ML20040E792

Startup Test Rept,Part 2

ML20040E792
Person / Time
Site:	Salem
Issue date:	01/29/1982
From:	Schell W Public Service Enterprise Group
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ML18086B287	List: ML18086B286 ML20040E792
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NUDOCS 8202050377
Download: ML20040E792 (198)

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{{#Wiki_filter:, I I PUBLIC SERVICE ELECTRIC AND GAS COMPANY SALEM NUCLEAR GENERATING STATION UNIT NO. 2 STARTUP REPORT BY WILLIAM H. SCHELL I I l lI i APPROVED: REACTOR ENGINEER: M

1. ' 82-F.

SCHNARR (DATE) '((* !I1/h-l TECHNICAL MANAGER-SALEM L. K. MILLER (DATE) I lI GENERAL MANAGER M< '4'd //d7[F SALEM OPERATIONS: w H. M'lDUR'A (DATE) I I 8202050377 820202 PDR ADOCK 05000311 l P PDR

I

I I

ACKNOWLEDGEMENT The success of the startup program depended upon many people. The Reactor Engineer and his staff express their gratitude to the entire Salem Generating Station Staff. Special tenks to Fred Twogood, Ed Watj en, Al Ha ye s, Fred Baskerville and Lou Grubmeyer of Westinghouse for their contributions. Thanks to George Druf fner of the Energy Laboratory and to John Dal Pan for his assistance in compiling this report. i I I I 109D (1 ) : 28 I

i TABLE OF CONTENTS l PAGE NO. LIST OF FIGURES iii - x LIST OF TABLES xi

1.0 INTRODUCTION

1 2.0 INTEGRATED TESTING 19 2. 1 SUP 81.5 DYNAMIC AUTOMATIC STEAM DUMP CONTROL 19 2. 2 SUP 81.3 TURBINE OVERSPEED TRIP TEST 23 2. 3 SUP 82.6 LOSS OF OFF-SITE POWER 26 2. 4 SUP 82.5 SHUTDOWN FROM OUTSIDE OF THE CONTROL ROOM 36 2. 5 SUP 82.1 LOAD SWING TESTS 51 2. 6 SUP 82.4 RODS DROP AND PLANT TRIP 57 2. 7 SUP 82.2 LARGE REDUCTION TEST 61 2. 8 SUP 82.7 STEAM GENERATOR MOISTURE CARRYOVER MEASUREMENT 69 2. 9 SUP 82.8 NSSS ACCEPTANCE TEST 74 2.10 SUP 82.9 - GENERATOR TRIP FROM 100% POWER 76 2.11 SUP 90.9 BORON MIXING AND COOLDOWN 80 2.12 RADIATION SHIELDING EVALUATION, EFFLUENT MONITORING, CHEMISTRY TESTS 85 2.12.1 SUP 81.13 - RADIATION MONITORING AND SHIELDING EVALUATION 85 2.12.2 SUP 81.14 - EFFLUENT MONITORING SYSTEMS 85 2.12.3 SUP 81.15 - CHEMISTRY AND RADIOCHEMISTRY TESTS 86 2.13 SUP 81.4 AUTOMATIC STEAM GENERATOR LEVEL CONTROL 89 2.14 SUP 81.6 AUTOMATIC REACTOR CONTROL 91 2.15' SUP 80.1 APPENDIX 6, FEEDWATER HAMMER TEST 94 I 109D (1 ) : 29 i

I TABLE OF CONTENTS PAGE NO. 3.0 CALIBRATION OF TEMPERATURS AND FLOW INSTRUMENTATION DURING POWER ESCALATION 98 I 3.1 SUP 81.12A - ALIGNMENT OF PROCESS TEMPERATURE INSTRUMENTATION 99 3.2 SUP 81.12B - STATEPOINT DATA 105 3.3 SUP 80.7 - TURBINE CONTROL SYSTEM CHECKOUT AND STARTUP ADJUSTMENTS OF THE REACTOR CONTROL SYSTEM 113 3.4 SUP 81.7 - CALIBRATION OF STEAM AND FEEDWATER FLOW INSTRUMENTATION AT POWER 118 4.0 PHYSICS TESTING 146 4.1 POWER AND BURN DISTRIBUTION MEASUREMENTS 146 4.2 SUP 81.9 - RCCA PSEUDO EJECTION AND RCCA ABOVE BANK MEASUREMENT 153 4.3 SUP 81.10 - STATIC RCCA DROP AND RCCA BELOW BANK POSITION MEASUREMENTS 159 4.4 SUP 81.8 - POWER COEFFICIENT AND INTEGRAL POWER DEFECT MEASUREMENT 167 4.5 SUP 81.11 - fNCORE - EXCORE DETECTOR FLUX DIFFERENCE CALIBRATIONS 172 4.6 SUP 81.12C - INTERMEDIATE AND POWER RANGE CHANNEL HIGH VOLTAGE SETTING VERIFICATION 182 'I .I l l 1E l il l 109D:(1):30 1

I LIST OF FIGURES FIGURE TITLE PAGE NO. 1.1 SALEM UNIT 2 CYCLE 1 HOURLY POWER FOR MAY '81 5 1.2 SALEM UNIT 2 CYCLE 1 HOURLY POWER FOR JUNE '81 6 I 1.3 SALEM UNIT 2 CYCLE 1 HOURLY POWER FOR JULY '81 7 I 1.4 SALEM UNIT 2 CYCLE 1 HOURLY POWER FOR AUGUST '81 8 1.5 SALEM UNIT 2 CYCLE 1 I HOURLY POWER FOR SEPTEMBER '81 9 1.6 SALEM UNIT 2 CYCLE 1 HOURLY POWER FOR OCTOBER '81 10 1.7 SALEM UNIT 2 CYCLE 1 HOURLY POWER FOR NOVEMBER '81 11 1.8 SALEM UNIT 2 CYCLE 1 HOURLY POWER FOR DECEMB'ER '81 12 1.9 CORE LOAD THRU HOT FUNCTIONAL TESTING - PLANNED / ACTUAL 13 1.10 LOW POWER THRU 10% PLATEAU TESTING - PLANNED / ACTUAL 14 1.11 30% TESTING - PLANNED / ACTUAL 15 1.12 50% TESTING - PLANNED / ACTUAL 16 1.13 75% THRU 90% TESTING -PLANNED / ACTUAL 17 1.14 100% TESTING - PLANNED / ACTUAL 18

I lI iii 109D (1)

31 I

I LIST OF FIGURES FIGURE TITLE PAGE NO. 2.3.1 BLACKOUT SUP 82. 6 RCS LOOPS HOT / COLD LEG. TEM PERATURE 27 2.3.2 B LACKOUT SUP 82. 6 PRESSURIZER PRESSURE, PRESSURIZER LEVEL AND HOTTEST INCORE 28 2.3.3 LOSS OF OFF-SITE POWER NO. 24 STEAM GENERATOR 29 2.3.4 LOSS OF OFF-SITE POWER NO. 23 STEAM GENERATOR 30 2.3.5 LOSS OF OFF-SITE POWER NO. 22 STEAM GENERATOR 31 I 2.3.6 LOSS OF OFF-SITE POWER NO. 21 STEAM GENERATOR 32 2.3.7 LOSS OF OFF-SITE POWER 'I T,y - AUCTIONED / REFERENCE / LOOP 33 2.3.8 LOSS OF OFF-SITE POWER I PRESSURIZER PRESSURE 34 2.3.9 LOSS OF OFF-SITE POWER PRESSURIZER LEVEL AND LEVEL SETPOINT 35 2.4.1 SHUTDOWN FROM OUTSIDE CONTROL ROOM RCS LOOPS HOT / COLD LEG TEMPERATURE 40 2.4.2 SHUTDOWN FROM OUTSIDE CONTROL ROOM RCS LOOP HOT / COLD LEG TEMPERATURE (CONTINUATION) 41 2.4.3 SHUTDOWN FROM OUTSIDE CONTROL ROOM PR2SSURIZER PRESSURE, PRESSURIZER LEVEL AND HCTTEST INCORE 42 2.4.4 SHUTDOWN FROM OUTSIDE CONTROL ROOM I PRESSURIZER PRESSURE, PRESSURIZER LEVEL AND HOTTEST INCORE (CONTINUATION) 43 2.4.5 SHUTDOWN FROM OUTSIDE CONTROL ROOM I PRESSURIZER LEVEL AND LEVEL SETPOINT 44 I iv + 109D (1 ) : 32 I p _sa s e n.

I LIST OF FIGURES FIGURE TITLE PAGE NO. 2.4. 6 SHUTDOWN FROM OUTSIDE CONTROL ROOM PRESSURIZER PRESSURE 45 2.4. 7 SHUTDOWN FROM OUTSIDE CONTROL ROOM T - AUCTIONED / REFERENCE / LOOP 46 avg 2.4. 8 SHUTDOWN FROM OUTSIDE CONTROL ROOM NO. 21 STEAM GENERATOR 47 2.4. 9 SHUTDOWN FROM OUTSIDE CONTROL ROOM NO. 22 STEAM GENERATOR 48 I 2.4.10 SHUTDOWN FROM OUTSIDE CONTROL ROOM NO. 23 STEAM GENERATOR 49 2.4.11 SHUTDOWN FROM OUTSIDE CONTROL ROOM NO. 24 5 STEAM GENERATOR 50 2.5. 1 LOAD SWING TEST 100% TO 90% FEED FLOW - I STEAM FLOW - FEED PUMP DISC PRESS. STEAM HDR PRESS. - STEAM GENERATOR LEVEL FEED PUMP SPEED - ROD CONTROL BANK D 53 2.5. 2 LOAD SWING TEST 100% TO 90% AUCT. T avg AUCT, AT - T -T Hot Cold AUCT. NUC FLUX - PRESSURIZER LEVEL 54

2. 5.

3 LOAD ShING TEST 90% TO 100% FEED FLOW - STEAM FLOW - FEED PUMP DISC PRESS. STEAM HDR PRESS - STEAM GENERATOR LEVEL FEED PUMP SPEED - ROD CONTROL BANK D 55

2. 5.

4 LOAD SWING TEST 90% TO 100% AUCT. T - AUCT AT - T -T avg Ho t Cold AUCT. NUC FLUX - PRESSURIZER LEVEL 56 2.6.1 SALEM NUCLEAR GENERATING STATION UNIT. 2 RCC INCORE DETECTOR AND THERMOCOUPLE LOCATIONS 60 2.7. 1 LOAD SWING TEST 100% TO 50% AUCT. T - AUCT AT - T -T avg Ho t Cold I, AUCT. NUC FLUX - PRESSURIZER LEVEL 67 I. - 2. 7., 2 LOAD SWING TEST 100% to 50% FEED LOW - STEAM FLOW - STEAM HDR PRESS. STEAM GENERATOR LEVEL - FEED PUMP SPEED ROD CONTROL BANK D 68 v 109D (1 ) : 33 l

I LIST OF FIGURES FIGURE TITLE PAGE NO. 1 2. 8.1 SERIES 51 STEAM GENERATOR 73 2.10.1 GENERATOR TRIP TEST FLUX - PRESSURIZER LEVEL - AUCT. Tavg -I AUCT AT - STEAM FLOW - FEED FLOW STEAM GENERATOR LEVEL - 21 LOOP THo t 21 LOOP T Cold 79 .I 2.11.'1 BORON MIXING AND COOLING LOOP 21, 22, & 23 - Tavg & AT 83 ~ 2.11.2 P250 COMPUTER TREND DURING NATURAL - c'IRCULATION C00LDOWN SUP 90.9 84 2.14.1 SUP 81.6 - AUTOMATIC REACTOR CONTROL RECOVERY FR0l4 LOWERED T 92 s avg j LW 2.14.2 SUP 81.6 - AUTOMATIC REACTOR CONTROL ~ RECOVERY FROM RAISED T 93 avg I-. 2.15.1 INSTRUMENTATION BRACKETS, FEEDWATER HANGER Fh H-21-17 96 !E 2.15 2' INSTRUMENTATION BRACKETS, FEEDWATER HANGER FWH-21-18 97 il iI l vi l 1090(1):34 tl \\I ~

I LIST OF FIGURES FIGURE TITLE PAGE NO. 3.1.1 LOOP 21 - AT (FIGURE 1) 101 3.1.2 LOOP 22 - AT (FIGURE 2) 102 3.1.3 LOOP 23 - AT (FIGURE 3) 103 3.1.4 LOOP 23 - AT (FIGURE 4) 104 I 3.3.1 TURBINE FIRST STAGE PRESSURE VS. REACTOR POWER 115 3.3.2 PROGRAMMED REFERENCE TEMPERATURE I VS. FIRST STAGE PRESSURE 116 3.3.3 STEAM GENERATOR PRESURE VS. REACTOR POWER 117 3.4.1 FW FLOW VS. REACTOR POWER LOOP 21 125 3.4.2 FW FLOW VS. REACTOR POWER LOOP 22 126 3.4.3 FW FLOW VS. REACTOR POWER LOOP 23 127 3.4.4 FW FLOW VS. REACTOR POWER LOOP 24 128 3.4.5 FW FLOW VENTURI DIFF. PRESSURE VS. FEED FLOW - LOOP 21 129 I 3.4.6 FW FLOW VENTURI DIFF. PRESSURE VS. FEED FLOW - LOOP 22 130 3.4.7 FW FLOW VENTURI DIFF. PRESSURE VS. FEED FLOW - LOOP 23 131 3.4.8 FW FLOW VENTURI DIFF. PRESSURE VS. FEED FLOW - LOOP 24 132 3.4.9 STEAM RESTRICTOR DIFF. PRESSURE VS. FEED FLOW - LOOP 21 (100% RX POWER) 133 3.4.10 STEAM RESTRICTOR DIFF. PRESSURE VS. FEED FLOW - LOOP 21 134 I 109(D): 35 I

I LIST OF FIGURES FIGURE TITLE PAGE NO. 3.4.11 ' STEAM RESTRICTOR DIFF. PRESSURE VS. FEED PLOW - LOOP 22 135 3.4.12 STEAM RESTRICTOR DIFF. PRESSURE i VS. FEED FLOW - LOOP 22 136 3.4.13 STEAM RESTRICTOR DIFF. PRESSURE VS. FEED FLOW - LOOP 23 137 3.4.14 STEAM RESTRICTOR DIFF. PRESSURE VS. FEED FLOW - LOOP 23 138 3.4.15 STEAM RESTRICTOR DIFF. PRESSURE VS. FEED FLOW - LOOP 24 139 I 3.4.16 STEAM RESTRICTOR DIFF. PRESSURE VS. FEED FLOW - LOOP 24 140 3.4.17 NO. 21 STEAM GENERATOR STEAM / FEED I FLOW AND LEVEL 8/29/81 141 ~ 3.4.18 NO. 21 STEAM GENERATOR STEAM / FEED FLOW AND LEVEL 9/11/81 142 bW ND VEL / /81 143 3.4.20 NO. 23 STEAM GENERATOR STEAM / FEED FLOW AND LEVEL 9/11/81 144 3.4.21 NO. 24 STEAM GENERATOR STEAM / FEED FLOW AND LEVEL 9/11/81 145 l I I I I .m 109 (D) : 36 I

I LIST OF FIGURES FIGURE TITLE PAGE NO. 4.1.1 POWER TILTS VS. CORE POWER 148 4.1.2 POWER TILTS VS. CORE POWER AND AXIAL OFFSET 149 4.1.3 POWER DISTRIBUTION - 200 RTP 150 4.1.4 POWER DISTRIBUTION - 30% RTP 151 4.1. 5 POWER DISTRIBUTION - 100% RTP 152 4.2.1 SALEM NUCLEAR GENERATING STATION, UNIT NO. 2 RCC INCORE DETECTOR THIMBLE AND THERMOCOUPLE LOCATIONS 155 4.2.2 BASE CASE FLUX MAP FOR ID2 EJECTION 156 I 4.2.3 EJECTED ROD FLUX MAP 157 4.2.4 INCORE POWER TILTS 158 4.3.1 SALEM NUCLEAR GENERATING STATION, UNIT NO. 2 RCC INCORE DETECTOR THIMBLE AND THERMOCOUPLE LOCATIONS 161 4.3.2 BASE CASE FLUX MAP FOR DROPPED ROD 162 4.3.3 DROPPED ROD FLUX MAP 163 4.3.4 INCORE POWER TILTS, BASE CASE, DROPPED ROD 164 4.3.5 BASE CASE THERMOCOUPLE MAP 165 4.3.6 DROPPED ROD THERMOCOUPLE MAP 166 4.4.1 SUP 81.8 - DOPPLER POWER COEFFICIENT MEASUREMENTS VS. FSAR CRITERIA 171 4.5.1 SALEM 2, REACTOR ENGINEERING MANUAL 100 % DWR 8/2 2/81, UNIT 2 CHANNELS N-41, N-42, N43, N -4 4 LINEARITY CHECK FOR IN/EX CALIBRATION 177 4.5.2 SALEM 2, REACTOR ENGINEERING MANUAL, 100% PWR 8 /2 2/81 UNIT 2, DETECTOR N-41 NORMALIZED DETECTOR CURRENTS 178 ,I I 1X 109D (1 ) : 37 a

I LIST OF FIGURES FIGURE TITLE PAGE NO. 4.5.3 SALEM 2, REACTOR ENGINEERING MANUAL 100% PWR 8/22/81 UNIT 2, DETECTOR N-42 NORMALIZED DETECTOR CURRENTS 179 4.5.4 SALEM 2, REACTOR ENGINEERING MANUAL 100% PWR 8/2 2/81 UNIT 2, DETECTOR N-43 NORMALIZED DETECTOR CURRENTS 180 I 4.5.5 SALEM 2, REACTOR ENGINEERING MANUAL 100% PWR 8/2 2/81 UNIT 2, DETECTOR N-44 NORMALIZED DETECTOR CURRENTS 181 4.6.1 N43 PLATEAU 10/26/81 99% RTP N43 PLATEAU 11/19/81 91% RTP 184 4.6.2 NIS FULL POWER CURRENT VS. BURNUP 185 I I I I l I x 109D (1 ) : 38 I

I LIST OF TABLES I TABLE TITLE PAGE NO. 2.2.1 TURBINE OVERSPEED TRIP TEST HISTORY 25 2.6.1 ISCl ROD DROP TEST RESULTS 59 2.8.1 STEAM GENERATOR MOISTURE CARRYOVER MEASUREMENT, DATA REVIEW 72 2.12.3.1 RCS CHEMISTRY / STEAM GENERATOR CHEMISTRY 88 3.1.1 DIFFERENTIAL TEMPERATURE VS. POWER LEVEL 100 3.2.1 STATEPOINT DATA

SUMMARY

107 3.2.2 STATEPOINT DATA, DIGITAL VOLTMETER READINGS 108 3.2.3 STATEPOINT DATA, LOCAL READINGS 109 3.2.4 STATEPOINT DATA, NIS AND CONTROL RM. READINGS 110 3.2.5 SECTION 2.6, CALORIMETRIC CALCULATION DATA SHEET 111 3.2.6 STATEPOINT DATA -

SUMMARY

DATA SHEET 112 3.4.1

SUMMARY

OF DATA FOR CALIBRATION OF STEAM AND FEEDWATER FLOW INSTRUMENTATION 123 3.4.2 STEAM FLOW DATA REVIEW 124 l - 4.4.1 POWER AND DOPPLER, COEFFICIENT REVIEW 170 4.5.1 100% POWER (8/22/8:), EXCORE DETECTOR FLUX DIFFERENCE CALIBRATION DATA SHEET 175 4.5.2 100% POWER ( 8/22/ 81), EXCORE DETECTOR FLUX DIFFERENCE CALIBRATION WORKSHEET 176 I I xi 109D (1) : 39 llI

I SECTION

1.0 INTRODUCTION

This report is in addition to the Startup Report submitted on May 1, 1981 which describe the testing from Core Load to the completion of Zero Power Physics Testing including Natural Circu.lation testing. Included in this report is the Power Range Test Program from 10% to 100% power testing. The period covered is from August 29, 1980 through October 13, 1981 with additional comments up to January, 1982. Salem Unit No. 2 is a four loop pressurized water reactor of 3411 mWt rated capacity. The Nuclear Steam Supply System (NSSS) was supplied by Westinghouse Electric Corporation, the Architect Engineer was Public Service Electric and Gas Company and the Constructor w.1s United Engineers and Constructors, Inc. The facility's operating license was issued April 18, 1980. Preparations for core load were completed by May 22, 1980 and core loading commenced on May 23, 1980. Core loading was completed by May 27, 1980. Initial criticality was achieved on' August 2, 1980 and the zero power physics test program was completed by August 12, 1980. Natural circulation tests were begun on August 23, 1980 and were partially completed August 29, 1980 before the Unit was shutdown to repair a leaking Control Rod Drive Mechanism vent. The natural circulation testing had been completed from a testing standpoint but were required to be reperformed for operator training of nine licensed operators as committed to in the license. The Unit entered Mode 5 (<200 F) to repair the leaky CRDM housing vent 109D (1) : 40

I and remained in Mode 5. On April 22, 1981 a heat-up was commenced to enter Mode 2 (547 F, <5% RTP) to complete Na t Circulation Testing in anticipation of receiving the Opers License allowing power asension testing. 1 During the period of time from August 29, 1980 through Apr 1981 the unit remained in Mode 5. Fire Protection System fications were made and Post -TMI design changes incorport as Engineering Design Package and materials arrived on-sit major delaying factor was the completion and trial run of Emergency Plans of PSE&G and the states of New Jersey and The coordinated emergency drill was successfully conductec 8, 1981. In late April, upon review of the work performed on the f: system to meet regulatory requirements, it was determined additional modifications were required. The review, by t: staff, consisted of examining the capability of the unit down from a remote location should a fire occur in the Co o r elsewhere that could af fect the safe operation of the the Control Room. The inspection team concluded that the up control system was adequate to safely shutdown the uni emergency. The team said, however, that some modificatio fire protection system must be made before the Facility F License could be issued. I The modifications involved, in part, improved protection cables needed for the operation of the plant from a remot I location. In the event of a fire that forces the evacuat o f the Control Room, the plant must be able to be operate 109D (1 ) : 41

using alternate locations and controls. Other modifications included upgraded procedures for dealing with a fire emergency emergency and improvement of various fire barriers and automatic s pr in kl e r s. Upon completion of those modifications the full power operating license was granted on May 19, 1981. Figures 1.1 through 1.8 graphically display the power history o f Un it 2 f rom May 1981 through December 1981. Along with the graph is an explanation of the testing at the particular power level and the day the test was performed. Al so listed are the reasons for various trips and delays effecting the startup s ched ul e. Fig ures 1.10 through Fig ure 1.14 shc w the planned .I vs. the actual number of days of testing at each power plateau. The total planned days were 166 whereas the actual days were 186. Several of the larger delays were: 1) the replacing of an intermediate range channel (3 1/2 days) 2) steam flow sensing line modifications (8 days) 3) main turbine generator governor adj ustment (4 days) 4) condenser tube leakage requiring unit shutdown (5 days) 5) outage to modify steam generator separation equipment (15 days) l 6) unplanned reactor trips (10 days) i Following the steam generator outage in September 1981, to modify i j the r.oisture separation equipment, the moisture carryover test (Section 2.8) was reperformed and verified the steam moisture content to be acceptable. The following day Salem Unit 2 was declared commercial, October 13, 1981, com pleting the startup test y 109D (1 ) : 42

I program. Several main feedwater pump trips had occurred between October 1981 and December 1981. A test program was formulated to determine the cause of the believed " low suction pressure" l trips (see Section 2.7 for details). In December 1981 the high steam flow indications, observed prior to the steam generator l modifications., re-occurred. An additional moisture carryover test was conducted in January 1982 (see Sections 2.8 and 3.4 for i details). I I I I .I ' 109D (1) : 43 e

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9- % RTP ,u a 2 -u m ~ = im g G G G.G G G @ @ G G HORKING 21 RUX FD PP BERRING g m) SUP 80.1. T/G DRTR 5 L w-SUP 8B.1, SYNCHRONIZATION TO GRID em I 5 BALANCE MRIN T/G, RX SHUTDOWN A SUP 80.1, T/G 8 HR. RUN g u SUP 81.3, T/G OVERSPEED TEST, UNMT. = RDJUST GOVERNOR HEIGHTS, RE-TEST. UNSRT ~ % ] RDJUST GOVERNOR HEIGHTS RE-TEST, UNSRT gl, = 2 UNUSURL EVENT, 2CV396 NIPPLE FRILURE 9 =>. g2 m y Bii REPAIR 2CV396 VENT LITE y ggI SUP 81.3, T/G MECH. OVERSPEED TEST, SRT. f $"ru;G MODIFY STERM FLOH SENSING LINES EQU w a 2, _E I_ ~ E gz ui g o a b y joN O l Ehm 8G MODIFY STERM FLOW SENSING LINES u @p@_. REPLRCE 23 RUX. FD. PP. CHECK VLVS. P,a CHECK SPEED CONTROL, 23 RUX. FD. PP. N = m $~$ RETURN TO 10% RTP o ( SUP 92.S, ELRCKDUT SUP 92.5, SHUTDOWN OUTSIDE CONT. ROOM 3 E RX TRIP, HI/LO S/G WATER LEVEL W m " L-E RX TRIP, HI/LO S/G HRTER LEVEL Em 2*I Td ggt RETURN TO SB% RTP I t 7 f f f f f f f

5 e o e o m.m o e ee FLUX MRP e SUP 81.4, RUTO S/G LEVEL CONTROL j m SUP 81.8,P0HER COEFFICIENT w 3 SUP 81.5, RUTO ROD CONT: 82.1, LORD SWN 3 A l 30% TESTS COMPLETE, CLERN STRAINERS u REDUCE LORD TO HORK 21BF35, FD PP CK VL = c. ~ N MAIN FD PP TRIP, RX TRIP CONDENSER TUBE LERK - GOING TO = 6 l MODE 5 TO FLUSH = m 2 " '5 Gli STE M GENERRTORS hE% e " Fu STERM GENERRTORS m z 3QC INCRERSING POWER RND CLERNING STRRIlERS n m8EI = RX TRIP, FRILED FD HTR CHANNEL g2E o a hE s_ ,w h C 2hE SUP 81.11, INCORE/EXCORE CRL. 1 S 3G 2 ,$pE SUP 81.12B, STATEPOINT DATR E "_.

