 1.525 F-10 1.53 K-10 1.475 K 10 1.545 K-10 1.490 K-10 1.52 K-06 1.465 K-06 1.510 -

K-06 1.470 K-06 1.47 D-04 1.505 D-04 1.525 D-04 1.485 D-04 1.5 M-12 1.495 M-12 1.615 M-12 1.500 M-12 1.52 D-12 1.485 D-12 1 625-D 12 1.480 D-12 1.5 4

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Table 2.1 Unit 1 RCCA Rod drop Time Comparison 1

B1R06 B1R07 #1 B1R07 #2 B1R08 Startup M-04 1.47 M-04 1.495 M-04 1.490 MN 1.5 H-08 1.525 HG 1.575 E-08 1.505 H-08 1.52.

Average 1.508 Average 1.540 Average 1.498 Average 1.521 Std. Dev. 0.02306 Std. Dev. 0.03046 Std. Dev. 0.01935 Std. Dev. 0.02588

+2 Sigma 1.554

+2 Sigma 1.600

+2 Sigma 1.537

+2 Sigma 1.573

-2 Sigma 1.462

-2 Sigma 1.479

-2 Sigma 1.459

-2 Sigma 1.469 Total 0.03 Sigma Total Average 1.516 Total +2 Sigma 1.58 Total -2 Sigma 136 l

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Table 2.2 B1R08 Startup Physics Test Results i

Review Acceptance Parameter Predicted Measured Difference Criteria Criteria ARO Critical Boron 1437 ppm 1397 ppm 40 pyn 150 ppm 1000 pcm Critical Ca with Reference 1304 ppm 1265 ppm 39 ppm 150 pcm N/A Bank Fully Inserted DitTerential Boron Wonh

-8.32

-8.37 0.6%

10% of design N/A pcm/ ppm pcm/ ppm ARO ITC

-2.814

-2.82 0.0 2 pcm/F of N/A pcm/F pcm/F design value ARO MTC

-1.134

-1.14 0.0 N/A Within Tech pcm/F pcm/F Spec 3.1.1.3 Reference Bank 1109 pcm 1102.7 pcm

-0.57%

$10% between

$15% between (Shutdown Bank B) measured &

measured &

Worth design design Control Bank A Worth 309 pcm 254.6 pcm

-54.4 pcm 515% or $100 530% or $200 pcm of design pcm of design Control Bank B Worth 789 pcm 81R.3 pcm

+29.3 pcm

<l5% or <100

$30% or $200 I

pcm of design pcm of design Control Bani: C Worth 686 pcm 648.1 pcm

-5.52%

<l5% or <100 530% or 5200 pcm of design pcm of design Control Bank D Worth 573 pcm 551.5 pcm

-21.5 pcm

<l5% or <100 530% or 5200 pcm of design pcm of design Shutdown Bank A 233 pcm 277.8 pcm

-44.8 pcm 515% or $100 530% or $200 pcm of design pcm of design Shutdown Bank C 448 pcm 444.4 pcm

-3.6 pcm

<l5% or <100 530% or 5200 pcm of design pcm of design Shutdown Bank D 450 pcm 445 pcm

-5.0 pcm

$15% or $100 530% or 5200 pcm of design pcm of design Shutdown Bank E 534 pcm 503.5 pcm

-30.5 pcm

<l5% or <100 530% or 5200

)

pcm of design pcm of design 1

Total Rod Worth 5131 pcm 4995.9 pcm

-2.63%

$10% between

>90% of the measured &

predicted sum design of bank worths

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c Table 2.3 Core Power Distribution Results 25% Power Plant Data I

Map ID:

Byl0901 Date ofMap:

3/11/98 Cycle Burnup:

0.9 EFPD Power Level:

24.9 %

Control Bank D Position:

153 steps INCORE 3-D Results Core Average Axial Offset

-1.39%

Tilt Rations for Entire Core Height: Quadrant 1:

1.0159 Quadrant 2:

1.0157 Quadrant 3:

0.9685 Quadrant 4:

0.999 Maximum corrected Fxy:

1.8674 Fxy"#-

1.930 Table 2.4 Core Power Distribution Results 46% Power Plant Data Map ID:

Byl0902 j

Date ofMap:

3/13/98 Cycle Burnup:

1.51 EFPD Power Level:

45.9 %

1 Control Bank D Position:

172 steps INCORE 3-D Results l

Core Average Axial Offset

.795 %

Tilt Rations for Entire Core Height: Quadrant 1.

0.9837 l

Quadrant 2:

1.0242 Quadrant 3:

0.9970 Quadrant 4:

0.9951 Maximum corrected Fxy:

1.8992 Fxy""-

1.892 Max. Nudear Enthalpy Rise Hot Channel Factor:

1.7248 Nuclear Enthalpy Rise Hot Channel Factor Limit:

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Table 2.5 Core Power Distribution Results 60.4% Power Plant Data Map ID:

Byl0903 Date of Map:

3/17/98 Cycle Burnup:

3.42 EFPD Power Level:

60.4 %

Control Bank D Rod Position:

185 steps INCORE 3-D Results Core Average Axial Offset

-0.619 Tilt Ratios for Entire Core Height: Quadrant 1:

0.9826 Quadrant 2:

1.0103 Quadrant 3:

1.0100 Quadrant 4:

.9941 Maximum corrected Fxy:

