Text

Final Summary Rept,Edwin I Hatch Unit 2 Startup Test Results
	ML20137W640
Person / Time
Site:	Hatch, Brunswick, 05000000
Issue date:	10/31/1979
From:	Turkowski R, Yee W; GENERAL ELECTRIC CO.
To:	;
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ML20137W593	List: ML20137W587; ML20137W619; ML20137W640;
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	79NED135, NEDO-24734, NUDOCS 8512100291
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{{#Wiki_filter:NEDO-34734 79NED135 CLASSI OCTOBER 1979 l l FINAL

SUMMARY

REPORT l l EDWIN 1. HATCH UNIT 2 l STARTUP TEST RESULTS l R. W. TURKOWSKI W.YEE 0D111!!!P GENERAL ELECTRIC Otil ? t 00291 "? ^ ""c "

T NEDO 24734 79NED135 Class i October 1979 FINAL

SUMMARY

REPORT EDWIN 1. HATCH' UNIT 2 STARTUP TEST RESULTS t R. W. Turkowski W.Yee k, $a? g, Y anager f Approved' G. T. Uorst, W Plant Startup and Test NUCLE AR PUEL AND StnVICES OlVISION e GENERAL ELECTHic COMPANY BAN JOSE. CALIF ORN! A 96126 GENER AL $ ELECTRIC

t I OMR OF RESPO90SIStuTY l t l t + This document was prepared by or for the General Electhc Company, Norther th6 General BecMc Company nor any of the contnbutors to this document: A. Makes any warranty or representation, express or imphed, wrth respect to the I accuracy, comoktsness, or useMness of the information contamed in ttka I document, or thst the use of any inkmotion discbsed M this document may not Inkinge privately owned rights; or i B. Assumes any responeitnty for liabiMy or damage of any kind which may resuM l kom the use of any MWmahon dieckeed M thse document. t

I l NECD 24734 CONTENTS Page A B STR A CT ...... - -.1x 1. INTROD UCTION.. .- 1 1 1.1 Purpose. ..1 1 1.2 Plant Description.. .11 1.3 Startup Test Program. .1 1 1.4 Startup Test Descripton.. ...1 1 1.5 Startup Test Acceptance Criteria. 4 ..1 1 2.

SUMMARY

OF THE TEST PROCRAM. ..... 21 2.1 Chronobgy of Startup Testing. .21 2.2 Test Completion Dates for Startup Tests ..21 2.3 Power / Flow Map with Startup Test Conditons........ .21 3. SU MM ARY O F TE ST R ESULTS............. .. 3 1 3.1 STl 1, Chemical and Radiochumical. ....31 3.2 ST12 Radiaton Measurements.......... .3-6 3.3 ST13, Fuel Loading. .3-7 3.4 STI 4, Full Core Shutdown Margin.... .......... 3 7 3.5 STI 5, Control-Rod Drive Systom.. ..........................................3-8 3.6 STl 6, SRM Performance and Contro'-Rod Sequence. ..... 3 10 3.7 STl 8, Rod Sequence Exchange. ..3 10 3.8 STI 9, Water Level Measurement:...... ... 3 13 3.9 STI 10, IRM Performance........ .......................315 3.10 STI 11, LPRM Cahbraten..... ................... 3 1 5 3.11 STl 12. APRM Cahbration.. .3 15 3.12 STI 13, Process Computer... .3 16 3.13 STl 14, Reactor Core isolaton Coohng System..................... ..... 3 17 3,14 STl 15. High Pressure Coolant injection System (HPCI)............. ,.. 318 3.15 STl 16. Selected Procoss Temperatures...................................................... 3-1 9 3.16 STl 17, System Enpanslon..... .3 20 3.17 STI 18. Core Power Distnbuton. .. 3-21 3.18 STI 19. Coro Performance... .3-22 3.19 STl 20, Steam Producton. .. 3-23 3 20 STI 21. Core Power - Void Mode Response............ ..................324 3.21 STl 22. Pressure Regulator... ..3 24 3 22 STl 23. Feedwator System.... .....3-29 3.23 STI 24, Turbine Valve Surveillance................. ........ 3-31 3 24 STl 25. Main Steam Une isolation Valves........................................................ 3 32 3 25 STI 26. Rohef Valves................ ...... 3 34 3.26 STI 27. Turtune Trip and Generator Load Rejecten........... .3 37 3 27 STl 28, Shutdown from Outside the Contrel Room.. ....... 3 40 3.28 STI 20. Flow Control. .. 3 41 3.29 GTI 30. Recirculation System.. ..............345 3.30 STI 31, Loss of Turtxne Generator and Offsite Power................. .3 45 3 31 STl 33. Drywell Piping Vibtat on. ...... 3 4 7 3 32 STl 35, Recircutaton Systom Flow Cahbraten. .3 47 3 33 STI 70, Reactor Water Cleanup System....... ..... 3 49 3 34 STl 71, Residual Heat Removal System.... ... 3 51 3 35 STl 74. Offgas System. ... 3 53 4. DISTAlDUTION : _1 .til./.lv.

NEDO 24734 TABLES Table Title Page 21 Sqnificant Dates Dur!ng the Startup Test Program.

-2-1 22

, Stcrtup Test Completion Dates 2-2 31 Chemical and Radochemical Test Results. .3-2 3-2 High Radiaton Areas identified at Test Condition 6.. 7 33 Mean Scram Times (Seconds). ..3-9 3-4 Scram Times of Slowest Rods (Seconds).. .3-9 3-5 Scram Times to Position 06 (Seconds)... ... 3-9 .. = 3-6 Selected Rod Scram Times to Position 06 (Seconds).. 3-10 37 Coro Parameters Before and After Rod Sequence Exchange..... .3-11 38 APRM Tracking Ability.. .... 3 16 39 Results of RCIC Testing. .3-17 1 to final RCIC Control Settings. .3 18 3 11 Final Results of HPCI Testing.... ... 3-19 3 12 Final HPCI Control Settings. .3-19 3-13 Summary of Temperature Behavior (*F) .3-20 3 t4 TIP Reptoducibility Data. .. 3-21 3 15 Summary of Core Performance Parameters. ..3 22 3 16 Steam Producten Test Data..... .. 3-23 3 17 Final Pressure Regulator Control Settings.. .3-25 3 18 Results of Pressure Regulator Testing at Test Conditon 6. . 3 26 3-t 9 feedy,ater Controller Settings.. . 3 29 3 20 Foodwater Actuator Flow Response to Small Stop Changes (Seconds). .. 3-30 341 Plant Conditions During Turbine Valve Surveillance Testing ...... 3-31 3 22 Tuibine Valve Surveillance Results.... .3-31 3 23 Individual MSIV Closure Results.... ..3 32 .v.

NEDO-24734, TABLES (Continued) Table Title Page 3-24 MSIV Closure Times - 33 3-25. Sequence of Events During Full Closure of All MSIV Tests. .3-34 3-26 SRV Valve Timing. .3-35 3-27 Relief Valve Capacities 3-36 3-28 STI 27 Test Results. 37 3-29 Turbine Trip at TC3 t-3-38 3-30 Generator Load Rejection at TC6.. 3-39 3 31 Sequence of Events for Shutdown-Outside-the-Control-Room Test 3-40 3-32 Recirculation System Controller Settings - 3-41 s s 3-33 Response to Recirculation System Step Changes - Test Condition 3 .. 3-42 < 3-34 Recirculation System Load Following Demonstration -Test Condition 3 3-43 t 3-35 Response to Recirculation System Step Changes - Test Condition 6 3-44 3-36 Single Recirculation Pump Trip Results - 3-45 s., 3-37 Sequence of Events During Loss of Turbine Generator and Offsite Power Test. 3-46, 3-38 Results of Jet Pump Calculations by Nozzia Method and by Pump Head Curve Method .3-48 3-39 Reactor Water Cleanup System Performance.

3-50 s

3-40 RHR Torus Cooling Mode Average Results 3-52 3-41 RHR Steam Condensing Mode 3-52 3-42 RHR Controller Settings 3-53 3-43 Offgas System Design Parameters and Results - ... 3-54 + \\ -vi-t

NEDO-24734 ILLUSTRATIONS Figure Title Page 2-1 Histogram of Startup Test Program (July 1978) 2-5 2-2 Histogram of Startup Test Program (July-August 1978).. 2-6 2-3 Histogram of Startup Test Program (August September 1978) - 2-7 l 2-4 Histogram of Startup Test Program (September-October 1978) 2-8 2-5 Histogram of Startup Test Program (October 1978) - 2-9 2-6 Histogram of Startup Test Program (October November 1978). 2-10 2-7 Histogram of Startup Test Program (November-December 1978) 2-11 2-8 Histogram of Startup Test Program (December 1978-January 1979). 2-12 i 2-9 Histogram of Startup Test Program (January 1979)... 2-13 2-10 Histogram of Startup Test Program (January-February 1979). ... 2-14 2-11 Histogram of Startup Test Program (February-March 1979) 2-15 2-12 Histogram of Startup Test Program (March-April 1979). 2-16 2-13 Histogram of Startup Test Program (April 1979). 2-17 2-14 Histogram of Startup Test Program (April-May 1979) 2-18 2-15 Histogram of Startup Test Program (May-June 1979). 2-19 2-16 Histogram of Startup Test Program (June-July 1979). .2-20 2-17 Histogram o' Startup Test Program (July 1979) 2-21 2-18 Histogram of Startup Test Program (July-August 1979) 2-22 2-19 Approximate Power Flow Map Showing Startup Test Conditions 2-23 3-1 Posttreatment Offgas Monitor Calibration Curve 3-3 3-2 Pretreatment Offgas Monitor Calibration Curve.. 3-4 3-3 Stack Monitor Calibration Curve - 3-5 3-4 Rod Pattem Before and After Exchange.... 3-12 3-5 Wide Range Water Level Variation with Reactor Power .3-14 vil-

NEDO 24734 ILLUSTRATIONS (Continued) Fibure Title Page 3-6 Wde Range Water Level Variation with Core Flow. - 14 l 37 . Steam Flow Versus Pressure Regulator Outp:A. 3-27 3-8 Steam Flow Demand Versus Pressure Regulator Output 3-27 3-9 Steam Flow Demand Versus Control Valve Position - 3-28 i f 1 -vi;i-

.~.. NEDO 24734 i 4 ABSTRACT This repott consists of a summary of the Startup Test Program performed at Unit 2 of the Edwin I. Hatch Nucbear P6wer Plant. It includes resuMs of static and dynamic reactor performance tests of the reactor and related systems within the General Electric scope of supply. ix/ x-

. NEDO 24734 a

1. INTRODUCTION 1.1 PURPOSE This report presents a brief summary of the results of startup testing on General Electric related systems in Unit 2 of the Edwin 1. Hatch Plant. The startup test program encompasses core physics, thermal hydraulic, electromechanical, and overall dynamic performance of the reactor and related systems-1.2 PLANT DESCRIPTION The Edwin I. Hatch Nuclear Power Plant Unit 2 is a single-cycle boiling-water reactor designed by General Electric for the Georgia Power Company.The plant is located on the south side of the Altamaha River, southeast of the intersection of the river with U.S. Highway No.1 in the northwestern sector of Appling County, Georgia. The power plant is warranted for 2436 MWt. At this power level the main generator is warranted for 820 MWe.

1.3 STARTUP TEST PROGRAM The startup test program began with fuelloading on June 22,1978, and fini;,hed with the end of the warranty run on August 2,1979. The plant testing consisted of the following successive phases: Phase 1 - Pre-operational testing (not covered in this report) Phase 2 - Fue! loading and open vessel testing Phase 3 - Initial heatup to rated temperature and pressure Phase 4 - Power tests Phase 5 - Warranty tests 1.4 STARTUP TEST DESCRIPTIC-N Documents such as the operating license, technical specifications, plant operating proceoures, and equipment manuals control reactor operations during the startup test program. The startup test program is implemented using the Startup Test Specification (22A4140) supplied by GE-NEBG for testing on equipment it has designed and supplied. From the Startup Test Specifications, plant-specific startup test procedures were written to perform the required test. The Startup Test Specification is a document issued for review and approval by GE managemment and is used for planning and scheduling tests. The chosen tests are required either to demonstrate that iils safe to proceed, to demonstrate performance, or to obtain engineering data. This document defines the minimum test program needed for a safe, efficient startup. The purpose, description, and criteria are given for each test together with a description of each test condition. The 6tartup Test Procedure is a document written for use in the control room by qualified GE/GPC personnel to properly perform and evaluate each startup test. These instructions are part of plant operating procedures and are subject to review and approval by customer personnel 1.5 STARTUP TEST ACCEPTANCE CRITERIA . The Startup Test Specification contains criteria for acceptance of ' esults of that test. There are two levels of criteria r identified, Level 1 and Level 2. Level 1 criteria include the values of process variables assigned in the design of the plant and equipment. If a Level I criterion is not satisfied, the plant is placed in a satisfactory HOLD condition until a resolution is made. Tests compatible with a HOLD condition may be continued. Following resolution, applicable tests must be repeated to verify that requirements of the Level 1 criterion are satisfied. 1-1 i -]

NEDO-24734 Level 2 criteria are associated with expectations in regard to performance of the system. If a Level 2 criterion is not satisfied, operating and testing plans would not necessarily be altered, investigations of the measurements and of the analytical techniques used for the predictions would be started. Safety limits, as set forth in plant technical specifications, are not included because there are no planned operations of testing at such levels. By meeting the criteria, startup test results demonstrate agreement with design specifications and predictions. T 1 12

~ NEDO 24734 2.

SUMMARY

OF THE TEST PROGRAM 2.1 CHRONOLOGY OF STARTUP TESTING Some dates that were significant during the test program are listed in Table 3-1. The dates of testing of the startup tests at the specified test conditions are shown in Table 2-2. Figures 2-1 through 2-18 display a histogram (power / pressure versus time) of the test program beginning with reactor startup in June 1978. 2.2 TEST COMPLETION DATES FOR STARTUP TESTS The test completion dates are summarized in Table 2-2 for the entire Edwin 1. Hatch Unit 2 startup test program, 2.3 POWER / FLOW MAP WITH STARTUP TEST CONDITIONS Figure 2-19 shows a plot of core power versus core flow which identifies each test condition. Table 21 SIGNIFICANT DATES DURING THE STARTUP TEST PROGRAM Operation Date Began Fuel Loading 6/20/78 Completed Fuel Loading 6/30/78 initial Criticality 7/4/78 First Heatup 7/16/78 Maintenance Outage to Correct High Drywell Temperature Problems 8/20/78-9/16/78 First Generator Synchronization 9/22/78 Began Test Condition 1 (TC1) Testing 9/29/78 Finished Test Condition 1 (TC1) Testing 10/12/78 Began Test Condition 2 (TC2) Testing 10/12/78 Finished Test Condition 2 (TC2) Testing 10/25/78 Began Test Condition 3 (TC3) Testing 10/25/78 Conducted Test Condition 7 (TC7) Testing 11/20/78 Began Test Condition 4 (TC4) Testing 12/1/78 Finished Test Condition 4 (TC4) Testing 12/2/78 Began Test Condition 5 (TC5) Testing 12/7/78 Finished Test Condition 5 (TCS) Testing 12/12/78 Finished Test Condition 3 (TC3) Testing 12/15/78 Began Test Condition 6 (TC6) Testing 12/16/78 Maintenance Outage to Modify Steam Dryer 12/25/78-1/30/79 MSIV Full Closure 2/14/79 Maintenance Outage to Repair and Test Plant Hangers 2/15/79-5/28/79 Load Rejection at TC6 6/19/79 MSIV Full Closure 6/27/79 Feedwater Flow Instrument Miscalibration Discovered 7/18/79 Finished Test Condition 6 (TC6) Testing 7/27/79 Began Warranty Run 7/28/79 Completed Warranty Run 8/2/79 2-1 l

NEDO-24734. Table 2-2 STARTUP TEST COMPLETION DATES Startup Test Open Procedues Vessel Hestup TC1 TC2 TC3 TC4 TC5 TC6 Chemical and 7/3/78 9/17/78 9/30/78 10/2598-12/12/78-12/15/78-Radiochemical 10/27/78 12/20/78 5/8/79 Radiation 6/7/78-8/21/78 10/12n8 10/27/78 12/16/78 Measurements 7/5/78 Fuet 8/22/78-Loading 6/30/78 Full Core 7/4/78 Shutdown Margin Control Rod 6/9/78-7/24/78-9/29/78-11/23/78 2/14/79 Drive System 7/9/78 9/22/78 9/30/78 SRM Performance 7/4/78 7/16/78-9/29/78-and 9/18/78 10/3/78 Control Rod Seq 4 Rod Sequence 2/4/79 Exchange Water Level 9/20/78-11/24/78 11/24/78 11/26/78 12/1/78 12/7/78 12/16/78 Measurements 11/27/78 IRM 7/4/78 7/16/78-9/30/78-Performance 9/25/78 10/2/78 8/19/78 10/1/78 10/26/78-12/16/78-LPRM Calibration 10/28/78 12/17/78 APRM 8/14/78 9/28/78-10/12/78 10/26/78 12/7/78 12/16/78-Calibraton 10/3/78 12/18/78 Process 7/13/70-9/25/78 9/30/78-10/28/78 12/22/78-Computer 8/11/78 10/5/78 11/14/78 1/3/79 RCIC 10/20/78-11/7/78-11/29/78-10/22/78 11/19/78 1/31/79 j i HPCI 9/28/78 11/12/78 Selected Process 9/23/78 10/2/78 11/7/78-1 12/1/78-12/16/78 j Temperatures 11/18/78 12/2/78 System 7/15/78-10/3/78 10/12/78 10/26/7F 12/18/78-Expansion 9/24/78 6/15/79 Core Power 9/28/78-10/28/711 12/18/78-Distribution 10/5/78 7/27/79 Core 10/3/78 10/12/78 11/7/78 12/1/78 12/7/78 7/27/79 Performance Steam 7/28/79-Production 8/2/79 2-2