• SUP 81.10, STATIC ROD DROP m

,~$ M EUP 81.8. POWER COEFTICID4T g C'. SUP 22.4, RODS DROP - PLANT TRIP SORC RPPROVRL FOR 75% TESTING U CONTROLLED SHUTDOWN, SEC CHENISTRY INCRERSING POWER TO 75% PLRTERU l N l N ru G RX TRIP, RCS FLOW INSTRUMENTATION G ~ _ _ _

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_^ -gt- ,u w. u c ooooo ooeoS in ~== s e a a n PHR TO 70%, CONTINUE S/G FD PP 21 REPRIR ru w E g a u m g REDUCED PWR, HTR DRN PUMP 22 STRNR MRINT esz$m.. [*m 5 21 FD PP REPAIRED + ON LINE, INCR. POWER g g g g*E-PHR TO 95%, HI STERM FLOH ON CH. 21 i 5 19 I BpG-. i , n myl5_. TRIP 9 0555, 22 FD PP, TRIP RGRIN 6 0910 . L. a TRIP G 2004. S/G LO LVL 22 FD PP TRIP ~ 11 8 3(E_. TRIP 9 0714, S/G LO LVL, 24 RCP TRIP 2 9 "o E LD RED. TESTS: 0130: 75-50% OSES: 75-58% e hl@ 1933: 85-75% 2220: 85-50% h,h T. LD RED. TEST; 2037: 85-47% e 23/24/25 HTR BYPRSS FD PP SUCT PRES TEST 9 ~ Ej LD RED. TESTS: 1354: 85-90% 1450: 95-85% N 4 w t.n REDUCE POWER, HI STERM FLOW S/G 21 ru N a l CD J m G l L. 8*T c.m6,g T

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I SECTION 2.0 INTEGRATED TESTING This section deals with testing performed to evaluate overall plant response to rapid load changes and changes in system parameters to evaluate integraded systems response. Included in this section are tests performed by the Chemistry and Ilealth Physics department which were part of the startup program. 2.1 SUP 81. 5 - DYNAMIC AUTOMATIC STEAM DUMP CONTROL .I This test was performed at the 10% power testing plateau with ~ reactor power being varied between 1% and 10% depending on the test requi rem ents. The turbine generator was not on the line at this time. The objectives of the test were to verify the proper operation of both modes (turbine trip and load r ej ec tion) of the T steam dump control system and to avg obtain final settings for steam pressure control mode of the steam dump valves (12 valves). the turbine trip mode of the steam dump control system, To test with the steam dump control system in manual and reactor power at about 1%, T was raised 3 F above the normal no load Tavg gyg 1 o f 547 F. the steam dump system was then placed in automatic was controlled by the and since the turbine was tripped, Tavg turbine trip controller. The steam dump valves opened and Tavg l ( 109D (1 ) : 44 1

I was controlled within a degree of the no load T V^1V** avg Reactor power was then increased to about 6%, at 2%/ minute, by rod withdrawal. The steam dump valves opened as reactor power increased and T was controlled between 3 F and 5 F above avg the no load T,yg value. Reactor power was then decreased and the steam dump valves modulated closed, tracking reactor power. In testing the response of the 1 css of load controller, the steam dump system control was initially placed in manual and reactor power increased to approximately 3%. The turbine was latched and the T input to the loss of load controller was ref disconnected. A test signal was injected in place of Tref signal, which was equivalent to a T f 4 F less than the ref no load of T f 547. The steam dump controller was then ref switched to the T mode of control. T increased above avg avg the test signal by approximatelv 5 F due to controller dead band and then by another 2 F to provide a steam dump valve position equivalent to 3% reactor power. Power was then reduced to 1% and T returned to its no load value. The avg T mp rator was found faulty and replaced and tested. I avg The response of the steam header pressure controller was .I earily verified. The steam dump control was placed in the i 109D (1) : 4 5 i lI l I 1

I steam header pressure control mode with a controller set-point of 1005 psi. Reactor power was increased to approxi-mately 5% and the steam dump valves modulated open maintaining steam generator pressute at 1005 psi (T was increased from avg 547 F to 550 F). The only mechanical difficulty encountered during the tests were the " popping" open of the dump valves instead of modulating open as designed. The flow markings on the valve indicated the valve might have been installed incorrectly, but later investigations indicated the valves were installed c o r r ec tl y. The diaphram operated valve is designed to modulate from the fully closed position to the fully open position using supply air pressure of 9 psi thru 45 psi. Stroking of the valve required 25-35 psi to pop the valve off its seat at which point it would then modulate until closed. Disassembly of the valves for inspection of the intervals indicated no abnormal conditions. The valve vendor was contacted and arrived on site for observation of the valve operation during the 100% testing plateau. New internals were ordered and installed with no change in valve operation. The internals are to be modified and retested until the operation of the valve is acceptable. The. modification consists of adj usting the trim of the internals o f the valve to relieve the off-balancing of the valve disc during the opening stroke which is causing the valve disc to bind on the seating l . 109D (1 ) : 46

surface. Once the correct internals are designed for one valve the other 11 valves will be modified. This modification is also planned for Unit 1 valves. The p; resent operational characteristics of the valves are acceptable for plant operation as determined during plant I trip tests and load swings; but the modulating rather than popping operation of the valves would provide smoother transient - for steam generator pressure and levels, and RCS temperatures and pressures. I I I I I I l 8 l 'I I I l 109D (1 ) : 47

i. g I

2. 2 SUP 81.3 - TUR31NE OVERSPEED TRIP TEST The test of the mechanical turbine overspeed trip device was performed during the 10% power testing program.

The purpose of the test was to verify that the turbine overspeed pro-tection device would operate to trip the turbine in the event of an overspeed condition. Prior to the test, the turbine-generato'r was operating at approximately 10% power for eight hours in order to bring the machine to thermal equilibrium. Af ter the turbine-generator was unloaded and prior to the overspeed~ test, the operability of the overspeed mechanism ~ was checked. At the pedestal end of the turbine, oil was intho'duced up to 48 psig to the overspeed trip mechanism to trip the; mechanism. The manual trip lever moved from the normal to the trip position indicating that the mechanism g was operating freely and had tripped. ,To : allow th'e turbine-generator to actually overspeed, the OVERSPEED PROTECTION ' CONTROLLER had to be removed from s'e rv ic e. This was. easily accomplished by use of a key 8; { c. ..[ s -switch on-the contro1~ console. Using the E-H CONTROLLER, c, turbine speed'was I,ncreased at a rate of 50 rpm /m until the 0 '/ ' UnittrIpped. The m'aximum allowable overspeed is 1998 rpm. During the

three test r un s., the Unit tripped at 1955, 2003 and 2000 rpm.-

It wfs determined that a weight adjustment of + m i N'_ ' i x ~ 109D (1 ) : 48

I the governor was required. Af ter the weight adj ustment the oil-trip test was repeated with a trip oil pressure of 56 psig required. Oil pressure should have decreased following the adj ustment. An inspection of the governor adj ustment mechanism was made and retests of the oil-trip test were inconsistent (62 psig-90 psig) The governor mechanism was disassembled and inspected with no abnormal conditions found. Upon reassembly the oil-trip retest was consistent and the mechanical overspeed test performed with the trip speed still too high. A recheck of the oil-trip pressure came up with inconsistent oil-trip pressure. The governor mechanism was disassembled and new parts installed that were machined to increase the clearances to allow more freedom of movement. Subsequent oil-trip retests and mechanical overspeed tests were successful. Sse Table 2. 2.1 for the sequence of events. I I I I I I 109D (1 ) : 49 I

I TABLE 2.2.1 TURBINE OVERSPEED TRIP TEST HISTORY I Date Event 6/5/81 Oil-trip 48 psig Mechanical trip 1955, 2003, 2000 rpm 6/6/81 Oil-trip after weight adjustment 58, 56, 56 psig Oil-trip after governor inspection 62-90 psig ll 6/7/81 Oil-trip (after governor disassembly and cleaning) i m 58, 58, 56 psig 6/8/81 Mechanical trip - 2000 rpm 6/9/81 Replacing governor internals / machining J

g 6/11/81 Oil-trip 24, 22, 21 psig

!E Mechanical trip 1836, 1841, 1840 rpm I l !I

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I 2.3 SUP 82. 6 - LOSS OF OFF-SITE POWER This startup procedure was completed during the 10% testing plateau. The purpose of the test was to demonstrate that the emergency power system was capable of maintaining the plant in a safe condition by carrying the required loads for at least thirty minutes following a plant trip caused by a total lo ss o f o f f-si te po we r. I With the turbine generator on the line at minimum load (10% reactor power) and with a normal electrical lineup, the black-out was initiated by opening the 13kV infeed breakers for 21 and 22 station power transformers followed closely by the operator opening the generator output breakers. All operations were carried out from the control console. I All systems, equipment and indicators operated properly. The three diesel generators picked up their respective blackout loads and ran for the required thirty minutes. No problems were encountered during the test. Fig ures 2. 3.1 thru 2. 3. 9 indicate plant trends fo r pressure, levels and temperatures of the RCS and steam generators during the transient using Plant Computer data and Control Console recorder strip charts. I I I I 109D (1 ) : 51 I

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I 2.4 SUP 82.5 - SHUTDOWN FROM OUTSIDE OF THE CONTROL ROOM This was the last test performed at the 10% testing plateau. The purpose of this procedure was to verify that the plant could be shutdown from outside the Control Room and be I maintained at hot standby for an hour utilizing the minimum shift crew. Limits on various parameters (pressurizer level, pressure, T,yg, steam generator levels) were included in the acceptance criteria. All control systems were kept in automatic and the Control Room was not evacuated for the test. The procedure was modified to incorporate the requirements of Amendment 6 to the Operating License based on the results of a fire protection review. The additional requirements included: 1) local start of a diesel generator using alternative control power source 2) local operation of a 4kV breaker .I 3) local start of the containment fan cooler unit. I 4) local operation'of a motor operated and an air operated valve 5) local control of charging flow l This portion of the testing was performed while the plant was being maintained in HOT STANDBY at the remote control station. l The plant was operating at 10% RTP with the Control Room lI manned by the regular shif t personnel (2 NCO's). The minimum ! 1090(1):52 !I !I

I shif t crew was ccmprised of the following: SRO - Senior Reactor Operator - 1 'NCO - Nuclear Control Operator - 2 EO/UO Equipment / Utility Operator - 3 STA - Shif t Technical Advisor - 1 Electrician - 1 The following stations were designated: (1) Unit 1 Control Room SRO (1 ), STA (1) Electrician (1) (2) Hot Shutdown Panel (213) NCO (1 ) (3) Reactor Trip Switchgear NCO (1 ) (4) Main Feedpump Local Control Panel EO (1 ) I i (5) Auxiliary Feedwater Pump Panels EO (1) (6) Main Turbine Turning GEAR UO (1 ) The Shift Supervisor of Unit 2 simulated the evacuation of Unit 2 Control Room and established a Control Center in Unit 1 Control Room. From the center the shutdown and control of the plant in HOT STANDBY was maintained thru communications to the personnel at remote stations. The minimum shif t crew was assigned their positions at this point. The NCO tripped the plant at the Reactor Trip Switchgear and de-energized the Rod Drive MG sets to insure that an ATWS (anticipated transient without scram) event would not occur and that all rods would drop to the bottom of the core. The EO and UO in the turbine building verified the 500 kV I ' 109D (1 ) : 53 l l

breakers and field breakers were open and the group buses had transferred from the Auxiliary Power Transformer to the Station Power Transformer. They also verified that the main turbine generator and main feedwater pumps had tripped, and placed them on their turning gears when they coasted to a stop. The NCO and EO at the Hot Shutdown Panel (213) verified the following: (1) Pressurizer level controlling automatically at 22% 1 5%. (2) Pressurizer pressure controlling automatically 2235 psig 1 50 psig (3) Steam generator pressure 1000 psig i 25 psig and level (wide range) 58% - 69% At this point (75 minutes from reactor trip) a one hour hold period was commenced to demonstrate the ability to maintain the plant in a HOT STANDBY condition f rom the HOT SHUTDOWN PANEL. The NCO and EO at the HOT SHUTDOWN PANEL manually opened and closed the auxiliary feedwater pump discharge valves to maintain steam generator levels as indicated at the HOT SHUTDOWN PANEL (the auxiliary feedwater pumps and associated valves are located next to this panel) within the wide range indication of 58% - 69%. Following the one hour hold period, the second phase of this test started while the plant was being remotely maintained in HOT STANDBY. Using the appropriate sections from the Fire Hazards Analysis - Emergency Equipment Operation the following operations 109D (1) : 54

I were demonstrated as directed by the Unit 2 Shift Supervisor: (1) Local start of #24 Fan Coil Unit (2) Local start of #24 Service Water Pump (3) Local operation of 22SW17 (header isolation) (4) Local operation of 2CV55 (control charging) (5) Local starting of a Diesel Generator These operations were performed by the Shift Electrician who performed the control circuit modifications and a NCO who operated the equipment. All phases of this test were demonstrated successfully. The following graphs (Figure 2.4.1-2.4.11) indicate plant trends for pressures, levels and temperatures of the RCS and steam generators during the transient and stabilization period using Plant Computer data and Control Console recorder strip charts. I . 109D (1) : 55

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2. 5 SUP S2.1 - LOAD SWING TESTS I

3 'The load swing tests were a series of integrated plant response I tests performed to verify that the plant was capable of auto-matically accepting a 10% step load change from 30%, 75% and 100% po we r. The load changes were initiated, using the turbine Electric Hydraulic control system, at a rate of 200% per minute. Each test consisted of two parts: a 10% load decrease fo llo wed, a f.ter equilibrium conditions had been reached, by a 10% load increase. The ' load swing was evaluated based on the following criteria : (1) - The reactor and/or turbine did not trip (2) Sa fety inj ection was not initiated '(3) Neither steam line relief valve or safety valve lifted (4) Neither pressurizer relief valve or safety valve lifted ~' s (5) No operator action required to restore plant conditions to steady state '(6) Plant variables 'such as T,y feedwater flow, steam flow, etc. should not incur sustained I oscillations or large variations. 1 (7) Nuclear po wer overshoot less than 3 % fo r the load decrease. s The initial load-swing at 30% po we r wa s to 13%. The overshoot wa s d ue to. setting the turbine load reference too low. Automatic steam generator level control cannot control at less than 15% RTP so operator action was required to s control levels in the steam generators. The up po we r swing . 109D (1 ) : 56 s____

I to 30% RTP had acceptable results. All other parameters during the 30% swings fell within the acceptable range. Testing.at 7 5% and 100% had similar results. The results from the 100% RTP swings are depicted in Fig ures 2. 5.1 thru 2. 5. 4. 1 i !I i i !I f I I

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!I I i 109D (1 ) : 57 I

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2.6 SUP 82.4 - RODS DROP AND PLANT TRIP This test was performed at 50% power. The purpose of the test was to demonstrate the operation of the negative rate trip circuitry. Two rods were dropped from the rod group most difficult to detect by the excore detectors due to low worth and/or core location. In addition, it was the function of the test to review plant response and control systems behavior to a trip from an intermediate power level prior to the plant trip test from 100% power. The two rods chosen were located in core positions B-4 and D-14. The acceptance criteria specified that a reactor trip must occur as a result of two of the four negative rate bistables tripping. (see figure 2.6.1 for the core location of the rods vs. the excore detectors). The rods selected were dropped simultaneously from the Rod Control System DC Hold Power Cabinet. The negative rate bistables for N42 and N13 tripped simultaneously (+.01 seconds) followed by N41 and N44 negative rate bistables .5 seconds later. The N41 and N44 bistables tripped following the reactor trip from the N42 and 43 bistables at a point where the control rods were dropped approximately 50% into the core. Also measured during the reactor trip was the control rod drop time of IScl (core location E3) for comparison with the drop time at zero power. This rod was also monitored during the 100% trig per SUP 82.9, 109D (1) : 58

i GENERATOR TRIP. See Table 2. 6.1 fo r a summary of the results. 1 The rod drop time was faster as measured during the reactor

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trip f rom power operation compared. to zero power operation. Following the trip the plant was stabilized at the no load Tavg of 547 F successfully. I

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TABLE 2.6.1 ISCl ROD DROP TEST RESULTS Initiations of Event Initiations of Event RCS Conditions To Da shpo t En tr y to Bo ttom o f Da shpo t 1 0 547 F, 4 RCP's 1.35 (Seconds) 1.88 0 % Po we r 563 F, 4 RCP's 1.26 1.82 50 % Po we r o 570 F, 4 RCP's 1.30 1.85 100 % Po we r I I e O I ll - Se - 109D (1 ) : 60 1

Figura 2.6.1 i SALEM NUCLEAR GENERATING STATION l( UNIT NO. 2 RCC INCORE DETECTOR THIMBLE AND THERMOCOUPLE LOCA TIONS S/G 22 Cold Leg S/G 21 Cold Lcq S/G 22 Hot Lcq S/G 21 Hot Leg I \\ 270* s s i 2 3 4 5 6 7 8 9 10 11 12 13 14 15 + \\ TI T}4 T$ y y Tf 'SAI}6 T3 C 2 1 262 IC 182 ISA2 N SI 2 82 IS22 ISC2 W m \\ / ISAI IDI 202 10 2 2 2 T41 X T7 T8 T9 TIO \\@f g y E ISci 1502 0 T44 MS Tot T12 f 8 C B E e 'm. IBt 2CI 2At 2C2 203 Tt3 r46 Ta 7 Tag Tis i (SR31 a ISet. 25g3 Tt6 TIf g Mi Tre M9 TS 'h a A C* ggn y p. C ICI 20t IAI 205 IA2 203 IC3 5 CR35: 2SB' ISe3 R'S T21 T22 TS3 T54 T23 IE3 l g g { 2 81 2C4 2A _ 2C3 T24 TSS b TB6 T26 T57 l l/y I g g g 1504 ISC3 T56 T27 T59 T29 \\ g l 2SAa 10 4 204' 103 ISA 3 s Oh 0 f l Of 8 0 \\ N ISC4 ISE4 2SO4 ISD3 T3s T63 T32 IS 4 184 IC4 224 2SA3 T&4 y y TQ T65 90* N / \\ S/G 24 Hot Leg S/G 23 Hot Leg ) N k S/G 24 Cold Leg S/G 23 Cold Lcq u (. 4 THERMOCCUPLES North A= FLUX OETECTOR PATHS CONTROL R005 F

I 2.7 SUP 82.2 - LARGE REDUCTION TESTS The LARGE LOAD REDUCTION TESTS were conducted to verify the capability of the primary and secondary systems to automatically accept a 50% load reduction from 75% and 100 % of f ull po we r. The tests were further used to evaluate the interaction between I control systems and to determine if system setpoints should be changed to improve transient r e s po r.s e. 75% POWER I The first tests were conducted at the reactor power level of 75%. The load changes were initated by using the Electric Hydraulic system at a rate of change of 200% per minute. I The follcwing list shows the range of selected parameter move-ments during the power reduction: 1. Feod Water Temperature 401 F 335 F 2. Steam Header Pressure 792 psi 878 psi 3. Feed Flow 69?':vg) - 26% (avg) 4. Steam Flo w 69% ( vg) - 26% (avg) 5. Steam Generator Level 44% - 24% - 44% 6. Control Bank D 228 steps - 122 steps 7. Av erag e Loop AT 46.5 F 22 F 8. Nuclea r Po we r Fl ux 71% 32% 9. Pressurize r Level 39% 29% I 10. Pressurizer Pressure 2260 psi - 2175 psi - 2300 psi 2250 psi I 11. Auctioneered T,yg 563 F - 570 F - 554 F 12. Plant Load ( MW-G r o ss) 765 megawatts - 285 megawatts 109D (1 ) : 61 ~ ~

I The following acceptance criteria items were met: 1. The reactor and turbine did not trip. 2. Sa fety inj ection was not initiated. 3. Pressurizer safety valves did not lift. 4. Steam generator safety valves did not lift. I During the transient the steam dump valves operated (condenser d um ps) to restore T to its program value. The dump valves avg did not open until there was a maximum demand signal. They are designed to modulate open based on an increasing demand signal but instead they " pop" open when they receive a max imum demand signal. (See SUP 81. 5, Dynamic Automatic Steam Dump Control). This type of operation causes the steam generator levels to drop to a lower level than they normally would due to the shrink effect in the steam generators caused by the rapid increase in steam generator pressure. Once the cause of the popping operation is corrected and the valves modulate with demand, the steam generator pressure will peak at a lesser pressure assisting in reducing the amount that the steam generator levels are lowered to before they are restored to normal. The present operation of the steam dump valves is acceptable but is being r ev ie wed. 100% POWER The LARGE LOAD REDUCTION f rom 100% power was performed prior to the plant trip test. The load change was initiated at a I 109D (1 ) : 62 I I

