ML16315A361
| ML16315A361 | |
| Person / Time | |
|---|---|
| Site: | Watts Bar  |
| Issue date: | 11/10/2016 |
| From: | Tennessee Valley Authority |
| To: | Office of Nuclear Reactor Regulation |
| Shared Package | |
| ML16319A191 | List: |
| References | |
| Download: ML16315A361 (125) | |
Text
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7.2.2 Automatic Reactor Control System (2-PAT-6.1) (continued) FIGURE 7.2.2-3 RCS Auctioneered Tavg vs Tr"r Decreasing Tavs Transient DatAnare HJstory 1l-lul-2016 12:20:OO to lt-lul-2016 I'2:5E:OO (EgT) i*4: FoctTed SGdy StdE ill:zo:oo EI,T t2i26i20 eDr u!:3234,o ErrT l2:3t300 EUT !234S:2O EDT [l:st:{o EI,T 12:st:OO EDT al-ftI-20a6 al-rfl-2018 ilt-rul-20-f6 al-rul-2016 tt-ful-2016 Ll-llrl-2O16 Il-lul-tO16 11: lll:23:@. Qs, l2z77t5l 3z 12t{.7t25 ltc {1e54:Oi! Lc-Y lli-Y Urits oTlrtl.# cTlttlts o?txut3 uTlttlts ffi:Er) (z) :2-r3o99nro{!r6A srmil,DsrEPurr (Y2:rrz) nc rnEF o 560 231 sto SIEPS 1r3 s70.o571 t!t3 w, lltl. (3) r2-8r05/TO{99A (I2rU2) rrl. DE6F s69.!r!lE 569.4323 559.9223 HIGTIST TAIG (flrcTrfiCEn) sCO 580 ffiGF 5X).2{41 5rc.2r5E 963.9375 559.1{Ar 134
7.2.2 Automatic Reactor Control System (2-PAT.6.1) (continued) FIGURE 7.2.24 Rod Speed and Direction Demand Increasing Tavs Transient DatA,rlare H'islory lt-lul-?016 li:1.7:O0 to u-lu'l-:oL6 tl:+f:oo (EoT) lll: Steady Sta0e 1fi2: S-trrEd tloving Tl: MTcet Sbrt Corfol Rods Slcody S[* Ll:T7:OO EDT Ll:2T:TO EDT T1:25:UO EDT TLi29:3(} EDT LT:33:{O EUT LL:37:tO EIrf LLi42,3OO EDT Lt-ruI-2016 Lt-ful-2(,I.6 Lt-luI -2016 Ll-Iul-2016 rL-rul-20r.6 tl-fuI-2016 tt-lul -2016 Il: Ll:17159 12: Ll.:21:O3 13: l-1:27:11 14:11:33:t2 Point fD,/Dcscriotion Lor-Y r{i -Y Uni tg 07 / LLI tC a7lLLltG O7ltttl:6 A7/LL/L6 ffi2:uz) ctlST Ro BilK D srEP ctI;rrT (2) f,2-U996lY9I26A (rr:U2) RoO SPEED o 23r STEPS t9t 192 205 19S o too {8.31696 48. 33696 {E.33695 E.l33l5rl 135
7.2.2 Automatic Reactor Control System (2-PAT-6.1) (continued) FIGURE 7.2.2.5 Rod Speed and Direction Demand Decreasing Tavs Transient DatAh,are Hisrory lr-lul-lo.L6 t::20:oo to lt-lu'l-toL6 tt:sBtoo (EDT) Ml: Sbdy $afre M2 Sterted Morib Strt Canh Rda i t2:20:oo EDT 12:26:20 EDT 12i32:4O EDT 12:39:(x' EDT 12:45:20 EDT 1:!:51.:40 EDT 12:58:OO EDT 1r-lul -z016 Lt-lul-2016 tl-lul-2()16 tl-lul-2(}I'6 tl-Jul-2016 ,'t-lul-2016 lr-tul-2016 LI: l2:23:Ol rl.Zt L2r27:5E X3: Llt17226 14: l2:53r59 Lor-Y Hi-Y Units O7fLLILG O7/LLILG oTlLL/L6 07/LLlL6 12-15t53 :U2) CONT Rm $lX O STEP COUilT o 231 STEPS 193 r.93 L77 191 Y2-L7996/Y9126A (X2:U?) ROO SPEED o roo 48.33696 48.33696 48.3t596 E.lO59E 136