NEDO 24734 Tatde 2-2 STARTUP TEST COMPLETION DATES (Continued) Startup Test Open Procedure Vessel Hestup TC1 TC2 TC3 TC4 TC5 TC6 Core Power 12/1n8 Void Mode

Response

Pressure 10/8/78 10/24n8 11/6/78 12/1/78 12/8/78 12/19n8-Regulator 6/28/79 Feedwater System a) Feedwater Pump Trip 7/21 69 b) Water Level 10/4/78-10/18/78 10/31/78-12/1/78-12/8n8 12/19n8 Setpoint 10/10/78 11/22/78 12/2/78 Change c) Heater Loss 6/18/79 d) Maximum 2/13/79-Runout 2/14/79 Capability Turbine Vane 11/7n8-12/8n8-7/21/79 Surveinance 11/13n8 12/13n8 Main Steam isolation Vanes a) Each 9/18 68 10/26/78-12/12/79-VaNo 10/27/78 12/13/79 b) One 10/26n8-12/12/79-Vane 10/27n8 12/13/79 c) Full 6/27 a9 isolation Relief Valves 7/20/78 10/15n8-11/25 n8 Load Rejection 10/3168 6/19/79 Turbire Trip 11/23/78 Shutdown from 10/8n8 Outside the Control Room Flow Control 12/19/78 12/2008 12/21/78 12/21/78-12/22/78 Recirculation 11/18/78 2/6/79-System 2/7/79 a) One-Pump Trip b) Two-Pump 11/18/78 Trip 2-3

) NEDO-24734 Table 2-2 STARTUP TEST COMPLETION DATES (Continued) Startup Test Open Procedure Vessel Hestup TC1 TC2 TC3 TC4 TC5 TC6 c) System 9/30/78 10/13/78 11/16/78 12/1/78 2/6/79 Performance d) Noa-Cavit 11/20/78 VertAcation t D Loss of 11/3/78 Turbine Gen Offsite Power Drywell Piping 7/15/78-10/31/78 10/12/78-10/24/78-12/18/78-Vibration 9/23/78 11/6/78 11/23/78 6/28/79 Core Flow 7/13/78 10/24/78-12/7/78-12/12/78-Calibration 12/4/78 12/8/78 12/18/78 Reactor Water 8/19/78 10/22/78 Cleanup System Residual Heat 9/24/78-11/13/78-Removat System 9/26/78 11/16/78 Offgas 9/17/78 10/2/78 10/26/78-12/18/78-System 11/7/78 7/27/79 l l 2-4

Z g TN2 l sb5E 0 0 = 0 0 0 0 0 0 0 0 0 0 1 0 0 0 0 3 7 3 2 1 1 1 ~ l 42 l f 32 j l 2 G 2 I w l N TSsg 1 a 2 E p T 0p I 5 C 1 0 P 2 HT / A l C I 9 C 1 R )8 8 7 1 L 9 1 7 y I l 1 u I (J 6 m c 1 a e r L s I g A0 o C 8 5 rP I 1 1 TF I 7 s I 8 t R O 9 e 4 CD 1 T 1 RO p O R I Y I L u T 3 U t E r 1 J C P a A t E A I S f RN 2 o O 1 m I a 1 r 1 go N I ts i I 0 H G 1 e Le R I 1. s A A9 MD 9 2 C8 E ITF N N e I O WI l r C D O M u R 8 g DR i O E OR U T l F RB T E E R TE H 7 D R U CP S S AA E i E S ER N R W E O R O O 6 P P C I I 5 I 4 I 3 l 2 l 1 ~ 0 n e 0 0 0 0 0 0 8 7 3 2 1 1 1 i 2i on6c 9= j l lllll l

ties 110 PRESSURE REDUCED TO 1000 100 l FIX SMALL STEAM POWER LEAK IN MSLC " " '"""" PRESSURE 900 90 I I AVERAGE DRYWELL f 300 TEMP EXCEEDED g 80 135*F (Q PRESSURE REDUCED 3 I 70 - REACTOR SHUTDOWN AVERAGE DRYWELL AVER AGE DRYWELL 700 -f FOR WORK ON TEMP EXCEEDED TEMP EXCEEDED AVERAGE DRYWELL g DRYWELL COOLERS 135*F - RE ACTOR 135*F TEMP EXCEEDED l { SHUTDOWN 136*F REACTOR SHUTDOWN q l 000 w go q .. INSPEO11. g 1h p lI l - gg - - M s l I l l1 lIj l L_>4 3 E h .0 REACTOR CRITICAL. I REACTOR REACTOR REACTOR l f i A PERIOD OF CRITICAL ON CRITICAL ON CRITICAL ON '0* A PERIOD OF A PERIOD OF l l A PERIOD OF i l q 17, _ i g 20 i i i \\ l i I 1 I [ l \\ l I l 10 i Jl ( l \\ l IY 1, ,l l ml\\l l I, l l l I l Mi l l I, o 24 25 26 27 28 29 30 31 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 JULY 1978 AUGUST 1978 Figure 2-2. Histogram of Startup Test Program (July-August 1978)

l= W _I lrjv = 0 0 1 0 0 = = = 0 0 0 a 0 00 0 1 1 3 7 3 2 1 0 ~ l 9 m' l 8 E R l U R S E 7 SE W l R O P P 6 l R E 5 BM l T E 4 P ) l S 7 E 8 9 1 X 3 I r l F e b L 2 L m E e t W p l Y e R S 1 O t 8 s l R7 u O/ g 1 6 3 F1 u /A EG 9 ( I 0 A8 m 3 T7 a / r U0 g l O2 o 9 / r 2 E8 P C t N I s 8 A e 2 N T P l E p T u I R N t RO 7 I r 2 T R A a t E M S 3MR I MRE 6 o f L AI R 2 1 RH O m C T l a S OA r 5 T R M 2 g T o EE A S t W L UP R l U s E DO4 C L L L 2 U i 4 G H V =S FE AF AF AF I A OL ^L aA CO CO I I CO 3 SW cU I Oe I O c. ITD 2 2 TD TD I 3 SO sN R I e R I s I s r O L R Oc e e L/ A C Rs C R C R u I O M RE 6 R OP= 3 2 RE RE 9 2 g E 1 T OP 2 2 OP i T A N C C l F 1 TA TA TA NI1lIl1Il EA C UW A N A N 1 D D EO EO EO 2 E R TR I m' R E F 02 l I 9 lllIll 1 IIIlI I I 8 1 I I lI I l l l i1 lg l iiiliii 7 1 gg l l lll ltIl k u l 0 0 0 a a e 0 0 0 1 0 8 7 3 2 1 1 1 Ei:jr e .llllllll i lll llt

1100 110 REDUCED 8 PRESSURE 1000 TO CONDUCl k[--- 100 A 550 psig AND --- PRESSURE N RC ll rlI I m TIN o I I I i l = PO.ER I il l l MA,NOEN,RATOR; i I i 11 300 l

==caaoal=o le4 i i; I TO GRID ( 80 g f gg g gl TURBINE I A - SCRAM 5 l ll' ROTOR I g g gg l lI l ll 700 I 70 MANUAL SCRAM DUE TO g l BALANCING u s Is HIGH TURBINE Vf BRATION j f b 8 - SCRAM 6 60 GP 1 ISOLATION IN RUN g l ll ll 800 DUE TO INSTRUMENT l 3 g g it g [ MALFUNCTION a. l 8 2 O C - ERAM 7 f j ~ 50 LOW H O LEVEL DUE TO 2 ua ,NSTRUMENT TECH ERROR q D ) l [% a l REACTOR - 400 g D - SCRAM 8 40 LOW H O LEVEL DUE TO ^ l INSTRUMENT TECH ERROR D E - SCRAM 9 \\ PERIOD OF 30 APRM HIGH DUE TO - 194 sec 300 OPERATOR ERROR, R EACTOR CRITICAL REACTOR ON A PERIOD OF l CRITICAL l A OD 200 20 J OF 175 sec { [ l tJ REACTOR CRITICAL REACTOR CRITICAL REACTOR CRITICAL 10 ON A PERIOD OF ON A PERIOD OF 82 sec ] l l l l l l l l l l u o 9 10 11 12 13 14 1E 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 1 2 3 SEPTEMBER 1978 OCTOSER 1978 j TESTING Figure 2-4. Histogram of Startup Test Program (September-October 1978)

810 1100 NOTE: SINCE RATED PRESSURE HAS 3EEN /.CHIEVED THE PLOT OF PRESSURE VERSUS TIME WILL BE DISCONTINUED 1000 90 900 80 800 70 BYPASS VALVE 700 CALIBRATION ~g REACTOR CRITICAL ON g A PERIOD OF 235 sec REACTOR CRITICAL ON - w ^ SCR AM 11 - COMPLETE SHUTDOWN a. FROM OUTSIDE THE CONTROL ROOM REDUCING POWER ass REACTOR CRITICAL ON A UN ABLE TO SCR AM 13 f 50 PERIOD OF 116 see MAINTAIN TORUS DUE TO LOW 500 g k 6 SCR AM 10 TO DRYWELL AP LEVEL CAUSED BY g u O E DUE TO LOW LEVEL OPERATOR ERROR ( m _HILE BREAKING VACUUM t E g W ^ REDUCED POWER AND BROKE VACUUM TO 30 - FIX EHC OIL LEAK 300 e REDUCED POWER OUTAGE I TO CONDUCT HPCI FM REPM VALVE MAINTEN NCE d OF VACUUM 200 f BREAKERS 10 y SCRAM 12 100 MANUAL SCRAM 1 l l l l lh l l l l l l l t l l l l l l I l 0 0 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 26 26 OCTOBER 1978 4 TC1 TESTING ? O TC2 TESTING Figure 2-5. Histogram of Startup Test Program (October 1978)

=_ - OL-C l RE ACTOR POWER (%) o 5 8 8 8 8 8 8 8 8 8 5 a i l i I I i l l I I g g 8 ox ze= _ 2" 2 0 E 5zdn 2zP-o o _ lOynH Eyn N e DO o myyo Q F3 m C O 8 HmC" 3m" 5888 "8 $25 y x s l ? N m 8 SCRAM 16 SPURIOUS 1RM Hi HI b y DURING ROD WITHDR AWAL o l 9 e REACTOR CRITICAL PERIOD 208 sec 00 - SCRAM 17 LOW LEVEL TECH ERROR {$ 3k N g -E RE ACTOR CRITICAL PERIOD 157 see mE g2 I u l c h SCRAM 18 LOSP 35 S$ W B REACTOR CRITICAL PERIOD 95 see %g 50 3 h SCRAM 19 DUE TO LOW LEVEL 2$ 2o E E

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110 1100 SCRAM 23 DUE TO TCV FAST 100 F-CLOSURE DURING 1000 TURBINE SURVEILLANCE 90 900 i SCRAM 24 SCRAM 22 DUE TO LOW LEVEL SCRAM 21 DUE TO LOW EHC OIL CAUSED BY LOSS OF 80 - PLANNED TURBINE q PRESS AND RESULTING B FW CONTROLLER 800 REACTOR THIP PER ST1-27 TSV FAST CLOSURE POWER SUPPLY CRITICAL ON A 70 - PERIOD OF - 700 g q 151.oc 3 _6 I nu e REACTOR REACTOR E g g g CRITICAL CRITICAL 2 ON A ON A y e PERIOD PERIOD L OF 125 sec . OF 64.8 sec 500 b 50 E I U M E 6 m r e 9 b 40 400 $ua i 30 f 300 g RECIRC PUMP RECIRC PUMP REClRC N,4 5 i + TUNING AND .q. TUNING AND + PUMP -to-20 FLOW CONTROL FLOW CONTROL TUNING _

oo TESTING TESTING AND FLOW RECIRC PUMP CONTROL TUNING AND REACTOR TESTING 10 FLOW CONTROL CRITICAL TESTING ON A g

l PERIOD OF 1 260 e l]a l I I I I I I I I I I I l I I I l I I I l i I a o 18 19 20 21 22 23 24 25 26 27 28 29 30 1 2 3 4 5 6 7 8 9 10 11 12 I e TC3 ->- O TC3 %.TC4 h TC3 O TCS -*-- TC3 --h-TESTING TESTING TESTING TESTING TESTING TESTING -p- + TC7 TESTING NOVEMBER 1978 DECEMBER 1978 Figure 2-7. Histogram of Startup Test Program (November-December 1978) i

1100 110 FEEDWATER HEATER SCRAM 26 1000 100 - PROBLEMS MANUAL SCRAM SCRAM 25 i DUE TO TCV 900 90 - FAST CLOSURE DURING CONTROL ] VALVE TESTING 800 80 70 - - REDUCED 700 ~g POWER ON j RECIRC TO 3 g m PULL RODS g 600 w 60 - S a E z O = 500 g m u 50 y ? 5 O G e E 5 T = 0 40 - 5 400 o 5 m STEADY STATE MAINTENANCE OUTAGE m m a OPERATION FOR STEAM DRYER FIX 300 g R ECIRC 30 h PUMP Z TUNING Z AND FLOW g 20 F CONTROL I g TESTING 2 10 - o 100 1 e I 5 I "I I I I I I I I I I I i I I I I I I I I I o g 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 1 2 3 4 DECEMBER 1978 JANUARY 1979 + 4-TC6 TESTINO*- TCS TESTING Figure 2-8. Histogram of Startup Test Program (December 1978-January 1979)

l zm0 2~T _i_=88E gb$* n o 0 o o o o o o 0 o a 0 a o o 0 o o i o .a 3 2 l o s 7 s t i I 62 I 52 I 42 I 32 I 22 I )9 1 7 2 9 I 1 y o r 2 au I na 9 J( 1 I ma 8 r E X 1 g G I I o A F rP T R 7 U E 1 9 t O Y 7 s E R I 9 e T 1 C D 6 1 Y p N M I A r R u A t A N E 5 U a E t T 1 N S T S A f N I J o R I O 4 m A M F 1 a r I g 3 o t 1 is I H 2 1 9-I 2 1 e 1 ru I g i o' F t I 9 I 8 I 7 I 6 I 5 I o o o o 0 o o e o o o o i o s 8 7 6 s s 2 t l t 2_ey28b5* 90 i! Iil

110 1100 TRIPPED A RECIRC PUMP SCRAM 28 PER STI-30 DUE TO LOW SCRAM 30 100 WATER LEVEL DUE TO MSIV 3000 CAUSED BY BOTH FULL CLOSURE RFP TRifPING STI-25 DURING STI 23 go Q 900 80 POWER REDUCED 800 TO PERFORM MAX RFP CAPACITY TEST STI-23 7 SCRAM 29 g 60 DUE TO TURBINE 600 g g POWER LEVEL TRIP 05 O HELD CONSTANT g FOR FEEDWATER l MAINTENANCE k 50 HEATER WORK OUTAGEFOR 500 g N o PIPING HANGER F Y k b O FIX 2 = E E a 40 E STEADY STATE SCR AM 27 j OPERATION AT j DUE TO LOW LEVEL o <50% CTP UNTIL CAUSED BY RFP TRIP PRodLEM WITH 300 o RFP RESOLVED x HPCI k 20 RCIC E 200 AND SRV E REACTOR TESTING CRITICAL ON A REACTOR CRITICAL REACTOR CRITICAL 10 - PERIOD OF ON A PERIOD OF ON A PERIOD OF jon 115 sec 165.5 sec 98 sec l l l k l l l l l l l J J l l l l l l l l l l l 0 27 28 29 30 31 1 2 3 4 5 6 7 8 9 to 11 19 13 14 15 16 17 18 19 20 JANUARY 1979 FEBRU ARY 1979 TC6 TESTING Figure 2-10. Histogram of Startup Test Program (January-February 1979)