I E rate of 200% per minute using the Electric Hydraulic system. The following acceptance criteria items were met: 1. The reactor and turbine did not trip. 2. Safety inj ection was not initiated. 3. Pressurizer safety valves did not lift. The following list shows the range of selected parameter move-ment during the power reduction. 1. Feed Water Temperature 432 F 380 F 2. Steam Header Pressure 774 psi 984 psi - 852 ps 3. Feed Flow 99 % (avg) - 48% (avg) 46% (avg) 4. Steam Flow 98 % (avg) 5. Steam Generator Level 44% - 49% - 28% 6. Control Bank D 228 steps - 141 steps 36.5 F 7. Av e rag e Ic op AT 62.5 F I 56% 8. Nuclear Power Flux 100% 9. Pressurizer Level 50% - 34% - 59% - 34% 10. Pressurizer Pressure 2235 psi - 2322 psi - 2108 p 2335 psi 11. Auctioneered T 571 F - 580 F - 559 F avg I 12. Plant Io ad ( MW-G r o ss) 1140 megawatts - 590 megawat During the transient, the steam dump valves operated at a lower demand signal providing a smoother transient for steam generator level and pressure than was observed during the 75% testing plateau. I 109D (1 ) : 63

I Prior to the commencing the load reduction the condensate polishers were bypassed providing an additional 75 psi at the feedwater pump suction. This was done based on observation during the 10% load swing from 100-90-100%. During the 10% load swing it was noted that the MSR Coil Drain Tanks dropped in level causing the Heater Drain Pumps to go in a recirculation mode reducing the feed' water pump suction pressure by approximately 60 psi. The cause of this transient is unknown at this time. To prevent reactor trip on loss of a feedwater pump on low suction pressure the polishers were bypassed to provide additional margin at the f eedwater pump suction. During the 50% load reduction the feedwater pump suction decreased by approximately 90 psi l again due to the loss of the Heater Drain Pump flow. This transient is being reviewed to determine its cause. 1 The overall transient was acceptable and is graphically l d isplayed in Fig ures 2. 7.1 and 2. 7. 2. I Following several feedwater pump trips from 100% RTP, due to a loss of feedwater pump suction pressure, the feed and [ condensate system was instrumented for continuous monitoring to determine the cause of the rapid reduction in suction pressure. Following a feedwater pump trip, the review of the data indicated the cause to be compounded by a rapid load reduction to restore suction pressure. Several load reductions (7) were made and reviewed to further determine the cause and effects. E 109D (1 ) : 64 r

I During a load reduction rondition the H.P. turbine extraction pressure decreases accordingly leaving the saturated liquid of the heater drain system in an unstable condition (subject to flashing). The instability results in decay of heater drain tank level which calls for the heater drain pump discharge valves to close and therefore heater drain flow (1/3 total feedpump demand suppled to feedpump) is reduced. The loss of flow supplied from heater drain system is pro-portionally more severe with greater load reduction resulting in a corresponding and instantaneous loss of feed pumps suction pressure. Based on the load reduction tests, it has been determined that with the condensate polisher in service the system can correct for large reduction effects if the initial power level is below 85%. When operating at power levels in excess of 85% the following operation precautions are being observed to eleviate the possibility of a feedpump trip: 1) When operating above 85% power open bypass (2CN-47) around 23, 24 & 25 heaters, (gain of 30 psi on feed-water pump suction). 2) Heater Drain Pump recirculation (21HD17, 22HD17, 23HD17) valves are to be failed open to add stability to heater drain system. 3) The feedpump suction pressure alarm increased to 300 psig from 270 psig for early warning (feedpump trip at 215 psig). 4) If an alarm occurs and a rapid load reduction is necessary (provided their is no chem stry problem I present) the condensate polisher bypa s can be opened to recover feedpump suction pressure end the operator can then successfully complete a large load reduction (gain of 65 psi on feed pump suction). E - 6s - g 109D (1) : 65

I 5) If an alarm occurs and a sudden load reduction is not necessary, the load should be reduced in 1-10% increments until suction pressure is restored. The following design charges are being revie wed to provide stability to the feed pump suction during steady state operation and transients. I 1) Increasing the capability of the existing condensate pumps for greater head at the same flow (impeller change). 2) Diverting a percentage of condensate flow after the No. 2 feedwater heater to a spray sparger in the heater drain tanks. 3) The possibility of new condensate pumps, and an additional condensate pump or condensate polisher booster pumps. 4) Commonize the heater drain pump suctions so that one pump could be used as a standby pump. This change is I also expected to stabilize the heater drain pump flow at steady state and transient conditions. I ~I I !I ,il .I ,I I I 109D (1 ) : 66 I l

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4== I 2.8 SUP 82.7 - STEAM GENERATOR MOISTURE CARRY OVER MEASUREMENT The steam generator moisture carryover measurement was orignally scheduled to be performed at three power levels; 75, 90 and 100%. l l Based on previous experience, Westinghouse ( the turbine gener-ator and NSSS supplier) recommended that we perform this test only at 100% RTP under various conditions. The variations included altering T steam generator levels, and reactor power to determine their effects on moisture carryover. The determination was made to conduct the test as recommended. The test procedure requires the use of a radioactive tracer, Sodium 24, in the form of an aqueous solution of sodium nitrate. The traces had an activity of 1.2 curies at the time of its arrival on-site af ter being activated at the University of Missouri Test Reactor. The tracer was inj ected into the feed-water system using the chemical addition system. The phosphate feed pump (5 gpn) took suction from a 50 gallon drum to which the source was added (located on 100' elevation of the turbine building) and inj ected it into the main feedwater line of each steam generator j ust upstream of the main feedwater regulating valve. The inj ection lines were valved in and out to equalize the quantity of the source in each steam generator ( 3 minutes for each steam generator). I I 109D (1 ) : 67 I I i

I Three sets of samples were taken at each test condition. Each set consisted of a blowdown sample and a steam sample from each steam generator and a common feedwater sample for a total of 27 samples per test condition. The results were based on analysis of the blowdown and feedwater samples. The main steam samples were analyzed, but the results are used as a general indicator for comparison of each steam generator moisture removal performance. During the performance of the first test, on 8 /2 8/81, two vials containing the source were received and used for inj ection into the feedwa ter system. This resulted in uneven distribution of the source from one steam generator to the next. When the test was re-run on 9/10/81 and 10/12/81 four vials were used each containing equal strength. Each vial was added to the 50 gallon drum separately and fully inj ected into one steam generator, the drum flushed to the generator and then a second generator lined up. The process repeated for each steam generator. This method provided excellent distribution of the source with less than 5% deviation in activity levels between any tw'o steam generators. I The perfo rmance of the first moisture carryover test was conducted o n Aug us t 28, 1981 a t 100% RTP and 44% steam generator levels, and at 100% RTP and 40% steam generator levels. With normal levels (44%) in the steam generators the average carryover was.33%. ~ j With levels reduced to 40% the average carryover was.20%. The tI 109D (1 ) : 68 'I

I steam samples indicated that #21 steam generator moisture carryover was significantly higher than the other three steam generators. It was also noted that #21 steam flow signals were 10-20% higher than the other steam generators (see SUP 81.7, calibration of stream flow and feedwater flow instrumentation). A retest on September 10, 1981 had similar results with #21 steam generator having the greatest carryover. Even with reduced levels, the carryover on #21 steam generator was still greater than 1.0%. The determination was made to shutdown and inspect the internals of all four steam generators. The inspection did not uncover any faults. The second stage separation equipment was modified to provide additional moisture drainage paths for each steam generator to reduce any carryover. (See Figure 2.8.1) A retest performed on October 12, 1981 indicated the average carryover was.13% with normal steam generator levels (44%). The carryover measured for #21 steam generator had been reduced to.17%. The acceptance criteria was less than.25% moisture carryover and was easily met. It was also noted that No.21 Steam Generator steam flow signals were reduced in magnitude by 10-20%. See Table 2.8.1 for a review of the carryover measurements. Note: An additional carryover test was performed on January 22, 1982 due to reoccurrence of high steam flows in December, 1981 for no apparent reason. The results from that test were similar to the results in October, 1981. See Section 3.4 for explanation. I I 109D (1) : 69 I

M M M M M M M N m M M M M M M STEAM GENERA'IDR MOISTURE CARRYOVER MEASUREMENT DATA REVIEW Power SG SG T Feed with Level Levels Pressure ag Ioad Temp Cahybr carrhI5682 (%) Ph8Nure Notes Dates (%) (%) (PSIA) (UF) (MWC) (OF) (%) 21 22 23 24 (PSIA) Before 8-23-81 99.7 44 802 572.2 1110 431 .342 3.4 MOD's 99.2 40 808 572.6 1140 431 .200 3.3 9-11-81 98.5 44 813 572.4 1134 432 .280 1.49 .69 .28 .02 2.3 Retest for 98.9 36 809 572.3 1140 432 .180 1.27 .44 .13 .01 2.3 Verification of 91.8 44 813 569.9 1053 426 < Min. Detectable Activity 2.2 Carryover 96.7 44 812 571.4 1110 430 .080 2.4 After 10-12-81 100.1 36 791 570.6 1187 432 .125 .16 .14 .12 .01 1.7 SG 99.67 44 792 570.8 1180 432 .133 .15 .15 .11 .01 1.7 MOD's 94.33 44 792 567.6 1110 430 .05 1.7 b a 7 Er P 109D(1):70 m e

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I 2.9 SUP 82.8 - NSSS ACCEPTANCE TEST This was one of the last tests performed during the startup of Unit 2. The test had two purposes: first, to demonstrate the reliability of the NSSS by maintaining the plant at rated out-put of 3411 MW (+0%, -5%) for 100 hours without a load red uc-tion or plant trip resulting from an NSSS malfunction and second, to measure the gross electrical output and the turbine heat rate to verify the capability of the Un i t. I The 100 hour run was attempted several times during the 100% testing plateau. Each time the unit was forced to red uc e power to clean condensate, heater drain or feedwater pump .7 trainers. The maximum run at greater than 95% po we r wa s 69 hours before a load reduction was required. Total accumulated time at greater than 95% power was 205 hours. Based on the fact that the load reductions were not NSSS related the 100

• I hour run was accepted on an accumulated basis.

Since this run, Unit 2 has accumulated better than 100 hours of continuous operation at greater than 95% po we r. I The second part of the NSSS acceptance test was the measurement of the gross electrical output and the turbine heat rate. No rmal plant instrumentation was used as a backup to a primary data logger which was fed from test instrumentation installed for the test run. The data logger received a data scan every 2 minutes whereas the plant instrumentation was read every I 109D (1 ) : 72 I

30 minutes. Data was accumulated over a 4 hour period with reactor power and turbine power held steady at 100% RTP. The results were corrected to design conditions and are listed Co r rected t

• Date Goss Electrical Output Heat Rate 8/27/81 1161.4 - (MW) 10,059 (BTU /KWH) 10/15/81 1172.4 9,963 10/21/81 1173.9 9,950 I
• The test run on 8/27/81 had 5 out of 6 circulating water pump operating.

To reduce the errors involved in correcting for backpressure, data was taken with 6 circulating water pump on 10/15 and 10/21/81. The calorimetric results using plant vs. test instrumentation -indicated less than a.5% difference for all three test runs. I I I I I 109D (1 ) : 73 I

I 2.10 SUP 82.9 - GENERATOR TRIP FROM 100% POWER This was the last test performed during the startup of Salem 2. The test had three purposes : first, to verify the capacity of the primary and secondary plant systems to automatically accept a generator trip from 100% power and to bring the plant to a stable condition following the trip; second, to verify that the turbine overspeed mechanism operates to limit turbine speed in an actual overspeed condition; and finally, to deter-mine the overall response time of the reactor coolant hot leg resistance temperature detectors (RTD). The RTD response time was defined as the time interval between the point where the neutron flux had decreased by 50% of its initial value to the point where the hot leg temperature had decreased by 33-1/3% of its initial loop AT value. In addition the rod drop time of a selected rod was monitored during the reactor trip. I l The reactor was operating at 98% power when the trip was initiated at 0924 hrs. on September 2, 1981. The trip was initiated by the Control Room Operator simultaneously opening the main generator output breakers to the 500 KV bus (bus sections 1-9 and 9-10) to trip the generator. The main turbine tripped on overspeed at its trip setting of 183 5 R PM in less than 1 second causing a reactor trip. The main steam stop valves (21-2 4M S167 ) were closed immediately a f ter the reactor trip to contain as much heat as possible in the RCS to avoid delays in restoring T required fo r avg SUP 90.9, BORON MIXING AND COOLDOWN TEST. This caused the 109D (1 ) : 74 I

I steam generator pressure to increase higher than normally e x pec ted. The atmospheric relief valves (21-24MS10) operated as designed to maintain steam generator pressure at approximately 1000 psig. On No. 23 Steam Generator the setpoint of the first safety valve was reached (2 3M S 15, 1070 psig) approximately 30 seconds following the trip. The actual pressure reached was 1050 psig indicating the safety valve is set on the " light side". The valve was reset and did not lif t again. I The remainder of the test went smoothly. Listed below are some of the parameters that were monitored and how they varied during the test: I Pressurizer level ranged from 46% at the time of the trip, to a high of 46% and a low of 23%. Pressurizer pressure ranged from 2240 psi prior to the test, to a high of 2240 psi and a low of 2010 psi. When the generator output breakers were opened, turbine speed increased 90 rpm to 1890 rpm. l Steam generator levels decreased from 44' to 0 % indicated level. t l T f 597 F at the start of the test to 547 F. H T f 570 F at the start of the transient to 547 F. avg Maximum steam dump demand was generated 5 seconds af ter the generator trip. l 109D (1 ) : 75 I l

J The steam adunp valves started opening six seconds af ter the g enerator trip. The RTD response time was measured to be 5.5 seconds versus a maximum of 6. 3 seconds. The rod drop time was measured as 1.30 seconds from the fully withdrawn position at the time of decay of stationary gripper coil voltage to dashpot _ entry versus the Technical Specification maximum of 2. 2 seconds. Th e rod measured was 1SCl. I The transient response of selected parameters is graphically d isplayed in Fig ur es 2.10.1. I O !I < I 109D (1 ) : 76 .I

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I 2.11 SUP 90.9 - BORON MIXING AND COOLDOWN The objectives of this tests were: (1) to borate the RCS and verify boron mixing while in the natural circulation mode. (2) to demonstrate the capability to cooldown the RCS while in natural circulation. This test was originally scheduled to be performed during the initial natural circulation test program af ter low power physics testing. During that time the reactor was maintained critical at approximately 3% RTP af ter the RCP's were secured. To perform a more realistic test the test was delayed until the Generator Trip Test (Section 2.10) when the reactor core had built-in decay heat following 1310 MWD /MTU of core burnup and 200 hours at greater than 95% RTP accumulated (see fig ures 1.1 thru 1. 5 f o r reacto r power histo ry prio r to the plant l t r i p). The Ge ne r a to r Tr ip Te st wa s initiated on 9/2/81 at 0924 (see Section 2.10) and caused an immediate turbine trip and reactor trip. The plant was stabilized at a T f 547 F. avg The pressurizer and RCS were sampled to obtain a baseline boron concentration (960 ppm). At 10 5 6 h r s., the RCP's were tripped, t im e " O" on figure 2.11.1. T and Delta T stabilized af ter 15 minutes. T increased to avg avg 558 F and delta T to approx. 18 F. Auxiliary spray was initiated to maintain pressurizer pressure at 2235 psig (charging isolated 109D (2 ) : 01

j and reinstated after 2 minutes). From this point on, auxiliary spray was used to control pressurizer pressure since normal spray is not effective without the driving head of the RCPs. Starting at 1116 hrs. a boration of the RCS at 5 gpm was commenced to increase the RCS boron concentration by 100 ppm, from 960 ppm to 1060 ppm. By 1226 hrs.,367 gallons of boric acid had been added to the RCS, the boron concentration, as measured in loop 21 and 23 hot legs, was 1031 ppm. At 1410 hrs. the RCS samples indicated the corcentration had stabilized at 1090 ppm. Using the auxiliary spray flow, the pressurizer boron concentration was increased to equal the RCS boron concentration. As indicated in figure 2.11.1, loop 23 T and Delta T indicated a sharp increase in temperatur-ayg This was due to diverting all charging flow to the pressurizer to equalize the RCS and pressurizer boron concentration. The increase in flow to the pressurizer through the auxiliary spray line caused an outsurge from the pressurizer through the surge line. The hotter water was sensed by loop 23 hot leg RTD. The second phase of this test was to verify the ability to cooldown the RCS while in natural circulation. Cooldown was commenced at 1600 hrs. using the steam generator atmospheric relief valves (MS-10fs) starting with an average T of 555 F avg The cooldown rate was limited to less than 25 F per hour with an average cooldown rate of 19 F per hour. The cooldown 109 D (2) : 02 I I

was secured four (4) hours later at which time the average coolant temperatEce was 480 F. The only difficulty encountered during the cooldown was the controlling of the MS-10s to maintain the steam pressure difference between the steam generators to less than 100 psi to avoid a safety injection signal. As can be seen in figure 2.11.2, between hours 2 and 3, the cooldown rate increased for a period of 15 minutes at . I greater than 25 F per hour. Charging was increased to maintain pressurizer level greater than 20% indicated level. The cooldown was temporarily secured until parameters stabilized and again initiated after 30 minutes of stabi-lization. During the first hour, pressurizer level and pressure increased due to manual control of pressurizer heaters and charging. Pressurizer pressure was allowed to slowly decrease during the cooldown to maintain the pressure / temperature limitations. I 109 D ( 2) : 0 3 I

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i t [ y ~ g, 1 :: .y g Q., I ,!~ ' - ~ ~ s---- y. y. i t-A a e i a __n I ,D 7 D 8 O ~ q g c; m x v. I 2.12 RADIATION SHIELDING EVALUATION, EFFLUENT MONITORING, I CHEMISTRY AND RADIOCHEMISTRY TESTS I 2.12.1 SUP 81.13 - RADIATION MONITORING AND SHIELDING EVAL-UATION The objectives of the shielding test were threefold: first, to obtain baseline radiation level data at 0%, 30%, 75% and 100% reactor power by measuring radia-tion levels at locations throughout the plant; second, to detect and identify localized high radiation levels and streaming to protect personnel f rom overexposure during plant power escalation and power operation; and finally, to obtain radiation data necessary to correct or reduce localized high radiation levels. I, At each power level, radiation levels were measured at 211 points throughout the plant. In all cases, the radiation levels were within the design limits. No hot spots or indications of streaming were found. At the present time in the shielding evaluation, it is anticipated that no additional shielding will be required. I 2.12.2 SUP 81.14 - EFFLUENT MONITORING SYSTEMS The purpose of this procedure was to verify the cali-bration of the ef fluent monitors by laboratory analysis o f radioactive waste samples. These tests were to be performed as early in the power escalation as possible, I 109D (3 ) : 04 I

I and were to be repeated after operation at 30%, 50%, 7 5 % and 100 % po we r. The tests were performed on the following ef fluent monitoring systems: Containment Sam pl ing System: Channels 2-RilA (Pa r tic ula te) 2-R12A (Noble Gas) 2-12B (Iodine) Plant Vent Sampling & Monitoring: Channels 2-R16 (Bypass Activity) 2-R41A (Pa r tic ula te) 2-R41B (Iodine) Liquid Waste Monitoring Channel 2-R18 (Gross Common Activity) To properly correlate the channel reading to the lab analysis, a minimum upscale reading was required. Once the minimum criteria was met, the actual response of the monitor was compared to the calculated response expected from radio-analysis in the laboratory. The acceptance criteria was that they agree within a factor o f +2 to -0. 5. All channels tested which had the I minimum upsale reading fell within the acceptance criteria. 2.12.3 SUP 81.15 - CHEMISTRY AND RADIOCHEMISTRY TESTS The purpose of this test was to verify the water chemistry requirements of the RCS and the radio-109D (2 ) : 05

chemistry requirements as set forth by Westinghouse can be maintained within the specified lim its. The g ability to control the water chemistry was demonstrated at lo w po we r, 30 %, 50%, 75% and 100% RTP. E l Table 2.12.3.1 lists the results of those measurements along with the specified liraits. All parameters i l monitored were maintained within their specified limits. I L EI i m P u L_ [ E L F L ~ H 109D (2 ) : 06 I

I TABLE 2.12.13.1 I RCS CHD4ISTRY I PARAMETER LNIT POWm EVEL(%) Acceptable <5 30 50 75 100 Value PH 6.31 6.66 6.59

6. 53 6.58

4. 2 to 10. 5 Chloride ppu

<0.05 <0.05 <0. 05 <0. 05 <0. 05 1 0.15 Flouride ppn <0. 014 <0.014 <0.014 <0; 014 <0.014 f 0.15 Lithiun ppn 0.78 1.8 1.84 1,71 1.61

0. 7 to 2. 2 Dissolve Oxwen ppn

<0.005 <0.005 <0.005 <0.005 <0.05 f 0.10 Gross Beta-Gamma mi/ml 3. 92E-5 2.99E-1 3.59E-1 3.98E-1 5.49E-1 N/A Dose EQuil. I-133 uci/gm 0.00 0.00

4. 93E-4 0.0

4. 99E-4 f 1.0 I

STEAM GENERA'IOR CHEMISTRY I E PARAMETER (NIT POWm GVEL(%) V:ceptable E <5 30 50 75 100 Value Gross Beta-Gamma uci/ml 2.01E-7

1. 36E-7 9.70E-8

1. 01E-7

1. 35E-7

<0.10 (121) I Gross Beta-Gamma uci/ml 1.93E-7

1. 36E-7 9.70E-8

1. 01E-7

1. 35E-7

<0.10 (122) Gross Beta-Gamma mi/ml

2. 08E-7

1. 36E-7 9.70E-8 1.01-7

1. 35E-7

<0.10 I (23) Gross Beta-Gamma uci/ml

7. 24E-7

1. 36E-7

9. 70E-8 1.13E-7

1. 35E-7

<o.10 (#24) 109D (2): 07 E

l 2.13 SUP 81.4 - AUTOMATIC STEAM GENERATOR LEVEL CONTROL l The obj ectives of the test procedure were the following: (1) To verify the stability of the AUTO S/G 1evel control system following simulated transients at low power conditions and adj ust controller set points as required to achieve the required system response. (2) To verify the proper operation of the variable speed feature of the feedwater pumps and adj ust controller setpoints to achieve the required results. The intent of this test was to verify the automatic level control prior to placing the steam generator level controller in automatic. During normal power operation the steam generators were placed in automatic level control at 15% RTP. During the power ascension to 30% RTP the level controls were placed in automatic to give the control room operators more flexibility, and to prevent unplanned reactor trips due to high/ low steam generator levels. While at 30% RTP each steam generator level controller was tested ind iv id ually. The level controller for the steam generator to be tested was placed in manual control. The level error signal induced called for increased feedwater flow. The time response of the system and the degree of level overshoot were monitored and controller adjustment made until an acceptable response was obtained (within 5 minutes for response and less than 5% overshoot). Each steam generator level controller was adjusted in this manner. The initial controller settings were derived from the PLS (P r ec aut io ns, Limitations and Setpoints) doc um en t. I 109D (2 ) : 08

I The second phase of this test verified the operation of the main feed pump speed controller by inducing a step speed change of 5%, and making controller adjustments until the overshoot and time for stability to be achieved was acceptable. Parallel operation of the f eed wa te r pum ps, to verify the bias portion of the control circuit, was d e f e r red until 50% RTP when both feedwater pumps could be operated wi thout bypass flow. Final adj ustments were made and system response was acceptable. I I I i lI r lI lI I I I 109D (2 ) : 09 I

2.14 SUP 81. 6 - AUTOMATIC REACTOR CONTROL The objective of this procedure was to verify that the rod control system can automatically maintain the RCS T at avg its proper value (Tref) i 1.5 F. Re ac to r po we r wa s held constant during this test. The operation of the automatic reactor control system during power level changes will be demonstrated during the performance of other scheduled transient tests. I The Rod Control System was transferred to manual control and Control Bank D withdrawn until T was 6 F higher than its avg programmed value. The Rod Control System was then transferred to automatic control. The control rods inserted automatically ] to restore T to its program value i 1.5 F. Pressurizer avg level and pressure response were monitored along with Tavg during the transient with no anomalies noted. The transient was repeated starting out with T 6 F below the program value 3yg again with no anomalies noted. From the time of the initiation of the transient to the time T,yg was restored to within i 1.5 F I of the program temperature was approximately 100 seconds with a maximum pressurizer level change of 8 % from 32% and pressure change of less than 50 psi from 2235 psig. Fig ures 2.14.1 and 2.14.2 graphically display the transient when lowering and raising Tavg

• 109D (2 ) : 10 I

SUP Oi.6 - AUTOMATIC REACTOR CONTROL Reco ver y Frces Lowered Tave Figure 2.14.1 a ' __. _, ; g u../ %. q =fi *= ~ q =p. =s,E-== =w- .a.n

=

---r = - "Y er n-y= = t =;g ,2. = t_ -l i =. r; +=p_3:=. e, a -.. _; } ; .=_p=.~,.-q,. =; b - p- ~' i .e o = _. _< =.: _.;-l -.- t = :. =., _. _._ 7 =. _ . e m : --

. 3 -

--- -t7 y = 4

=: t .._ c;r - - - --.-4 i.I-_ ,3 33]=% x-t E . < i! i 1- ..o.