1.7216 Fxy"TP-1.892 Max. Nuclear Enthalpy Rise Hot Channel Factor:

NA Nuclear Enthalpy Rise Hot Channel Factor Limit:

NA Table 2.6 Core Power Distribut on Results Full Power Map Plant Data Map ID:

Byl0904 Date of Map:

3/30/98 Cycle Bumup:

14.6 EFPD Power Level:

97.9 %

Control Rod Position:

219 steps INCORE 3-D Results Core Average AxialOffset

-2.861 Tilt Ratios for Entire Core Height: Quadrant 1:

.9897 Quadrant 2:

1.017 Quadrant 3:

1.001 Quadrant 4:

.9933 Maximum corrected Fxy:

1.6760 Fxy*T"-

1.930 Max. Nuclear Enthalpy Rise Hot Channel Factor:

1.5421 Nuclear Enthalpy Rise Hot Channel Factor Limit:

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i Table 2.7 Full Power Loop Delta-T Loop Thot _

Tcold Full Power Previous Delta-T Cycle Delta-T

-A 610.2 553.0 57.2 59.1 B

609.5 551.9 57.6 60.6 C

610.6 553.1 57.5 60.8 D

611.2 552.7 58.6 62.I L

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3.0 Steam Generator Replacement Related Testing

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3.1 Containment Pressure Test (CPT) (SPP 97-042) l This test was performed +o demonstrate the operability of the primary containment structure and containma liner following the closure of the temporary construction opening for the replacent nt of the Unit 1 S/Gs.

The acceptance criteria were:

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1)

The maximum measured increase of the width of a crack on the outside surface of containment during the test shall be < 0.060 inch.

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There are no indications of gross deformation.

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The test was conducted in conjunction with IBVS 6.1.2.a-1, Integrated Leak Rate Test (ILRT). The containment volume test pressure was stabilized at a value between 47.8 psig and 50 psig and maintained at this level during inspection / mapping.

A pre-pressurization inspection was performed to map concrete cracks. The cracks observed were allless than 0.010" wide. A crack width of 0.010"is the minimum size i

l crack deemed to be structurally meaningful (cracks less than this width are normal shrinkage cracks that occur routinely in all concrete placements). The cracks grew in length, but not significantly in width when the containment was pressurized. A few additional small cracks (less than 0.010" wide) were obsented when at pressure. Crack l

inspections, with containment depressurized, found that portions of a few of the cracks were no longer visible. No new cracks had developed and all cracks remained below the 0.010" threshold. None of the cracks were structurally significant.

l In addition, the general visual inspection of the containment exterior concrete surfaces, performed prior to pressurization, revealed two localized areas where previous repairs (patches) had degraded over time. Loose concrete and rusting rebar were observed. Due to the limited area and depth of these two patches, they were classified as not structurally l

significant. However, it was recommended that these areas be repaired prior to completion of the next refueling outage. Upon depressurization at the end of the CPT, the containment exterior concrete surfaces were re-inspected. No further deterioration of the two patches had occurred nor were any other degraded areas identified. The two localized areas have since been repaired.

A visual (VT) examination of the containment liner plate removal area listed two Information Only (IO) items: areas of discoloration due to condensation and a limited number of "possible" paint blisters (five items approximately 0.75" diameter each). NTS item # 454-514-98BVSXII-lI was initiated to ensure the paint anomalies are reinspected during a future outage.

The size and extent of concrete cracking was very minor. No structural concerns were identified.

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The restoration of the construction opening made during the Steam Generator Replacement (SGR) as well as the general state of the overall containment structure has been shown to be acceptable for return to service.

3.2 Steam Generator Blowdown Flowrate Measurement (SPP 97-043)

This procedure was initiated to measure blowdown flowrate following the replacement of the S/Gs. This procedure measured total blowdown flow and blowdown flow for each i

flow path on each S/G with no flow through each S/G's second flow path.

Acceptance criteria were:

1)

Total S/G blowdown flow of at least 280 gpm.

2)

At least 70 gpm flow achieved through each blowdown flow path.

I The total measured flow was 324 gpm, which exceeded acceptance criterion No.l.

l Acceptance criterion No.2 was met as shown in Table 3.1.

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3.3 SGR Recirculation Pump Performance Tests (SPP 97-44,66,67,68) l This test is performed to verify the pump's capability to recirculate the RSG water inventory in a cold shutdown condition. There is one Wet Lay-up recirculation pump installed per RSG. Various data are collected to determine the recirculation rate of the RSG water inventory as well as obtain baseline pump performance data.

The acceptance criteria were:

1)

Pump flow capabk: of recirculating the S/G at a rate of once per eight hours (;t 37 gpm).

2)

Pump performance in accordance with the manufacturer's pump curve (t 10%).

3)

All ANSI B31.1 pipingjoints are leak-tight (visual).

The SGR Recirculation Pump performance tests obtained initial pump data for all four recirculation pumps and verified the pumps' capability to recirculate the associated S/G, as

. shown in Table 3.2.

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During initial testing, all required data was obtained and acceptance criteria were met except for criterion 3 for S/G Loop "A." In this case, the leaking flanges were repaired.

The applicable portion of the test was performed again, and verified that no visualleakage existed.