Zm 5 T~W ~ _{ Ea3{ 805e 0 0 0 0 o o 0 o o 0 o 0 0 1 0 o o 0 a o 0 o 0 0 1 1 s s 7 s 4 a 2 1 a 4 1 1 3 1 l 2 1 l 1 1 l o t l 9 )9 9 7 l 7 9 9 8 1 1 H h l C c r 7 R a A M l M -yr 6 au r l be 5 F( l ma X 4 r E I g G F o A l P r R T 3 E t U G s O l Te N E A 2 p C H N u A G l tr N NI 1 a t E P S TI I R l f P N o A O 28 m MF a r l g 7 o 2 tis I H 62 1 I 1 5 2 2 9 e 7 r I 9 u 1 g 4 i 2 Y F R I A 3 U 2 R B I E 2 F 2 I 1 2 I 02 l 9 1 3 o 0 o 0 o o o o 0 0 o 1 o 9 a 7 s s 4 a 2 1 1 i _t e=h' gob 5" uS I,

m6To. 5 E g gt<E 0 0 0 0 0 0 m 0 0 0 0 0 m = 1 0 0 0 0 3 2 i 1 1 9 s 7 I 8 I 5 I 4 I 3 I 2 I ) 1 97 I 9 1 1 li 3 rp I A-0 h 3 cra I M 9 ( 2 m I a 8 r 2 g X o E I I r G F P A 7 t T R 2 s E U e O G I T N 6 p E A 2 u C H t I r NA G a t 5 E PI 2 S N N fo T I I N P 4 m I R 2 a A O r MF 9 g 1 7 o 3 9 2 1 ts H H i 1 C 2 R 2 A 2 1 M l -2 1 2 e ru l g 0 iF 2 l 9 1 l 8 1 l 7 1 l 6 1 l 5 1 l 0 0 0 o 0 0 0 0 0 0 1 0 9 s 7 8 5 4 3 2 1 1 1 ,;yo u<E m== t ,t {' I i i E@ y $ gf gQ.* o o o o m m o o o o o o o o o l o o o e o s s l o i i s s 7 s I 92 I 82 I 72 I 62 I 52 l 42 ) l 97 3 9 2 1 i lirp 22 A( i m 1 ar 2 g E X i o r GI 0 P F 2 t A s T R e I UE 9 T O G 9 7 1 9 p N 1 u E A t C I L r H a N 8 I t 1 R S A G N N P f A E I i P o T l 7 IN P m 1 R a A r M O I g F E o t 1 is I H 5 1 I 3 1 4 2 1 er I u 1 ig 3 F i 2 1 I 1 1 I o t I 9 I 8 I 7 o 0 o o 9 o o o 0 o u e s 2 t 1 o s s 7 a 1 i 9amh g$5a 2~

zmS g~y j 5hf eOb5* 0 o o o o o o o 0 o o m o o e e e o 1 o o o o G s 4 3 2 l 1 t s s I 22 I 1 2 I o 2 I 9 1 I 8 1 I 7 )9 1 7 I 9 1 6 y 1 a I M l-5 ir 1 p I A ( 4 m 1 X I a E I 3 rg G F A o 1 T R r 9 P U E I 7 t O GN 2 9 s 1 e 1 E A I A p T C Y H N M u A G 1 t 1 N N r I a E PI S T I t N P o f I R I o A O M I m F a 9 rgo I ts i 8 H I 4 7 1 I 2 e 6 rug I F i 5 I 4 I 3 l 2 l 1 97 i 9 1 o3 L IR P o o o 0 o o o A G 0 0 o m S s 4 3 2 l 1 0 9 a 1 1

6

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11@ 1100 100 1000 SCRAM 31 DUE TO LOW WATER ~ LEVEL AFTER FEED ~ M PUMP TRIP 80 800 POWER REDUCED DUE TO LOW 70 VACUUM AFTER 700 9 SJAE FLOODING 3j g REACTOR SHUTDOWN E 60 ~ FOR HPCI 3 g AND RCIC O 0 REPAIRS f 0 m co 500 0 9 h E k 2 POWER RECUCED REACTOH DUE TO LOW w N CRITICAL E 40 CONDENSER VACUUM g PERIOD CAUSED BY BLOWN - 60.5 see FEED PUMP SEAL SCRAM 32 30 POWER REDUCED g CONTINUED DUE TO LOW TO UT FEEDWATER . WATER LEVEL HPCI LINE WELOS PROBLEMS FOLLOWING FEEO PUMP ~ 200 REACTOR M 3 CRITICAL REACTOR CRITICAL ON A 10 - ON A PERIOD OF 100 PERIOD OF 129 see 171 sec l 9 e l l l l l l I W l I I O O 23 24 25 26 27 28 29 30 31 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 MAY 1979 Figure 2-15. Histogram of Startup Test Program (May-June 1979)

1100 110 SCRAM 33 ON HIGH NEUTRON FLUX DURING ~ TURBINE CONTROL SCRAM 34 ON MAIN SCRAM 36 1000 VALVE SURV GENERATOR LOAD ON CROUP 1 REJECTION FOR STI 27 ISOLATION go _ FOR STI 25 g 80 - 300 q 700 N 70 i ti s ? x h = o x au 60 SCRAM 35 800 BmE OUTAGE TO E 2 EVALUATE REASONS 50 - g 3 FOR HPCI AND RCIC 500 $ TRIPS DURING GROUP 1 g Q [ g g g ISOLATION g h o e oo RHR STEAM g y 40 - I CONDENSING 400 a E E MODE TESTING [ FOR STI 71 O ( AND DRYWELL 30 - { TEMPERATURE HPCI AND RCIC ~ CRITICAL j R 6 / MONITORING OPERA 81LITY 73 TESTING xO k REACTOR 20 - 'RPT CRITICAL j4 >l 200 TEST PEA.OD REACTOR 81sec CRITICAL 10 - TC6 PERIOD TC6 100 TESTING 130 sec TESTING O !<I l I U l I I I I I I I I I I l I I I b I O O 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 1 2 3 4 5 6 7 8 9 JUNE 1979 JULY 1979 + e TC 6 TESTING Figure 2-16. Histogram of Startup Test Program (June-July 1979)

l i 1l' Il i! 5@M&oA ^T.3 W

m$G<w E 0

0 = = 0 0 0 m m 0 0 0 0 0 0 0 0~ 0 1 0 0 3 2 1 8 1 1 ? 1 3 YTN 0 A N 3 R U R R A 9 W 2 82 g m 7 E 2 SU C ALE I Y CLR CT 6 EEU RI G 2 L N BWT DI I P-I ET 9 B DYA N T A AS 5 9) ERR RE 2 7 CD2 U F C D HM P 1 PH O 4 y GE E l RHI T 2 u RF I J( R EOA 3 m W 2 a O r P g 2 o r 2 P D 9 EU 3 7 t P CCN I2 9 s 1 e U WO RI 2 T 1 TT Y D RIT S L p E P ROA 0 U u TL WR t O 2 J r R O F E E F a t S W UI S O D f 9 o P 4 1 ma r 8 g r 1 o ts i 7 H 1 d 7 6 1 1 -2 e r 5 u 1 g i l oso9 6 ) <U E $ E EW F 4 1 E fwEUGEE 28O$3 m yw I 3 1 2 1 ICY PT 1 HI G 1 L N DI I B N T A AS 0 1 RE CET I P C O 9 P 8 4-w 0 0 0 0 w m n 0 0 0 3 2 1 6 1 0 1 1 7E a !Wwz .l i l' l

110 1100 100 1000 90 900 80 300 70 700, -e -{ = 5 5 so e00 E R g s00 g R r 50 < x-e Y 9 E WARRANTY E RUN a 400 40 300 30 200 20 to 100 i I I I I I I I I I I I I I I I I I I I I I I I o o 31 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 AUGUST 1979 y 1979 Figure 2-18. Histogram of Startup Test Program (July-August 1979)

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NEDO-24734 { l 3.

SUMMARY

OF TEST RESULTS 3.1 STI1, CHEMICAL AND RADIOCHEMICAL 3.1.1 Level 1 Criteria

1. Chemical factors taken duing the test program were consistent with Technical Specifications.

2. Liquid and gaseous releases during the test period remained within license limits.

3. Throughout the Startup Test Program, water quality measurements were taken and remained within the General Electric Water Qualrty Specification.

3.1.2 Discussion . The STI 1 testing was conducted during open vessel, heatup, Test Conditions 1,3, 5, and 6 as defined on the Power Flow Map (Figure 2-19). Chemical tests of the primary coolant prior to open vessel and during heatup yielded the results shown in Table 3-1. During the initial checkout at open vessel testing, the conductivities of the condensate and feedwater were above the required limits. However, at that time there was no condenser vacuum and the conductivity was attributed to dissolved gases. Since the remaining parameters were within limit, the test was passed noting the above conditions. During the heatup phase, the condensate conductivity was above the limit due to caked deposit breaking loose in the pipes and stagnant water entering from systems being put into service. With use of the condensate filter-demineralizer the conductivity could be reduced. The heatup testing was acceptable noting that exception. Also given in Table 3-1 are results taken during Test Conditions 1, 3, 5, and 6. The 0.1 umho/cm limit on condensate conductivity is for normal operations. During the startup test program, the values recorded were slightly above the limit due to deposits being released as the system pipes expanded. Except for the condensate conductivity, all criteria were met regarding water quality. During Test Conditions 3 and 6, several special tests were performed. The no-cleanup test indicated no abnormal build-up with respect to impurities or activities in the reactor. The moisture carryover measurement results were 1.7 x 10-*% (Na-24). Carryover was reverified at Test Condition 6 to be 7 x 10-*%, which was well within the warranted limit of s;0.3% moisture as measured at the outboard main steam isolation valves. At lower power levels, condenser infeakage was high resulting in high noncondensable off-gas flow and lower residence times on the charcoal beds. At higher power, reduced condenser inleakage resulted in lower off-gas system flows and longer charcoal bed residence times. This allowed for longer decay times and lower activities at the stack for higher powers as seen in the post-treatment off-gas monitor calibration curve (Figure 3-1). Pretreatment activities were, as expected, higher at higher powers (Figure 3-2). Stack gas monitoring was a little misleading in that, due to the hold-up time phenomenon, the sum of two units divided by the proportion of the off-gas flow for Unit 2 did not necessarily give the activity attributable to Unit 2 operation. It should be noted however, that above 25% (after system calibration) all data points fell on or near the calibration curve seen in Figure 3-3. Overall, the chemical and radiochemical parameters were normal or acceptable, indicating proper demineralizer performance and good fuelintegrity. 3-1

NEDO 24734 Table 3-1 CHEMICAL AND RADIOCHEMICAL TEST RESULTS Open Limit Vessel Heatup TC1 TC3 TCS TC6 Test Reactor Water Conductivity, umho/cm 1.0 0.61 0.47 0.28 0.595 0.41 0.49 Chloride, ppm 0.2 <0.05 <0.05 <0.05 <0.05 <C.05 < 0.05 Turbidity or - Insolubles, ppm 10 0.07 0.24 0.07 0.17 0.04 0.22 lodine - 131 (gci/ml) 10 xx 1.99x10-8 3.3x10-' 2.86x10-* 3.56x10-* 1.27x10-* lodine - 133 (gci/ml) N/A xx <6.47x10-7 <3.4x10-* 5.01x10-$ 4.029x10-$ 3.41x10-$ Gross Activity SILICA, ppm 5.0 0.005 0.145 0.034 0.380 0.153 0.242 BORON, ppm 50 <0.025 <0.025 <0.025 <0.025 <0.025 <0.025 Condensate Conductivity, umho/cm < 0.1 0.139 0.35 0.067 0.21 0.41 0.11 Chloride, ppm N/A <0.05 <0.05 < 0.05 <0.05 <0.05 <0.05 Insoluble Iron, ppb N/A <10 3.75 3.12 14.5 10 46.2 Condensate Domin Effluent Conductivity, umho/cm 0.10 0.088 0.089 0.084 O.082 0.075 0.068 Iron, inscluble, ppb 20 xx xx 0.4 3.69 0.223 0.38 Oxygen, ppb 20-50 xx xx 150 20 50 25 Feedwater Conductivity, umho/cm 0.10 0.23 0.058 0.084 0.073 0.076 0.062 fron, insoluble, ppb 2.34 0.78 0.1 0.5 0.158 0.043 Iron, Soluble, ppb xx xx x.t 0.64 0.079 0.26

- Total metalhc impurmes (soluble and insolubie) hmd is 15 ppb of whch total Cu must not meJ 2 ppb.

xx Testing not requred. 3-2

l ) 5 U 5 1 4 l 1 3 1 RL OAR sTME 5 CRW 2 AEO EHP I 2 RT 1 1 I 1 I 0 1 evruC no i I 9 tarb ila S C A r G o I 8 F t i F n O oM m f s c a x I 7 g s ff pc O tne m t I 6 ae r ttso P I 5 1 -3 e rug i I 4 F I 3 R R O O T T I I N N O O I 2 m M M fc A B 4 s 8O 5 p 7 c / "I 1 ces /iC p 6 1 0 4 1 o 9 8 7 6 5 4 3 2 0 1 x 24 _4y agMj I 9 g l l l .l ll l l l

l ZA y 06 I 2 04 I 2 0 I 22 00 I 0 0 0 1 2 I 08 e 1 v ru C no 0 ita I 6 rb 1 S li A a G C F r F o i 0 O itn 4 m o 1 M fc x s r a h g / f r f 0 M O I 2 t 1 ne RL m OAR t %TME ae 5 CRW r 7 AEO I 0 e t 0 EHP r R T P 1 2 -3 O s% I 0 e r 8 u 0 g iF l 06 R R O O T T m I f IN N c O O M M i 0 x 4 rh A B / r M 8O E A J 0 S I 2 TA c es 5 / 2 i C 0 p 0 0 0 0 0 0 0 0 o 6 w 9 7 s 3 1 9 7 3 x 1 1 i 1 1 E 59 1

GE254$

2 9#

I'l

140 R ATED STACK FLOW

10400 120 8 A MONITOR Q B MONITOR bD l

REACTOR THERMAL 100 POWER x e 80 M A O k 25% 25% g 100% dy e0 z* o y g 75% g 6 40 U A 20 0 1 2 3 4 5 6 7 8 9 10 11 12 13 ces x ACTUAL FLOW / RATED FLOW ' RATED STACK FLOW FOR SINGLE UNIT OPERATING. IF SITE HAS ONLY ONE UNIT, ACTUAL FLOW EQUALS RATED FLOW.

8.57E-4 pCi/sec STACK cps x cfm Figure 3-3.

Stack Monitor Calibration Curve

NEDO-24734 3.2 STI 2, RADIATION MEASUREMENTS 3.2.1 Level 1 Criteria Radiation doses and personnel occupancy in radiation zones are consistent with the guidelines of the standards for protection against radiation outlined in 10CFP20, USNRC General Design Criteria. 3.2.2 Discussion Radiation surveys were conducted during open vessel (prior to fuel loading and after the initial reactor criticality), heatup, and Test Conditions 2,3, and 6 as defined on the Power Flow Map (Figure 2-19). One hundred and seventy-two locations were surveyed for gamma and neutron radiation levels. The radiation levels for both surveys conducted during open vessel testing were found to be negligible (8 50.1 mr/hr except in areas of sources where 8 50.2 mr/hr, n 50.1 mr/hr). During the full core verification conducted at the completion of the fuelloading, radiation measurements taken above the upper core plate indicated about 1 mr/hr beta-gamma dose and about zero mr/hr neutron dose. During the heatup phase, the radiation levels at all locations surveyed were less than, or equal to,1 mr/hr. No h,gh radiation areas (>100 mr/hr) were identified. Radiation surveys at Test Condition 2 showed that there were no high radiation areas and all levels were less than, or equal to,6 mr/hr. All points surveyed were less than 1 mr/hr except three points. The areas for which dose rates were taken are the torus catwalk underneath the main steam lines (3 mr/hr), vicinity of the steam chase / TIP machines (1.5 mr/hr), and vicinity of the reactor water sample hood (6.0 mr/hr). These areas are marked as a radiation area. The Test Condition 3 radiation survey identified eight high radiation (>100 mr/ht) areas. Five of the high radiation areas were located in the condenser bay, which is a controlled-access area, and the high radiation level was expected. Three other areas were also identified. The points were located near the main steamlines (150-400 mr/hr), near the low pressure heaters (100 mr/hr), and near the moisture separator reheaters (150-220 mr/hr). All radiation zones were properly marked and controlled per 10CFR20 General Design Cnteria. At Test Condition 6, seven high radiation areas were identified, five of which were located in the condenser bay which is behind locked docrs. Table 3-2 gives the location, radiation type, and the dose rate recorded. Noutron streaming was discovered at two points not located at normal survey points. Radiation levels of 7 mr/hr and 15 mr/hr were found at the X73 and X42 penetrations. These levels were sufficiently low that no corrective action was necessary; however, Health Physics will fill the penetrations with parafin as a precaution. 1 i 1 1 3-6

NEDO-24734 Table 3-2 HIGH RADIATION AREAS IDENTIFIED AT TEST CONDITION 6 Location Radiation Type Value

1. Rx Bidg 118-ft elev below main steam lines Gamma 100 Mrem /hr

2. Rx Bldg 130-ft elev TIP Room Gamma 700 Mrem /hr

3. Turbine /Condensor Bay Bldg 147-ft elev a) Point L33 Gamma 700 Mrem /hr b) Point 71 Gamma 240 Mrem /hr c) Point 72 Gamma 500 Mrem /hr