. =-+:. - " -t = -. i

= 8-

---

t.=-r-

--. t y g i.. ,u ..).- -1: .4 .? Q-.---- A :. a, a 1: =, n=- l -t .,,p z,= = c e =m _ =3 s 3s.

=r

-i= J

l

.b :

-,., g r - i - = I li ~=. -- 1-En -f,- .[-:- i o e a, - _ =.. c.F-j h i i=t %

== -[} . u t

== - - = ===h =w = + =.

== r: -_ rr=~i. b,. _. e s. =- = a.-- =.:

_.._ w. a

:c--- - -.

.4 -...

= _.. - ..= u = m .:i .= L '(M I y7

-+

.H.- d. g- . =. k.. =; =- = = :_;

= =+ p

. _ =. :== Z -pc .. ;.=.g. g_ g=. 7 =; s I7 i=i-t'1 .? i- =h- 'H

1. - ' ' TI= d _. =

I .. Ei ... -1 ..;.. ; t = - gp= =..=j

= ~- I-~

'- ! - 3=i= ,r - ~ j t . + ; __ s y

== yr. g x=x. =;. ;; p -i:ll= i =, = -4 != :.. _y=

== =. : _ ,. g '=x p - --- =iqi;i_ri =.g= m. '-- f._. - -r ,- --=j -.= r c =; 4 - t- - = =:-...:=. c=-

== 2

==_. 7 ;=- ~ . [li] 3] 9} "H -e u i. 19= n.=_ uih __. { -t !Ti?..:8:1 = c l TEi! ig: ---ig=r p m-i= :=+ is=te +=== 13 =: s_!,is peri =p=: -r=i-) z==- q:.1=

==

== - ircm iH+ CE 4 M.. g y_ =. s. = yi-:= - - T '. - w =-i. U~] .=.} = =... - - - =. --=u

==,;

=t ---t -= 'igi.. =. :ii-ag=) = i =.==.=3si = i:

m.= _Ag g._

diq -=t 4 g-8 T p_=..si. s- ,- -- = = a a=_ i:_ i = - -E- :a

c. :

J: 12 92+- =E

==iog-iws -- .t1 !=.j=j =l!-i re :-. .irg, 14= --. i: - i- ;= 3 r:p =j l=4 ' u= m 154 :"=t--- :=4""* Wi"=-t ""=- -_t 1_._ -is g =_ =4 -i.i i.a. E=ir p=. :=as 42=r =:.=g il Vf ~E F Er i;

==- :* = d E=* TEE i ;- i= - 4.=i: a

i=

ijpjaim =1

a=.i=if W i"* a if-PEE--i

=E dE:i"i - WE =dsn = rr=i=i E =E=i + =EiE E i! = "i= E-?' =s EELE- =a I~I~

s f#'? =ii = += t=- d!

J-=5i = wZe?, ~" = t t 5-=hb5N5I!= 955 E-l.i :Ni-dTl#5i -!U= E~I5Edi55 EI N h=. ih ; Sf555 521 4 }S-- 5i t= = g 1- =- = t= ~~, ,=r - r= = = a=-.1 =:= -

===r ,-- = r. = =- =-==-F.-~- -a = r= - = r r f3 #tEM'e FREI Eda: t ag; =iei.si_=- .7== -Eha i==i #=ii= E=iti&E jiElg iiWiMIE4 E= t=i

b's EiE9M =i=

J i#iEE=s ^ E E E-i=Eti -e, i=::taista ilai t:--i ciE izE: o s:= _3 err===t. s=.a_ ap=.ig -gigg=it: =.. _=q= i=p;_i:,2==_ =hi c Eg==:=r;=.==s 2aE . E-m Elaz+-== : 14_=..... c. - =Ei

== si =1e=i==a E==1ar o z = = = = =: a r= ei==j+i==i }---4 +4 si sv E di+ _ = =. = = E-ein=-(g=[ =Ett:=== = z-.- _q qi=ei-r = p i-~= MEE j g iji{;=24=iiii } hi_ 'b ELEi"4E= ti= jjt,P 4E+ E%i==i 'iiE-5==.=i-EE E ~.ll:M j !#9+i9 isE5EiME5 3 i=

r=-

EisI=pid ={= ps _=,=E j=q t. g ej=4 j=i=rE =-- idELaE=21-Ei aEa=E-tEr ~l='t=p==r s. _r =_.===5 ; = r- ~ -a s..=.:.=..:.===.us -'. v'- Y __.__.:t.=_=...=.=.=.: +=. 3< a.. -..+1. =.. :=_. = +~=-:=== '=i -s e=.i.a.-.n.-.=l. t.- Wt 1

==..=.==.=.-m. w Y===iEE- !}

fiEis 1-IEjsfE EHE =El =iEE! tEi EE # E =

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== =. ia =. =.,2 9 _ .;g =r. s..,.: E _+T ia.; y i.isiz.. _ =

i

=:=.. aa_ =. =. =. =... - ' ~7== E=. a 2;.i. r.= =.

.=.E-E mr

=.ri.=. f=Em.-

T----' !C j Ii hi; 'b"Ei-f=^f'i Ch 2- . _ Eibib-i=h==~- s= ="==n Er d b:. - '- tbi 51 i D* ec= :=i,= 2Pr=% =, M T =! Mimir -; idMU_ E== M Mt W m = J= tiMiEii:#.2 ] u g=_=e=i=.=it= E= Mts=is.p =s Ei!.a =taEEiz =y=igi=--i=i+=.4=,= ;r= E;=_=}si- ; I ~ l% f@ti==t==5 iEf5i El=.~5 EE= ii-M*[Ii4 emf +=- #=i = ' E'~Eiii- .+ =i.isi- =i=3 E- = '-~~' zge.+- { . i < iiEf!ElEii= ===dMb ;= =4:E'ii*7=i!iii=- 151#9/J#EiE? ".=f ""1Ef = i = r==E4 =i-i* is f!EOEis

=12.

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== !I EE II i TEi+is-i==i i-Et.5Fj iMiis 3fE =i -=iPEpck- =- E=u =li= i+m..... 2 Y N N.., _ _ligi"E!"E

nM )=.:""*iE4 E= i=_.

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==.,.=

m i= = =p u. ----- c. , =i-' Wi?j;i=g'= _d~fiz T '=iE' EH=l+J+i ' I~lEf+i=i==i

Pt Eh

=~i-E. ="= +: ~ iEM:iT =++Mfi5 =i = T/ *= PEl :i?"-t"silE i j.=i-ii1, = + Uii" 5 Ii= 4 = "=ri-'.t !". r :_jg==gi=; f,gq=g j= i i -milirI= 2 =-i .F. 1 p.= _ipp.g =4 qg y g._=gg q.-p = E-r =

===q =g .=.g

== == g 4:=1==g 1+E-iii-1=g

7 q==ig=#1=4=g a=pTE: y==g.-2

-==.=q i= =; =:+ =-iq ys-p Spir ti= _ir{Epup. : glas==f==r p 3== E = % r=f = ...as=p=i 2a g gigs pss '._= :e

g. g -i z=; = ppa

-.%==. w k. _. - 2rc $+rn t== = := =a =1===r v. 3-- =-s= = s u=== == y==u

== sy=.: tf= n =t =. - x _.,_-_ur..,. .u- !F= E.i== P= :l is: La 1:W E - =ii s $.EE= =;i= i=J $ =i==iniEFE -%EsiEE-iEMfEfi:+-

==

L===- =P i H =!!E idii- ' 7..-I=ik=r r kil:1+c ;i=bifi-td==4&c =!E siai-il Ei-s ="i N EtMiiiif=-Ei! M id M i J r2ili. iis==15=iEs lita y q=g: : npj_.eg -i=Wi-. +;=b=g i=;=g=-fi[ipp=i s!=;y g;Aa==)-i=-Q E ppi= ja;= 7

-t 205ft:t=EpiEE 2 3.iri(O! 5 3 'EiE i=a

E

iiE ai MiJ.Wi.

1. i.- ei g -t=3==I'5T; E.iE-! b 5I N =Ei=i T EV = = i ji= ~-=:;-i ig. al=7 EiK M== ='Et!EA -e =+t b--- tE:===jsa= h==irEei+ i=4=gg=PitX i=g 3 =_.w ;m-rsi i=i =_i= = \\ = =-[=i=w;:'; rgip=b= Eiaai =Es ht r.m =i+ = 72; I-r. + ,i.

i =i=ng_g ;;4apui-+g = e.-

-=i-pi-j=.-=i=,i s ! =r 1 = +=g a

=u t c r :1 a2i==_= = g= =y==iref=q =g . =a=3 -; =g _ _ i.g t== - _2g

1. ~ ! 74i.

;

.3 p_....;_.:=,-- .- -- w==- a- = - .. = ._.-2=._.1 -- F. =- r = r =,= -e ,m. i _:= -.r.z.t== = = a _, 4. . t=_ t y. _. 3,,._. _. :.~.., + .==

=

=y_=w=g =3 =i

=

m

=

m,,, m m. ~. = * +

,

m m m m m m 4 m m m m m g g . NOIIIS0d 380SS3Hd 380SS3Hd GNVW3G ,0, NNUg anel dZd dQH W1S J0JJa1 033dS 008

SUP Oi.6 - AUTOMATIC REACTOR CONTROL Recovery From Reiced Teve Figure 2.14.2 =r L_ =~= = =~f? .H4 tg - g=i:

a={IIQ=& 7.ag.,.

- _.. =r 4=sr3 =g=; p.t=_= =_as__ =..m..=_r3.=..a=+t =':..]g =s i =.;.3;;:; s. I ..t: c1=

2. -

. i -+ ---j = j -- +i m. [miit 7.c _ ;.iE...._- -Etd-- =--- E = 4 = - - =H" L:_ w a M- -ia - r -- ,i i _ M =;',g t- = -+ = = M=- - 4'=.t -M-i_ u-pa= :i =f =- =4= E = ,= : L_ CD "

• 1:

--J it!EM =far= 1 =_===s : ,._ T e. _ s Am-7g -.i.. fii-21.;;-i=g=. !... N .;j = + - - i- ,= i 2,.

...

I =....t. __. +=, g 2 =.ig e-- 2 t..- =.. =.a i .m___, 4: =7=

a.=

..y r- =..n y

3._.

=,_ --J e { a;+23=22.' qi.j.. .11 1,;=.;-j=4.EpE _; _ i-EiJi)..si:-- ggi= ] ~ F:

i. ;

-i-- --j = -- F-r:.- a.i-I

• * ^ *

' 57 7 a =- =i:= i.-- ! W m:ri =. l - = I4. =.E. L. =ai__ . p_. =.h._: =-. i.n r = . +..

=

. x . ' --I ' . 3 ---5 iiihii-fd5.'-. =f W ^ ' l

3. ;

iN- '- -{* -y=-- - - ='=:-

=*--

.Z ;_-. .. ~ T.:Fji ;: ww

- W

:

i

17 =M

h--

. o

.er.

_g

n. i== =:={=.

..-t - .= m z 2

;~

= g ~~3-i ij..g ici :9 pi-i;

54== t=.y 34

gp_..

7:;._- :"Mr.- iir? ". g.:= n.i.. E _ 'P4 j-fir =h;H 2Eji'- W-Ff i.+; - =--i, -E.=..:

t,-i.i.j--i. =.._= =..a=. _2.g; ji..==- _:.-. _n..

. i.i; i.j }: ui.=. =.is. a != si i =E:. Q g s&.ii=:=; =

u: =:== 3.g sq g

s_..:;., {;;t=~ =-s

. c ti

s

. =m p.

,a

uc r.r;q r_} #y =. a.. =-i. s.,s.. i=. __t..=3. +..,..., u.3._ 2 =-.=_=.. _.._.p.. _.i. - - h -.... . ~.. .= ga y g :ica_

iap

= j; m =23= =4 _ g_g -E; q=a.spe-g

n s==is

= gi g u ,I p"i:i g,_ . :2,l2 fr:i i_t.---d-.' s,=q=ig;i=- =q sag i. P _ =.

- - r=.4, 6 :-

._+.i =i_ -- m.i=- az! g i_- _. _== !. t -. i...i=. ji. !. -__._~- --:

ta

=. -a-l =- _ _ ._....g_=.- .+ r a. . = ,.4 as -f = I : rs.=;=2 ts.._s=1: s=:: -sp=a. gui:rgy. ;g 3;=5 ag-- =._ ysigs..; =g=42=,3E r

9 u

• • = s vi-==i r=z t=t=r+i s.= si#si g4=i s'.q=gsts =. 5 s +._- ig=M.-g m

=i. i-i=ig =i-.4=p=j = @ i.: 1-p r -4lTE g.=== i_r ' if :_; . =.j 2 --Ej -E'i p i G=' ii=.t=g:.-El:4 ]-~=E =i5.j}==!=7-i-EE; r:::i-{ [ 2:=j==4 ~ = 4 b .. =. -E45-i=i-il== { i=:

=s= > 2r sisi =..i_.i=..i= 2-ti --gsgs

i i :

m .gsii &ig.:;.1=-~ i =i--isii4

==j=..EE r M = ...-.!. rit-F;:._ _. = _..., __ =. 3=;._, _.__; p_._ ._ 4:- =R ' T' ~~ fs' fE5/ =

==._44 ! F= f:-~r-- ~&-f~2 _~ _~~T3-5 ~~ l-P-~E3~'=~~ H _=m. 2 q ..-.-b. ., =

=1.- t. _= -l.. d.. -_. a =_

a =.. 1.i=_ = ' _ a-4."... a'__ i-- u= =: =....i=.=__=_r-- _-__.

• _ - r_ai. h. =..-i.E_

_: gg_ = _.., =...=_E...=....g_ . _. _j:.=fExi.i_ i I _2.=lE=i.ii-r _ _.. =i =: =i= g -] r-a_. y_ -.__., _, EE n=p==.ri = =ga =r==:==g;=; = _.23 g-; j=-==p=s=. : ' assi=s.5 i i=i =. ;g ta=:_ ii g =&=Eise :ggy+;q ig=. g;;s; : -(=. d= =$= " t=i.W .7 l=M=iDi 1-;~ii-!

== ~'~ ~~~ J =y= Em ci:#g +.. p a.=q=:== = =.==;= =asas --, 3. ;;; pa #g 1:taq==- _-7-- =g=r.= g .; ;gss : B .a 2.=== _...,3 __u. -. _ g_=_ g_= u3_5g. 3.i.gg.=_;:=-- ; _==-_p_;.. = = ._.,=-t- _=:=_;ig. . =. _ _ -_ =._ =.. .= . _ g. ,_a g... =a g = a-e=t=12Ep7 .==.=..p=gpsij-ii p...a....... =. =....=a.__=_ r r =-

=

m.._ .. __.. r.E=_4r.."__. _.. _. - _.=7 =.=.d=-i=..-a. x i ____.-2... _.t-- c u = 2.

:==

= =

_ c= gr. _ .g=r. _ =i-u_gu.=_j. _..-.1=- p.=. _ _.==~;- =_-m. w=. =t=a.

; =1

=.,=_3.====n,

=

m;, ~ + - - = r-- = = =_ 23p m==2 = .a =-,

e Mhici .EiE' E C - is 4E!EE 7._ --'2= t=!.52=E! ! =EE!=.Eim _.. _ _ _ = * - Ei =;+: di Wis=== N t B ' Di==j=== =2,- t n=-=== .p i~~:4=._=.==.=.:d.3 =_=.... p h...:.=.. s.. i...~__- .-~ &=r i . _' i. 2.=. S. _iE_..-i.?:=.a *=..-=_rji.i.=. a=rr .,C... _- a...-._;=_.- d =* 2: i.--_..... =--: --

r=; j

m. mga. xi.;.333= gig-3=. 333g y = =: t=E

==i;=.c y s. =i- - =i=i-ga

= qsg =aa iy =-qq.g g;; g_

.__;;t-g=.; j ;;;- g.;; M s; _2 i=+=ea+7 u =

a3=

13 j y I

= =. =:

a= ; r - w-g

=p=4=a g;;

. ;.t;;

g;7 i= =a piggg;s r= "=

ffi

Mgsii ins niiiggis-- ii;;Q.i =itsrta=[!!. g3.g5. - -~ Z e i-~i s=a 2"r f:= n = i,,a=.. p =;&ggii-j

=== j n H tc = m z t : u... = .==.. p_,=..=.. =. =.=..=._._.......;_

= =. =,,=...== _

.. _ -=_ =_=..: _gi ; = r. ...;.= . :4_ 1. g g;: g_ . g +

J:-

r ;;--- I - *r=i=

=--: - =hi=f =

-iM=i;i.i Fi .E -Es =.E=i = s =_E 1===2 = g: s i!M-f._ _.i==* r sa.- ;= i _--- "= "-i ii 3 =: = =:=i=El-s'i? 2-ia-i ;h;ifi4ML1 s_{;;;f;] is. "f==lis =E5'8 -MEEEi=.=ipg= si.__.

=iEER "_==-f f E5EEi=

= ~ ~ ~ --} Ej~El+!= f s t=+s i== - ._5 .;;: l=p== i=. :=..m==

• ^

=7=_.,

1...;;;i-

__ h =.=3:.-..=i= r --

===.- =- _ c:3

== r

a= = 1 =rt=w =i: 3 jg g g g r = =._; = ma==-_ _ _., _ ii;guijimia".a --.._-_ _.__ .1 ,_..g ;.. I p -.. = =.

==iL E-4 =i =i g M ElT.p} 2j.ij q f p=-

~;2={._ __Fj ]Ey - - -

_._[ =:T--;Ilji :-~- j =[E!= i' ~ - F... = 3== =g . _. _ _ _-r7 -1 . 3.# - jg-3 m. ;.=. g-- -....- :;

g;irg=psas n'-. _..-=iit= =

=iq

.". i-. __-

-

=.. -.'H-~-5 1:Ji) lE-3 -~h. -j= f =lE.. g.; ;_.f: _!:= jE E-[E

== qgr-jgiy-4 st g333. g-- =r-jyiq~E*I)

== = = P = = _EE

== I p'Ei! _i.=.a._ a..=y. =: t=_=Es-== j =. _c.s_= { u ~, '==,is. =rs_-==.s_. t z _.1 =_--:a_isa=n.i.,ssi~ _Ji.i - --s__a_ q_ i.=_. f..r _-a_. _=:. =._=_: W. ~

=...

g i:L;M '== ! i ni m, E -i =E-JEFh:i = iji f-~ =iihib g:q =Ig-r. : =_=..z=. _.._=.. _W....... s ic;;:!s;;; i __._.. ".i ElE;;w=: = L=~ t=i _.. [ r.{ :{ ... ]

• = - - y-j

..,-Q E =h=r:' -a .; =j:;fj- }j{, ... '-{ ;- -- j= j.. ~-~ ._g .f 2 .} ~~ !==-sq-s

gt==; :;aE+ mi i isri Z a=

i= ng

+1 =ia-i=asji= als 1

Egj.:t Ersstas i

===- E =i =w w :a -Een ; rt

= s-52 a===E ei=l====

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I 2.15 SUP. 80. 1 - APPENDIX G, FEEDWATER HAMMER TEST The purpose of this test was to verify that following a reactor / turbine trip the operation of the auxiliary feed-water system will not cause an unacceptable feedwater hammer in the main feedwater pipeline. The test was performed in conjunction with SUP 82.4, RODS DROP AND PLANT TRIP (Section 2.6) which initiated the reactor trip. The initial conditions were with the reactor operating at 50% power and normal steam generator levels of 44% in each steam generator. The main feedwater line in the containment for No.21 Steam Generator was instrumented at key locations based on the piping configuration to monitor piping moveme'nt and fluid system pressure spikes. The piping was monitored at two separate locations in the x-y-z direction. The electrical signals, for piping movement and pressure spikes, were connected to a visicorder located outside the containment. See Figure 2.15.1 and 2.15.2 for instrumentation locations. I The reactor trip was initiated by SUP 82.4 on July 23, 1981. Following the reactor trip, the main feedwater system was isolated automatically; and the auxiliary feedwater pump started automatically. The flow to the g steam generator was allowed to exceed 440 gpm (220,000 5 lbm/hr.). Following the reactor trip, the steam generator

I 109 D ( 2) :11 Y

i 1 I levels were reduced from 44% to < 11 % in 9 seconds due to , su shrinking of the fluid / vapor volume in the steam generator. 5 At this point the feedwater ring was uncovered (covered at a water level of 11%). The auxiliary feedwater pumps restored the level in the steam generators above 11% in 19 seconds. From the time the reactor trip was initiated to the time the feedwater level was restored above the feedwater ring, the maximum deflection of the piping was.35 inches at the z axes at both locations and at a frequency of 3. 33 Hz. The z axes is the longitudinal direction of the pipe at hanger FWH-21-17 and perpendicular to the pipe at FWH-21-18. There was no dynamic pressure response noted following the reactor trip. I

I lI I

'I lI lI 1 'g 1090(2):12 I

Figure 2.15.1 'I INSTRUMENTATION BRACKETS FEEDWATER HANGER FWH-21-17 lI 15 X-LVDT g 7 y~ L.V.D.T. Target P' late.--> 'l l 8 >I I' ]' .,I L.V.D.T. Support Bracket g -l Spring Hanger ~~ FWH 21-17 - Y.. f 7 4 ~ l .l 3 Z-LVDT Restraint 21FWR-6 L Y-LVDT ,g - _ J L ;__ l l+ i, .. g 4..

g reedwater Pipe Approx. 14" OsD.