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4 3.4 Auxiliary Feedwater Flowpath Verification (SPP 97-045)

SPP 97-045 tested the following performance and functional aspects of the Auxiliary Feedwater (AF) system upon completion of related modifications:

1)

The AF pump performance is within the limits required by calculation.

2)

Perform a mechanical flow balance of both trains of the AF system to establish fhw rates that provide a suflicient margin to overfill for the S/Gs.

3)

Test the function of the 7300 Lead / Lag card to filter the AF suction transient and support the new Technical Specification Condensate Storage Tank (CST) Icvel of 60% (no acceptance criteria were specified for this part of the test).

The acceptance criteria were specified for AF system operation with depressurized steam generators (Modes 5/6):

1)

AF Motor Driven Pumps I AF0lPA and l AF0lPB performance data (differential pressure vs. pump flow) within test limits.

2)

AF Motor Driven Pump 1 AF0lPA and I AF0lPB suction pressure between 18.1 psia and 46.4 psia.

3)

During dual branch line testing, final recirculation flow between 66.9 gpm and 84.4 gpm.

4)

During single branch line testing, final branch line flows (i.e., flows through individual AF flow control valves) between 387.1 gpm and 421.1 gpm.

5)

During single branch line testing, final recirculation flow between 71.7 gpm and 90.2 gpm.

6)

No external leakage observed from flow control valves l AF005 A-H.

The AF pumps test acceptance criteria were conservative since they account for a postulated -15% degraded pump curve and the +7% increased pump curve envelope to assure proper accident flow. The pumps performed satisfactorily and were within both the required curves. The flow balance testing ensured that the accident flow criteria are met for both trains of AF. The filtering function of the 7300 Lead / Lag card was demonstrated to allow the existing administrative level of the CST to be lowered to the new Technical Specification level of 60%. This was accomplished by attaching recorders to the filtered and unfiltered suction pressure of the AF pumps during a dual pump start with the system in a normal configuration. Analysis of the data determined that the Lead / Lag card functioned properly.

3.5 SGR Thermal Expansion Test (SPP 97-046)

The Thermal Expansion Test verifies that identified equipment, piping and components associated with the SGR expand during' heat-up without obstructions or restrictions and that thermal movements for each support, restraint, and/or component are within i

anticipated ranges or evaluated as acceptable. Inspections / evaluations are conducted at nominal ambient temperature,170 F,340 *F,450 F, and 557 F. For elevated temperatures, a minimum soak time of four hours is required prior to taking measurements.

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l The acceptance criteria were:

1)

The equipment, piping and components addressed in the procedure shall expand

. during heat-up without obstructions or restrictions.

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Thermal movements for each suppon, restraint, and/or component shall be within j

the anticipated ranges or evaluated as acceptable.

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Snubbers shall not become fully extended, fully retracted, or bind.

4)

Spring hanger movements shall remain within their working range.

5)

Piping and components shall not cause interference with surrounding equipment, suppons, restraints and structures. There shall be no adjacent plant systems / supports / components, which could come in contact with the subject system during Reactor Coolant System (RCS) heatup.

All required data was obtained and all acceptance criteria were met. Additionally, inspections of modified supports were conducted prior to heatup and after shim j

adjustments, as required.

- 3.6 Large Load Reduction (SPP 97-048)

A 25% load rejection was performed in accordance with SPP 97-048 from an initial power level of approximately 96%. The demanded rate was 200 %/ min and the demanded load change was 290 MW (i.e...~25%). The load rejection was manually initiated from the l

turbine control panel on 3/25/98.

The acceptance criteria were:

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Neither the reactor nor the turbine tripped.

-2)

The S/G safety valves did not lift.

- 3)-

The pressurizer safety valves did not lift.

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Safety injection did not initiate.

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Plant parameters stabilized without significant manual intervention.

l 6)

Plant panmeters, with emphasis on S/G levels and the feedwater system, did not incur sustained or diverging oscillations..

l

- Load and reactor power rapidly decreased and plant parameters subsequently stabilized at

-the reduced power level.

' S/G levels returned to near (i.e., within 2% of setpoint) the 60% setpoint within ten

. minutes.' RCS average temperatures rose slightly before dropping to and stabilizing at final values. There were no significant oscillations.

. Steam dump actuated and modulated, without cycling from open to closed position.

b All steam dump valves had fully closed within six minutes.

i

(.

S/G relief and safety valves did not open during the test.

l

' Pressurizer relief valves did not open during the test.

Control rods initially drove in at high speed to compensate for the positive reactivity -

- e from the power decrease. During the subsequent stabilization period, rod motion 13-

_ - - - - - ~ - _ _ _

_J

_a

l maintained RCS temperature near program. Axial flux difference deve outside the target band but remained inside the " doghouse." Rod position remained ahcVe the rod insertion limit throughout the transient.

No manual intervention was required during the rapid portion of the transient or during the subsequent stabilization.

Plant parameters generally stabilized near their respective setpoints within ten minutes of the initiation of the transient. Specifically, all four S/G levels stabilized near setpoint (i.e.,60%) within ten minutes. Steam pressure, feedwater flow, steam flow, and feedwater pump speed also stabilized without sustained or diverging oscillations.

Selected parameters responded as shown in Table 3.3.

All acceptance criteria were successfully met. Figures 1 through 5 depict typical plant responses for selected parameters.