4. Turbine Bldg 130-ft elev e

a) Point 74 Gamma 1000 Mrem /hr b) Point 78 Gamma 1000 Mrem /hr 3.3 STI 3 FUEL LOADING 3.3.1 Level 1 Criteria Throughout fuel loading the partially loaded core remained suberitical by at least 0.38% AK/K with the analytically strongest rod fully withdrawn. 3.3.2 Discussion Prior to fuel loading, all FLC were " bugged" with an operational source to determine their proper high voltage and discriminator settings and that adequate margin existed above the scram setpoint before the detector saturated. Fuelloading began at 0030 on 6/22/78 after placing the neutron detection /RPS system in the noncoincidence scram mode. During fuel loading 1/M plots were maintained and shutdown margin checks performed on the 16,64, and 144 bundle core. The partially loaded core behaved as expected, and all shutdown margin criteria were met. Before the first SRM could replace a FLC,210 bundles were loaded. Occasional refueling bridge problems caused delays during 'oading. The core was completely loaded at 0030 on 6/10/78. The core was visually verified et 1955 on 6/30/78. The only incident during fuel loading invoived the channel of bundle LJ-7830 which was slightly gouged when it was lifted from a fuel pod location which had buckled slightly. An inspection of the damage revealed the bundle to still be within tolerances. 3.4 STI 4, FULL CORE-SHUTDOWN MARGIN 3.4.1 Level 1 Criteria The shutdown margin of the fully loaded core with the analytically strongest rod withdrawn was successfully denionstrated to be 2.45% AK/K, thereby satisfying the Level 1 criterion of 0.38% AK/K. 3-7

NEDO-24734 3.4.2 Level 2 Criteria Criticality occurred within 0.09% AK/K of the predicted rod configuration. Therefore, the Level 2 criterion of 1.0% AK/K was satisfied. 3.4.3 Discussion initial criticality of the fully loaded core was achieved by withdrawing B-sequence rods at 1310 on 7/4/78. Criticality occurred when the 38th control rod (30-31) in the B-sequence was withdrawn to notch 18. The reactor period was calculated to be approximately 69 seconds. IRM D faileo to respond properly during the initial criticality, and it was decided to take the reactor to a subcritical stage to troubleshoot the problem. Rod 30-31 was inserted to notch 14.The IRM problem was found to be a bent pin in a connector, which was quickly repaired. The reactor was again taken to critical stage with the same critical rod pattern as before at 1442. Moderator temperature was 98*F, and the reactor period was measured at 119 seconds. Shutdown Margin (SDM) was calculated to be 2.45% AK/K. 3.5 STI 5, CONTROL-ROD DRIVE SYSTEM 3.5.1 Level 1 Criteria Each Control-Rod Drive (CRD) was determined to have or adjusted (where necessary) to have a normal withdrawal speed less than or equal to 3.6 inches per second as required for a full 12-foot withdrawal stroke :n a minimum of 40 seconds. The control-rod scram insertion time to notch position 06 for each rod and each 2x2 array were well within the limits specified in STI 5. 3.5.2 The insertion and withdrawal speed of each CRD was determined or adjusted to be 3.0 0.6 inches per second as required for a full insertion or withdrawal stroke in 40 to 60 seconds. All CRDs but one met the required limit of 15 psid variation in differential pressure during continuous insertion. The CRD which failed the differential pressure test met the requirements of a differential setting pressure test. Scram tests were conducted with normal and minimum accumulator pressure Each rod and 2 x 2 array met the STI 5 requirements. 3.5.3 Discussion STI 5 was conducted at open vessel, during heatup, and in conjunction with other startup tests that resuited in a scram. Duriag zero reactor pressure testing, all control rods mot or were adjusted to meet the requirements on position indication, rod timing, stall flows, and coupling. During open vessel testing each rod met or was adjusted to meet the required speed criteria of stroke times. A!! control rod drives were sucessfully friction tested during beatup testing except rod 26-23. A setting test was conducted because 36-23 showed a psid difference of 23. The sma'lest differential pressure noted was 42 psid and the variation during the stroke was 7 psid which met the settling-pressure test requirements. Scram-time testing on each rod was conducted during open vessel testing and at rated pressure following initial heatup.,In each case the mean scram times for all rods and for the three fastest rods in each 2x2 array met the criteria I requirements. In addition, each individual control rod met its scram time limit requirements. Mean scram-time results are I l shown in Table 3-3. 3-8

NEDO 24734 Table 3-3 MEAN SCRAM TIMES (Seconds) All Rods Slowest 2x2 Array Notch 0 Psig Rated Psig 0 Psig Rated Psig 46 0.214 0.254 0.231 0.261 36 0.538 0.753 0.576 0.798 26 0.863 1.264 0.938 1.365 06 1.602 2.322 1.749 2.484 The rods with the slowest scram times during open vessel testing are shown in Table 3-4. These rods were retested with minimum accumulator pressure. Insertion times to position 06 are also shown in Teble 3-4. Table 3-4 SCRAM TIMES OF SLOWEST RODS (Seconds) Rod Normal Accumulator Minimum Accumulator Pressure Pressure Sequence A 14-43 1.796 1.805 26-15 1.734 1.778 10-31 1.724 1.745 22 27 1.725 1.749 Sequence B 22-23 1.810 1.893 14-47 1.786 1.762 26-43 1.724 1.771 30-07 1.719 1.712 The slowest B-Sequence rods were individually scrammed at 600 and 800 psig during heatup. The results are shown in Table 3-5. Tabis 3-5 SCRAM TIMES TO POSITION 06 (Seconds) Rod Lccation 600 Psig 800 Psig 22 23 2.473 2.563 14-47 2.614 2.576 26-43 2.756 2.612 30-07 2.693 2.408 The slowest rods tested at rated pressure were monitored during other tests which resulted in scrams. Table 3-6 shows how the slowest A-Sequence rods responded throughout the test program. 3-9

NEDO-24734 Table 3-6 SELECTED ROD SCRAM TIMES TO POSITION 06 (Seconds) Pressure Test Condition Rod Location 0 Psig Rated Psig 1 3 6 26-31 1.672 2.686 2.422 2.595 2.509 14-27 1.687 2.640 2.662 2.465 2.426 26-23 1.557 2.568 2.158 2.261 2.304 34-23 1.703 2.554 2.304 2.540 2.410 14-43 1.796 2.288 2.316 2.335 2.501 26-15 1.734 2.337 2.278 2.341 2.359 22-27 1.725 2.458 2.333 2.507 2.467 10-31 1.724 2.389 2.229 2.412 2.381 3.6 STI 6, SRM PERFORMANCE AND CONTROL-ROD SEQUENCE 3.6.1 Level 1 Criteria l 1. The Intermediate Range Monitors (IRM) were demonstrated to be on scale before the SRM exceeded the rod-block set point. 2. The SRM system adequately monitored the approach to criticality. 3. The SRM were demonstrated to have a signal-to-noise ratio greater than 2 and a count rate greater than 3 cps with the core fully loaded. 3.6.2 Discussion The STI 6 testing was performed during the open ver,sel anJ heatup phases and at Test Condition 1, as indicated on the Power Flow Map (Figure 2-19). The SRM were all in service after 240 of the 560 fuel assemblies had been loaded. The SRM did not saturate for count rates 57.5 x 105 cps enabling adequate SRM/lRM overlap data to be taken. Initial criticality was achieved in B-Sequence on rod No. 38 (30-31), notch 18, with a period of 119 seconds. The IRM were shown to be functional and the IRM/SRM overlap was confirmed. Once overlap had been demonstrated tne shorting links were installed placing the IRM and APRM in the coincidence scram mode and eliminating the SRM scram. The reactor heatup proceeded from atmospheric to rated by pulling control rods in B-Sequence. Neutron instrumentation was monitored to ensure a safe heatup rate, no anomalies were noted. 3.7 STI 8 ROD SEQUENCE EXCHANGE 3.7.1 Level 1 Criteria Alllicensed core limits were satisfied during an on-line rod sequence exchange. 3.7.2 Level 2 Criteria All nodal powers remained below their threshold limits during this test. 3-10

NEDO 24734 3.7.3 Discussion A representative control-rod sequence exchange from sequence B2 to A2 was conducted. The exchange was done between Test Conditions 2 and 5, defined by the Power Flow Map (Figure 2-19). The initial rod pattern was adjusted to minimize the likelihood of power dropping below the bypass setpoint of the rod worth minimizer and rising above the rod block monitor setpoint during the exchange. An OD 1 and P1 were performed before the exchange and approximate limiting powers were plotted on the TIP traces. TIP traces were then done on adjacent LPRM strings as each row of the exchange was completed. Another OD-1 and P1 was conducted following the exchange. Initial and final rod patterns are shown in Figure 3-4 a and b. initial and final P1 results are summarized in Table 3-7. Table 3-7 CORE PARAMETERS BEFORE AND AFTER ROD SEQUENCE EXCHANGE Parameter Before After Reactor Power (% of 2436) 42.6 41.0 Core Flow (% of 77) 35.9 35.9 MCPR 2.345 2.519 MLHGR (kw/ft) 5.855 6.719 MAPLHGR (kw/ft) 5.052 5.507 ) CMPF 2.449 2.923 3 11 i

NEDO 24734 51 i 47 44 44 t 43 22 00 00 22 39 38 24 38 35 16 06 00 00 06 16 31 24 24 27 00 00 06 06 00 00 23 24 24 19 16 06 00 00 06 16 15 38 24 38 f 11 22 00 00 22 07 44 44 03 02 06 to 14 18 22 26 30 34 38 42 46 50

a. 8EFORE EXCHANGE 51 24 47 43 32 12 00 12 32 39 38 38 35 12 00 00 00 12 31 38 42 42 38 27 24 00 00 00 00 00 24 23 38 42 42 38 19 12 00 00 00 12 15 38 38 11 32 12 00 12 32 07 03 24 02 06 10 14 18 22 26 30 34 38 42 46 50

b. AFTER EXCHANGE Figure 3-4.

Rod Pattem Before and After Exchange 3-12

a NEDO 24734 3.8 STI 9 WATER LEVEL MEASOREMENTS 3.8.1 Level 2 Critoria 1. The narrow range water level indicatoss all read within 1.5 inchet af their average reading. 2. All wide range indicators agree to wimin 6 inches of the average read.ng initially or after recalibration. 3.8.2 ' Discussion The STI 9 testing was conducted during heatup and at all Test Condrtions defined by the Power Flow Map (Figure 2-19). Calibrations of narrow and wide range water level instrumentation were verified to give accurate reactor water level indication at all times. The reference leg temperatures assumed during calibration did agree with the measured values; recahbration to the as-found values was not necessary. Graphs of average wide minus narrow water level versus power and versus flow are plotted in Figures 3-5 and 3-6. These figures verify the conservatism of the wide range instruments at high core flows. j 3-13

NEDO-24734 4 0 2 z g O 87 O O O u-50 0 z5j5 -2 35 ca i s -4 c" E 5 O $2 -e o r 5 -e I I I I I I I I I O 10 20 30 40 50 60 70 80 90 100 REACTOR POWER (%) Figure 3-5. Wide Range Water Level Variation with Reaction Power 4 o 2 ie O e-50 0 zg E5 -2 O 3:5 i os i s -4 = "i 8.e 82 O 4 at 5 g -s i I I I l l l l l _,o 0 10 20 30 40 50 60 70 80 90 100 CORE FLOW (%) Figure 3-6. Wide Range Water Level Variation with Core Flow l l l 3-14

NEDO-24734 ' 3.9 STI 10, IRM PERFORMANCE 3.9.1 Level 1 Criterle 1. Each IRM channel was adjusted so that it was on scale on the lowest range before any SRM exceeded the rod block set point. 2. Each IRM was adjusted so that it was not upscale on the highest range before all APRM cleared the APRM downscale trip setting. 3.9.2 Discussion The STI 10 testing was conducted at open vessel, heatup, and Test Condition 1 as defined on the Power Flow Map (Figure 2-19). There was a minimum overlap of over 5 decades between the IRM and SRM. During the first heatup, all of the IRM were adjusted to produce adequate continuity between ranges 6 and 7.The IRM exhibited a minimum overlap of slightly less than one decade with the APRM. IRM B was out of service for much of the heatup and TC1 testing. The IRM B detector was replaced during a later maintenance outage. Testing on IRM B was then conducted during the subsequent startup, when it exhibited adequate overlap with SRM and APRM, and proper range 6/7 correlation. 3.10 STI 11, LPRM CALIBRATION 3.10.1 Level 1 Criteria The LPRM gains were calibrated so that their meter readings were proportional to the neutron flux in the narrow-narrow water gap at the chamber elevation. 3.10.2 Discussion The STI 11 testing was conducted at Test Conditions 1,3, and 6 as defined by the Power Flow Map (Figure 2-19).The location, continuity, and correct hookup of the LPRM to its respective meter and computer readout was verified by observance of the appropriate signal response during initial control-rod movements in both sequences. The LPRM GAF were calculated by the process computer OD-1 and P1 programs. No problems were encountered in calibrating the TIP or LPRM to the correct heat flux during the startup program. l 3.11 STI12, APRM CALIBRATION l 3.11.1 Level 1 Criteria l 1. The APRM channels were calibrated to read equal to or greater than actual core thermal power at all test conditions. 2. In the startup mode all APRM channels produced a scram at less than or equal to 15% of rated power. 3. Technical specification and fuel warranty limits on APRM scram and rod blocks were not exceeded. 3.11.2 Level 2 Criteria The APRM channels were considered to be tracking core thermal power accurately when they agreed with the heat balance to within 6% of rated power. l l 3-15

NEDO-24734 3.11.3 Discussion The APRM system was calibrated after each change in the gain of the LPRM system and whenever changes in the rod pattem had a significant effect on the APRM readings. Actual core thermal power was calculated by a heat balance done by the process computer or manually. During the first heatup, a special heat balance, using the estimated heat capacity of the vessel and coolant, was employed. No problems were encountered in adjusting the APRM system to read reactor power or higher. The tracking ability of the APRM system was venfied by monitoring all APRM readings taken during a power decrease to conduct turbine control valve surveillance. The power decrease was from 99% to 66%; actual power was measured via OD-3 option 2 on the process computer. All APRM were shown to tract within the 7% criterion. Data from this test is presented in Table 3-8. Table 3-8 APRM TRACKING ABILITY Actual Core Power / Flow (%) 99.31/99.29 66.08/54.21 APRM A 100.25 66.53 APRM B 99.31 66.59 APRM C 99.47 67.25 APRM D 101.06 69.44 APRM E 99.03 67.00 APRM F 100.03 67.44 3.12 STI 13, PROCESS COMPUTER 3.12.1 Level 2 Criteria 1. Successfulcompletionof P1,OD-1 OD-3,OD-7,andOD-8with BUCLEbackupwasdemonstratedandthese programs are considered operational. The parameters MFLPD, PF, CPR.,MAPLHGR, PBUN, W, and RCAL all agree within 0.48% of those calculated by BUCLE (within 2% is required). 2. The LPRM calibration factors calculated by BUCLE and the process computer agreed to within 1.0% (w; thin 2% is required). I 3. The static and dynamic testing of the other process computer programs have been successfully completed. 3.12.2 Discussion Process computer testing was conducted during open vessel, heatup, and Test Conditions 1,3, and 6 as defined in the Power Flow Map (Figure 2-19). The Dynamic System Test Case v as completed during Test Condition 1 oxcept for a number of subsidiary program checks which were done when convenient. Comparisons of P1 and BUCLE for steady state thermal parameters and exposure were found to agree within 2% and in most cases to within 0.5%. Bundle powers calculated by P1 and BUCLE agreed to within 0.3%. The thermal limit estimate programs, OD-4 and 00-5, agreed with P1 calculations within 2.53% when large changes in power were made via recirculation flow and within 26.3% when large changes in power are made via control rods. All other NSS programs were checked out and proven operational. The Process Computer is capable of accurately determining plant power thermallimits and accumulating core exposure. i 3 16