, ll ll( l l 'il ) __a__ I I I I

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i; l c y

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I I SECTION 3.0 CALIBRATION OF TEMPERATURE AND FLOW INSTRUMENTATION DURING POWER ESCALATION INTRODUCTION This section describes three related tests and their results. Certain plant instrumentation requires full power values of various plant. parameters for calibration ( e.g., primary loop I average temperature (Tavg), reactor differential tem pe r a ture ( AT) and feedwater flow). Since these values are not known prior to operation, conservative values are initially set into the instrumentation for startup testing. Pa r t o f SUP 81.12 directed the collection of the required calibration d a ta a t lo we r po we r lev els, f rom which full power values were then ex tr apo'.ated. Other sections of SUP 81.12 derived values for calibrating nuclear instrumentation and AT trip setpoint circuitry. SUP 80.7 involved deriving the T program fo r avg the rod control circuitry while SUP 81.7 calibrated the steam and feedwater flow transmitters. I I I I I 109D (2 ) : 13 I

I I 3.1 SUP 81.12 A - ALIGNMENT OF PROCESS TEMPERATURE INSTRUMENTATION The purpose of this procedure was to determine the full power reactor coolant system differential tem pe ra tur e for each reactor coolant loop for the purposes of calibrating the Overpower and Overtemperature differential temperature trip circuitry setpoints. Conservative value are initially used during plant startup testing and are revised based on measured values. I Da ta fo r this proced ure was taken in SUP 81.12B, Statepoint Da ta Collection (Section 3. 2). The initial valves used were derived from the Westinghouse Precautions, Limitations and Setpoints documents which recommended a conservative value of 55 F. The loop statepoint data for differential tempera-ture was taken at 30%, 50%, 75% 90% and 100% RTP. The data was reviewed following the 75% power data collection and plotted based on reactor power for each loop (see figures 3.1.1 thru 3.1.4). The derived full power dif ferential temperatures were used as inputs to the Overpower and Overtemperature trip circuitry to allow operation above 85% RTP. Data taken at 90% RTP indicated no recalibration of the trip circuitry was required. At 100% RTP the trip circuitry was recalibrated using the measured differential temperatures at 100% RTP. See Table 3.1.1 for a review o f the data collected. I 109D (2 ) : 14 I l

- I I TABLE 3.1.1 DIFFERENTIAL TEMPERATURE VS. POWER LEVEL I Po we r Loop Di f f erential Tem pe ra ture Level 21 22 23 24 Avg. 30% 20.9 20.0 20.2 20.2 20.3 50% 32.2 31.9 31.8 31.6 31.9 75% 48.8 49.2 48.6 48.0 48.7 90% 58.4 58.8 58.3 57.4 58.2 I 100% 63.4 63.8 63.4 62.5 63.3 I I Po we r _ Ex trapolated Di f f e rential Tem pe ra tur e (To 100%) Level 21 22 23 24 Av g. 75% 64.7 65.2 64.4 63.6 64.5 90% 64.6 65.1 64.5 63.5 64.4 100% 63.8 64.1 63.7 62.8 63.6 lI ,I g - 100 - 1000(2):15 I

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I 3.2 SUP 81.12B - STATEPOINT DATA This section collected plant steady state performance ( sta te po in t) data required to calibrate steam and feed-water flow channels, T and Dif ferential Temperature avg channels. The statepoint data was taken at power levels of approx-imately 30%, 50%, 75%, 90% and 100% of rated thermal po we r. It was important to have steady state conditions when this data was recorded. These included being at a steady power level, xenon at equilibrium, no rod motion, T equal to Tref, and blowdown secured. The conditions avg I minimized the errors induced since the data ( eig ht sets) is collected over approximately one hour and averaged. The data included voltage readings from the process racks for T T T Tref, steam flow D/P, RCS flow, turbine first h, c,

avg, stage pressure and Delta T.

Information was obtained in the field for heat balance data for determining the reac to r po we r level. Eig ht successive sets of data were recorded at each powe r level (105 data points per set). A summary sheet averaged the eight sets of data recorded. Table 3. 2.1 displays a summary of the results of the measurements. Table 3. 2. 2 thru 3.2.5 are samples of the forms used for acquiring the field data. Table 3. 2. 6 is a summary of the 100% Statepoint Data. I - 105 - 109D (2 ) : 16 I

The statepoint data taken at each new testing plateau included data for eight reactor heat balances. The steam generator feedwater temperature was determined from individual feed line thermocouples with a local Do ric Model 400 Trendicator readout. The feed flow to each steam generator was deter-mined by measuring the pressure dif ferential on a calibrated venturi in each line. The control console steam generator pressure indicators were used to determine the steam enthalpy (assuming saturated steam). Any time a heat balance was conducted, the NIS percent power indicators were recorded for comparison and possible adj ust-ment. The excore detectors are affected by rod position and reactor inlet temperature (Tcold). It is important that T be within 1 F of T and the control rods be at their avg ref normal operating position ( AI band) whenever the calorimetric results are-used to reset the percent power indicators. 1 I I 1I I I g - 1oe - 109D (2 ) : 17

Table 3. 2.1 STATEPOINT DATA

SUMMARY

I PLATEAU POWER 30 50 75 90 100 DATE TAKEN 7/3/81 7/20/81 8/ 3/81 8/14/81 8/20/81 CALORINETRIC POWER 29.90 48.3 75.45 90.36 99.51 "D" BK ROD POSITION 153 228 228 228 228 FW TEMP ( F) 325 367 398 421 430 6 FW FLOW ( x10 LB/ HR) LOOP: 21 .9378 1.6358 2.6663 3.260 3.651 22 1.002 1.6603 2.7235 3.319 3.698 I 23 .9695 1.6594 2.6905 3.285 3.649 24 1.016 1.6751 2.7146 3.323 3.688 STEAM GEN PRESS GEN: 21 966 928 888 788 785 22 964 927 886 787 789 23 968 932 891 793 797 24 965 928 890 791 794 TAVE ( F) ' LOOP: 21 559.' 562.9 571.0 565.5 569.7 22 560.3 564.0 572.4 567.2 571.5 23 560.1 563.4 571.5 566.4 570. 6 24 559.7 563.2 571.5 566.3 570.8 DELTA T ( F) LOOP: 21 20.9 32.2 48.8 58.4 63.4 22 20.0 31.9 49.2 58.8 63.8 23 20.2 31.8 48.6 58.3 63.4 24 20.2 37,A 48.0 57.4 62.5 -. _. 1 NI PWER RANGE CURRENTS CHNL: 41U 123

4 319 350 381 41L 159 22d 352 405 451 42U 136 228 1

342 371 408 42L 179 249 391 447 499 43U 125 212 317 347 375 43L 151 215 335 379 421 44U 119 203 305 334 364 44L 140 200 317 361 403 - 107 - 109D (2 ) : 18

Table 3.2.2 STATEPOINT DATA DIGITAL VCLTMETER READINGS

Salem, Unit Da te

, % RTP ,Run of RA W FINAL LCOP PARAMETER DATA SOURCE (unt ts ) VALUE VA L UE I That TP A l l-I (R 2) volts I Tcold TP A ll-2 [R 2) I Tava Input to TM 4I28 (R2) I Delta T Input tc TM 4 I I D (R2) i RCS Flow TP 4 I 6 (R 12) 2 That TP 42 I-I [R 6) volts 2 Tcold TP 421-2[RE) 2 Tava Input to TM 422 8 (R6) 2 Delta T Input to TM 421D (R6) 2 RCS Flow TP 426 [R I2) 3 That TP 431-1[Rl3) volts 3 _ Tea (d TP 431-2 [R 13) 3 Tavq Input to TM 432 8 (Rl3) 3 Delta T Input to TM 431D (RI3) 3 RCS Flow TP 436 [R 12) 4 That TP 441-1 [RI5) volts 4 TcoId TP 44I-2[R15) 4 Tava Input to TM 442 8 (RI5) 4 Delta T Input to TM 441O (RI5) 4 RCS Flow TP 446 [R12) Tre

• TP 505-4 (R I23-2)

Turbine iSt l Stace press TP 506-I [R9) SYE$bre'sS TP 505-i (R5) Recorded by Reviewed by -108-

Table 3.2.3 S TA TEP OIN T DA TA, LOCAL READillGS Seiem Unit No. Dete i Tim e 5 eem Ge-p"ess: special gage (psig) ., es,, Run SLG I S/G 2 S/G 3 S/G 4 i i j 2 J l 4l l g Si l i 6l 7' l 8 lS l /Ol l Steam Restrictor Differential press (inches H90 ) c S/GI S/G 2 S/G 3 S/G 4 S Chen I Chen2 ChanI Chen 2 ChenI Chan 2 ChanI Chan 2 I E 3 4 l 5 6 7 8 Feedwater Venturi D/P (inches H O)~ S/G I S/G 2 S/G 3 S/G 4 2 Feedwater Temp (*F) S/G I S/G 2 S/G 3 S/G a l I l 2 3 4 l l 5 6 l l 7 8 i l l l Recorded by Reviewed by -109-

S TATEPOIN T DA TA, NIS and CON TROL ROOM READINGS Salem Da te Time Unit Percent Power Ref Test Table 3.2.4 NIS Detector Currents (y amps)_ and -7: Power 8__l_ l a,C h an/Run+ 1 2 3 4 5 6 7 I .lN4 /(upperj (lower) % Pwr lN42 U L To i N43 U l I I l L i i EN44 U l 1 c s Feedwater Flow (%) & S/GI (I) E (2) S/G 2 (I) (2) S/G 3 (I) (2) (I) i S/G A (2) Steam flow (9c) g El S/G I (I) (2) S/G 2 (1) l (2) S/G 3 (I) (2) l S/ G 4 (1) (2) Reac tor Coolant flow (%) RCL I (I) i (2) 'i (3) RCL 2 ft) l R (2) E f3) RCL 3 (I) g (2) j m (3) ~ --i RCL 4 (I) I j (2) E (3) l l l Recorded bu Reviewed bG -110-

RX ENG MAN, Part 2 Table 3.2.5

gg Sec tion 2.6 CALORIMETRIC CALCULATION DATA SHEET S lem Unit 2 Date Time Recorded btj

^ Gross Gen Output MWe RCS Baron Conc ppm Control Bank Position: Bank at steps Tave - Tref < 0.5'F: T F errorLooo 21 Leoo 22 Looo 23 Loco 24 Tave (Cons ole) *F aT (Console)*F Steam Pressure I I I (Psig) 2 2 2 2 3 3 3 3 Am Am Avg Avg BIowdown Flow (Ibs/hr) in Total Blowdown Feedwater Temperature *F Feedwater flow AP (Inches) NIS CHANNEL: N 41 N 42 N 43 N 44 i Indicated Power (during Calorimetric) Calculated %RTP (Sect 2.7) Difference (NIS-Cal) If calorimetric power <98% a tolerance no more negative than -2.0% is i permissible for difference (NIS - CAL). If calorimetric power 1 8% a tolerance no more negative than -1.0% is 9 permissible for difference (NIS - CAL). The average of the 4 NI's should be equal to or greater than the calorimetric. NIS power after adjustment Sen. Reactor Operator -111-

Table 3.2.6 I STATEPOINT DATA

SUMMARY

DATA SHEET Date: 8/20/81 Salen Unit 2 Reference Test: Sup 81.12B 100%RTP 100 % RTP I Ren i Run 2 Run 3 Ron 4 Ron 5 Run 6 Run 7 Run 8 Averages % RTP 101.06 99.93 99.72 99.42 99.28 99.07 99.36 99.26 99.51 ITURBist 50S 561.48 560.81 560.81 560.98 559.97 558.29 559.64 558.29 560.04 STG PSIA 506 568.03 566.46 568.37 567.19 566.02 563.H 566,.35 565.18 566.42 FW D7P SGi 708.301 702.800 691.708 691.100 691.600 689.700 685.700 691.500 694.05'O (inches SG2 718.000 715.500 715.208 709.900 709.700 704.400 708.700 708.300 711.213 H2O) SG3 698.700 692.500 694.300 691.400 680.200 678.300 688.100 682.300 688.225 SG4 710.308 715.308 712.608 702.300 703.900 697.500 705.600 699.000 705.813 699.825 IFWFLOW SGi 3.688 3.673 3.644 3.643 3.645 3.640 3.630 3.645 3.651 (1b/hr SG2 3.714 3.708 3.708 3.694 3.693 3.681 3.691 3.691 3.698

• E6)

SG3 3.676 3.659 3.664 3.658 3.628 3.623 3.649 3.634 3.649 SG4 3.699 3.712 3.706 3.679 3.683 3.667 3.688 3.670 3.688 3.671 FW TEMP SGi 429.000 429.000 429.000 429.000 428.500 428.000 428.000 428.000 428.563 (Dag F) SG2 431.500 430.000 430.008 430.000 430.000 429.000 430.000 429.500 429.875 SG3 430.000 430.000 430.000 429.000 429.000 429.000 429.000 429.000 429.375 I SG4 431.000 430.500 438.000 438.001 430.000 430.000 430.000 430.000 430.188 429.500 S/G HEAT SGi 292.088 298.935 288.595 288.452 288.797 288.692 287.870 289.085 289.314 IRATE SG2 293.652 293.339 293.268 292.154 292.113 291.541 291.957 292.136 292.519 (btu /hr SG3 291.824 289.499 289.859 289.778 287.398 286.996 289.094 287.873 288.914

• E7)

SG4 292.131 293.367 293.058 290.915 291.263 289.912 291.649 290.316 291.575 290.581 I~(DegF) ~' S Lpi 601.048 601.700 681.640 601.910 681.820 681.228 601.168 600.530 601.378 .ot L2 683.450 603.440 603.620 683.590 603.650 602.870 602.900 602.510, 603.204 L3 602.090 602.750 602.991 602.930 602.450 602.180 601.850 601.430 602.334 L4 601.558 601.888 602.090 602.120 601.790 601.670 601.010 601.070 601.648 602.141 IRCS Li 537.240 538.140 538.440 538.470 538.620 537.750 537.450 537.180 537.911 Tcold L2 539.360 539.640 539.820 539.490 539.360 539.550 538.950 538.710 539.360 (Dag F) L3 538.880 538.980 539.130 539.378 539.370 539.010 538.230 538.230 538.800 L4 538.860 539.340 539.520 539.610 539.520 539.520 538.590 538.710 539.209 538.820 IRCS Lpi 569.225 570.075 570.150 570.150 570.275 569.650' 569 350 568.975 569.731 Tave L2 570.900 571.750 572,000 571.825 571.950 571.500 571*.158. 570.875 571.494 (Dag F) L3 571.200 570.925 570.975 571.125 570.825 570.700 570.150 570.025 570.616 L4 570.600 570.950 571.175 571.200 571.000 570.950 570.250 570.275 570.788 570.657 RCS Li 63.875 63.600 63.175 63.450 63.225 63.300 63.425 63.325 63.422 Dalta T L2 64.275 63.950 63.875 63.850 63.600 63.425 63.750 63.900 63.828 (Dag F) L3 63.775 63.500 63.500 63.475 63.075 63.175 63.550 63.375 63.428 I S/G i L4 62.750 62.450 62.675 62.680 62.300 62.250 62.450 62.150 62.453 - 63.283 i 800.000 805.000 805.000 810.000 8t0.000 810.000 805.000 805.080 806.250 PRESSURE 2 775.000 775.004 780.000 780.000 780.000 780.000 775.000 775.000 777.500 (psig) 3 780.000 780.004 785.000 785.000 790.000' 780.000 785.000 785.000 783.750 789.167 S/G 2 i 781.000 790.000 795.000 795.000 795.000 795.000 790.000 790.000 791.250 PRESSURE 2 780.008 785.000 785.000 790.000 790.000 790.000 780.000 780.000 785.000 (psig) 3 775.800 780.000 780.000 780.000 780.000 780.000 780.000 780.000 779.375 785.208 S/G 3 i 775.000 775.000 775.000 775.000 780.000 780.000 775.000 770.000 775.625 PRESSURE 2 775.000 780.000 780.000 780.000 780.000 780.000 775.000 780.000 778.750 (psig) 3 780.000 785.000 790.000 790.000 790.000 790.000 790.000 790.000 788.125 780.833 E S/G 4 1 798.000 795.000 795.000 000.000 000.000 800.000 795.000 790.000 795.625

g PDESSURE 2 798.000 790.000 795.000 795.000 799.000 800.000 790.000 790.000 792.500 sig) 3 780.000 790.000 790.000 790.000 791.000 790.000 785.000 780.000 786.875 791.667

-112-

I 3.3 SUP 80.7 - TURBINE CONTROL SYSTEM CHECKOUT AND STARTUP ADJUSTMENTS OF THE REACTOR CONTROL SYSTEM Automatic reactor rod control is achieved with a reference i average temperature (T,yg) program. The turbine first stage pressure increases approximately linearly with turbine (or reacto r) po we r. This pressure is converted to a reference temperature (Tref). The control rods are driven by an error signal derived from the difference between the actual T and the programmed T avg ref (T = T,yg - Tref) until the error is cancelled. error The reference full power T is set so that the f ull po we r avg s t e o.a generator pressure (turbine throttle pressure) is at the value recommended by the turbine manufacturer. By adj usting the full power reference T ( AT across the avg I steam generator tubes being fixed) any desired steam generator pressure can be obtained. SUP 80.7 developed the Salem Unit 2T pr gram. avg I For initial startup, the vendor recommended an initial full po we r T v l ue f 577.9 F. This was expected to produce ref a full power turbine impulse pressure of 550 psia. No adj ust-ments were to be made to the Tref pr gram until after 75% statepoint data had been collected. l l - 113 - 109D (2 ) : 19 i

Af ter collecting data at 75% power, extrapolation of the measured steam generator pressure to 100% power showed that a drop of 62 psia would be necessary to maintain design pressure. This corresponded to a drop in Tref pr gram of 8.6 F. T was then reprogrammed to 569.8 F at f ull po we r. g This was calculated to correspond to a full powr first stage turbine pressure at 560 psia. Proceeding to f ull po we r, the statepoint data showed the steam generator pressure to be approximately 800 psia. No f urther adj ustments were made to the Tref program. Full power first stage turbine pressure was measured at 560 psia. Fig ure 3. 3.1 shows the turbine first state pressure extra-polation. Fig ure 3. 3. 2 shows the T ex trapolation, and avg Fig ur e 3. 3. 3. shows steam generator pressure vs. reactor po we r. - 114 - 109D (2 ) : 20

i e Figure 3.3.1 1, TURBINE FIRST STAGE PRESSURE vs REACTOR POWER I i I rQu

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I 3.4 SUP 81.7 - CALIBRATION OF STEAM AND PEEDWATER FLOW INSTRUMENTATION AT POWER I i The purpose of this test was to calibrate the feedwater flow and steam flow signals to actual measured flow during low power testing, so that escalation to full power would be possible. The feedwater and steam flow signals are used in the plant's control and protection instrumentation. These signals are d er iv ed fro 1 the differential pressure across a calibrated venturi fo; feed flow and a flow restrictor for steam fl o w. The differential pressure transmitters produce currents that a re propo rtional to the Ap. The steam flow Ap signal is multiplied by the steam line pressure (steam is compressible) and then the square root of the product is taken. The feed-water dp signal is input directly through a square root extractor circuit. These square root signals are propor-tional to t-heir respective flo ws. Calibrating these channels actually amounts to scaling these transmitters so that the full output corresponds to a op equivalent to 120% fl o w. Fo r initial startup, the f eed wa te r Ap transmitters were scaled for predicted f ull po we r flo ws. Since steam flow restrictors are crude orifices, no calibration data was I provided on them. Th e r e fo r e, the steam flow transmitters were scaled to numbers provided by the vendor (based on past ex perience). 109D (2 ) : 21 I

I The statepoint data from the 30%, 50%, and 75% power levels was used to plot feedwater flow and temperature versus power as well as feedwater venturi p versus feed flow. Feedwater flows at 120% RTP were obtained by extrapolating these plots. The feedwater venturi equation can be expressed as: Flow = ( A p) l/2 (y) (fa) (Const.) 1/2 Cost. = Flow constant unique to that venturi fa = No zzel expansion factor Y = Specific weight of feedwater Using the extrapolated 120% feed flow (average of four loops), the 120% power expected differential pressure values can be obtained for each loop. The results are shown in Table 3.4.1 and Fig ures 3. 4.1 thru 3. 4. 8. ( A p) l/2 (y)1/2 Const. Flow = The restrictors, not being calibrated devices, have unknown constants. The constants were evaluated using the 75% measured data. Then the ex pected p values were determined using the average 120% ex trapola ted feed flows. Ap (Flow) = Y ( Const.) 2 The results of these measurements are shown in Table 3. 4.1, Table 3. 4. 2 and Fig ures 3. 4. 9 thru 3. 4.16. - 119 - 'g 109D (2 ) : 22 ,E I

I All steam flow channels appeared to be indicating correctly a f ter calibration at 75% RTP. When reac to r po we r wa s escalated above 90% No. 21 a nd No. 24 S/G steam flow channels started to indicate high. High flow alarms were received. A second set of "90%" Statepoint data (SUP 81.12B) was taken on Aug us t 15, 1981 to reconfirm the 90% Statepoint Data taken the previous day. This was actually at 91.88% RTP. Po we r wa s raised to 96% and held on August 16, 1981 to obtain another ( un sched ul ed) set of Statepoint Da ta for recalibration of the steam flow channels. As a result of these measurements No. 21 S/G steam flow channels 1 and 2, and No. 24 S/G steam flo w channel 2 were re-scaled to reduce the indicated steam flow. Po wer was raised to 100%, and full power ( 9 9. 51 % ) Statepoint Da ta was taken on Aug ust 20, 1981. High steam flow signals were noted again in us. 21 S/G. The measured flow element d/p i n No. 21 S/G steam line was higher than predicted from the 96% measurements. All other channels appeared close to predic-tions. It was speculated that high steam moisture content was causing the unusual high d/p on this flow element. Subsequent power reductions showed this No. 21 S/G steam flow signal too low at power levels below approximately 92%. On Aug ust 28, 1981 the first moisture carryover test (S UP 82. 7, S.ection 2.8) was run at 100% ETP. This confirmed that there was h!gh moisture content i n No. 21 S/G steam ( ~ 1. 5% vs. design o f <.25). l - 120 - 109D (2 ) : 23 ll

l l l Station management felt that the abnormal behavior of No. 21 S/G steam flow channels made them inoperable. These 2 channels were re-scaled back to d/p values extrapolated from 75% Statepoint Da ta, and the reactor power level was limited to 92%. Above this power level these steam flow channels indicated abnormally high. On September 11 and 12 a second moisture carryover test was run confirming previous measurements. Also extensive instrumentation was used to observe the steam flow channels' b ehav io r. A safety analysis was run to allow this operation at 100% reac to r po we r. On Sept. 21, 1981 Salem, Unit 2, was shutdown and cooled down to modify the steam generators by installing additional separator drain lines. Salem 2 was started up on October 8, and a third moisture carryover test was run on October 12, 1981. In parallel with this test, Statepoint Data was again taken to observe steam flow element d/p valves. The results showed the steam moisture content was within acceptable levels (.13%) and the high steam flow signals were greatly reduced. This 99.67% reactor power data was used to re-calibrate steam flow channels. Both channels of No. 21 S/G and channel 1 of No. 24 S/G were re-scaled After re-sc al ing these steam flow signals were observed to be acceptable. - 121 - 1090(2):24 I

Fo r the next two months the plant operated up to 100% power without any further high steam flow indications. On December 3, 1981 power was reduced to 70% due to a leak on No. 21 f eedwater pump. Upon completion of the repairs to the pum p ( about 7 dsys), the plant was escalating in po wer when the steam flows were again indicating high flow. Statepoint data on 12/11/81, as sho wn in Table 3. 4. 2, indicates that the steam flow D/P 's had increased. Fig ures 3. 4. 9 thru 3. 4.16 plot the eight s*eam flow channel D/P 's vs. feedwater flow during startup testing and show the same trend in higher than expected steam flows at < 90% RTP. Fig ur es 3. 4.12 thru 3. 4. 21 show steam generator level change and reactor power change. From ' the figures and tables it can be concluded that the steam flow channels are af fected by moisutre carryover. An additional moisture carryover test is scheduled for January 1982 to confirm the suspected carryover and determine the % of c a r r yov er. Based on the test results a determination would be made as to what additional steam generator modifications are required. The test re;ults indicated the carryover was acceptable as found in October, 1981. Inspection of the steam flow nozzles is planned during the next plant shutdown to determine if corrosion / erosion of the nozzle area has occurred which could cause the higher dips measured in the~ steam flow signals. - 122 - 109D (2 ) : 25 I

\\ TABLE 3.4.1

SUMMARY

OF DATA FOR CLAIBRATION OF STEAM AND FEEDWATER FLOW INSTRUMENTATION (Pressure Differentials in inches water etxrapolated to 120%) Values predicted afer 75% Statepoint Data 6 Ex trapola ted N Fl o w = 4.369 10 lb/hr. LOOP VENTURI STEAM RESTRICTOR AP AP (FEED) CHANNEL 1 CHANNEL 2 21 983 168 155 22 999 207 212 23 984 188 197 24 993 169 171 Values predicted af ter 100% Statepoint Data and af ter Steam Generato r modifications 6 Extrapolated N Flow = 4.454 10 lb/hr LOOP VENTURI STEAM RESTRICTOR AP OP (FEED) CHANNEL 1 CHANNEL 2 21 1012 182 185 I 22 1048 215 211 23 1012 198 203 l 24 1044 183 182 I - 123 - l l 109D (2 ) : 26 l l

TABLE 3.4.2 STEAM FLOW DATA REVIEW I BEFORE S/G MODIFICATIONS AFTER MODIFICATIONS DATE 8-10-81 8-14-81 8-16-81 8-22-81 10-12-81 12-11-81 I % RTP 75.4 90.4 96.0 99.5 99.7 98.8 21A 56.19 90.82 115.49 133.79 118.86 132.95 21B 51.92 87.80 109.43 128.60 120.53 136.78 22A 70.70 109.96 126.46 141.35 140.52 144.41 22B 72.55 106.99 125.63 138.72 137.39 142.82 23A 63.59 10;. 28 113.27 123.18 129.18 ' 132.67 R 23B 66.37 106.01 118.91 127.19 132.37 137.69 Q 24A 57.93 93.49 104.38 116.92 121.34 131.87 24B 58.74 97.64 111.57 115.91 120.80 129.99 21A 168.24 169.07 195.53 205.73 182.18 207.38 a 21B 155.45 163.26 185.27 197.75 184.75 213.35 $a22A 206.98 204.51 213.14 217.35 215.38 225.30 5 228 212.39 202.71 211.74 213.31 210.58 222.79 4

• m 23A 188.39 188.35 192.41 189.41 198.00 206.94 SN23B 196.62 197.16 201.98 195.58 202.90 214.78 I
• " 24A 168.67 173.87 175. 64 179.79 182.59 205.70 24B 171.04 181.60 187.73 178.24 181.79 202.77 l

l 1 - 124 - 109D (2 ) : 27 a

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i e) S G Level Change from Q 4 44% to 40% e ! N w 1 NOTE: Steam flow transmitter calibrated to 97% statepoint data.