3.7 10.% Load Decrease (SPP 97-049)

A 10% load decrease in accordance with SPP 97-049 was performed on 3/15/98 from an initial power level of approximately 46%. The demanded rate was 200 %/ min and the demanded load change was 116 MW (i.e., ~10%). The load rejection was manually initiated from the turbine control panel.

Acceptance criteria for this test were as follows:

1)

Neither the reactor nor the turbine tripped.

2)

The S/G safety valves did not lift.

3)

The pressurizer safety valves did not lift.

4).

Safety injection did not initiate.

5)'

Plant parameters stabilized without significant manual intervention.

6)

- Plant parameters, with emphasis on steam generator levels and the feedwater system, did not incur sustained or diverging oscillations.

l Load and reactor power rapidly decreased and plant parameters subsequently stabilized at the reduced power level. The actual load decrease was approximately 120 MWe.

Plant response is summarized below:

S/G levels returned to near the 60% setpoint within five minutes.

.. RCS average temperatures rose slightly before dropping to and stabilizing at final values. There were no significant oscillations.

. Steam dumps actuated, with one valve bank partially opening and closing shortly thereafter.

l S/G relief and safety valves did not open during the test.

Pressurizer relief valves did not open during the test.

j e

Control rods initially drove in at high speed to compensate for the positive reactivity from the power decrease. During the subsequent stabilization period, rod motion maintained RCS temperature near program. Axial flux difference remained within the target band.

14 I

No manual intervention was required during the rapid portion of the transient or e

during the subsequent stabilization.

Plant parameters generally stabilized near their respective setpoints within ten minutes of the initiation of the transient. Specifically, all four S/G levels stabilized near setpoint (i.e.,60%) within five minutes. All other significant parameters (including steam pressure, pressurizer pressure, RCS temperature, and feedwater pump speed) also stabilized without sustained or diverging oscillations.

Selected parameters responded a' shown in Table 3.4.

s All acceptance criteria were successfully met. Figures 6 through 10 depict typical plant responses for selected parameters.

3.8 Steam Generator Level Control (SPP 97-050)

Level setpoint decrease and increase perturbations were performed at approximately 50%

and 75% power level lateaus. In addition, at approximately 50% power, a feedwater f

pump speed transient was initiated.

Acceptance criteria for this test were:

l 1)

S/G narrow range level decreases to and remains within 2% of the level setpoint I

following a level setpoint decrease.

2)

S/G narrow range level increases to and remains within 2% of the level setpoint j

following a level setpoint increase.

3)

S/G narrow range levels stabilize within 2% of the level setpoint following a

{

feedwater pump speed transient.

]

Acceptance criterion No.1 was met. S/G levels decreased to and remained within 2% of the test level setpoint of 55%. Acceptance criterion No.2 was also met as S/G levels increased to and remained within 2% of the test level setpoint of 60%.

S/G level response for the 5% level deviations is summarized in Tables 3.5 and 3.6.

The feedwater pump speed perturbation portion of the test was performed at the 50% test plateau. The perturbation is induced by manual adjustment of the controller for pump speed control. A +25 psi perturbation is induced, followed by observation of parameters.

Once stability is achieved, a -25 psi perturbation is induced. Acceptance criterion 3 was successfully met for all S/G. During manual operation, levels deviated slightly from setpoint. Upon return to automatic, levels returned to and stabilized at setpoint within five minutes from initiation of the transient.

The Steam Generator Water Level Control System (SGWLC) performed satisfactorily at the 50% and 75% power test plateaus. The expected performance criteria for SGWLC following a 5% level setpoint change are as follows:

i 15

(1) the maximum overshoot and undershoot will be less than 4%, and l

(2) narrow range level will be controlled to within 2% of setpoint within j

three time constants (360 seconds) of the step change.

These performance criteria were met. Figures 11 through 14 depict typical plant responses for selected parameters.

3.9 Moisture Carryover Test (SPP 97-051)

This test was conducted on April 3-4*,1998 with the unit at full power. Na-24 was utilized as a radioactive tracer to measure MCO from the RSGs.

The acceptance criterion for this test was:.

1)

Measured moisture carryover (MCO) less than or equal to 0.1%

The % MCO was calculated using three different methods and data sets. The results of all three methods were consistent, with the feedwater calculation being considered the most reliable, resulting in a final value of 0.105% i 0.006 %. While somewhat higher than expected, the MCO value is an improvement over the original S/Gs. The results of this test

{

have been reviewed against the original design specification for moisture content. Based d

on original specification for moisture content of steam, there is no negative impact of operation of the plant with a MCO value as determined with this test.

3.10 Feedwater System Test (SPP 97-052)

This test monitors various parameters associated with the feedwater system during low power operations and during power ascension.

Acceptance criteria were as follows:

1)

The difference between Actual S/G Level and Program S/G Level less than or equal to 2%.

2)

The difrerence between Actual DP and Program DP less than or equal to 25.0 psi.

3)

Main Feedwater Regulating Valve position between the maximum and minimum valve position curves.

4)

Main Feedwater pump turbine speed is less than 5200 RPM.

S/G Level data was collected at four power plateaus, and compared to the level setpoint.

A summary of the results are presented in Table 3.7. Acceptance criterion 1 was met for all S/Gs at all power levels.