NEDO 24734 3.13 STI 14, REACTOR CORE ISOLATION COOLING SYSTEM 3.13.1 Level 1 Criteria 1. The time from the actuating signal to required flow was $22.5 seconds at any reactor pressure between 150 psig and rated (530 seconds is required). 2. The pump discharge flow at any pressure between 150 psig and rated was >400 gpm. 3. The RCIC turbine controls were adjusted so that RCIC did not trip off during startup. Thus, all Level 1 criteria were satisfied. 3.13.2 Level 2 Critorie 1. Inspection of the RCIC turbine during operation found it to be free of steam leaks. 2. Tha High Steam Flow isolation Switch trip setpoints were adjusted to actuate at 300% of the maximum required steady state flow. Thus, all Level 2 criteria were met. i 3.13.3 Discussion The STI 14 testing was conducted at heatup and Test Condition 3 as defined in the Power Flow Map (Figure 2-19).The RCIC system demonstrated at all test conditions the ability to reach rated flow in less than 30 seconds. During the RCIC condensate storage tank injection testing, no problems were encountered in meeting the required time to rated flow. Problems were encountered related to the proper setup of the control system for fast, stable response with minimal flow saturation. RCIC testing results are shown in Table 3-9. During the vesselinjection, turtene speed slightly exceeded the 10% margin to trip (4530 rpm versus 4500 rpm limit). This was within the accuracy of the instrument and was considered acceptable. Table 3-9 RESULTS OF RCIC TESTING Measured Required Reactor Pump Turbine Flow Time Flow Time Pressure Discharge Speed Peak . Test Condition (gpm) (sec) (gpm) (soc) (psig) Pressure (rpm) Heatup 400 10.0 400 30 165 350 2840 Heatup 400 15.0 400 30 550 650 4450 Heatup 400 21.0 400 30 997 1210 3675 Vessel injection 430 22.5 400 30 940 1025 4530 Various problems were encountered while tuning RCIC including a failed ramp generator, improperly calibrated overspeed trip, overly conservative high steam flow trip setting, and unsatisfactory settings for the electrical null voltage. Final RCIC EGM/EGR and ramp generator settings are found in Table 3-10. 3-17 ~

NEDO 24734 Table 3-10 FINAL RCIC CONTROL SETTINGS Proportional band (PB)-- 200% Repeats per minute (R/ min). .25 Ramp time. 19 seconds Ramp idle voltage._ -0.5 volts EGR needle valve._ _.1 1/2 tums CCW EGM gain = - 0.8 EGM stability - 0.4 During the Group I isolation transient conducted for STI 25, RCIC isolated on high steam flow. An extensive system reliability test was conducted as a result. It was found that during automatic system initiations from a cold condition (greater than 72 hours since last system operation). the initial steam flow transient during startup momentarily exceeded 300% of the steady state flow. A three-second time delay was installed in the trip circuitry to prevent the isolation from occurring. Five system automatic initiations were then conducted, four with discharge to the condensate storage tank and one injection to the reactor vessel. The results of this reliability test were satisfactory. 3.14 STI 15. HIGH PRESSURE COOLANT INJECTION SYSTEM (HPCI) 3.14.1 Level 1 Critoria 1. The time from initiation to the required High Pressure Coolant Injection (H PCI) flow was less than 25 s6conds for any reactor pressure between 150 and 1000 psig. 2. Dunng testing the pump discharge flow at any discharge pressure between 150 psig and 1220 psig was greater than 4250 gpm. 3. After system adjustments and modifications, the HPCI turbine did not trip off during startup. Thus, all Level 1 criteria were met. 3.14.2 Level 2 Criteria 1. Inspection of the HPCI turbine gland seal condenser system during operation found it to be capable of preventing HPCI steam leaks. 2. The iP switches for the HPCI steam supply line high flow isolation trip were adjusted to activate at 300% of the maximum required steady state steam flow. Thus, all Level 2 criteria were met. 3.14.3 r)lecuasion The STI 15 testing was conducted at heatup and Test Condition 3 as defined on the Power Flow Map (Figure 219). During the heatup testing phase, the HPCI system took suction from and discharged to the condensate storage tank. 1 A vessel injectien and flow changes with discharge to the vessel were conducted at TC3. Due to modifications made to the hydraulic sys*w '~ ting conducted at 150 psig and rated pressure had to be repeated. Data for the two quickstarts with discharge to t.,. c 4 n. sate storage tank arid the vessel injection are summarized in Table 3-11. Final system settings a re included in TE s.' <.:. 3-18

NEDO-24734 Tobis 3-11 FINAL RESULTS OF HPCI TESTING Maximum Measured Required Reactor Pump Discharge Turbine Flow Time Flow Time Pressure Pressure Speed Test Condition (gpm) (sec) (gpm) (sec) (pelg) (pelg) (rpm) Heatup 4250 17.4 4250 <25 157 260 2000 Heatup 4250 19.75 4250 <25 925 970 3900 Vessel injection 4250 23.19 4250 <25 952 1000 3980 Table 3-12 FINAL HPCI CONTROL SETTINGS Proportional band (PB).-

350 %

Resets per minute. 25 Ramp generator time.. --10 seconds Ramp idle - 0.5 volts Null voltage - . 0.75 volts EGM needle valve.- -5/16 tum CCW During the Group 1 isolation transient conducted for STI 25, HPCI isolated on high steam flow. An extensive system reliability test was conducted as a result. It was found that during cold system, automatic Initiations (quickstarts) the HPCI turbine stop valve main valve disk was found to pop open to a position further than that called for during its opening ramp, and then reclosing to the position it should be on the ramp. When the valve popped open, steam flow to the turbine sometimes Cxceeded the 300% steady state flow. The internals of the stop valve were inspected and the baiancing chamber pressure readjusted to 300 psi, three times the pressure recommended by the supplier, in addition, a three-second time delay was inserted in the high-steam flow trip circuitry to prevent unnecessary isolation during automatic initiations. The reliability tests included four cold quickstarts with discharge to the condenate storage tank and one with discharge to the reactor vessel. The results of the tests were satisfactory. 3.15 STI 16, SELECTED PROCESS TEMPERATURES 3.15.1 Level 1 Criterla 1. The reactor recirculation pumps were not operated unless the coolant temperatures between the upper and lower regions of the reactor were within 145'F. 2. An idle recirculation pump was not restarted if there was an excessive differential temperature between the idle and active loop pump suctions or between an idle loop suction and steam dome temperature if both pumps were idle. 3.15.2 Level 2 Criteria The bottom head coolant temperature as measured by the bottom drain line thermocouple was within 50*F of reactor coolant saturation temperature. 3.15.3 Discussion The STl 16 testing was conducted during heatup and Test Conditions 1,4, and 6 as defined on the Power Flow Map (Figure 219). The results of selected process temperature data taking for all test conditions are presented in Table 313. During heatup and at Test Condition 1, data were taken while varying the percent pump speed between 20 and 30 for both A and B recirculation pumps. The bottom drain thermocouple appears to adequately monitor the bottr.,m drain line temperature. 3-19

NEDO-24734 The indicated absence of temperature stratification aRowed the recirculation pump tow-speed stops to be set to 20% speed. The plant operated at TC $ for over 20 continuous hours without reaching the limits preventing recirculation pump restarts. Table 313 SUMBAARY OF TERAPERATURE BEHAVIOR (*F) TC4 Racirculation Position Hestup TC1 Pumps Tripped TCS 'c ~ Recirculation Pump A Inlet Temperature 533 N 518 509 530 Recirculation Pump B Inlet Temperature 533 W 515 497 520 Saturation Temperature 547 7%i 540 541 545 Reactor Bottom Head Drain Temperature 535 777 O 518 500 524 AT (Recirculation Purm - Bottom Drain) 2 3 9 6 AT (Saturation - Bottom Drain) 12 22 41 21 3.16 STI 17, SYSTEM EXPANSION 3.16.1 Level 1 Criteria 1. During system thermal expansion all system components remained free and no displacement blockage occurred. 2. All hangers in the drywell were checked and presented no problems. 3. All accessible shock suppressor pistons were found to be centered about the midpoint of their total travel range. 4. No electrical cables were found to be stressed or fully stretched. 3.16.2 Level 2 Criteria Most displacements of instrumented points with special recording davices did not vary from their ctJculated values by more than 50% or 20.25 inch (whichever is smaller). Severalinstrumented points fell slightly short of meeting the Level 2 cnteria. San Jose examination of these points verified that the resulting stresses were acceptable. 3.16.3 Discussion Before the first heatup, the drywell was inspected and all noted expansion problems were corrected. During heatup, visual inspections revealed other obstructions to movement, in particular, a deck grating near a recirculation pump and a whip restraint at the elbow at the suction of a recirculaton pump. These obstructions were modified to correct the problem, and inspection of these locations were conducted throughout the startup program with no further problems observed. The recirculation and main steam systems were also monitored at several points during tho heatup with displacernent sensors. Although scme of these points showed movement not meeting the Level 2 criterion, further stress analysis of the system showed no problems due to these slight deviations. 3-20

NEDO.24734 3.17 STI 18, CORE POWER DIST RIBUTION 3.17.1 Level 1 Criterie The total TIP uncertainty for all data sets was less than 7.8%. 3.17.2 Discussion .The STI 18 testing was conducted at Test Conditions 1,3, and 6 as defined on the Power Flow Map (Figure 2-19). Initial TIP system setup was conducted at Test Condition 1. A full TIP set was run at each test condition to ensure that accurate distributions were ublized by the process computor. The process computer bundle power array data were used to analyze the core power symmetry; no anomalies were noted. Complete sets of TIP scans and appropriate process computer output were obtained at Test Conditions 3 and 6 as defined on the Power Flow Map (Figure 2-19). An offline computer program analyzed the random, geometrical, and total noise of the TIP system. The random noise data were obtained by the analysis of multiple traces of the common beation taken by each TIP machine. The total noise data were obtained by the analysis of diagonally symmetric TIP locations from a complete 00-1. All data were taken while the reactor was operating in an octant symmetric rod pattem. Table 314 summarizes the results of the above investigations. Table 314 TIP REPROCUCIBILITY DATA Uncertainty (%) Test Condition Random Geometric Total 3 0.933 1.990 2.198 3 0.934 2.092 2.291 6 1,770 2.287 2.892 6 1.771 2.166 2.798 Average 1.352 2.134 2.546 4 3-21

NEDO-24734 3.14 STI 19, CORE PERFORMANCE 3.18.1 Level 1 Criteria 1. The Maximum Linear Heat Generation Rate (MLHGR) of all rods during steady-state conditions did not exceed the limit specified by the Plant Technical Specifications (13.4 kW/ft). 2. The steady-state Minimum Critical Power Ratio (MCPR) did not exceed the limits specified by the Plant Technical Specifications (1.30). 3. The Maximum Average Linear Heat Generation Rate (MAPLHGR) did not exceed the limits specified by Plant Technical Specifications. 4. Steady-state reactor power was limited to 2436 MWt and values on or below the design flow control line. 3.18.2 Discussion The STI 19 testing was performed at Test Conditions 1 through 6 as defined on the Power Flow Map (Figure 2-19). Process computer calculations were used throughout the STI 19 testing. The core parameters are summarized in Table 3-15. Table 315

SUMMARY

OF CORE PERFORMANCE PARAMETERS Test Power Flow MLHGR MAPLHGR Condition (% of 2438) (% of 77) MCPR (kW/ft) (kW/ft) CMPF 1 13.1 40.3 6.1159 3.366 2.82 4.574 2 24.3 40.6 3.7840 4.090 3.34 3.003 3 46.2 94.9 2.8085 6.681 5.77 2.577 4 40.4 31.2 2.3410 5.246 4.55 2.314 5 60.9 53.8 1.9235 7.976 6.86 2.336 6 96.3 96.1 1.4081 12.636 10.86 2.338 3 22 1

NEDO 24734 3.19 STI 20,5, TEAM PRODUCTION 3.19.1 Level 1 Criteria 1. The NSSS parameters determined by normal operating procedures were within the appropriate license estrictions. 2. The nuclear steam supply system was capable of supplying steam of better than 99.7% quality at a pressure of 985 psia at the second isolation valve in an amount consistent with the f;nal feedwater temperature and control-rod drive flow as given by the formula: = + W,,,(Mib/hr). W.,. H9 5 N 3.19.2 Diecussion The steam production test commenced at 1600 (EDT) on 7/28/79 and was completed at 2400 (EDT) on 8/2/79. Data were taken in two 2-hour periods during the test. Plant parameters for each period are summarized in Table 3-18. Steam carry-over at rated conditions had been determined eartier. From this, it was determined that steam quality at the second MSIV at rated conditions is 99.72% (99.70% required). Table 310 STEAM PRODUCTION TEST DATA Value Received Warranted First Second Parameter in Teet Value Run Run Average 2426.45/ 2423.59/ 2425.02/ Thermal Power 2436/100 % (CMWT/%) +0,-2% 99.61 99.49 99.55 1004.70 1004.06 1004.38 Dome Pressure 1005 2 (psig) 419.17 419.13 419.15 Feedwater Temperature ('F) 985 2 2.80 983.33 983.57 983.45 Extrapolated Pressure at Second MSIV (psig) 10.458 2 0.010 10.4488 10.4503 10.450 Extrapolated Rated Steam Flow (MLB/hr) 1 3-23

NEDO-24734 3.20 STI 21, CORE POWER - VOID MODE RESPONSE 3.20.1 Level 1 Critoria The decay rauo was less than 1.0 for each variable that exhibited an oscillatory response to reactivity changes. 3.20.2 Level 2 Criteria 'The decay ratio was less than 0.50 for each variable that exhibited an oscillatory response to reactivity change. 3.20.3 Discussion The STI 21 testing was conducted at Test Condrtion 4 as definec on the Power Flow Map (Figure 2-19). The stability of the core power reactivity feedback mechanism was tested by checking the local and macroscopic effects of control rod movement and pressure regulator failures. The demonstrated decay ratios were less than 0.25, except in one instance, where the decay ratio was 0.26. 3.21 STI 22, PRESSURE REGULATOR 3.21.1 Level 1 Criteria The decay ratio was < 1.0 for each process variable that exhibited oscillatory response to pressure regulator changes. 3.21.2 Level 2 Criteria 1. The decay ratio was less than 0.25 for each process variable that exhibited oscillatory response to pressure regulator changes when the pf ant was operating above the lower limit setting of the Master Flow Controller and less than 0.50 when operating below this range. 2. The Pressure Control System deadband, delay, etc., were small enough to prevent steady state limit cycles from producing a turbine steam flow variation larger than 20.5% of rated steam flow. 3. During the simulated failure of the primary controlling pressure regulator,'the set point of the backup pressure regulator was set at its optimum value, narrow enough to eliminate any possibility of regulator-induced scramt durir'g the transient, but wide enough to keep the backup regulator out of action during normal transients. 4 Following a sma!I-pressure set point change, the time between the set point change and the occurrence of the pressure peak was always <10.0 seconds. 3.21.3 Discussion The STI 22 testing was conducted at Test Conditions 1,2,3,4,5, and 6 as defined on the Power Flow Map (Figure 2 19). After extensive testing and retesting at all conditions, final optimum values for the controller settings were achieved so that Level 1 and 2 cnteria were met at every test condition. Table 317 summarizes the final pressure regulator control settings. Table 3-18 summarizes the pressure regulator testing at Test Condition 6. Pressure regulator bias potentiometer settings are as follows: 5.06 for A regulator in control,5.56 for 8 in control. The 0.50 difference corresponds to a 3 psi bias between the regulators. The relation between steam flow and pressure regulator output is shown in Figure 3 7. Steam flow demand versus pressure regulator output is shown in Figure 3-8. Steam flow demand versus control valve position is shown in Figure 3-9. 3 24

NEDO 24734 Table 317 FINAL PRESSURE REGULATOR CONTROL SETTINGS Prosauro Reguietor Setting Pressure Regulation (0 - 10% Flow / psi) 3.36 A Regulator Lag (r = 12.2 sec) 4.20 i Lead (r = 2.8 sec) 6.24 B Regulator Lag (r = 10.65 sec) 4.20 Lead (r = 2.45 sec) 5.47 Speed Regulation 7.455 Intercept Valve Bias 10.00 Bypass Valve Bias 2.04 Recirculation Flow Signal Umiter 2.31 Steamline Resonance Compensator Corde Card A42 Cerd A46 Notch Center (T.) 3.885 3.87 Notch Depth ((,/(,) 2.0 2.0 Notch Width ((,) 1.785 1.775 Small Lag (TR,) 2.80 2.81 3 25

NEDO-24734 Table 318 RESULTS OF PRESSURE REGULATOR TESTING AT TEST CONDITION 6 Recirculation System Statue Master Manual Master Auto Time to Peak Decay Ratio Time to Peak Decay Ratio A Regulator Load Umit High (+) Steo 2.0 0 2.7 0 (-) Step 2.8 0 2.4 0 Load Umit incipient (+) Step 3.4 0 (-) Step 3.6 0 Load Umit Low (+) Step 3.2 0 (-) Step 3.2 0 B Regulator Load Umit High (+) Step 3.0 0 3.6 0 (-) Step 3.2 0 2.8 O Load Umit incipient (+) Step 2.4 0 (-) Step 3.2 0 Load Limit Low (+) Step 2.4 0 (-) Step 2.0 0 Failure B to A Load Umit High 2.0 0 1.5 0 Load Umit incipient 1.4 0 Load Limit Low 1.0 0 Failure A to B Load Umit High 1.0 0 1.6 0 Load Umit incipient 0.8 0 Load Umit Low 0.8 0 3 26

3 NEDO-24734 100 80 I so 8 d lE 6g 40 20 0 5 4 3 2 1 0 PRESSURE REGULATOR OUTPUT (Vdc) Figure 3-7. Steam Flow Versus Pressure Regulator Output 5 4 k 2: o i lE 3 o 8

)

2 w i I I I 0 5 4 3 2 1 0 PRESSURE REGULATOR OUTPUT (Vde) Figure 3-8. Steam Flow Demand Versus Pressure Regulator Output 3-27 Y