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No. 22 STEAM GENERATOR STEAM / FEED FLOW AND LEVEL 1 99% RTP

4 42% RTP 97%

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} SECTION 4.0 PHYSICS TESTING This section deals with testing to determine various physics parameters during power ascension testing. Those tests included dropped and ej ected rod case, power coef ficient tests, incore/excore calibration, NIS plateau checks and fl ux mapping. 4.1 POWER AND BURNUP DISTRIBUTION MEASUREMENTS s Power distribution measurements were performed throughout the startup program both at low power (< 5%) and d ur ing po we r escalation up to and incl ud ing 100 % po we r. Using the MID system, these measurements were made to verify design calculations, to show compliance with TECHNICAL SPECIFICATION and to provide calibration data for the excore detectors. Three dimensional core power distributions were derived from moveable detector data through the INCORE code using power to activation ratios obtained f rom design calculations. During the power escalation program, flux maps were obtained at each of the major testing plateaus. At 5 0 % po we r, m aps were obtained fo r the pseudo rod ej ection test and for the pseudo dropped rod tests. At power levels between 50 and 75% power, data was obtained for the incore/excore calibrations. At each plateau, flux maps were obtained in rod configuration which could be expected during normal operations in order to show compliance with TECHNICAL SPECIFICATIONS limits and to demonstrate conformance with acceptance criteria. 109D (2 ) : 28 ~ ~

Fig ures 4.1.1 through 4.1. 5 present the results of some of the more representative power distributions, along with the powe r level, rod position, and burnup at which these measure-ments were made. No abnormalities were detected by the incore detectors. I I 'I I 6 I l l - 147 - 109D (2 ) : 29 N

l i Figure 4.1.1 POWER TILTS vs CORE POWER . ~.. D957,1161PPMe11.' MWD /MTuePT.47e48,6-6-8 SALM INCORE MAP 2010,20.5% PWReBK 3 I CALCULATED POWiR TILTi (NORMALIZED TO 1.000) 1.0071..9879 ^795 ---~3 1.0008. .9884 .9945 .9899 ^74^ ^^10 .rv. rr. .9938 .9946 1.0023 1.0085 1.^445 1.0107 1.0224 SALM IUCORE MAP 2011e29.3% PWReBK D9155,1042PPMe59 MWD /MTuePT.48e47 CALCULATED POWER TILTS (NORMALIZED TO 1.000) ll 1.0103..9924 1.0014 1.0011 .9967 .9919 1.0009 .9932 1.0056 .9945 1.0103 .9949 1.0073 g .9998 .9953.1.0043 SALM INCORE MAP 2030,100% PWReBK DB219,895PPMe900 MWD /MTUePT.54e56e53,55 CALCULATED POWER TILTS (NORMALIZED TO 1 000) i 1.0083..9994 1.0038 1.0017 1.0011 .9952 ... 1.0029 .B .9942 1.0044 .9932. 1.0060 .9954 1.0017 .9975 .I .9976..9974 Il II J i u Figure 4.1.2 1 1 POWER TILTS vs CORE POWER < g lg AND i AXIAL OFFSET t i SALM INCORE MAP 2010e M PWRe8n 0857 1141PPne11.3nW3/nfuePT.47 48 6-e-8 RELATIVE '0WER IN RELATIVE POWER IN PERCENT AXIAL OFFSET UPPER MALF OF C091 iowE R-et ALP -OP--CO*E- ? ;.;1:He*-9P-C 0;; j (te+) (+et) (-e+) (-e+) (+e+) (-e+) .4891 1 3143. 1 2877 -31.319 -30.284 .6474

s. r.m.

iI .6975. .7057 1 3070. 1.3114 -30.403. -30 029 i (+e-) (+e-) (-e=) (+e-) (-e-) i (-e-D I 1 { +0WER TILT IN POWER TILT IN CORE AVERA0E UPPER etALP-07-TC;; ieutfHeALf--Of-Ce#f .;;G 0770;7 (+ee) (-e+) (te+) (*e+) l .9892. .9916 1.0070 .9867 -30.509 I j - - - -.. c rv.... i 1.0038. 1.0155 1.0014. 1.0048 (+e-) i (-e.) (+e-) ( e-) l l l SALM INCORE MAP 2011 29.32 PWR 8K D0155e1042PPMe59mWp/nfuepf.4g,47 RELAT!vt POWER IN RELATIVE POWER IN PERCENT ARIAL OFFSET UPPER MALF OF CORE LOWER MALF OF CORE TOWARD TOP OF CORE j (+e+) (-s+) (+e+) ( e+) (+e+) ( ee) i l .8542 1 1518 e 1 1372 -15 033. -14.096 r .4504 g i .8546. .8447 1.1332 1 1500 -13.899 -14 161 I (+e-) ( e-) (te-) ( e-) ( e-) (+e-) POWER TILT IN PohER TILT IN C0gg avggagg UPPER MALF QF CORE LOWER MALF QF CORE Ax!AL OFFSET g ....) (...) (...) ....) .9991 1.0077

• M4'

-14.302 9924 E .9996 1.0090 .9914 1 0041 (+e-) ( e-) (+.-) (-e-) N I SALM INCORE MAP 2030e g PWae8K D8219e895PPne900nW8/nfuePT.54eSee53 55 9 RELATIVE POWER IN RELATIVE POWER IN PERCENT AIIAL OFFRET I UPPER MALF OF CORE LOWER MALF OF CORE TOWARD TOP OF CORE V (-e+) (+e+) (-e+) (+e+) ( e+) (+e+) .9379 1.0699 1.0644 -6.007 -e.315 .9336 l .9337. .9401 1 0571. 1.0633 -e.197. -e.149 ( e-) (+e-) (-e-) (ee-) (-e-) (+e-) I POWER TILT IN CORE AVERASE UPPER MALF OF CORE LOWER MALF OF CORE AIIAL OFFSET (+,+) (-e+) (+e+) '-e+) .9970 1 0017 1.0059. 1.0007 -e.347 I k .9972. 1.0040 .9938. .9996 (=.=) (+e-) (-e-) (ee-) I F-M- -149- ~

ll Figure 4.1.3 POWER DISTRIBUTION 20% RTP I 11 MEASU2ED AND PERCENT. DIFF. OF FDHN SALM INCORE MAP 2010,20.5% PWR.BK D957,1161PPMv11.3 MWD /MfuePT.47,48 6-6-8 IR P N N .L .K .J. .H. .G .F .E. D C B A .466. .796. .945. .855. .937. .760. .632. 3 rt. 2iii. 1 s 9T---1,2. 1.0. 2.3. 2.3. .505. .919. 1 129. 1.150. 1.165. 1 136. 1 137. 1.097. 1.076. .881. .500. 1.7. 3.4. 3.2. 2.4. .0. -1.1. -2.4. -2.3. -1 6. .9. .7. . 50S c lv44b--.GG &,- 44 &44rar1961-15 8 84r-1 457.-1,168.---1,1-421-4 rGGG. .0"7. .""3. .606. 3 - 2.4. 2.4. 1.8. 3.5. 3.3. .5. -2.4. -=&c43 -2.2. -1 6. -1.0. .8. 2.4. .911. .886. .856. .993. 1 197. 1 011. .779. 1.042. 1.174. .974. .850. .879. .913. . - 2. t. - 2. 4. i r4. .9.~ . 9. --h t r- -314 6 - - 3. 0.- - --1 41.--- . 92 .7. tT6. 2r63 .465 1.102. 1.114. .986. 1.155. 1.163. 1.148. 1.030. 1 138. 1.147. 1 147. .999. 1.121. 1.107. .643. lT-2.96 st. T9 r . 3.- .2. 1 6. a.w. .a. .794. 1 096. 1.130. 1 171. 1.144 1.165. 1.023. 1.077. 1.029. 1.169. 1 155. 1 180. 1.149. 1 114. .774 6. 2.1. a8. - s e s----t s ta 1ser 34 .2 .o. .3. .3. .5T-- _I.... .-2. 4. -2 s +

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.947 1.153. 1.157. 1.0,49. 1.,114. 1.007. 1.012. . 8 7,4. 1.012,. . 9,9 6,. 1.,102,. 1.013,. 1.,145. 1.,126. .919. I gg, _g., y,- t .841. 1.132. 1.054. .790. 1.007. 1.060. .865. .667. .865. 1.062. 1.004. .773. 1.037. 3.111. .838. .I 5. -4.". -2.'. 2.^. 2.4, 23 5. Ev41---1,Gr --2r3r --2 3v---217. 1.2. 4.3v - Ji3. .Gr-, .............................................. t .921. 1.147. 1.150. 1.043. 1.106. .997. .990. .961. 1.005. 1.011. 1.112. 1 029. 1.138. 1.133. .921. C. .9i I?r -' v77-e ts-- -3 r4. -ty dr. .773. 1.114. 1.119. 1 167. 1.133. 1.142. 1.002. 1 062. 1.024. 1.157. 1.130. 1.164. 1.078. 1.121. .776. -1.8. -1.8 7--3r2. -213. .9. -1.e. -2.0. -2.0. -e.7. .2. .2 r .s................... .440. 1.117. 1 129. .949. 1 129. 1.122. 1.111. 1 011. 1.132. 1.138. 1.122. .965. 1.171. 1.158. .445. ft. 2.-1. . 3. .929. .923. .872. 1.000. 1.207. 1.048. .803. 1.064. 1.171. .972. .915. .917. .942. 12 . - - -4. + r --er. 7 e-3 3. 1.I. 1,93 .4. .4. . 91---l r 3 -112,-Gd. 4^... '.". I .530. 1.051. .905. 1.133. 1.183. 1.207. 1.086. 1.206. 1.180. 1.180. .940. 1.057. .526. 3 6 9%-- 1kr7. 4.7. 2.5. 2 11. 1.7. .3. 1.7. 1.7. 4.7 Ova. 7.3. 4.0. .530. .928. 1.128. 1.152. 1.188. 1.171. 1.208. 1.178. 1.167. .966. .533. t- - - - 6v7. - 4r44 311. - h d r - t.t. 2.06 -3.7. 4 7.

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7.3. .670. .799. .944. .861. .941. .817. .690. n2 3 15 3.7. 2.7. 1.9. 1.9. 3.6. 5.0. 6.8. . DIFF I~ =~ . - - -.. ~.. _ ~.. _ I I I -150-I

11 Figure 4.1.4 POWER DISTRIBUTION 30 % FEEP I 11 EASURED AND FERCENT. DIFF. OF FDHN SALM INCORE MAP 2011,29.3% PWR,BK DG155,1042FFN.59HWD/MTUePT.48 47 .E D C B A .H .G .F .L. .K .J R P N M .603. .708. .847. .773. .840. .688. .580. 1.8. .8. 1 6. 1 0. .8. -2 1. -2 0. .510. .895. 1 054. 1.049. 1.080. 1.064. 1 060. 1.009. 1 012. .865. .504. 2.6. 2 6. 1 9. 1 0. .2. .2. -1.7. -2.9. -2 2. .9. 1.3. .503. 1.041. .940. 1.131. 1.138. 1.170. 1.107. 1 153. 1.074. 1.082. .925. 1 043. .515. 3 1.1. 1.2. 1.0. 2 2. 2 0. .3. .3. -1.1. -3.7. -2.2. .7. 1.4. 3.5. .877. .935. 1.173. 1 060. 1.192. 1.107. 1 084. 1 110. 1.167. 1.031. 1.169. .942. .891. .5.' .4. .5. 1 4. 1.2. -2.0. .7. -1.6. .9. -1.3. .2. 1.2. 2.0. .389. 1 024. 1.100. 1.040. 1 175. 1.149. 1.175. 1 115. 1 175. 1 145. 1.166. 1.050. 1 112. 1 039. .594. .5. -1.0. .6. .5. 1.0. .9. 1.1. 1 3. 1 1. .5. .2. .4. .5. .4. .3. .e87. 1.014. 1.085. 1.161. 1 135. 1 163. 1.041. 1.111. 1.020. 1.136. 1.116. 1.178. 1 116. 1.039. .705. 6 -2.2. -2.3. -2.7. -1 4. .3. 12. 1.5. 1 4. .5. -1.2. -2.0. .0. .1. .0. .3. .828. 1.065. 1.141. 1.107. 1 147. 1.024. 1.056. .953. 1 046. 1.011. 1.154. 1 119. 1 165. 1 076. . 8 4 5. _, .7. -1.2. -2.1. -1.9. -1 3. .1. .8. .9. .2. -1.4. .7. .9. .1. .2. 13. .754. 1.057. 1.089. 1.077. 1 078. 1 088. .946. .939. .945. 1.094. 1.098. 1 090, 1 108. 1.045. .769. I .8. .9. -2.0. -1 4. -2.1. .4. .2. 1.0. .1. .1. .2. .2. .2. .1. 1.2. ! IS .i .826. 1.066. 1.145. 1.107. 1.132. 1.001. 1.026. .939. 1.070. 1 041. 1.174. 1 128. 1.169. 1.077. .843. 9 .9. -1 1. -1.8. -2.0. -2.6. -2.4. -2.1. .6. 2.1. 1.5. 1.0. .0. .3. .0. 1.1. * .704. 1.039. 1.084. 1.161. 1.122. 1.128. 1.003. 1.084. 1.028. 1.162. 1.149. 1.189. 1 129. 1.058. . 715. ' I 10. .2 .1. -2.4. -1.4. -1.5. -1.9. -2.2. .8. .3. 1.1. .9. .9. 1 2. 1.8. 1 8. .010. 1.066. 1.142. 1.032. 1.159. 1.128. 1.150. 1.076. 1.136. 1.128. 1.165. 1.047. 1 101. 1.072. .413. 3.0. 3.1. 3.2. -1.2. .4. -1.0. -1.0. -2.3. -2.2. .9. .1. .2. .5. 3.6. 3.5. I 11. . - ~........................ .888. .935. 1.179. 1.060. 1.194. 1.116. 1.067. 1.099. 1.166. 1.040. 1.164. .939. .907. 1.7. .5. 1.1. 1.4. 1.3. -1.2. -2.4. -2.4. -1.0. .5. .2. .9. 3.9. 12 .502. 1 038. .943. 1.125. 1.112. 1 140. 1.072. i.157. 1 125. 1.125. .933. 1.045. .518. I13 .9. .9. 1.3 1.7. .3. -2.3. -3.5. .7. .9. 1.6. .2. 1 5. 4.1. .502. .885. 1.053 1.035. 1.052. 1.044. 1.087. 1.085. 1 071. .895. .514. 1.0. 1.4. 1.8. .4. -2.3. -2.2. .8. 4.5. 3.5. 2.5. 3 3. 'I10 MEAS .602. .494. .822. .751. .858. .734. .413. 1.6. -1.3. -1.4. -1.1. 2.9. 4.4. 3.5. DIFF 15 I l I 11 11 -151-11

Figure 4.1.5 POWER DISTRIBUTION 100% FtPP I ll DIFF. OF FDHN SALM INCORE MAP 2030,100% PWReBK D9219e895PPMe900 MWD /MTuePT.54e56e53e55 fiSUIEDANDPERCENT. .H.. .u.. .F.. .E.. D C 8 A .L.. .K.. .J R P N M .554. .466. .782. .723. .782. .668. .562. 1.6. 2 4. 2.4. 2.7. 2 4. 2.7. 2.7. 1 I .500. .865. .980. 1 003. 1.026. 1.019. 1.011. .976. .962. .812. .478. l 6.8. 6.7. 1 7. 2.4. .4. .3. .8. .4. .2. .1. 2.0. .485. .999. 948. 1.099. 1 116. 1 158. 1 122. 1.143. 1.061. 1.063. .917. .983. .486. 3.7. 3.8. 3 7. 1.8. .1 7. .1. .4. -1.1. -3.3. -1.5. .3. 2.1. 3.9. ,I .829. 934. 1.231. 1.075. 1.192. 1 162. 1.214. 1.168. 1 180. 1 059. 1.226. .929. .828. 2.3. 2.2. .6. .2. .1. -1 4. .1. -1 0. .9. -1.3. .3. 1.6. 2.2. l4 l B 518. .977. 1 086. 1.067. 1 167. 1.152. 1.210. 1 203. 1 238. 1.184. 1 178. 1 070. 1.088. .971. .553. 3 7. 1.3. .4. .5. -2 1. -2.5. .7. 1.7. 16. .3. -1.2. .3. .8. .7. 1.1. t 473. .985. 1 070. 1 172. 1.151. 1.178. 1.087. 1.184. 1 097a 1.185. 1 150. 1 195. 1 109. .989. .457. .5. -2.5. -1.7. -2.5. -1.9. -1.2. 1.1. .3. -1.3. -2.4. .3. 1.1. 1.0. 1.0. 4 3.5. .782. 1.021. 1.131. 1.154. 1.178. 1 076. 1.127. 1 057. 1.132. 1.081. 1 209. 1 181. 1.165. 1 026. .777. 2.3. .1. -2.2. -2.1. -3.3. -2.1. -1.1. .2. .6. -1 7. .7. .2. .8. .4. 1.7. 1.006. 1 104. 1.192. 1 155. 1.157. 1 050. 1.101. 1 041. 1.157. 1 178. 1.218. 1.134. 1.028. .724. I.701. .5. -1.0. -2.1. -1.8. -2.4. -1 2. . 4.' .4. -1.3. -1.1. .4. .4. .6. 1.2. 2.9. .759. 1.008. 1 133. 1 151. 1.184. 1 070. 1.111. 1 033. 1 135. 1 096. 1.212. 1.163. 1.147. 1 031. .787. .4. -1.1. -2.0. -2.4. -2 9. -2.7. -2 4. -2.1. .4. .3. .5. -1.4. .8. 1.1. 3.0. .448. .974. 1.072. 1.169. 1.158. 1 170. 1.070. 1 144. 1.082. 1 171. 1.144. 1 153. 1.054. 1.032. .685. O. .3. .4. -2.3. -1.9. -2.0. -2.5. -2.7. -2.3. -1 6. -2.5. -3.2. -3.2. -3 9. 5.4. 5 3. .557. .982. 1.101. 1 055. 1.179. 1.160. 1 198. 1.154. 1.191. 1 132. 1.161. 1 048. 1.069. 1.034. .587. I1. 1.8. 1.8. 2.0. -1.6. -1 1. -1.8. -1.7. -2.5. -2.2. -4 2. -2.6. -2.3. -1.0. 7.2. 7.1. .830. .942. 1 250. 1.083. 1.200. 1.154. 1.180. 1.143. 1.143. 1.056. 1.213. .950. .863. 2 2.4. 3.1. 2.2. .9. .7. -1.9. -2.7. -3.0. -4.1. -1.6. .8. 3.9. 6 5. .489. 1.005. .950. 1.095. 1.101. 1.130. 1.090. 1.139. 1.103. 1.113. .940. 1.000. .495. 4.4. 4.4. 3.9. 1.5. .3. -2.2. -3.3. -1.5. .5. 3.2. 2.9. 3.9. 5 7. l3 .490. .839. .987. .988. 1.000. 2997. 1.020. 1.017. 1.000. .840. .490. I4 4.6. 3.5. 2.3. -v. -1.9. -1.9. .1. 3.8. 34 3.6. 4.4. .560. .452. .762. .703. .783. .67% .567. MEAS. l I 15 2.3. .2. .3. .1. 2.5. 3 7. 3.6. DIFF I 1 I l I 1 L -152- [-

I 4.2 SUP 81.9 - RCCA PSEUDO EJECTION AND RCCA ABOVE BANK MEASUREMENT I The objective of this test was to determine the worth of the most reactive RCCA " ejected" out of the core from the full power control bank insertion limit. The worth had to be conservative with respect to the value assumed in the Salem Final Safety Analysis Report, also various acceptance criteria on incore power and flux distribution had to be met. Control bank "D" rods were positioned at their full power insertion limit of 188 steps (all other banks out). Steady I state conditions were established with the reactor at 48% rated thermal power. Base case incore flux and thermocouple maps were taken with these conditions. All of the lift coils in control bank "D" were disconnected except for the lif t coil for control rod 1D2, core location D12 (see Figure

4. 2.1).

This rod was withdrawn as requested by the Test Engineer and RCS temperature was allowed to increase compensating for the reactivity addition of the rod (increase in T f 1. 5 F). Various incore thermocouples, avg incore flux detectors, and excore detectors were monitored

I during this rod withdrawal.