Actual differential pressure (DP) between the Feedwater (FW) header and the Main Steam (MS) header was collected at four power plateaus, and Program DP was calculated at the same time. Each actual DP was compare to a calculated DP. A summary of the results 16

are presented in Table 3.8. As can be seen from Table 3.8, acceptance criterion 2 was met for all power levels.

Main Feedwater Regulating Valve position was measured at four power plateaus, and compared to the maximum and minimum valve position curves. A summary of the results are presented in Table 3.9. The Main Feedwater Regulating Valve position acceptance criterion (3) was successfully met at the 75% and 100% power levels. At the 30% and 50% power levels, Main Feedwater Regulating Valve position fell outside of the maximum and minimum valve position curves. Design Engineering has reviewed the failed acceptance criteria and recommended no setpoint changes at the 30% and 50% power levels.

l The Main Feedwater pump turbine speed acceptance criterion (4) was successfully met at all power levels. The speed of each running turbine Main Feedwater pump was recorded at four power plateaus. The maximum speed was 4741 RPM on the IC FW Pump at approximately 100% power. A summary of the results are presented in Table 3.10.

This test also monitored parameters in SGWLC during (1) unit synchronization to the grid and (2) transfer from the Bypass Regulating Valves to the Main Feedwater Regulating l

Valves. These sections do not have any acceptance criteria. Deta was collected only as a l

contingency in case there were significant level control problems associated with the new i

- steam generators at low power. The results of these sections of the test are discussed below.

L While the unit was being synchronized to the grid, control parameters for SGWLC were.

l

. monitored. The Bypass Regulating Control Valves responded satisfactorily and no anomalies were observed. The maximum level deviation was observed on S/Gs 1 A and

' 1B. S/G IB experienced the most swell at synchronization, having a maximum level of ~

approximately 60.8%. S/G 1 A had a minimum level of approximately 54.5%.

i Turbine load was increased to approximately 22%. The transfer of SGWLC from the Bypass Regulat:ng Valves to the Main Feedwater Regulating Valves followed as expected. After the transfer, SGWLC maintained level within 2% of setpoint.

All acceptance criteria associated with this procedure were successfully met with the exception of Main Feedwater Regulating Valve position at low power levels. At the 30%

and 50% power levels, the positions of all Feedwater Regulating Valves plotted above the maximum expected position curve. As previously stated, Design Engineering has reviewed the failed acceptance criteria and recommended no setpoint changes at the 30%

and 50% powerlevels.

l Subsequent to the completion of this test, observations were made relative to Feedwater Regulating Valve position and pump speed. Operations requested a change to the pump speed controller. A setpoint change was prepared, approved and implemented which l

17

provided for a final Feedwater Regulating Valve position of approximately 75% open at full power conditions. FW pump speed remained in an acceptable range.

3.11 Steam Generator Thermal Performance (SPP 97-053)

Using data from the surveillance procedure, IBVS 2.3.5-1 (Reactor Coolant System Flow Measurement), measurements of steam pressure and Taoi for each steam generator were compared against the manufacturer's design performance characteristic of steam pressure vs. Thm. Corrections were made for power and temperature conditions. High accuracy temporary instrumentation was installed for steam pressure and feedwater flow measurements.

The acceptance criterion for this test was:

1)

For cach steam generator, the full-power S/G pressure was greater than or equal to the contract pressure at the biased hot-leg temperature.

This acceptance criterion was successfully met, as steam pressures were approximately 45 psi above contract requirements. The average S/G pressure at nominal conditions was 998 psia or 11 psi above the expected value of 987 psia. A summary of the results is presented in Table 3.11.

Approximately 13.4 psi is the measurement uncertainty for "S/G pressure at nominal conditions" based on using the precision test instmmentation of IBVS 2.3.5-1 " Reactor Coolant System Flow Measurement," so the S/G pressure differences are essentially within this value. S/G pressure was also monitored in SPP 97-055, Plant Performance Baseline Data, although plant instruments (computer points) were used. At 96% power, the SPP 97-055 data indicated average S/G pressure to be ~ 5 psi below expected values. Actual S/G nozzle outlet pressure therefore appears to be consistent with design to within measurement capabilities.

Subsequent to completion of this performance test, discussions with the S/G manufacturer indicated that a portion of the difference between observed steam pressure and the expected value of 987 psia can be attributed to the tube wall thickness used in their calculations. Based on average tube wall thickness (as opposed to maximum tube wall thickness), the revised expected steam pressure for nominal conditions would be 994 psia.

This would result in an average S/G pressure 4 psi above the revised best estimate pressure.

3.12 RCS Flow Verification (SPP 97-054) l This test had two major objectives:

1)

To verify the calibration of the reactor coolant system (RSC) flow transmitters and indications.

2)

To verify RCS flow rate is near predicted values and that no gross problems exist.

l 18 L_____________.__

]

1 Acceptance criteria for this test were:

1) in Modes 3 and 1 (<30% power), total RCS flow was at least 375,114 gpm and each loop flow was at least 93,779 gpm.

2)

The maximum flow acceptance criteria of IBVS 2.3.5-1, " Reactor Coolant System Flow Measurement," have been met.

Acceptance criterion I was successfully met for both Mode 3 and nominal 30% power level measurements. Acceptance criterion 2 was also successfully met as shown in Table 3.12.