NEDO-24734 4 O 3 ~ CV 3 'd ) aa k ( 2 0 2 CV's 1 AND 2 8 d 3 e. 1 0 O 20 40 60 80 100 CONTROL VALVE POSITION (%) l Figure 3-9. Steam Flow Demand Versus Contxil Valve Position 3-28

NEDO-24734 3.22 STI 23, FEEDWATER SYSTEM 3.22.1 Level 1 Critoria 1. The decay ratio was less than 1.0 for each process variable that exhibited oscillatory response to feedwater system changes. 2. For the feedwater temperature loss test, the maximum feedwater temperature decrease due to a sing le failure case was 45.83*F (100*F maximum allowed). 3. The resultant MC PR was greater than the fuel thermal safety limit. For the feedwater temperature-loss test, the increase in the simulated heat flux did not exceed the predicted Level 2 value. 4. Calculated feedwater flow-runout capability was 140% of rated compared to 127% assumed in the FSAR. The value for MCPR resulting from this would be 1.12 which is still higher thaq the limit of 1.06, so no MCPR penalty was required. 3.22.2 1.evel 2 Criteria 1. The decay ratio was less tnan 0.25 for each process variable that exhibited oscillatory response to water level set point changes when the plant was operating above the lower limit of the Master Flow Controller and less than 0.50 when the plant was operating below the minimum core flow. 2. During the feedwater pump trip the automatic recirculation flow runback responded adequately to avoid a low-water level scram. 3. For the feedwater temperature-loss test, the increase in simulated heat flux was less than the predicted value referenced to the actual feedwater temperature change and power level. 4. The response of a feedwater actuator to a large step disturbance was shown to be nearty 25 percent of rated feedwater flow per second. 5. The dynamic response of each feedwater actuator to small step disturbances was satisfactorily rapid. 3.22.3 Discussion The STI 23 testing was conducted at Test Conditions 1, 2. 3, 4, 5, and 6 as defined on the Power Flow Map (Figure 2-19). Set point changes in single-element control and three-element control were made at each test condition with the decay ratio criteria being met in each case. in addition, testing was done to optimize the startup level control system which includes controllers for the stirG o level control-valve positior. and for the feedwater turbines to maintain the desired differential pressure across the A-rtsp level control valve. Controller settings are included in Table 3-19. Table 3-19 FEEDWATER CONTROLLER SETTINGS Master Controller Proportional Band (PB).. .. 50% Repeats per minute (R/ min).. .1.8 Mismatch gain - . 48 in. Startup Level Controller Proportional Band (PB).. 50% Repeats per minute (R/ min) . 0.2 Differential Pressure Controller Proportional Band (PB).- .150 % Repeats per minute (R/ min).. . 3.0 3 29

NEDO 24734 i The loss of the high-pressure feedwater heater at 81% power,100% flow, resulted in a 4.9% power increase with the feedwater temperature dropping 45.8'F to its steady-state value. Thermallimit margins were mantained throughout the transient: CPR changed from 1.676 to 1.608 and MLHGR changed from 10.57 to 11.24. Predicted values for a 77'F drop in feedwater temperature were a 6.5% rise in power and a final MCPR of 1.54. Maximum feedwater runout capability was found to be limited at the same value by saturated controller output and low pump-suction pressure. In either case, the maximum flow was about 140% of rated which did not result in a MCPR transient worse than had already been analyzed. During the feedwater pump trip test, approximately 26 seconds after the B feedwater pump trip (at 96.5% power, 99.1% flow) the water level dropped from 38 inches to 20 inches and eventually leveled off at 36 inches. The power level ~ dropped from 96.5% to 40% and leveled off at 69%. The recirculation ruriback began 24 seconds after the trip and reached steady state 10 seconds later. Feedwater actuator response to large (>20%) step disturbances was analyzed from a transient which occurred when a tripped feedpump was reset too quickly following the trip and came back on line. The actuator response between 10% and 90% of the difference of the initial and final flows showed the rate of response to be 23.5 percent of rated flow per second. Dynamic flow response of each feedwater actuator to small (<10%) step disturbances was measured at Test Conditions 3 and 6 One pump was placed in manual and the other in auto. Step changes in flow were made on the pump in manual and its flow response was then measured. Worst-case results for each pump at each test condition are shown in Table 3-20. Table 3-20 FEEDWATER ACTUATOR FLOW RESPONSE TO SMALL STEP CHANGES (seconds) Test Condition 3 3 6 6 Feed Pump Tested A B A B Maximum Tima to 10%* 1.00 0.81 0.83 0.60 Maximum Timo from 10%* 1.90 1.56 1.48 1.42 to 90%* Settling T'me to Within 3.05 2.56 5.47 8.50 i tS% of the Final Value i Peak Overshoot (%) 0 0 9 8

Percent of Step Daturbance i

On July 18,1979,it was discovered that the feedwater flow transmitters had been miscalibrated during the entire startup test program through that data. This resulted in power b&g improperly calculated and a lower indication than actual reactor power by a factor of 0.947. A study was made of all startup testing done through July 18,1979, and some Test Condition 6 testing was repeated; although the majority of all testing was found to have been conducted under conditions whlch met the intent of the STI. l l l 3-30 1

. NEDO-24734 3.23 STI 24, TUR81NE VALVE SURVEILLANCE 3.23.1 Level 1 Criteria The decay ratio was less than 1.0 for each process variable exhibiting an oscillatory response to turbine valve, operation. 3.23.2 Level 2 Critoria 1. The decay ratio was less than 0.25 for each process variable exhibiting an oscillatory response to turbine valve operation when the plant was operating above the lower limit of the Master Flow Controller. 2. There was more than adequate margin between peak neutron flux, vessel pressure, and steamline flow to the scram and isolation trip settings. 3.23.3 Discussion STI 24 testing was conducted at Test Condit.ons 3,5, and 6 as defined on the Power Flow Map (Figure 2-19). It was found that stop valve, combined intermediate valve, and bypass valve testing could be done safely at rated conditions. Control valve testing was last done at Test Condition 5 because several scrams occurred during control valve surveillance, and the Georgia Power Company agreed to conduct future surveillance testing at the same power (No. 3 Control Valve about 5% open). Georgia Power intends to investigate the problem after the startup program is over and then determine a new power level at which control valve surveillance can be safely conducted. The test conditions at which valve surveillance was done during startup is summarized in Table 3-21. Surveillance results and limits are included in Table 3-22. Table 3-21 PLANT CONDITIONS DURING TURBINE VALVE SURVEILLANCE TESTING SV, BPV, & CIV CV Reactor Power (%) 96.5 69.8 Core Flow (%) 99.1 63.2 Reactor Dome Pressure (psig) 982 954 Flux Scram Set Point (%) 114.75 93 Pressure Scram Set Point (psig) 1045 1045 Steamline Flow isolation Set Point (MLB/hr) 3.66 3.66 Table 3-22 TURBINE VALVE SURVEILLANCE RESULTS SV CV CIV BPV Peak Neutron Flux (%) 103.0 76.0 101.2 102.5 Peak Steam Pressure (psig) 987.7 976.0 982.5 983.5 Peak Steamline Flow (MLB/hr) 2.80 1.82 2.58 2.56 3-31

NEDO 24734 3.24 STI 25, MAIN STEAM LINE ISOLATION VALVES 3.24.1 Level 1 Criteria 1. The MSIV closure times satisfied the 3-to-5-second requirement. 2. The initial transient rise in vessel dome pressure occurring after the main steam isolation valve trip initiation was 112 psi (to a peak of 1088 psig), well below the 1145 psig limit. Heat flux dropped immediately during the transient. 3. Maximum vessel dome pressure during the main steam isolation trip transient was 1088 psig mmpared to the 1120 psig limit. Heat flux dropped immediately following the trip with no merease due to the pressure transient. 3.24.2 Level 2 Criteria 1. During full closure of individual MSIV, peak pressure, neutron flux, and steam line flow displayed adequate margin to their scram and isolation trip set points. 2. RCIC isolated on high steam flow during the main steam isolation valve trip. Water level was adequately maintained by starting up RCIC manually following its isolation. 3. Maximum vessel dome pressure during the main steam isolation trip transient was 1088 psig compared to the 1120 psig limit. Heat flux dropped immediately following the trip with no increase because of the pressure transient. 3.24.3 Discussion STI 25 testing was conducted at heatup and Test Conditions 2,3,5, and 6 as defined on the Power Flow Map (Figure 2-19). Individual MSIV closures were successfully completed during heatup and Test Conditions 2,3, and 5. The 0-to-100% closure times were obtained by linear extrapolation of the 10%-to-90% closure time, after determining the actual valve positions corresponding to 10% and 90% indication light pickup. Extrapolations of pressure rise, neutron flux peak, and steamline flow were performed to predict response at the next test condition. Final testing was done at 80% power and 970-psig reactor dome pressure. Results and limits are provided in Table 3-23. Closure time results are in Table 3-24. Table 3-23 INDIVIDUAL MSIV CLOSURE RESULTS Worst Indicated Peak Scram / Isolation During Testing Setpoint Neutron flux (%) 94.1 103.5 Dome pressure (psig) 1000 1045 Steamline flow (MLB/hr) 2.74 3.66 3 32

NEDO-24734 Table 3-24 MSIV CLOSURE TIMES Excluding Electrical Delay including Electrical Delay Valve (Seconds) (Seconds) 2821-F022A 3.876 4.227 2B21-F022B 4.182 4.5285 2B21-F022C 3.850 4.167 2821-F022D 3.220 3.708 2B21-F028A 4.012 4.42 2821 F0288 3.363 3.518 2821-F028C 3.678 3.918 2821-F028D 3.560 3.928 The full-closure test of all MSIV was initially attempted on February 14, 1979. Several system malfunctions occurred during this test: the outboard steam'ine A MSIV closed in 1.65 seconds, violating the Level 1 criteria; safety relief valves C and G failed to lift at their setpoint pressure of 1090 psig; multiple lifts occurred on several relief valves; steamline B exhibited vibration amplitudes violating Level I criteria; several feedwater system hangers in the turbine building were torn from their anchor points; several vacuum breakers on the SRV discharge lines were damaged; and damage was done to the upper ring header in the torus. A lengthy outage to repair damage followed. The MSIV was adjusted and retimed satisfactorily; the SRV were modified to increase the percent of blowdown and decrease their sensitivity to back pressure; a snubber support for steam line B was repaired; the vacuum breakers and damage in the torus were repaired; and an extensive inspection and repair program was conducted on all plant hangers. A second MSIV closure test was conducted on June 27,1979. All criteria were met except that RCIC initially tripped on high steam flow during an automatic initiation. This malfunction was not considered to have adversely affected the test results, since RCIC was subsequently started up manually and adequately maintained reactor water level. Resolution of the RCIC problem is described in the STI 14 section of ths report. The sequence of events during the transient is given in Table 3-25. 3-33

REDO-24734 Table 3-25 SEQUENCE OF EVENTS DURING FULL CLOSURE OF ALL MSIV TESTS Time (seconds) Event 0 Group 1 isolation initiated with high steam-flow signal Initial conditions: 90.7% power; 99.6% core flow; 975.8 psig reactor pressure. Reactor scram shortly after initiation. 5 Manual turbine trip followed by RPT. 8 Minimum water level: -44.7 inches 26 Initial pressure peak of 1088 psig - SRV F, G, & K opened 162 Second pressure peak approximately 1065 psig - SRV F & K opened 190 Maximum water level: 74.2 inches 299 SRV F opened Following the automatic SRV actuations, several manual initiations were conducted to measure effects on water level instrumentation and to monitor steam piping and SRV response with accelerometers, LVDT, strain gages, and various pressure instruments. Plant response was found to be as expected for the transient. 3.25 STI 26, RELIEF VALVES l 3.25.1 Level 1 Criteria 1. The capacity of all eleven relief valves exceeded the required total of 9.46 x 10*lb/hr corrected for an inlet pressure of 1112 psig. 2. During manual actuation, each valve exhibited positive indication of steam discharge by increasing downstream pipa temperature and suppression pool shell vibration. I 3.25.2 Level 2 Criteria 1. Relief valve leakage was low enough that the temperature measured by the thermocouples on the discharge side of the valve fell within the specified 10*F of the temperature recorded prior to valve opening. 2. The pressure regulator satisfactorily controlled the reactor transient during relief valve testing and closed the control valves or bypass valves by an amount equivalent to the relief valve discharge. 3. The transient recorder siOnatures for each valve showed a maximum delay time between trip and valve motion of 0.40 second and a maximum main disk stroke time of 0.096 second. 4. No individual relief valve had a flow rate, corrected to 1112 psig, less than 102% or greater than 115% of rated flow (860,463 ib/hr). 3-34 f

NEDO-24734 3.25.3 Discussion STI 26 testing was conducted at heatup and Test Condition 2 as defined on the Power Flow Map (Figure 2-13). During heatup, an initial SRV functional test was done. Each valve opened and then reseated properly. At Test Cond; tion 2, SRV signatures were analyzed and valve capacities determined. An ultrasonic transdi cer was mounted in contact with the shell of the suppression pool. This device showed response during valve operc. tion. Delay time was measured between the electrical valve actuation signal and the beginning of the ultrasonic transducer response. Main disk stroke time was measured as the time from the beginning of transducer response until it had reached a peak value. Results are shown in Table 3-26. Table 3-26 SRV VALVE TIMING Delay Time Response Time Valve (seconds) (seconds) F013A 0.32 0.088 F0138 0.31 0.096 F013C 0.34 0.096 F0130 0.36 0.096 F013E 0.40 0.080 F013F 0.36 0.080 F013G 0.28 0.088 F013H 0.30 0.096 F013K 0.40 0.080 F013L 0.36 0.080 F013M 0.38 0.096 Relief valve capacities were calculated using two methods. The first involved the calibration of bypass valve position against steam flow. Once this was done, the closure of the bypass valve during SRV operation would be a direct measurement of valve capacity. Capacities measured in this manner were calculated to be greater than 122.5% of expected for each valve. An alternate method was then used which correlated steam flow with generator electrical output and then measuring the drop in generator output during relief valve operation. This method gave good results, and the resultant relief valve capacities are given in Table 3-27. 3-35

NEDO-24734 Table 3-27 RELIEF VALVE CAPACITIES Capacity Capacity Valve (MLB/hr) (% of rated) F013A 0.894 104 F013B 0.929 108 F013C 0.920 107 F013D 0.894 104 F013E 0.989 115 F013F 0.894 104 F013G 0.963 112 F013H 0.877 102 F013K 0.972 113 F013L 0.989 115 g F013M 0.929 108 3-36

NEDO-24734 3.26 STI 27, TURBINE TRIP AND GENERATOR LOAD REJECTION 3.26.1 Level 1 Criterla 1. Reactor dome pressure and heat flux rise during the transients did not exceed the Level 1 criteria limits. 2. The feedwater system settings prevented flooding of the steamhnes following these transients. 3. The two-pump drive flow coastdown transient during the first three seconds was faster than that specified in the Nuclear Boiler System Transient Data Sheet, MPL A12-5031. p 4. During the tus bine trip, the bypass valve opening began within 0.1 second after the start of stop-valve closure and flow of 80% of L tas bypass capacity was achieved in less than 0.2 second more. 3.26.2 Level 2 Criteria 1. Reactor dome pressure and heat flux rise during the transients did not exceed the Level 2 cnteria limits. 2. The MSIV did not trip closed during the transients. 3. The load rejection within bypass capacity did not cause a scram. The trip scram function for higher power levels met RPS specifications. 3.26.3 Discussion STI 27 testing was conducted at Test Conditions 2,3, and 6 as defined on the Power Flow Map (Figure 2-19). The testing results are summarized in Table 3-28. Table 3-28 STI 27 TEST RESULTS Test Condition 2 3-6 Type Test Load Rejection Turbine Trip Load Rejection Date 10/31/78 11/23/78 6/19/79 Initial power (%) 20.2 68.7 93.1 Core flow (%) 37.9 99.0 99.6 Reactor pressure (psig) 945 970 980 Peak neutron flux 21.6 68.7 99.6 Heat flux rise 0 0 0 Maximum pressure 948 1023 1077 Level 1 pressure rise limit (psig) 1075 1137 Level 2 pressure nse limit (psig) 1050 1112 3-37