After the rod 1D2 was fully withdrawn, another incore flux and thermocouple map was taken (ejected condition). The " ejected rod" was inserted back to 188 steps and the disconnect switches reconnected 153 - 109 D ( 2) : 30 I

I I returning control bank "D" to normal operation. Turbine and reactor power were held constant during this test. The ej ected rod worth was measured and determined to be less than 20 pcm. During the rod withdrawal to 228 steps, the incore thermocouples showed no change in temperature. There was no indication of the rod withdrawal indicated on the excore detectors. Th e flux maps taken before and after the rod wi thd rawal are shown in Fig ures 4. 2. 2. thru 4.2.4. They indicate the ef fects of the ej ected rod on power sharing and incore tilts. I The m ax im um He a t Fl ux Ho t Channel Factor at the peak core 'I T location [FQ (2) ] was measured as 2. 2172, well within,the acceptance criteria of less than 6.09 with the rod ej ected. I I .I I l II 1 - 154 - 1 109D (2 ) : 31 1 I l

Figure 4.2.1 FIGURE 2.14 SALEM NUCLEAR GENERATING STA TION UNIT NO. 2 i RCC INCORE DETECTOR THIMBLE AND THERMOCOUPLE LOCA TIONS N S/G 21 Ccid Lcy S/G 22 Ccid Lcq \\ x' \\ S/G 21 Hot Leg S/G 22 Hot Lcq \\ E \\ /l

N42 l

N43 27C* / I 2 3 4 5 6 7 8 10 II I2 I3 14 15 ~ / TI T4 T5 A 9 Tf T36 M N g C 2SAf 262 IC2 182 ISA2 l ~J ISbr E l 2Se2 ,g y, ,gg, ~ T6 T39 T40 D 0 B A W / ISAI IDI 2D2 10 2 2SA2' T41 T7 To T9 it0 T42 g E Isti 1S92 O w T45 Tis F B C 8 E ( lTl2 ry IBI 2Cr 2At 2C2 263l r $R32) T'3 T* 6 Tar ri I'* SR31) a o C F i Iset 2Say Q* '# 5 Tis T49 T50 Ti T51 O k E A c g A C* i IBC* H F ICI 2Cl lAl 20$ IA2 2D3 IC3 O 2 SRI Ise! lT21 T22 T53 T54 f23 Y' K A g { 2BI ' 2C4 2A2 2C3 123 ' T24 ibb T25 T56 T26 T57 l l/y L g !SD4 ISC3 it,~,: T27 T59 T25 \\ g 2SA4-104 204 103 ISA ! i T3G TEj y 0 f l524 T6; b Oh o k N l1 2S54 ISD3 \\ ISC4. '3s T63 T32 p ISA4l 194 IC4 224 2SA3 l l'** e T'E o T'S R / ,-'p () s 9C* / \\ s m / g S/G 2 4 Ho t Leg I S/G 23 Hot Le~ S/G 24 Ccid Leg # S/G 23 Call Lcq I THERMOCOUPLES I North FLUX DETECTOR PATHS CONTROL RCDS l -iss-

Figuro 4.2.4 l BASE CASE FLUX MAP FOR -= I 1D2 EJECTION I -REf.SUREDANDPERCENT. DIFF. OF FDHN SALM INCORE MAP 2022,47.6% PWReBK D9188,985PPMe245 MWD /MTuePT.54 56e53e55 .E.. D C B A R P N M .L .K ..J. .H .G .F .588. .693. .817. .748. .808. .676. .571. 3.3. 2.7. 2.8. 2.7. 1.7. .2. .3. gr .505. .878. 1.022. 1.033. 1.052. 1.044. 1.031. .992. .985. .847. .496. 5.4., 5.3., 3.4..- 2.p.,. 1.3.. .4. .8...- 1 %3.r. .3..r. 1.4 t. 3v4... ,e s. 2.... % mr... u. % g.., 2...., .499. 1.024.,.944.,1.1.V.',r.138. 1.17.4.. 1 1 L9 ;.k.156.;,1. 0 7.1.r.1. 0 E13.r.. 9 29.,.1. 017... 5 0. 4.0. 4.0.. - 3 0.. 3.5.. 3. 4.,. g .9... .,1. 3 .6.;. -2%'t.r,. .5.t,. 1 J.t. 3 J.,. 3 5 4;. ...,4 %.., o.,. o,4. %,g... 9.3.e .3, 3 .861. . 9 4 L.,1. 214.,1. 0 77 ,,1r. 21J,., h.14 4.,,1 105. *,1,.1 %.;,1. 17#.I.1 0 5 3,.c,1 2 L1 g, 9 4,9. ,. 8 43 g, 3 4 3.3. 3 3. ,, 1. 9.. *,- 1. j2 5,. .A.r, r 1. 3.,.- 1.,p.t. 3 .),.r, 1.J.g,. 3.A., 3 3.A.;, 4 a , e 1.S., ; 2.g., ....j.,..,,.. ..., n....,,..,... 3..r. - . r.*: *... -

• 2

..*3 e .503. .999. 1.102. jr.06o.,t.19a.,1.17p.,k.204c 1 1x1...t 20Ls.1 14,g.r.tf1 Eh3,.r.t 0 4.r.ty 11;u,.1:. 0 4,7... 5 %.. f %, e .A.r 3 .A.r,. .,9,.r 3 2.A g,3 1.,933 2.A. 2.5. 1 1. 1.J.i.e .,L .8. ep., t .J..;, g .45,3 9 3 .675. .Y94. 1.069. 1.172. 1.154. 1.183. 1.062. 1.140. 1.047. 1.157. 1.125. 1.199. 1.117. 1.020. .687. .2. -1.1. -2.9. -1.4. .7. .2. .8. .7. - 2. 3.,, :- 2.A.;,4 2cj a,..:8 s j 3 AA: 24 @ 334AA* * .798. 1.033. 1.137. 1.130. 1.173. 1.044. 1.090. .992. 1.085. 1 034. 1 174. 1 152. 1.169. 1.046. .811. 7. .4. .6. -2.2.,,-2.4g,-2.4f,, 7.,5r. 2 ,-1.8.. ,7.) e,-2.Q.g,7 5., ,-2. 3,...-.5. 2 3 ... r.,5 s. t.JMJ, r2 h

r..

.727. 1.033. 1.100. 1.145. 1.115. 1.111. . 9 8 0'. 1.012. .983. 1.121. 1.132. 1.169. 1.120. 1 044. .744. .2. .4. -1.6. -2.2. -3.2. -3.2. -3.3. -2.9. -2.9. -2.3. -1.4. .2. .1. .8. 2.2. .3,.. c.... ...,,...,,,........... e s............ A s., e as... p.. .792. 1.034. 1.152. 1 128. 1 158. 1.024. 1.054. .97D. 1.094. 1.060. 1.200. 1.150. 1.161. 1.047. .812. t. 3. .5. .9. -2.6. -3.7. -4.4. -5.1. -4.2. -1.5. -1.0. .2. .7. .1. .8. 2 2. .674. 1.005. 1.088. 1.162. 1.135. 1.146. 1.020. 1.101. 1.035. 1.178. 1.165. 1.191. 1.099. 1.036. .694. 10. .0. .0. -1.1. -2.2. -2.3. -3.3. -4.8. -4.1. -3.3. .6. .2. .2. .2. 3 1. 3.0. .576. 1.001. 1.104. 1.035. 1.169. 1.137. 1.166. 1.100. 1.153. 1.147. 1.190. 1.063. 1.091. 1.028. .592. 1. 1.2. 1.3. 1.3. -2.0. -1.2. -2.2. -3.0. -4.4. -4.1. -1.4. .7. .7. .2. 4.0. 3.9. .856. .951. 1.218. 1.065. 1.198. 1.135. 1.131. 1.115. 1.171. 1.067. 1.212. .938., .872. f2 2.7. 4.2. 2.1. .9. .8. -2.0. -3.4. -3.7. -1.5. 1.1. 1.4. 2.9. 4.6. .499. 1.022. .942. 1.102. 1.100. 1.143. 1.083. 1.143. 1.092. 1.116. .936. 1.016. .504. 13 4.0. 4.0. 3.3. 1.2. .1. -1.7. -3.2. -1.7. .8. 2.5. 2.6. 3.5. 5.1. I 14 .499. .856. 1.003. 1.005. 1.020. 1.020. 1.039. 1.030. 1.022. .870. .502. 4.0. 2.7. 1.4. .0. -1.8. -1.7. .1. 2.5. 3.5. 4.4. 4.8. .576. .669. .786. .722. .807. .691. .588. 15 1.2. .7. -1.1. .9. 1.5. 2.5. 3.4. I I I -156-I f

Figure 4.2.3 I EJECTED ROD FLUX PU1P I ' Ir. nkne .e t. - t:, .tdi. L.O. A FL-H

3. s INCORE HAFN.3 47.6% FWR.IA DW 18d. v d5F F M.245 MWD /MTU.PT.49 50

.G .F .J .H D C B A a e a N .6 .n .an3. .o72. .7Y6. .732. .834. .737. .620. 2.J. 2.6. 2.4. 2.4 7.0. 11.0. 11 8. .540. .931. 1.000. .980. 1.040. .986. 1.052. 1.003. 1.022. .820. .515. 2 14.2. 14.2. 2.2. 2.5. .4. .J. 1.2. 4.4. 2.8. .3. 7.7. - I .006.'t.035. .990. 1 075. 1.110. 1.099. 1.080. 1.088. 1.059. 1.042. .931. 1.055. .556. t 1.1. 7.0. 7.0. 2.1. 2.2. -1.2. -2.4. -2.5. -3.1. -1.7. .4. 7.7. 15.8. + .047. .955. 1 181. 1 049. 1.126. 1.093. 1.093. 1.109. 1.114. 1.042. 1 172. .979. .889. 3.2. .8. .8. .8. -4.2. -3.2. -3.2. -2.6. -2.4. -2.3. 4.1. 6.8. t... 3.0. .604. 1.034. 1.075. 1.052. 1 118. 1.126. 1.120. 1.111. 1.128. 1.125. 1.107. 1.042. 1.056. .995. .562. 4 5 9.6. 4.7. 2.1. .5. -1.1. -1.2. -1.7. -1.6. -1.6. -2.2. -3.4. -3.0. -1.7. -1.8. .9. l .734. 1.011. 1.075. 1.123. 1 124. 1.108. 1.034. 1.071. 1.028. 1.097. 1.111. 1.128. 1.095. .968. .471. ~ f, 12.0. 5.d. -1.1. -1.0. -1.4. .9. .9. .8. -2.3. -3.2. -4 2. -2.7. -1.9. -2.0. -1.1. .871. 1.094. 1.099. 1.121. 1.115. 1.025. 1.025. .975. 1.024. 1.028. 1.123. 1.126. 1.116. 1.049. .798. L - I'.12.0. 5.5. -1.2. -1.7. -2.1. -1.8. -1.3. -1 3. -2.4. -3.2. -3.5. -3.7. -2.9. -2,4. -1.6. ( .772. 1.033. 1.104. 1.103. 1 101. 1.058. .972. .971. .975. 1.075. 1.122. 1.120. 1.110. 1.015. .750. 7.9. d.5. .3. -2.4. -2.5. -1.9. -1.5. -1.6. -2.5. -2.7. -3.3. -3.0. -3.5. -2.1. .4. a. _.838. 1.085. 1.1246.1.120. 1.117. 1.025. 14022. . 9 22 Lweek..L,042. 1.155. 1.150- 1.131. J. 0 8 2. .826. ' B& 7.4. 4.3. .7. -2.2. -2.5. -2.5. -2.6. -2.3. -1.6. -2.1. -3.2. -4 1. -4.2. -2.1. .5. l .691. 1.008. 1.125. 1.123. 1.130. 1.110. 1.029. 1.074. 1.053. 1.145. 1.173. 1.176. 1.128. 1.061. .726. I 10. 5.0. 4.8. 2.8. -1.0. -1 8. -2.1. -3.1. -2.8. -2.9. -3.0. -3.8. -4.0. -4.3. 2.2. 2.1. { I1. " 4 tea

• 1 f 4 ?

.sp. .j gg y. '.593. 1.064. 1.134. 1.048. 1.131. 1.141. 1.137. 1.122. 1.148. 1.171. 1.178. 1.117. 1.107. 1.126. .625. 7.0. 7.0. 6.9. -1.8. - 1. 4.. r-J. 4r.s. .2 3.g -3 2.. 4 tr 3.ft.a - 4.,0 g. g-4.4.. - 4 9. 3 74 3.. r3. 3 3,.A.* 5 .875. .987. 1 215. 1.068. 1.153. 1.132. 1.112. 1.147. 1.174.; t.125.

1. 29;b.4,1,.0 7t4h,iO4 %h.t 4 r 9

2 6.3. 5.4. 1.3. .4. .6. -3.1. -3.7. -4.4. -4.1. -5.1. -5.5 1 2.3. 7.2. 3 . eg a .525. 1.073. 1.001. 1.072. 1.113. 1.124. 1.112. 1.142. 1.154. 1.152. 1.027. 1.121.. 5tSw 13 9.8. 9.6. 6.4. .2. .3. -2.2. -3.4. -3.2. -2.1. -1.4. -2.2. 2.1.. 11.0 .au.. .529. .886. 1.041. 1.003. 1.089. 1.049. 1.118. 1.036. 1.099. .930. . 5 49..). a 4 10.2. 6.5. 2.8. 1.6. 1.1. 1.1. 1.2. .2. .7. 1.7. 6 st. 1 I5 .598. .696. .849. .791. .872. .709. .610. 5.6. 2.5. 4.7. 5.1. 4.9. .3. .7. I I I ll -1s,-

~ Figure 4.2.4 H l INCORE POWER TILTS 1 BASE CASE D'f 188 e 9 85F F M e 24 5NW D/ MTU e P T.54,e 56 e 5 3

• 55 y,L4 thcGRf.fu2G22e47.6%P,WReBh L --

I PERC'ENT AXI'AL OFFIET RE(ATIVE P.0WER IN REL A TIVE WswEA IN. I UPPER HALF.OF, CORE LOWER, HALF OF CORE, TOWigRD TQP.0F CORF. i ..(+et) ( e+.) (+e+) (,+ e + ). ( +). (-e+) .9732 . 9,/ 0 6 1 JA75. 1 0304. -3s200 .-2.989 I 1.0(68. 1.,0324. -2 587 .-2.937 ..n. s. ..s s. s. .V300... 9,735 t*, (+e-) (+s-t (-e-) (-e-) I (~ -) 4,+e-s ~ F h e. riuf i ti, F0Wih TILI IN CQRE AVERAGE Or W.h H..L i-Ui,Cuhd

• t LOWEh HALE QF CORE,

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,-2.928, .9879 1.,00 30 ;(=, .9447. 1.d,02W k. I .(+e-) '-.-i ( h -) (~e-) EJECTED CASE 47.6% PWReBK D9188,98'5 PPM M SMWD/MTuePT.49,50 SALM INCORE MAP 2023 RELATIVE.*0WER IN RELATIVE POWER IN PERCENT AXIAL OFFSET UPPER HALF QF CORE LOWER HALF OF CORE TOWARD TOP OF CORE I (-e+) (+e+) (-e+) (+e+) (-e+) (+e+) -3.077 .9476 .9515 1 0265. 1.0119 -3.997 I 1.0241 1 0326 1.0382 -3.252 .688 .9676 I (-e-) (+e-) (-e-) (+e-) (-e-) (+e-) ~~ ~ POWER TILT IN POWER TILT IN CORE AVERAGE I UPPER HALF OF CORE LOWER HALF OF CORE AXIAL OFFSET (+e+) ( ,+) (+e+) (-s+) I .9742. 9782 .9992. .9850 -2.754 1F .9948.1.0528% 1.0052

1. 010 6.)fra I

( e-) (+e-) (-e-) (+e-) I -158-

3 I I 4.3 SUP 81.10 - STATIC RCCA DROP AND RCCA BELOW BANK POSITION MEASUREMENTS I This test had the following obj ectives: 1) To determine the neutron flux distribution with a RCCA below bank indication. 2) To demonstrate the excore response to a RCCA below bank indication. I 3) To determine the neutron flux distribution when a RCCA has been " dropped" from the controlling RCC config uration. 4) To determine the worth of the most reactive RCCA " dropped" f rom the full power RCC configuration. I This startup procedure was performed at 50% po we r wi th Co ntrol Bank D rod 2D3 in core location H-12 (see Fig ure 4. 3.1). Prior to starting the test, a base case, all rods out, equilibrium xenon, flux map and a thermocouple map were taken. The rod was " dropped" using a boron dilution. In order to drop the selected rod, all the lift coils in the bank containing the rod to be dropped were disconnected except the lift coll for the selected rod. A dilution was then started at a r a te o f 15 g pn. The reactivity addition caused by the dilution was monitored using the reactivity computer, and the l selected rod was stepped in to balance the reactivity change. Reactor coolant system and pressurizer boron samples were taken every twenty minutes during the insertion. When the " dropped" rod was fully inserted, a movable detector flux map was recorded in addition to a thermocouple map and excore { detector data. - 159 - 109D (2 ) : 32 lI

I l The reactivity traces obtained during this test, in addition to chemical analysis and primary water integrator readings, were used to calculate the integral worth of the rod. Good correlation was previously established between both the pri-mary water and the boric acid integrators and the amount of liquid added as mea.sured by the induced reactivity perturba-tion. Employing these methods of determining the amount of reactivity added, it was found that the integral worth of " dropped" rod was 100.5 pcm using the traces and 110 pcm using the integrator readings and analysis. Each of these values are well within the FSAR acceptance criteria of less than 250 pcm even after a 10% measurement uncertainty was incorporated. Figure 4.3.1 shows the location of the core of the dropped rod and its effects on the excore instrumentation and on T Figures 4.3.2 thru 4.3.4 show the ef fects of the gyg. dropped rod on power sharing and incore tilts. The maximum Nuclear Enthalpy Rise Hot Channel Factor (F as measured to be 1.6384 sadsMng Ge Core Design AH Report acceptance criteria of less than or equal to 1.68. I - 160 - 109D ( 2) : 33

E Figure 4.3.1 SALEM NUCLEAR GENERATING STATION UNIT NO. 2 RCC INCORE OETECTOR THIMBLE AND THERMOCOUPLE LOCA TIONS S/G 22 Ccid Lcq\\ \\ l \\ S/G 21 Cold Leg l } S/G 21 Hot Leg S/G 22 Hot Lcq \\ l \\ / s-n w N 2 7C* Gy,f ?, s s i 2 3 4 5 6 7 8 9 to eI 12 13 to I5 m \\ TI T3s T3S F B l Tf T36 U N g B 2SAI 282 IC2 IB2 ISA2 'b ' T3h TS l C C E E 'Y N ISDI 2S22 1522 ISC2 T T39 T40 ISAI IDI 2D2 ,g, pf,, / B e T44 T7 78 T9 T40 T42 g l 7 g l f ISCI 1502 '#0 V'E l ,Q IBt 2CI 2At 2C2 2{3 f f B C B E / 0 I 32) T I"6 I' ' T'c SR3/i, a 0 f ISet 25e3 l T4e Tie T49 Tso it6 TI,7 g TSI Ttg l ,go u f a ICI 2ut IA I 205 IA2 203.c IC3 D E m p3 2SBI ,,e, T2t T22 TS3 T$a lT2 \\ Q g g { 26! 2C4 2A2 2C3 IE3 < l T24 TS5 T2S 756 T26 T57 t g l/y 1504 ISC3 T56 T27 T59 T2t a g 2 SAC 1D4 2D4 103 ISA 3 l T6) T6j T2 T30 Of O F L N g ISC4. 1524 2S90 ISO 3 l T3t 763 T32 15 4 184 Ice 224 2SA3 l k T64 '00 p B 0 Y'

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c /' 'F cr9'F I \\ s e S/G 23 Hot Leg S/G 24 Hot Leg / Leg " " W S/G 23 Cold Lcq S/G 24 Cold I. THERMOCOUPLES North FLUX DETECTOR PATHS CONTROL RODS -161-

Figure 4.3.2 BASE CASE FLUX MAP FOR DROPPED ROD I e .*g L A.a.,h L.b. rt b li. M.Edi.. elf". CT. f uHW. 2.'.u I44CDRE.M2010 480 M bl. b9203 e ?v3M M e 195 MWD /4tiU e r I.61 L f .h .J ..h .0 .7 .E D 2 h A n i .4 .i .;a.. .o77 .dOp. .73". .400. .666. .565. } 2.1. 1.3. 1.0. 1.3. 1.1. ./. I 4 .L93. .474. 1.023. 1.01o. 1.040. A.02/. t.002. .7,,. .vo.. 47. 497. I* a.J. 2.0. 2.1. 1.4. .1. .1. s.5. -2.3. -1.&. .G. Y v p .17/. 6.0 eO. .154. 1.126. 1.A21 6.107. 1.122. 1 199. 1.05~. 1.076. .938. 1.03". .004. g i.2. .5. 2.4. 2.6. .4. .0. .7. -3.i. -2.4. .8. .J. 2.4. eg '. '.. S c.... 7 0.1.. '1. 2 U4, 1.v6*. 1 1,G. 1.14J. 1.2v2. 1.144. 1.1o4.

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Figure 4.3.3 1 DROPPED ROD FLUX FU4P ItCA5%E0 MT! PERCCNT. 41rf. Of fhHN S/.lgt @ CORE tts.P2016 e;404 FWJs.AN. De228,993PFfte200eWIvMTLhPT.52 .H .G .F .E D C b A .J R P H M .L .K .488. .819. .959. .883. .977. .885. .749. 1 5.0. 5.7. 5.3. 5.3. 9.4. 14.2. 14.2. .661. 1.116. 1.204. 1.172. 1 245. 1.185. 1.263, 1.207. 1.228. .993. .622. 16.5. 16.5. 5.0. 5.6. 4.0. 3.6. 5.5. 8.8. 7.1. 3.7. 9.o. .614. 1 230. 1.187. 1.279. 1.312. 1.312. 1.298. 1.307. 1.291. 1.261. 1 125. 1.240. .452. 8.7. 8.7. 9.3. 5.0. 5.0. 2.4. 1.6. 2.1. 3.3. 3.5. 3.7. 9.6. 15.6. .995. 1.128. 1.439. 1.268. 1.346. 1.311. 1.335. 1.328. 1.327. 1.254. 1.428. 1.151. 1.030. 4 5.0. 4.6. 3.1. 4 1. 4.1. .3. 1.1. 1 7. 2.7. 2.9. 2.4. 6.8. 8.7. .700. 1.188. 1.243. 1.239. 1.315. 1.315. 1.294. 1.292. 1.300. 1.308. 1.301. 1.226. 1.220. 1.144. .453. 9.4. 5.7. 3.7. 2.7. 3.0. 2.8. .9. 1.3. 1.4. 2.3. 1.9. 1.7. 1.7. 1.8. 2.1. .034. 1.145. 1.221. 1.283. 1.281. 1.255. 1.161. 1.202. 1.154. 1.237. 1.251. 1.275. 1.227. 1.088. .765. 11.2. 6.4. .5. 1.6. 1.6. 1.7. .6. 1.0. .1. .3. .7. 1.0. 1.0. 1.1. 2.1. ~ 939. 1.208. 1.228. 1.246. 1.228. 1.107. 1.110. 1.050. 1.103. 1.095. 1.203. 1.227. 1.216. 1 143. .881. 7 10.2. 5.5. .2. .5. .7. -1.7. -1.0. -1.7. -1.6. -2.8. -2.8. -2.1. .8. .2. 1.3. E .836. 1.115. 1.203. 1.224. 1.173. 1.009. .992. 1.009. .991. 1.086. 1.162. 1.210. 1.182. 1.073. .798. 5.9. 3.6. .2. -1.2. -1.9. -3.0. -3.2. -3.5. -3.3. -3.2. -2.9. -2.4. -1.5. .3. 1.1. gy) .890. 1.144. 1.186. 1.160. 1.113. .979. .940. .894. .972. .999. 1.126. 1.155. 1.151. 1.103. .853. f.5.5. 3.5. .8. -2.6. -3.8. -5.1. -6.5. -5.7. -3.3. -3.1. -2.7. -2.9. -2.1. .2. 1.2. .715. 1.018. 1.139. 1.075. 1.039. .964. .836. .849. .850. .982. 1.056. 1.094. 1.088. 1.026. .720. 10. 1.3. 1.4. 1.9. -5.7. -5.7. -6.3. -8.2. -7.0. -6.6. -4 6. -4.1. -4.0. -2.8. 2.1. 2.1. 2 I 11. .572. 1.027. 1.074. .979. .981. .906. .790. .696. .778' .893. .982. .973. .998. 1.042. .401. .9. .9. .9. -5.8. -6.4. -6.6. -8.1. -0.8. -9.4 -8.0. -6.3. -6.3. -6.3. 2.4. 2.4. .829. .912. 1.101. .886. .850. .667. x403 d .663 .840. .875. 1.061. .912. .873. 2 .2. -1.4. -4.8. -6.9. -7.0. -10.5. 11.3.j -11.1 -8.1. -0.1. -0.3. -1.4. 5.0. .485. .950. .857. .859. .798. .490. .635. .697 .803. .871. .820. .932. .517. 13 .7. .6. -1.8. -7.0. -7.9. -10.8. -11.6. -10.0 -7.3. -5.7. -4.0. -1.3. 7.5. .466. .735. .809. .721. .713. .657. .726. .735. .824. .735. .473. .9. -2.2. -5.3. -6.8. -8.2. -0.1. -6.6. -5.0. -3.6. -2.3. 2.5. ,4 .459. .504. .579. .525. .593. .514. .461. 15 -4.2. -6.8. -4.7. -4.2. -2.4. -5.0. -3.6. hl )', -163-

l i Figure 4.3.4 I INCORE POWER TILTS BASE CASE aALd INCORE.i AP2015 e 48% r'WR e BK UJ223,993 PPM,195 MWD /nTuePT.51 RELnTIVE FOWER IN RELATIVE POWER IN PERCENT AXIAL OFFSET UPFER HALF OF CORE LOWER HALF OF CORE TOWARL TOP OF CORE (,6) (+,+) (-e+) (te+) (-e+) (+,+) .7959 .9975 1.0086 .9980 .633 .027 .9922 1.0016 .9954. 1.0108 .160 .455 ( ,-) (+e-) (-e-) (+e-) ( e-) (te-) POWER TILT IN POWER TILT IN CORE AVERAGE UPPER HALF OF CORE LOWER HALF OF CORE AXIAL OFFSET I (+,+) (-r+) (+,+) ( e+) .9991 1.0007 1.0054 .9948 .319 .se; hhi.004'8 .9922',h1.0075 .9954 I DROPPED ROD 3 A4H JNQGRE, N AP.~41.6,48L PWR e BK. DG228,eB93;FPMe400 MWD /MTU,PT.52 ~ fI PERCENT AX.IAL OFFSET RELA.TIVE E0WER IN RELATIVE,FC,WEg IJ4,,, g. UFfen HALF.,0f,CQNE,,..,, LGuER HALv 0F CGRE. TOWARL TOP: 0F CORE 3 i l ( t e +-) t ,+) (+e+). ( edh - .,.,4,+,+). (, * + ) l c. 1,.o G72.. 1,. 0,51 J., (1sO240. 1.2070- -7.314 -4.895 ..... 3 I .u-J427 .9148 .-5.358. - -5.884 ..DJ3(.., .8 L99 ,~ s' .(+,*) ( e-) .,c, ...s, s, (ten) ., (,+ e - )..,,..,, (-.*,- ), (,,cA, c. I .g CORE AMERADE PGMER TIL.T IN PQEERt T I L T.,I N, 3 AXIAL OFFSET. UP.P.Ek H ALF.,0F, CO RE,, LOMEA HALF OF CGRE ...(,e + A.,. ,4.t e,+ ) 1.1497. 1.1337. -6.363 L,.4542 4,.12 3 9;.., .....e, . 85.73 .8593. .J765 3,694., 4 ,(gte-ky; ( oc ) }( ,( + e, -) inee) I g. -164-