RCS flow calibration checks were performed in Mode 3 and at the 30% power test plateau. Loop flowrates were calculated in units of % based on each transmitter's output voltage reading, with ideal flow being 100%. 9 of 12 transmitters in Mode 3 and 4 of 12 transmitters at 30% power were adjusted based on test data. Following recalibration and subsequent retests, all RCS transmitter flows were sufficiently close to 100%.

Main Control Board indicator readings and computer point readings were taken for RCS flow in units ofpercent. These indications showed good agreement with the flows from voltage readings.

3.13 Plant Performance Baseline Data (SPP 97-055)

This procedure monitored several plant parameters to trend actual vs. expected values during initial power ascension. All monitored parameters responded as expected.

The acceptance criterion for this test was:

1)

For the final evaluation of RCS delta T power, each RCS delta T power indication was within 2 % ofcalorimetric power.

This acceptance criterion was successfully met. A summary of the results is presented in Table 3.13.

The data was collected during steady-state operation at approximately 100% power. This data collection was performed following RCS delta-T power recalibrations in accordance with IBVS XPT-15 near 100% power.

An area of focus in Mode 3 was S/G level indication. Calculations were performed so that all narrow range (NR) and wide range (WR) indications for an individual S/G could be compared to the same standard (i.e., the average of the NR levels). The initial data showed that all indications were reasonable except those from WR transmitter ILT501.

I Following this transmitter's recalibration, all indications were reasonable.

i l

19

i l

3.14 Calibration of Steam Flow Transmitters (SPP 97-056) l The purpose of this test was to verify the calibration olthe steam flow transmitters. Data was collected at 0%, 30%, 50%, 75%, and 100% power.

The acceptance criterion for this test was:

1)

For the fmal test performance for each steam flow transmitter (nominal 100%

power), the % error for each steam flow transmitter is within i 2%, or the error has been deemed acceptable when within one of the following ranges: - 5% < %

error < - 2% or + 2% < error < + 5%.

This criterio, vas met for all steam flow transmitters. The % error (i.e., steam flow /feedwatei f10w " mismatch") for the final test performance is shawn ir. Table 3.14.

A steam flow check was performed in Mode 3 and at-power testing was performed at various power levels: 30%,50%, 75%, and 100%. Some problems were encountered with the Barton steam flow transmitters, which had been recently purcSsed and installed with the new S/Gs. The DP span within which the transmitters could la scaled was not J

large enough to accommodate the DP required to indicate the full range of steam flow.

Therefore, Rosemount steam flow transmitters, capable of operating with the required DP span, were procured.

At approximately 100% power, the Rosemount transmitters were scaled and installed at Byron Station Table 3.14 shows the percent error of the new steam flow transmitters after they had been properly scaled.

The resu!ts of this SPP were as expected despite the steam flow transmitters not having a large i.nough DP span for the full range of steam flow.

The test data that was taken with the original steam flow transmitters was applicable to scale the new transmitters. Therefore, performing the test again at the lower power levels was unnecessary even though the transmitters had been changed.

20 l

l

3.15 Loose Parts Monitor Baseline Test (SPP 97-057)

This test records the normal broadband background noise frequency response during plant operations. Data was obtained at approximately 0%,30%,50%,75%, and 100% power.

This procedure had no acceptance criteria.

All required data was obtained. At 50% power, sensor No.12 (S/G D Hot Leg) had no l

output. The evaluation of SPP 97-057 for this power level indicated that there is enough data from other sensors to obtain background noise frequency for the system. A work request was initiated to repair the sensor a: a diture outage, since access at power is not possible.

l s

)

3.16 Feedwater - Steady State Pipe Vibration (inside/outside containment)

(SPP 97-061)

T he test observed / monitored modified FW piping at approximately 96% reactor power.

j The acceptance criterion for this test was:

i 1)

The selected FW piping was qualified for steady state vibration by a separate Engineering evaluation in accordance,cith the criteria contained in reference document EMD-052640, " Criteria for Qualification of Piping Steady State Vibration."

This acceptance criterion was successfully met for FW piping inside and outside containment. Vibration data was evaluated in calculation BYR98-041 and calculation BYR98-040, Rev.1, and found to be within acceptable limits.

3.17 Feedwater-Steady State Pipe Vibration (outside cortsinment)

(SPP 97-062)

The test observed / monitored modified FW piping during Mode 3 conditions with I

tempering flow established.

I The acceptance criterion for this test was:

1)

The selected FW piping was qualified for steady state vibration by a separate Engineering evaluation in accordance with the criteria contained in reference document EMD-052640, "Cr'teria for Qualification of Piping Steady State l

Vibration."

l This acceptance criterion was successfully met for FW piping outside containment.

i Vibration data was evaluated in calculation BYR98-040, Rev.0, and found to be w thin acceptable limits.

21

a l

l 3.18 Steam Generator Primary Head Drain Lines Vibration (SPP 97-063) l This test measured pipe zibration on the S/G primary head drain lines.

The acceptance criterion for this test was:

1)

The piping was qualified for steady state vibration by a separate Engineering evaluation in accordance with the criteria contained in reference document EMD-

. 052640," Criteria for Qualification of Piping Steady State Vibration."

This acceptance criterion was successfully met for primary head drain line vibration.

Engineering performed an evaluation of the vibration test data gathered on the steam generator primary head drain lines and found to be within acceptable limits. The evaluation is documented in calculation BYR98-042.