NEDO-24734 l A load rejection within bypass valve capacity was conducted at TC2. No scram occurred. Bypass valves opened to 82% of their total capacity. Water level remained within 0.5 inch of its initial value. Dome pressure rose about 3 psi during the initial transient. APRM values peaked about 1.4% above initial, but there was no rise in simulated heat flux. A turbine trip was conducted at TC3. A chronology of events is provided in Table 3-29 A generator load rejection was conducted at TC6. A chronology of events is provided in Table 3-30. No relief valves opened in either test. As the tables show, dome pressure and heat flux did not exceed the criteria limits. Bypass valve operation was adequately fast. A Group 1 isolation did not occur. There was a significant amount of trouble verifying the flow coastdown criterion of the recirculation pumps following the TC3 turbine trip and TC6 load rejection. The problems were eventually traced to instrument electrical time delays and a small correction to the predicted coastdown that was due to initial reactor power, with lower initial power resulting in a slightly slower coastdown. When these factors had been taken into account, tne coastdown criterion was met for both transients. Table 3-29 TURBINE TRIP AT TC3 Time (seconds) Event 0 Turbine trip manua:ly initiated in control room 0.10 Stop valve fast closure signal 0.11 Recirc pumps tripped i 0.14 Automatic scram 0.20 Bypass valves begin opening 0.32 Bypass valves 80% open 3.7 Maximum reactor dome pressure of 1023 psig 37 Minimum reactor water level of -4 inches 59,71 HPCI & RCIC on line to control water level 270 Maximum water level of 67 inches 3 s 3-38

h!EDO-24734 Table 330 GENERATOR LOAD REJECTION AT TC6 Time (seconds) Event 0 Generator output breaker opened, reactor scram 0.3 Bypass valves opened 0.4 Control vanes closed 4.9 Peak reactor pressure 8.4 Minimum reactor water level of 17 inches 27 Maximum reactor water level of 50.5 inches 240 Turbine manually tripped 3-39

NEDO-24734 3.27 ST128, SHUTDOWN FROM OUTSIDE THE CONTROL ROOM 3.27.1 Level 2 Criteria During a simulated control room evacuation, the reactor was brought to the point where cooldown was initiated and under control, and the reactor vessel pressure and water level were controlled using equipment and controls outside the control room. 3.27.2 Discussion STI 28 testing was conducted at Test Condition 1 as defined on the Power Flow Map (Figure 2-19). A manual scram was initiated by actuating the scram discharge volume high-level switches locally. The sequence of events is summarized in Table 3-31. Table 3-31 SEQUENCE OF EVENTS FOR SHUTDOWN-OUTSIDE THE-CONTROL-ROOM TEST Time (seconds) Event 0 Scram initiated by activation of scram discharge volume high level switches 12 Minimum water level - about 16 in. 13 RCIC initiated from remote shutdown panel 44 Main turbine manually tripped from control room 49 Generator breakers opened manually 70 Group 1 isolation (about 865 psig) ~300 Feed Pump A tripped Reactor water level reached a minimum of 16 in., then slowly rose to a final value of ~48 in. Water level and pressure were controlled from the remote shutdown panel. RCIC was used as necessary to maintain water level and to draw steam to lower pressure and cool down the reactor. Measured cooldown rate was 30*F/hr. Although a higher rate was desired, problems with the RHR Service Water System made it undesirable to significantly raise torus water temperature. Higher cooldown rates could have been attained through relief valve actuation. The relief valves controlled from the remote shutdown panel were tested to assure operability. 3-40

NEDO-24734 3.28 STI 29, FLOW CONTROL 3.28.1 Level 1 Criteria The decay ratio during all flow control tests remained less than 1.0 for each process variable that exhibited oscillatory response to flow control changes. 3.28.2 Level 2 Criteria 1. The decay ratio remained less than 0.25 for each process variable that exhibited oscillatory response to flow control changes while the plant was operating above the lower limit setting of the master controller. 2. Flow control system limit cycles produced tJ,bine steam flow variation less than t 0.5% of the rated steam flow value. 3. Reactor scram did not occur due to flow control system maneuvers. The APRM flux margin was >7.5%. 4. The automatic load following range along the full power rod line was greater than 35% of rated power. 5. The load change resulting from a maximum ramp increase in load reference within the limits of the automatic flow control range was achieved within 60 seconds. 3.28.3 Discussion STl 29 testing was conducted at Test Conditions 2,3,5, and 6 as defined !,a the Power Flow Map (Figure 2-19). A significant amount of troubleshooting took place prior to obtaining satisfactory system response. This troubleshooting included the following: cutting new cams twice for each positioner, adjusting positioner linkage, replacing and adjusting positioner brakes, and replacing electrical components in the controller circuitry. Fina: recirculation controller settings are provided in Table 3-32. The majority of the testing was conducted along a midpower rod line between Test Conditions 2 and 3. Results were extrapolated to determine response on the fated rod line. Response to step changes is shown in Table. 3-33. Response to large flow ramps is shown in Tab!e 3-34 i e am flow variation was determined by observing main generator output so that 0.5% steam flow corresponded to 4 MWe. Time for completion of the load following ramp was measured from the start of the ramp until main turbine generator load demand error returned to zero. Criteria for minimum times to recirculation generator speed peaks were determined not to be applicable once the load following criterion had been met. Three controller settings for the master controller were determined; one optimum setting which would meet the load following criterion, one PCIOMR setting which would not exceed maximum PCIOMR ramp rates, and an intermediate setting. Results of steps changes done at Test Condition 6 are included in Table 3-35. Table 3-32 RECIRCULATION SYSTEM CONTROLLER SETTINGS Controller Proportional Band Resets Minute Local A 2B31-R622A 250 22 Local B 2B31-R622B 250 22 Master controller 2831-R600 Optimum 250 15 Intermediate 500 10 PCIOMR 2000 12 3-41

NEDO-24734 Table 3-33 RESPONSE TO RECIRCULATION SYSTEM STEP CHANGES -TEST CONDITION 3 Total Core Decay MWe Margin to Time to 1st Test A% Flow Ratio Variation Scram Generator Speed Peak Master manual A 23.1 sec 2 MWe at 90% flow + 9.4%, -6.8% 0 21.4 % B 29.4 sec Master auto at 90% flow + 7.7% 0 m2 MWe 20% A 24.4 sec optimum scttings -8.3% B 28.1 see Master auto at 90% flow + 7.5% 0 2 MWe 23.9 % A & B ~7 min PCIOMR settings -9.4% Master manual at 2 MWe A 39.6 sec 70% flow + 9.9%, - 10.1 0 19.6 % B 46.8 sec Master auto at 70% flow + 10.4% 0 22 MWe 24.2% A 51 sec optimum setting - 10.9% 0 B 56.4 sec Master auto at 70% flow + 11.4% 0 2MWe 17.1% A & B ~15.5 min PCIOMR settings -10.4% Master manual at 2 MWe A 18 sec 50% flow + 8.8%, - 6.8% 0 21.3 % B 15 see Master auto at 50% flow + 9.4% 0 2 MWe 23.5 % A 34.2 sec optimum settings -9.4% B 29.1 see Master auto at 50% flow +9.4%, -5.2% 0 2 MWe 25.9 % A 10 min 41 see PCIOMR settings B 10 min 27 sec Local manuai at 24.2% 0 2MWe 24.0 % A 19.7 sec minimum flow 23.9% 0 2 MWe 22.8 % B 17.3 sec Level 1 criteria N/A < 1.0 N/A N/A N/A Level 2 cnteria N/A 50.25 24 MWe a7.5% N/A 3-42

NEDO-24734 Table 3-34 RECIRCULATION SYSTEM LOAD FOLLOWING DEMONSTRATION -TEST CONDITION 3 Time for Full Ramp Change in in Load Total Core Decay MWe Margin to Following Test Flow Ratio Variation Scram Range AAPRM Master manual ramp to 100% flow 42.6% 0 2 MWe 7.7% 48.8 sec 28 % Master auto ramp 11 min PCIOMR settings 36.4 % 0 z2 MWe 13.8% 38 sec 25.6% Master auto ramp 2 min intermediate settings 37.4% 0 z2 MWe 14.4% 33 sec 29.6 % Master auto ramp optimum settings 46.8% 0 2 MWe 10.9% 59 sec 35.2% Level 1 cnteria N/A < 1.0 N/A N/A N/A N/A Level 2 criteria N/A 50.25 z4 MWe a7.5% 60 sec a35% 3-43

NEDO-24734 Table 3-35 RESPONSE TO RECIRCULATION SYSTEM STEP CHANGES - TEST CONDITION 6 Total Core Time to First Flow Step Decay MWe Margin to Generator Test Change Ratio Variation Scram Speed Peak Master manual +7% 0 2 MWe 10.2% A 24.6 see steps at 70% core flow -7% 0 N/A B 28.2 sec Master auto + 2.5% 0 2 MWe 14.0% N/A steps at 70% core flow - 5.2% 0 N/A Master manual + 8.8% 0 m2 MWe 9.9% A 21.1 sec steps at 90% core flow -6.8% 0 N/A B 27.2 sec Master auto -5.2% 0 22 MWe 12.5% N/A steps at 90% core flow + 5.2% 0 N/A Master manual - 9.4Y. 0 2MWe 16% A 25.8 sec steps at 100% core flow + 10.4s 0 N/A B 28.8 see Master auto - 6.8% 0 2MWe 14.4 % N/A steps at 100% core flow +3.1% 0 N/A Level 1 criteria N/A < 1.0 N/A N/A N/A Level 2 criteria N/A 5 0.25 4 MWe 37.5% N/A \\ I 3-44 ik_.

NEDO 24734 3.29 STI 30, RECIRCULATION SYSTEM 3.29.1 Level 1 Criteria The two pump drive flow coastdown following a two pump trip is faster than required. 3.29.2 Level 2 Criteria Single pump trips did not result in a high water level turbine trip. The margin to low-level scram was greater than 3.0 inches. Reactor scram did not occur during pump restart; the scram avoidance margin was greater than 7.5% for neutron flux. 3.29.3 Discussion STI 30 testing was conducted at Test Conditions 2,3,4, and 6 as defined by the Power Flow Map (Figure 2-19). Steady-state performance data were obtained at Test Conditions 2,3,4, and 6. One single pump trip was conducted at each of Test Conditions 5 and 6. A two-pump tiip was conducted at Test Condition 3. A recirculation and jet pump cavitation search was conducted by inserting control rods from Test Condition 3. The MG set motor breaker to pump B was opened at Test Condition 3. MG set motor breaker A was opened at Test Condition 6. Table 3-36 is a summary of the pump trip results. During the two pump trip, drive flow coasted down faster than the specified rate when instrument delay times and an initial reactor power effect ware taken into account. No indication of recirculation pump orpt pump cavitation was observed with reactor power reduced to 26.6% and core flow at 100%. Table 3-36 SINGLE RE(*1RCULATION PUMP TRIP RESULTS Test Condition 3 6 initial reactor power (%) 68.2 95.3 initial core flow (%) 92.3 98.8 Peak water level (inches) F).3 42.6 Margin to high water level trip (inches) 17.7 15.4 Margin to flux scram on pump restart (%) 26.7 14.6 3.30 STI 31 LOSS OF TURBINE GENERATOR AND OFFSITE POWER 3.30.1 Level 1 Criteria 1. The reactor protection system actions prevented violation of neutron flux and simulated fuel surface heat flux thermal power limitations. 2. Peak reactor dome pressure reached 971 psig from an initial pressure of 925 psig, so no relief valves lifted. 3 45

NEDO-24734 3. All safety systems including the Reactor Protection System and the diesel generators functioned properly without manual assistance. Minimum water level was 4.4 inches, so neither RCIC or HPCI initiated automatically. 3.30.2 Level 2 Criteria 1. Normal reactor cooling systems were able to maintain adequate suppression pool water temperature, maintain adequate drywell cooling, and prevent actuation of the auto-depressurization system. 2. The RCIC system was started manually to demonstrate operability and to maintain water level. 3.30.3 Discussion STI 31 testing was conducted at Test Condition 2 as defined on the Power Ficw Map (Figure 2-19) on November 3, 1978. Initial conditions were 21.8% power,16.5% generator output,38% core flow, and 925 psig dome pressure. The transient was initiated by manually tripping the generator negative sequ.1ce relay with a simultaneous isolation of the unit startup transformer. The sequence of events during the transient is included in Table 3-37. Following the transient initiations, a Group 1 isolation occurred immediately due to loss of power to the turbine building leak detection system. Reactor scram then followed due to MSIV at less than 90% open. All three diesel generators started automatically and fed to their respective busses within 10.8 seconds of the initiation of the test. Plant loads were observed to start in proper sequence. Suppression pool and drywell pressures were maintained below 2 psig, torus water temperature did not exceed 120*F. All drywell chillers were operating following the LOSP and maintained drywell temperatures below 135'F. The automatic depressurization system did not actuate. Table 3-37 SEQUENCE OF EVENTS DURING LOSS OF TURBINE GENERATOR AND OFFSITE POWER TEST Time (seconds) Event 0 Initiate transient < 0.1 Group 1 isolation ~0.7 Reactor scram on MSIV closure 10.8 All diesel generators tied to their respective busses 20 Minimum water level of 4.4 inches 22.2 Turbine tripped >150 Reactor pressure settles to 971 psig 3-46

NEDO-24734 s 3.31 STI 33, DRYWELL PIPING VIBRATION 3.31.1 Level 1 Criteria 1. The measured displacement for vibration of the recirculation system during recirculation pump trips and subsequent coastdown did not exceed the aHowable values as described in para 3.31.3. 2; The measured displacements in the main steam lines dt. ring reCef valve operation did not exceed the allowable values as described in para 3.31.3. 3. The measured displacements for steady-state vibration of the recirculation and main steam systems did not exceed the allowable values as desenbed in para 3.31.3. 4. The measured displacements of the main steam lines due to turbine stop valve trip and relief valve operation did not exceed the allowable values as desenbed in para 3.31.3. NOTE: The piping design subsection supplied the predicted and allowable vibration amplitude for steady-state operation, turbine trip, and relief valve operation based on the installed transducer locations. 3.31.1 Level 2 Criteria The measured vibration displacements of the main steam system and recirculation system following relief valve operation, turbine stop valve trip, and during steady-state operation did not exceed the expected range of displacement supplied by the piping design subsection. 3.31.3 Discussion STI 33 was conducted during heatup, and at Test Conditions 1,3, and 6 as defined on the Power Flow Map (Figure 2-19). Da'a was collected at each test condition during steady-state operation and also in conjunction with transients performed for other startup tests. The only time that a vibration amplitude was exceeded, or even approached, was during the first full closure of all MSIV tests conducted on February 14,1979. For this transient, Steamline B exhibited vibration in excess of the Level 1 criterion. Investigation following the test showed a snubber support on this steamline to be defective. In addition, multiple pops of the relief valves during the transient may have created a situation resulting in a worse vibration transient than initially expected. Following repairs, the second full closure of all MSIV tests was conducted and all vibrations were within the Level 2 cnterion limits. 3.32 STI 35, RECIRCULATION SYSTEM FLOW CALIBRATION 3.32.1 Level 2 Criteria 1. Jet pump flow instrumentation was adjusted so that the jet pump total flow recorder provided a correct core flow indication at rated conditions. 2. The APRM/RBM flow-bias instrumentation was adjusted to function properly at rated conditions. .[ 3.32.2 Discussion The STI 35 testing was conducted during the open vessel phase between Test Conditions 2 and 3, at Test Conditions 3 and 5, between Test Conditions 5 and 6, at Test Condition 6, and again at Test Condition 6 as a verification case. Test Conditions are defined on the Power Flow Map (Figure 2-19). s 3-47

NEDO-24734 Prior to the initial heatup, an integrated instrumentation calibration check on the flow instrumentation was performed. The recirculation flow nozzle transmitters were calibrated for a 0-45.4 psid span corresponding to 10-50 mA output. The double-tapped and single-tapped jet pump dP transmitters were calibrated for a 0-40 psid span corresponding to 10-60 mA output. All jet pump recirculation flow and core flow instruments were verified calibrated and 'unctionally working properly. Initially, for each flow calibration, the dP transmitters for single-and double-tapped jet pumps were verified for zero signal. Each single-tapped dP transmitter and square rooter was checked and adjusted, if necessary, so that for zero dP signal, the transmitter output was 11.16 0.1 mA and the square rooter output 16.09 : 0.5 mA. The double-tapped dP transmitters and the square rooter output were checked and adjusted as necessary for an output of 10.0 e 0.1 mA and 10.0 0.5 mA, respectively. Following this check, steady state data were obtair.od for recirculation pump flow nozzle and jet pump flow instrumentation. Recirculation drive flow was calculated by the nozzle method and the pump head curve method. The coie flow was calculated using the KCAllB for the design M ratio of 1.25 and then iterating unti! the M-ratio converged. A summary of the results are given in Table 3-38. The required gain adjustment factors for the APRM/RBM flow units and jet pump proportional amplifiers we.e calculated and adjustments were made to the instruments as necessary for a gain adjustment factor of 1.00 0.01. Jet pump loop flow was checked to ensure that the flow variation limit was met. The difference between loop flow calculated by single-tapped jet pumps and the loop flow calculated by double-tapped jet pump was less than 3% The jet pump plugging criteria in the riser (50.1) and in the nozzle (50.12) were verified for all jet pumps. Table 3-38 RESULTS OF JET PUMP CALCULATIONS BY NOZZLE METHOD AND BY PUMP HEAD CURVE METHOD Between Between Test Condition 2 and 3 3 5 5 and 6 6 6 (Verification) Parameter Head Head Head Head - Head Head (MLB/hr) Nonle Curve Nonle Curve Nonle Curve Nonle Curve Nonle Curve Nonle Curve Drive flow A 10.187 7.169 12.6$5 12.153 7.638 7.291 11.201 10.500 15.679 16.131 15.793 15.837 Dnve flow B 10.276 9.309 12.793 12.604 7.809 8.769 11.399 11.684 15.919 16.354 15.835 14.209 Loop flow A 26.769 27.081 31.185 31.219 19.703 19.547 27.615 27.761 36.945 36.843 36.371 36.365 Loop flow B 26.450 28.094 31.259 31.360 20.741 20.877 27.131 27.086 37.116 37.039 37.393 37.707 Total core flow 53.22 55.18 62.44 62.58 40.44 40.42 54.75 54.85 74.06 73.88 73.76 74.07 % of 77 MLB/hr 69.1 71.7 81.1 81.3 52.5 52.5 71.1 71.2 96.19 95.95 95.79 96.19 Indcated core flow MLB/hr 53.0 63.0 41.5 54.48 74.90 73.86 % of 77 MLB/hr 68.8 81.8 53.9 70.75 37.27 95.92.- 3-48 L