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4.4 SUP 81.8 - POWER COEFFICIENT AND INTEGRAL POWER DEFECT MEASUREMENT I The purpose of this test was to measure the differential power coefficient of reactivity and to measure the integral power defect. The test was conducted at 30%, 50%, 75% and 100% power. The differential power coefficient is defined as the change in core reactivity per percent increase in core power fo r the programmed T change. This coefficient consists of two avg components: the moderator temperature coefficient (pcm/ F) and the doppler coefficient (pcm/% power). The moderator temperature coefficient contribution results from a programmed change in the reactor coolant system average temperature fo r a unit change in core power level. This component is negative under normal operating conditions. The doppler coefficient of reactivity is always negative for low enrichment uranium 238 fuel due to the broadening of the U capture resonances. This effect is significant over the range from hot zero power to hot full power due to the large pellet temperature increase with power generation. The integral of the doppler I coefficient with respect to power is defined as the doppler defect. Measurement of the doppler defect is required to verify that the shutdown margin assumed in the Safety Analysis is conservative. I - 167 - 109 D (2) : 34 . I

F h J I During the power escalation program, the total power coefficient was measured over power levels ranging from 20% to 100% of full power. The measurement technique consisted of first decreasing and then increasing the power level 20%, in steps of approximately 10% using the E-H control system to change the generator electrical load. Reactor power was matched to turbine power by insertion of the controlling bank. Reactivity and T were monitored during the error power changes. At the power level "end-points" additional data was gathered including heat balance information for determination of the actual power level change. The power coefficient was determined from ratios of the change in reactivity to the change in power ( Ae/ AQ) corrected for variations in the Xenon concentration and T vs. Terror. Corrections to the measured data for avg Xenon changes over the duration of the measurements were based on Xenon histories generated from the point model Iodine / Xenon equations. No corrections were applied to account for possible effects of flux redistribution which was assumed to be negligible over the range of measurements. The doppler defect was determined by extracting the reactivity effect due to changing T fr m the reactivity measurement avg during the power change. - 168 - 109D( 2) : 35 l l d

I Table 4.4.1 and Figure 4.4.1 present the data obtained and the measurement results. As can be seen in the fig ur e, several measureuents were close or appear to have exceeded the FSAR limits, especially at 100% RTP. Reviewing Table 4. 4.1, it can be seen that those measurements nearest to exceeding the design criteria of + 30%, were those measure-ments taken with the Control Bank D rods starting or ending at a position greater than 210 steps. No t calculating the required value was attributed to the difficulty in deter-mining the rod worths f.n a very low worth region (200-228 steps). To confirm this the 100-90% RTP test was repeated with the starting position of control bank D at 205 steps. The design criteria was easily met. Fig ure 4. 4.1 sho ws one point at 100% below the FSAR limit. The point was calculated from a power swing of 91-93% RTP with rods movement from 200-219 steps. This calculation was repeated 90-98% with rod movemer.t from 175-210 steps and was well within the acceptance criteria. Rev ie wing the data obtained during Unit 1, Cycle 1 startup and comparing it to Fig ur e 4. 4.1, it can be seen that the data scattering is similar, thus further supporting this analysis. I I .I - 169 - 109D (2 ) : 36

I TABLE 4.4.1 POWER AND DOPPLER = COEFFICIENT REVIEW POWER BANK D POWER POWER LEVEL POSITION COEFFICIENT _ COEFFICIENT DATE (%) (STEPS) -(PCM/% POWER) -(PCM/% POWER)

I START FINISH START FINISH MEASURED DESIGN PEASURED DESIGN 7-3-81 30.14 20.68 148 122 16.8 16.2 (17.4)

• 14.9 (16.7)*

13.8 (30%) 20.68 29.58 122 150 17.9 17.2 7-22-81 45.29 33.11 188 154 12.7 14.1 12.0 13.2 (50%) 33.11 22.36 154 131 15.8 15.1 .I (16. 2)

• 14.9 (15.5)*

13.7 22.36 35.35 131 177 16.5 15.8 8-6-81 75.97 65.09 228 176 9.09 7.98 (75%) 65.09 54.23 176 154 11.07 10.16 (11.23)

• 14.34 (10.16)
• 12.10 54.23 66.06 154 193 11.39 10.15 (9.62) 14.21 (7.86) 12.24 66.06 69.67 193 228 10.15 7.73 8-21-81 99.76 90.29 211 180 8.90 13.8 7.1 11.5 I

(100%) 90.29 80.25 180 162 10.49 8.81 (10. 21)

• 14.0 (8.59) 12.1 80.25 90.75 162 200 9.93 8.37 90.75 92.90 200 219 6.65 13.96 4.84 11.3 I

10-13-81 99.52 89.70 205 175 9.86 7.60 (10.09)

• 13.8 (7.76)
• 10.9 (100%)

89.70 98.38 175 210 10.32 7.95 ( )* average value lI 'I - 170 - 109D(2) :37 1

Figure 4.4.1 I- *- - J.; s uo ri.e _ -N popys f.a Pawst CosHk.G ~ l -,w ~~s vs essa enarsia .x \\ t t t

• e-7r S

r= \\ ~ l mv---

1. r

's m. -1 +. ~. l T s, ~ w 'r'xXs

== m .d- \\X-l',; a esa i>~ or-m.zr nwn.a = m Doppe,4,_ _ _.t. ta g o g 0 1 : X. I T X s x g g 2 .z _r # ( h m" I - L.,. .A r ~ 's ~ 4: ~ v x [n 1 N c a !.= W m n,!- i=s4RE,rTr s- ' -Ma*. i, _ =- e- - x - m.. nessnus o.r.na.rpy X --[ u j = N-Myr 9, = L As 307. TE3n % 6s 5D7=

1. snwrnot, l

• ' ^ *# #

f-cs7d

980 truts 9m tao 7, c ' - -,

} 2. l l I 1 y .O ML a

r. -

l % Power D P- _. _.1 I l Ed L ------i -171-l

I I 4.5 SUP 81.11 INCORE - EXCORE DETECTOR FLUX DIFFERENCE CALIBRATIONS The power range nuclear instrumentation system produces output voltage signals proportional to the currents in the top and bottom neutron detectors of each channel. These signals are used for axial power imbalance (delta flux) indication, upper and lower quadrant power indication, process computer moni-toring of delta flux, and the generation of the F ( AI) function which reduces the overtemperature T trip setpoint for adverse axial power distribution. I Because of a variation in detector sensitivity and placement, calibration of each output voltage is required to produce an excore indicated avial power distribution which reflects actual core conditions. Although this test was formerly scheduled at 75% power as part of the startup program, it was actually performed at 50%, 75% and 100% power to comply with TECHNICAL SPECIFICATION surveillance requirements and to provide the necessary " tuning up" before reaching higher power levels. I The minimum requirement for performing an incore-excore calibration is three flux maps at different delta flux ( AI) values, ideally with as large a spread in values of delta flux as possible. Concurrent with the flux maps, readings of power range currents, T nd calorimetrics are performed. em - 172 - 109D(2):38 I

Different values of AI are obtained by varying rod position. Typically, a reference flux map is taken with the control bank at 200 steps. The rods are then inserted until the AI is 1-2% from its negative limit and left there. AI continues to move slowly in the negative direction, turns around and becomes more positive. It is during the negative peak that the second flux map is taken. Then, the control rods are I fully withdrawn (228 steps) ; the AI rises and slowly approaches a positive peak during which the third flux map is taken. Control rods can be inserted to prevent AI from exceeding its positive limit. Below 90% power, TECHNICAL SPECIFICATIONS allow up to 16 hours outside of the target band limits on axial flux difference without penalty for the performance of this test.

However, above 90%, no allowance is available and AI must remain inside the + 5% band, which means a maximum spread in data of

< 10% on AI. (To date this has not been a problem). I The linearity of channel response with measured incore power distribution for each of the four power range channels, a pre-requisite for adequate calibration, is demonstrated by the data presented in Figure 4.5.1 for 100% power calibration. As used in this calibration, excore axial offset, A0 s EX, defined as: T B x 100% AO = EX T + B I - 173 - I 109D ( 2) : 39 I

I where IT ""d I re the currents from the top and bottom B detecto rs, and the incore axial offset AO s deH ned as: INC T-B x 100% AO = I INC p ,p T B where P and P are the fractions of core power in top and T B bottom halves of the core as derived from the moveable detector flux map data. Calibration of the output voltage signals requires a determi-nation of the expected full power detector currents under the conditions of zero incore axial offset. Excore detector data was taken during the flux maps and scaled up to the f ull po we r condition through calorimetric measurements of core power. The excore detector currents vs. incore axial offset were fitted to a linear function and the calibration currents were derived by evaluating the function at zero axial offset. The results are plotted on Fig ures 4. 5. 2 through 4. 5. 5 and listed on Table 4. 5. 2. Table 4. 5.1 shows the data used to generate the figures for the 100% incore/excore calibration of August 22, 1981. I I - 174 - 109D (2 ): 44 I I

E Tdble 4.5.1 100% POWER (8/22/g1) EXCORE DETECTOR FLUX DIFFEREtlCE CALIBRATION DATA SHEET CALORI-INCORE EXCORE MAP METRIC QUADRANT AXIAL FP FP 4 O POWER CHANNEL Itop Ibot AXIAL OFFSET Iton Ibotton G. RTP) 0FFSET (%) 030 98.16 41 385.3 441.7 -6.367 -6.82 392.5 450.0 42 412.9 486.3 -8.16 420.6 495.4 43 379.9 411.6 -4.01 387.0 419.3 44 367.3 393.7 -3.47 374.2 401.1 031 97.97 41 376.9 452.7 -10.817 -9.14 384.7 462.1 42 402.5 500.0 -10.80 410.8 510.4 '43 369.8 420.5 -6.42 377.5 429.2 44 358.3 402.8 -5.85 365.7 411.1 2032 98.23 41 390.4 429.1 -2.634 -4.72 397.4 436.8 42 419.8 472.2 -5.87 427.4 480.7 I 43 385.9 400.7 -1.88 392.9 407.9 44 372.7 382.6 -1.31 379.4 389.5 Completed by __________________.Date _______ Time _______ Senior Reactor Operator ______________.___ Date _______ Tine _______ The equations of the lines to be 9raphed (see Fisure 27 Reactor { Ensineerins Manual) and convenient endpoints are as follous: TOP: Y= 401.9 + 1.561

• X (60s 495.6)

(-60, 300. 2) I 41 80TT0ti: Y= 429.3 + -3.074

• X (60, 244.9)

(-60, 613.8) 42 TOP: Y= 433.0 + 2.025

• X (60, 554.5)

(-60, 311.5) BOTTOM: Y= 471.6 + -3.615

• X (60, 254.7)

(-60, 688.5) 43 TOP: Y= 398.3 + 1.889

• X (60s 511.6)

(-60, 284.9) BOTTOM: Y= 401.7 + -2.590

• X (60, 246.3)

(-60s 557.1) I E 44 TOP: Y= 384.2 + 1.680

• X (60, 485.0)

(-60 283.4) r.' BOTTOM: Y= 383.2 + -2.634

• X

.(60s 225.1) <-60, 541.2) i, I I I ~ -175-

Table 4.5.2 100% POWER (8/22/81) l( EXCORE DETECTOR FLUX DIFFEREHCE CALIBRATION WORKSHEET INCORE g QURDRANT FP FP FP FP CHAHHEL RXIAL Itop Ibotton V;op Ybotton Delta V 0FFSET (%) I 41 +60 496 245 42 +60 555 255 43 +60 512 246 44 ~ +60 - -485 --225 41 +30 449 337 42 +30 494 363 43 +30 455 324 44 +30 435 304 41 +20 433 368 42 +20 473 399 43 +20 436 250 _ _ _ _ _ ~ _ _ 44 +20 418 330 41 +10 417 399 42 +10 453 435 I. 43 +10 417 376 44 +10 401 357 I 41 +0 402 429 8.33 8.33 0 42 +0 433 472 8.33 8.33 0 43 +0 398 402 8.33 8.33 0 44 +0 384' 383" 8.33 8.33 0 41 -10 386 4'60 42 -10 413 508 I 43 -10 379 428 44 -10 367 410 41 -20 371 491 42 -20 392 544 43 -20 360 454 44 -20 351 436 41 -30 355 522 42 -30 372 580 43 -30 342 479 I m 44 -30 334 462 41 -60 308 614 I 42 -60 311 689 43 -60 285 557 44 -60 283 541 Completed by __________________ Date _______ Tine _______ Senior Reactor Operator __________________ Date _______ Time _______ WO #: Date issued Date Completed: I Date Rx Ensr Manual, Table 2 was Updated: -176-

j SALEM 2 FIGURE 4.s.1 RERCTOR ENGINEERING f1RNURL 100% 'PWR 8/22/8I UNIT 2 7 CHANNA A N-4 L, N-42, N-43, N-44 LINERRITY CHECK FOR IN/EX CRLIERRTION a i I-1 .i 2-I h \\ j .\\ \\ \\ \\ p, J \\ \\ q s \\ \\ \\ \\ I \\ L \\ \\ T ^( \\ kg ~ 3 g \\ ( \\ \\ v \\ i .r t d \\ \\ \\ \\ \\ \\

. g.

\\. i \\ l \\ \\ i Q ( \\ \\ \\ C \\ \\ \\ 's g_ g N \\ l\\ l y 'lI ,s t l A \\ \\ \\ l \\ rg \\ \\ \\ A \\ 2-i t I i \\ \\ s \\ \\ i \\ 1, \\ \\ \\ \\ 6 \\ -u-s s 2 \\ \\ \\ \\ t i i \\ \\ \\ \\ \\ t T \\ g_ \\ \\ \\ \\ s \\ t \\ \\ \\ \\ \\ \\ \\ g \\, \\ GI-L \\ \\ \\ \\ p A l\\ \\ !\\ i Y I 7 Y E Y I E T E I -177-tel trJM "]Q Q Q,2,[Q 3D 1

SALEM 2 FIGURE 4.s.2 REliCTOR ENGINEERING MRNUf!L 100% PWR 8/22/81 UNIT 2 4 ~ Dt:.1 t.CTOR N-4 l NORMRLIZED DETECTOR CURRENTS 09 i i g i i la!l .i l_ [_ 4 0$ s j i / \\ / 09 L / P, V l t '08 ~ i i i r f i i i', i I. t 'I '88 gg f s \\ I t \\ i l i M i i GI O j ( v fi b / 1 e d g i s 8 W 't a t_ o 4 <g t-, \\ 'N i I[ J \\ ,az-a 1 s / ( OE- / \\ r a / [i .j 09-t \\ as- ~ f s s s l k j' I o q l l I I! k! t E E E E E,,. 5 E E E e o o n m m a

• • e*g.

j SRLEM 2 ' FIGURE 4.s.3 ttt.r1CTOR ENGINEERING MRNURL 100% PWR 8/22/81 UNIT 2 ( DETECTOR N-42 NORMFLIZED DETECTOR CURRENTS 69 9 i .J It i vi i i l N It i B A e 6 1 + gg i, j k / l L b i O t-i t l c i gJ OS ~ i ; I I i l[;. f I i ( l I O2 i, '~ n 1 \\1 1 j b-( i \\ GI C m ,q L , \\ u. o 7, \\ G a-GT-3 ( w cc \\ T i m h 02-i 3 ( I.. J \\ gg-i h-I; k I r .l 9 gy_ t; i \\, la .g g_ t 1 i i s l 1 I k I qq_ a ca m m m m ca m m m I w tn e to a to no n a n ~ N LO U3 to LO v v 'O M N 1 l (:due-aac pu) HGMH03 8013m(I -179-

FIGURE 4.s.4 SRLEM 2 RE!iCTOR ENGINEERING MRNtil ?' 100% PWR 8/22/81 UNIT 2

s

~~ DETECTOR N-43 NORi1RLIZED DETECTOR CURRENT 5 09 6i it 1 t i pi 4 I!ti , 4 1 i 6-i. I 4

1. 1 i

ii i if tt ii i i 6 i i ,f I I 4 ( ^ Q \\ Y h s 1 i A _qq t j .4 Ob g ~ /. l g I 1 8 l I / 1 I l I t i / i i l.02 j ~ ~ l +] \\ - 21 C g L. O b - I w } il g C g m 't i i ,at-g J.,I + m !tI l f(a f s 6 q[ i 02- ) \\ E / e \\ GE-r i i / h I- / \\ i Ok- -?] \\ i 09-e, p h 4 a; n l l l l l I l i . #.g g_ <a 5 m n ~ = m o n 4 (5dWE DJOpu) R G 'dO3 M0137I M -180-I t

l l SRLEM 2 FIGURE 4.s.s 4 FERCTOR ENGINEERING MRNURL qi 100% PWR 8/22/81 UNIT 2 } ~~ ~ DETECTOR N-44 NOFMRLIZED IiETECTOR CURRENT 5 69 r ll t 13 11 i i til 16tiH litt i lii i, it l j i, .i I 4 i 6 6V ii il j. g i 6 i 11 4,,VI li is, i i i 1l! li i l \\, i i/ 'gg i i l 4 + i s t A Ok ( 4 i i / g I b' ~ ~ i If 6: . b 7 i i li f, 3 4 4 s. -2 t t' Ii l i i V i A i i i i v1 6 i. l ii l' 02 3 q t t I 1. I 1 l \\ / ] + V gt [ \\ I, g \\ / e q 3 C f l / K g y / a. q / i -g 7_o 4 e i

=;

i i t / \\~ ,'az-ll l t x si i f I \\ GE-y / 5

0) ----

bl i s ? ,/ US-f . 6 l i e, p l\\} i I ( l I 6l 1 ? tt i i i it' t- .ti ttii i it g c,._ I E E E E. E E E E m m o q y m M N c :: din-aJ o itu).LNMR3 M0D31.2[I -181-f

I I 4.6 SUF Gl.12C - INTERMEDIATE AND POWER RANGE CHANNEL HIGH VOLTAGE SETTING VERIFICATION The objective of this test was _o verify that the 800 volt detector settings for each detector of the intermediate and power range channels is correct. This is done by varying the detector voltage from 200 - 1200 volts in 50 volt increments while at greater than 95% RTP. The 800 volts that the detector is manually set for is checked to insure it is at least 100 volts above the " knee " of the curve drawn comparing voltage to detector output every 50 volts. The intermediate detectors had no change in detector output from 200 volts to 1200 volts. The power range detectors varied approximately 5 microamps over the same voltage range with the exception of Detector N43. Detector N43 varied 50-60 microamps mostly in the area of 200-300 volts as can be seen in Figure 4.6.1 from plateaus performed on 10/26/81 and 11/19/81. Initially their was no concern over the variance in voltage because the voltage the detector operates at (800 volts) was well above the knee of the curve at "400 volts. An incore/excore detector calibration was performed at 50% and 100% RTP during initial startup testing. The 100% RTP calibration was performed at 900 MWD /MTU on August 19, 1981. The calibration was repeated on October 26, 1981 after a ( - 182 - 109D(2):41 l

I core burnup of 2230 MWD /MTU when quadrant tilts were indicated by the excore detectors. The incore detectors indicated their was no incore tilt. The excore detectors were recalibrated. On November 9, 1981 tilts were indicated again on the excore detectors. Again the incore detectors indicated no incore tilt. The extrapolated full power currents for the four power range detectors were plotted as core burnup ( see Fig ure 4. 6. 2). Reviewing core power distribution vs. burnup in the Co re Design Report, the periphery assemblies are expected to produce less power as the core nears 3000 MWD /MTU and then start producing more power af ter 3000 MWD /MTU. Since the neutrons that the excore detecto rs " see" is directly p ro po r tional to the neutron production in the periphery fuel assemblies, it is ex pected that the output current from the excore detectors will vary with periphery assembly ' power sharing. This can be seen in Figure 4.6. 2. The slope of the currents with burnup are similar for power range detector N41, N42 and N44. De tecto r N43 slope is sharper causing the indicated tilts and requiring more frequent inco re/ ex co re detector calibration ( we e kl y). Review of the incore flux maps indicated that all quadrant periphery fuel assemblies were sharing the core powe r equally, as designed. On November 2 4, 1981 following a plant shutdown the N43 detector was replaced. The excore detectors were recalibrated and tilt indications have not reoccurred to date (Ja n ua r y, 1982, 4600 MWD /MTU). 'I l 109D (2 ) : 42

Figure 4.6.1 g i 4 I J I ~ 5 . 3 6g ~ h,,. - ~ gi e ..s a ur N f 17; s .~ o. +M+_ I x a, s e = .u

• ++++_

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• =

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~c 1

'i 1 - q

~

s t = g x N

0. -

N - =~ y x ~ = Z A .. E i I, _L y _x '.'s- 's .x .x / gx. 1 -N, 1', D NT I w IE h h I fM)M*D m m m m m m m m -184-

Ic4 os O O O O C O O o o o o o o o o o O 3 o o O N 4 W C V = _1Eigure - -s-m r4 e d 4 Os-c-to oc m 1D 10 C Q (D C G r-r- N N e,,,,4.6.2 ae _L,_ -_--4 .--4-..-,.-_._4-..... -. + Y( ~. )_, __.-_.---...=..-----.===r---*------=-- -. = = - ._..-.4 - M ~~ ~

_..4 i"-*

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p

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