3.19 Loose Parts Monitoring System (LPMS) Hammer Test (SPP 97-137)

The SGR Loose Parts Monitor Baseline Impact Test provides baseline impact information for the sensors installed as a result of the modific tion. Data obtained during testing is reviewed for acceptability as it is recordeo and logged.

This procedure liad no acceptance criteria.

The test results are as follows:

1)

All data required by the test was obtained and is acceptable.

2)

Representative curves have been obtained from the data for each sensor that demonstrate the required sensitivity as defined by Regulatory Guide 1.133. Actual sensor sensitivity will be determined using background levels recorded during power escalat;on. The sensors were confirmed to be operating satisfactorily with the necessary sensitivity.

3.20 Steam Generator Level Instrumentation Tubing / Inservice Leak Testing These procedures provided for a visual inspection of piping components to verify structural integrity. The inspections are allowed by Code Case N-416-1, " Alternate Pressure Test Requirements for Weld Repairs or Installation of Replacement Items by Welding, Class 1,2, and 3."

i The acceptance criterion was:

1)

No visualleakage is observed S/G level tubing replaced under the S/G replacement modification was visually inspected for leaks. The acceptance criterion was met. No visual leaks were detected.

22 l

3.21 Surveillance Procedures Several normal plant surveillance procedures were performed to demonstrate proper equipment operation. The procedures listed below were performed satisfactodly, reviewed and approved as required by the Startup Testing Program:

1)

IBVS 6.1.2.a-1, Unit 1 Primary Containment Type A Integrated Leakage Rate Test (ILRT) 2).

1BVS 6.3.3-15, Unit 1 Main Feedwater System Containment Isolation Valves Full / Partial Stroke 3)

IBVS 6.3.3-20, Unit 1 Main Feedwater System Containment Isolation Valves Stroke Test

4) '.

IBOS 3.2.1-807, Unit 1 ESFAS Instrumentation Slave Relay Surveillance (Train A FW lso & SI)

5).

IBOS 3.2.1-817, Unit 1 ESFAS Instrumentation Slave Reicy Surveillance (Train B FW Iso & SI) 6)

1BOS 0.5-2.FW.3, Main Feedwater System Valves Indication 7)'

IBVS 0.5-2.FW.3, Main Feedwater System Valves Indication 8)

IBVS XPT-7 Unit 1 RCS RTD Cross Calibration

- 9) 1BVS 4.10-10, Unit 1 Non-Routine Visual Examination (VT-2) of ASME Class 1, 2, & 3 Components at Nominal Operating Pressures 10)

IBVS 1.3.4-lb, Unit 1 Manual Rod Drop Time 11)'

1BVS 7.8-2, Unit 1 Functional Testing of Technical Specification Mechanical &

. Hydraulic Snubbers 12) 1BOS 0.1-1,2 & 3, Unit 1 Mode 1,2, & 3 Shiftly and Daily Operating Surveillance 13) 1BOS 7.1.2.2-1, Unit 1 Train A Auxiliary Feedwater Flowpath Operabihty f

Surveillance Following Cold Shutdown 14) 1BOS 7.1.2.2-2, Unit 1 Train B Auxiliary Feedwater Flowpath Operability Surveillance Follow'mg Cold Shutdown -

15) 1BVS AF-3, Unit 1 Simultaneous Start ofBoth AF Pumps with Flow to the S/Gs i

I l

b l

i 23 Ln-_ _--_----

l' Table 3.1 S/G Blowdown Flow Steam Generator Instrument S/G Blowdown Flow (GPM) 1A 1FI-SD030 81.6 IB IFI-SD031 81.6 1C 1FI-SD032 79.4 1D 1FI-SD033 81.6 1A 1F1-SD038 82.I 1B 1FI-SD039 82.1 1C 1FI-SD040 82.1 1D 1FI-SD041 82.1 Table 3.2 Steam Generator Recirculation Flow Rate Steam Generator Recirculation Flow Rate A

80.1 GPM

,j 81.6 GPM C

74.1 GPM D

65.8 GPM Table 3.3 Large Load Reduction Plant Parameters Parameter Initial Minimum Maximum Final S/G 1 A level (%)

60 55 68 59 S/G 1B level (%)

60

.55 69 59 S/G 1C level (%)

60 55 72 59 S/G 1D level (%)

60 55 68 59 Pressurizer pressure (psig) 2233 2177 2266 2250 Steam hdr pressure (psig) 956 956 1037 978 24 u_____.________..___.__

.J

Table 3.4 10% Load Reduction Plant Parameters l

Parameter initial Minimum Maximum Final S/G 1 A leve!(%)

60.0 56.0 62.5 59.5 S/G 1B level (%)

59.5 56.5 62.5 59.5 S/G 1C level (%)

60.0 56.5 62.8 60.0 S/G 1D level (%)

59.5 56.0 62.5 59.5 Pressurizer pressure (psig) 2232 2212 2245 2232 Steam hdr pressure (psig) 1010 1010 1056 1020 I

I Table 3.5 1

Steam Generator Level Response - 50% power test plateau Test Parameter Units S/G 1A S/G 1B S/G IC S/G ID l

S/G level Initial S/G levei(1) 54.6 54.7 54.5 55.3 l

increase Maximum overshoot (2) 2.3 1.4 1.4 1.9 Maximum undershoot (3)

-0.8

-2.4

-1.8 Final S/G level (4) 59.9 60.5 60.5 60.0 l

Time to level stability (5) sec 127 53 49 47 l

S/G level Initial S/G level (1) 60.5 59.6 59.4 59.3 increase Maximum overshoot (2) 0.9 2.0 3.5 2.0 Maximum undershoot (3)

-1.7

-1.2

-2.0

-1.5 Final S/G level (4) 55.5 54.7 54.5 54.8 Time to level stability (5) sec 60.4 104.4 69.8 73.6 Notes: (1)

S/G leveljust prior to setpoint change.