REDO 24734 3.33 STI 70, REACTOR WATER CLEANUP SYSTEM 3.33.1 Level 2 Criteria 1. The temperature at the tube side outlet (RWCU Flow) of the nonregenerative heat exchanger did not exceed 140*F in any mode. 2. The pump available NPSH was demonstrated to be greater than 10 feet (216.9 feet actual) during the hot standby mode as defined in the process diagrams. 3. The cooling water supplied to the nonregenerative heat exchangers was within the flow and outlet temperature limits in the blowdown and normal modes as indicated in the process diagrams. 3.33.2 Discussion The Reactor Water Cleanup System (RWCU) testing was performed during heatup (blowdown and hot standby modes) and Test Condition 2 (normal mode) as defined on the Power Flow Map (Figure 2-19). Results are summarized in Table 3-39. All temperature criteria for the blowdown and hot standby modes were met even though the RWCU flow was higher than rated in each mode because of an incorrectly indicated flow. As determined during the hot standby mode, net positive suction head was found to exceed the required 10 feet by 206.9 feet. All temperature criteria for the normal mode of operation were met although the RWCU System flow was indicated as 203 gpm. Prior to testing in the normal mode, flow ar.alysis showed that rated RWCU System flow of 266 gpm was attained when the system flow indicator reached 203 gpm. This discrepancy was due to the calibration of the flow orifice, which does not compensate for the variation in flow rate caused by temperature increases. The utility has investigated this situation; however, it is of such a nature that no operating restrictions have been imposed on the system. Within the intent of this test, STI 70 was considered successfully completed. 3 1 49

NEDO-24734 Table 3-39 REACTOR WATER CLEANUP SYSTEM PERFORMANCE Blowdown Mode Hot Standby Mode Normal Mode Process Process Process Variable Measured Flow Value Measured Flow Value Measured Flow Value Pump suction pressure (psig) 950 940 995 890 1013 Cleanup system flow 129 94 296 270 204 266 Point 1 (gpm) (-275 actual) Temp at inlet to RHX Point 1 (*F) 545 545 535 545 518 532 Temp at outlet of RHX Point 2 (*F) 540 545 170 245 157 233 Temp at outlet of NRHX 100 100 98 130 60 120 Point 3 (*F) (calib error) Temp at outlet of RHX (to Rx vessel) Point 4 (*F) 540 N/A 425 448 409 436 Cooling water flow to NRHX point 5 (gpm) 475 477 480 477 475 477 Temp of cooling water at inlet to NRHX Point 5 (*F) 75 105 65 105 70 105 Temp of cooling water at outlet of NRHX Point 6 (*F) 180 180 135 176 118 153 Net positive suction N/A N/A 216.9 34.9 N/A N/A head (feet) (calculated) (N/A not appleable,5 4 ,1 3 50

idEDO-24734 3.34 STI 71, RESIDUAL HEAT REMOVAL SYSTEM 3.34.1 Level 2 Criteria 1. The Residual Heat Removal (RHR) system was capable of operating in the steam condensing mode (with both one and two heat exchangers) at the flow rates indicated c9 the process diagrams. 2 The process system variables were visually shown to have a elecay rato of less than 0.25 throughout each (level, pressure and differential pressure) controller's expected operating range. 3.34.2 Discussion During the heatup phase, each loop of the RHR System was operated in the torus cooling mode to verify adequate heat removal in accordance with the process diagram. RHR heat exchangers A and B removed an average of 32.74 x 108 Btu /hr and 34.2 x 10' Btu /hr, respectively, both greater than the required 30.8 x 108 lbm/hr. Average results are given in Table 3-40. No enterion applies to this RHR mode of operation. Note that both loops had been demonstrated capable of delivering RHR service water to the heat exchangers at 8000 gpm even though for the determination of heat exchanger B heat removal rate, the flow was slightly below 8000 gpm. Satisfactory operation of the RHR steam condensing mode was demonstrated for both one and two loops in service. This mode was performed with the reactor un-isolated during Test Condition 1 and again later with the reactor in hot standby, the MSIV closed (reactor isolated from the main condenser), and the RCIC System injecting into the reactor at approximately 700 psig. The RCIC mass flow rates are given in Table 3-41. While in tne steam condensing mode of operation, the differential pressure, steam inlet pressure, and the heat exchanger level controllers of both exchangers were exercised by introducing step changes in setpoint. For smah disturbances, each system variable had decay ratios less than 0.25 throughout the expected operating range of each of the controllers. The RCIC suction pressure controller was demonstrated to properly take over and protect the RCIC System from high suction pressure. Step changes caused heat exchanger high-level and high RCIC suction pressure. After discussion with the GE control systems engineer, demonstration of the take-over capability of the RCIC suction pressure controller was determined to be sufficient within the scope of the design criteria. The controller settings are summarized in Table 3-42. During a heatup late in the startup program, the RHR shutdown cooling mode of operation was performed and the RHR heat exchangers were found to be capable of removing residual and decay heat from the nuclear system. The heat removal capacity of each heat exchanger was sufficient. No criterion applies to this RHR mode of operation. 3-51

NEDO 24734 Table 3-40 RHR TORUS COOLING MODE AVERAGE RESULTS RHR HX A hHR HX B Process Diagram RHR pump flow (from torus) 15,475 gal / min 15,444 gal / min 15,400 gal / min RHR service water flow 8,000 gal / min 7,825 gal / min 8,000 gal / min Torus water temp HX inlet start 100Y 104*F 125*F finish 97'F 99*F RHR HX outlet temp start 95*F 100*F 117*F finish 93*F 95'F Cooling water inlet temp 80*F 85*F 85*F Cooling water outlet temp 87.9*F 88.3*C 92.7*F l Heat removal 32.74 MBtu/hr 34.2 MBtu/hr 30.8 MBtu/hr rate for 30 min test for 33 min test l Table 3-41 RHR STEAM COND5NSING MODE RHR RHR RHR Div1 Div 11 Div i and ll RCIC flow with reactor un-isolated 112.0 103.3 136.3 (x108 lbm/hr) l RCIC flow with reactor isolated 129.4 179.5 211.8 (x102 lbm/hr) RCIC flow per process diagram 3 99 299 =138 (x102 lbm/hr) B 3-52

NEDO-24734 Table 3-42 RHR CONTROLLER SETTINGS Steam Condensing Mode with Steam Condansing Mode with the Reactor Un-Isolated: the Reactor isolated: Final Settings Final Settings (After Setpoint Steps) (After Setpoint Steps) P:oportional Roset Proportional Reset Controller Panel Band (%) (repeats / min) Band (%) (repeats / min) Service water dP: 2E11 R628A 2H11-P613 400 3 400 3 2E11-R628B 2H11 P612 400 3 400 3 Inlet pressure: 2E11-R626A 2H11 P613 150 3 150 3 2E11-R626B 2H11-P612 150 4 170 10 HX level: 2E11-R627A 2H11-P613 40 1.5 40 1.5 2E11 R6278 2H11 P612 40 3 40 2.9 RCIC suction pressure: 2E11-R625 2H11-P612 100 5 100 5 3.35 STI 74, OFFGAS SYSTEM 3.35.1 Level 1 Criterla 1. The release of radioactive gaseous and particulate effluents did not exceed the limits specified in the site technical specifications. 2. There was no loss of flow of dilution steam to the noncondensing stage when the steam jet air ejectors were pumping. 3.35.2 Level 2 Criteria 1. The system flow, pressure, temperature, and relative humidity complied with the design specifications except as noted in the discussion below. 2. The catalytic recombiner, the hydrogen analyzer, the activated carbon beds and the filters were working properly during operations; that is, there was no gross malfunctioning of these components. 3.35.3 Discussion The STI 74 testing was conducted while at steady-state conditions during heatup and at Test Conditions 1,3, and 6 as defined by the Power Flow Map (Figure 2-19). All applicable Level 1 criteria were satisfied at each testing level. Because several parameters were outside the system design specifications, not all of the applicable Level 2 criteria were met. The offgas system parameter results are listed in Table 3-43. Discrepancies and justifications follow. The final conclusion is that the offgas system is capable of performing all design functions. 3 53

NEDO-24734 Glycol pump discharge pressure reads low because of the location of the pressure sensor which is downstream of a throttle valve. Design specifications for glycol pump pressure refer to a pressure indication upstres m of the throttle valve; therefore, unless the pressure sensor is moved, the glycol pump pressure will always read low. This discrepancy does not after tha performance of the offgas system and the Level 2 criterion is satisfied noting the preceding reason. The offgas condenser coolant and process outlet temperatures and the moisture separator outlet temperature were slightly higher than the estimated maximum values given in the Offgas System Process Diagram (105D4711BA); but, because_the relative humidity as determined by the reheater dewpoint and outlet temperature (which were within the design limits) entering the charcoalis the important parameter, these exceptions were considered acceptable. The applicable Level 2 criterion was satisfied noting the preceding exceptions and justifications. Table 3-43 OFFGAS SYSTEM DESIGN PARAMETERS AND RESULTS Normal Results for indicator Operation Design Test Condition Parameter (2N62) Range Limits Heatup 1 3 6 Date 9/17/78 10/2/78 10/26/78 7/26/79 Time 1530 0815 0815 0933 Core thermal power MWt OD3, Option 2 80 380 1140 2351 % of 2436 MWt 3.3 15.6 46.8 96.5 Dilution steam 2N11 - R304A/B 6510 - 8636 6510 - 8636 1400 5810 INOP 7650 (Ibm /hr) (Note 1) SJAE outist R600 1-5 0 - 6.7 1.2 18.5 16.4 3.2 pressure (psig) (Note 1) (Note 3) (Note 3) Preheater outlet temp (*F) R601 325 - 375 230 - 420 365 348 345 360 Active recombiner temp (*F): R602 Bottom N003 375 - 830 250 - 900 370 352 350 390 Middle N004 375 - 830 250 - 900 375 377 550 680 Top N005 375 - 830 250 - 900 375 378 560 680 Standby recombiner temp ('C): R602 Bottom N003 325 - 375 250 - 900 275 317 310 INOP Middle N004 325 - 375 250 - 900 270 325 317 335 Top N005 325 - 375 250 - 900 270 325 317 340 0.G. condenser R003 coolant outlet (:ocal) <123 <123 100 88 119 126 temp (*F) (Note 5) O.G. condenser R005 outlet temp (*F) (local) <140 <140 130 125 142 143 (Note 5) 3-54

NEDO 24734 Table 3-43 (Continued) OFFGAS SYSTEM DESIGN PARAMETERS AND RESULTS Normal Results for Indicator Operation Design Test Condition Parameter (2N62) Range Limits Heatup 1 3 6 H, concentration (%) R603 A/B 0-1 0-4 0 0 0 0 b Offgas flow (cfm) R604 6 - 18 6 - 40 50 43 27 14 G6fco; pump discearge R605 40 - 45 40 - 45 17.5 17.5 17.5 17 pressu,'e (psig) (Note 4) (Note 4) (Note 4) (Note 4) Glycol tank temp (*F) R606 34 - 36 32 - 40 34 34.5 34 34 Moisture separator R608 36 - 45 34 - 49 56 57 43 ~45 - 50 outlet temp (*F) (Note 5) Reheater dewpoint (*F) R609 34 - 45 34 - 49 45 41 42 38 Reheater outlet R610 72 - 76 70 - 80 365 77 74.5 74 temp (*F) (Note 2) Prefilter differential pressure (dP) (inches water) R611 0-2 0-8 0 0 0 0 Adsorber dP (psid) R612 0-3 0-4 N/A 0.09 0.175 0.087 Bypass dP (inches water) R612 0-2 0-8 0.2 N/A N/A N/A Adsorber vessel temp (*F): R613 B13, point 1 NO21 75 - 79 72 - 82 75.5 72 70 75 B12, point 2 N022 75 - 79 72 - 82 75.6 78 72 79 B1 1, point 3 NO23 75 - 79 72 - 82 75.5 71 72 72 B2, point 4 N024 75 - 79 72 - 82 76.5 72 73 78 B3, point 5 NO25 75 - 79 72 - 82 75.5 71 73 76 B6, poir.t 6 N026A 75 - 79 72 - 82 76.0 75 71 77 B12, point 7 N0263 75 - 79 72 - 82 76.5 77 72 77 B7, point 9 NO27 75 - 79 72 - 82 77.5 77 78 77 Adsorber vault temp (*F) R615 75 - 79 70 - 82 76 71 71 76 \\ 3-55

NEDO 24734 Table 3-43 (Continued) OFFGAS SYSTEM DESIGN PARAMETERS AND RESULTS Normal Results for Indicator Operation Design Test Condition Parameter (2N62) Range Limits Heatup 1 3 6 After filter dP (inches water) R616 0-2 0-8 0 0.2 0.2 0 Outside temperature (*F) 90 66 68 84 % Relative humidity 75 63 75 40 NOTES 1. The low dilution steam flow and low SJAE outlet pressure resulted from maintaining 90 psig on SJAE third stage. At this low pressure, the flow and pressure is sufficient. 2. This reading was erroneous. Subsequent readings at TC1,3, and 6 indicate the reading within design limits. 3. Readings taken at 2N22-R324 4. Readslowbecausethepr-94 s4p* is located downstream of a throttle valve rather than upstream Although these temperawes are st y higher than the estimated maximum design limits, they are 5. l acceptable because the reheater dewpoint and outlet temperatures are within design limits. N/A: not applicable INOP: Indicator inoperable (maintenance request to repair as necessary was written) l l 3-56

NEDO-24734 t 4. DISTRIBUTION Name M/C J. Armenta (5) : 881 A. P. Bray.- 600 F.R.Channon --174 R. C. Christianson 883 D. W. Diefenderfer. 883 D. C. Ditmore - 150 F. C. Downey - 391 E. C. Eckert. .763 N. L Felmus= 882 D. L Fischer-733 Intemational Ucensing c/o R. R. Roof (5). 126 A. J. James. ..740 F. D. Judge.. -150 E. F. Karner-- 884 J. B. Lambart-

180 B. E. Lawler 164 L. D. Marsin (6);

126 S. L. Mather 143 R. J. Pickering (3). -171

1. D. Poppel--

884 G. C. Ross 893 G. J. Scatena = 763 S.1. Schreiner - 174 R. G. Serenka - 156 J. J. Sheehan - 884 A. R. Smith. 385 E. L. Strickland 889 E. P. Stroupe.- -146 884 R. W. Turkowski _ R. D. Williams-197 R. M. Wyatt. 884 W. Yee. - 884 P. J. Zimmerman (40). 884 NEG Ubrary (5).. 328 TIE (5). VNC Ubrary (2)= VO-1 B. J. Pooler, Head Ubrarian Engineering Ubrary The Stanford University Ubraries Stanford Califomia 94305 i 1 I

l l NUCLEAR ENERGY DIVISION e GENERAL ELECTRIC COMPANY SAN JOSE, CALIFORNIA 96125 GENER AL h ELECTRIC TECHNICAL INFORMATION EXCHANGE TITLE PAGE AUTHOR SUBJECT TIE NUMBER R.W. Turkowski Nuclear Science 79NED135 W. Yee & Technology OgTE 9 TITLE GE CLASS Final Sumary Report Edwin I. Hatch I Unit 2 Startup Test Results GOVERNMENT CLASS REPRODUCIBLE COPY FILED AT TECHNICAL NUMBER OF PAGES SUPPORT SERVICES, R&UO SAN JOSE, CALIFORNI A 96125 (MAIL CODE 109) 100

SUMMARY

This report consists of a summary of the Startup Test Program performed at Unit 2 of the Edwin I. Hatch Nuclear Power Plant. It includes results of stdtic and dynamic reactor performance tests of the reactor and related systems within the General Electric scope of supply. By cutting out this rectangle and folding in half, the above information can be fited into a standerd card file. DOCUMENT NUMBER NED0-24734 INFORMATION PREPARED FOR Nuclear Servires Dept. Nuclear Field Services SECTION 1887/2019 886 uutcoog sulLDING AND ROOM NUMBER j

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