(2)

Difference between oscillation peak (maximum level) and final stable level.

(3)

Difference between oscillation peak (minimum level) and final sta' ole level.

(4)

S/G level at time of stability.

(5)

Time interval from level setpoint change to stability.

25

Table 3.6 Steam Generator Level Response - 75% power test plateau Test Parameter Units S/G 1A S/G IB S/G IC S/G ID S/G levcl Initial S/G level (1) 60.2 60.5 59.0 59.0 increase Maximum overshoot (2) 0.8 1.3 0.8 1.0 Maximum undershoot (3)

-1.8

-2.0

-2.4

-3.4 Final S/G level (4) 55.3 55.2 54.5 54.5 Time to lewl stability (5) sec 52 60 220 250 S/G level Initial S/G level (1) 55.0 55.0 54.5 54.5 increase Maximum overshoot (2) 2.2 2.9 2.1 1.9 Maximum undershoot (3)

-0.6

-0.7

-i.5 Final S/G level (4) 60.0 59.8 59.5 60.0 Time to level stability (5) sec 150 186 60 54 Notes: (1)

S/G leveljust prior to setpoint change.

'(2)

Difference between oscillation peak (maximum level) and final stable level.

(3)

Difference between oscillation peak (minimum level) and final stable level.

i (4)

S/G level at time of stability.

(5)

Time interval from ievel setpoint change to stability.

Table 3.7 Steam Generator Level Error vs. Power Level Power Steam Generator Level Error Level 1A 1B 1C 1D

(%)

30 0.6 0.9 0..

0.9 50 0.1 0.3 0.2 0.3 75 0.2 o7 0.5 0.2 100 0.7 0.8 0.02 0.4 Table 3.8 FW / MS DP Error vs. Power Power Level DP Error

(%)

, psid)

(

l 30 0.6 L

50 0.8 75 0.03 I

100 1

l 26 IL__-

=_

l i

J Table 3.9

}

Main Feedwater Regulating Valve Position vs. Power Power 5iain Feedwater Regulating Valve Position i

Level FCV-510 FCV-520 FCV-530 FCV-540

(%)

i Max Pos.

25.0 22.0 26.0 25.0 30 41.5 37.5 34.1 34.1 Min Pos.

0.75 0.75 0.8 0.8 Max Pos.

40.0 40.0 40.0 40.0 50 41.0 44.3 44.3 42.0 Min Pos.

19.0 19.0 20.0 19.0 Max Pos.

64.0 64.0 68.0 64.0 75 61.36 59.1 54.5 63.6 Min Pos.

43.0 43.0 47.0 43.0 Max Pos.

85.0 85.0 85.0 85.0 100 76.1 76.1 81.8 75.0 Min Pos.

60.0 60.0 60.0 60.0 Table 3.10 Main FW Pump Speed vs. Power Level i

Power Level IB FW Pump IC FW Pump

(%)

(RPM)

30 3500 N/A 50 4025 N/A 75 3943 3981 100 4735 4741 Table 3.11 Steam Generator Pressure vs. Best Estimate Predictions Parameter -

S/G 1A S/G IB S/G IC S/G ID S/G pressure at nominal conditions of 998.4 1003.4 996.7 994.1 100% power,582 deg F Tave (psia)

Expected S/G pressure at nominal 987 987 987 987 i

(.

conditions (psia)

S/G pressure difference 11.4 16.4 9.7 7.1 (psi) 27

Table 3.12 RCS Flow vs. Acceptance Criteria RCS loop Flow (gpm)

Maximum Flow Criteria (gpm) 1A 99779 s 103,651 IB 99284 s 103,651 1C 100808 s 103,651 1D 97837 s 103,651 Total 397708 s;412,782 Table 3.13 Full Delta T Power Indication Item Indicated Power Difference from

(%)

Calorimetric (%)

Loop 1 A delta T 97.87

-0.33 Loop 1B delta T 98.01

-0.19 Loop IC delta T 98.79 0.59 Loop ID delta T 97.12

-1.08 Calorimetric power 98.2 N/A Table 3.14 Steam Flow / Feed Flow Mismatch At 100% Power Level S/G Feed Flow Feed Flow Steam Flow Steam Flow

% error Transmitter (mpph)

Transmitter (mpph) 1A 1 FT-510 3.635 1FT-512 3.700 0.4 1 FT-511 3.661 1 FT-513 3.710 0.6 1B 1FT-520 3.597 1FT-522 3.636

-0.2 1FT-521 3.608 1FT-523 3.630

-0.4 1C 1FT-530 3.673 1FT-533 3.716 0.1 1FT-531 3.669 1FT-534 3.728 0.4 1D 1FT-540 3.624 1 FT-543 3.674

-0.1 1FT-541 3.649 1 FT-544 3.689 0.3 j

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