7.2.2 Automatic Reactor Control System (2-pAT-6.i) (continued) FIGURE 7.2.2-6 Pressurizer Pressure lncreasing Tavg Transient oatAflare History !l-lul-to:6 Ll:17:oo to rl-lul-2016 ll:.12:oo (EDT) l.t:17:oo EDT 11:21:10 EDT 11:25:20 EDT LL:29:30 EgT Lt:33:40 EDT 11:37:5O EDT 1l:42:O(, EDT L[-]uI -20r.6 .Lt-luI -2016 ,.1-f uI-2016 tl-fur-20I.6 Ll-luI -2()16 u-lul-2(}16 tr-:ul -2()16 Point fDlDeserietion tI: Ll:lt:fi) 12: ll:2tr02 ll3r Il.:27 tLr l},l: 11r35:0t Lor-Y Hi-Y Units o7lttlt6 07/LuL6 o7lLtt,^6 @:ua) Q) Yz-tzzo/m4$ol- CI2 :u2) conT Rfl) Bt'tK I PRESSURE D STEP COtt{T O 23r sTEP5 r92 192 205 AT/U.lLB 195 (1) a2-7v72/n48Ll (I2:U?) PZR 2I5O Z3SO PSr6 2230.808 2231.239 2282.507 ez3E.5r3 PZR ? PRESSURE 2I5O 2350 PSIG ?213.396 2213. E28 2254.7Et 224L.L61 L37
7.2.2 Automatic Reactor Control System (2-PAT6.1) (continued) FIGURE 7.2.2-7 Pressurizer Pressure Decreasing Tavg Transient Datlilane xistory l.l-lul-2016 12:2o:oo to ,.1-lul-2o16 12:58:oo (EDT)
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7.2.2 Automatic Reactor Gontrol System (2-PAT-6.1) (continued) FIGURE 7.2.2.8 Pressurizer Leve! and Level Setpoint lncreasing Tavg Transient oa?-A'4are History r1-]ul-2016 lt:.t7:00 to Ll-lul-2016 lI:41:00 (EDr) HT RBSS *eed h Auto 1t:17:oo EDT LL:21: rO EIIT ,_t:trs32() EDT Ll:29:30 EIIT tl:33:40 EDT t1:37:50 EIT 1t:42:OO EDT tl-Jul-2016 Ll-lul-2016 ar-lul-2016 It-rul-zot6 I'l-lul -2016 u-lul-2016 Lr"-Iul -20.t6 il"l: Ll:I't:ol tla! Il32t!o3 13! u!t7:u ras I'LrSE:oo
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7.2.2 Automatic Reactor Control System (2-PAT-6.1) (continued) FIGURE 7.2.2.9 Pressurizer Level and Level Setpoint Decreasing Tavs Transient oatAtare H'irtory tt-lul-2o16 12:20:oo to ll-lul-2016 t2:sB:oo (EDry) l{1: Sleady $# Mt Sffit ovirt Stad Confol Rorle 12:20:OO EI,T U132632O EDT 12:82:4O EDT I2:!X):fi! EDT 1ll:45:20 EtT Lll:Sl.:{o ET I2:58:OO EDT Il-rul-2016 tr-rul-2ors tt-lul-zote u.-rul-2016 tl-rul-2016 It-rul-2016 rr.-lul-2016 11! l2!21:ol frt. L2.27.57 It! 12;{7!25 I,t! Ul!S4!@
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7.2.3 Automatic Steam Generator Level Control Transients at 50% Power (2-PAr-6.2) This test was performed as part of test sequence 2-PAT-6.0, Test Sequence For 50% Plateau, and performed in conjunction with maintenance work order activities to collect data needed to calibrate and tune the feedwater control system components. The test began on 6/17116 and was field work complete on7116116. 1.0 Test Obiectives The objectives of this test were to: 1.1 Demonstrate proper operation and automatic response of the Steam Generator Level Control System, for each Steam Generator, during steady-state and transient operation. 1.2 Satisfy, in part, the requirements of UFSAR Table 14.2-2, Sheet 30, Automatic Steam Generator Level Control Test Summary. 2.0 Test Methods This test procedure demonstrated the operation of the Steam Generator Level Control System at 50% power. The control system was tested by observing each main feedwater reg. valve's response to 5% level setpoint step changes. One steam generator was tested at a time for both decreasing and increasing setpoint changes. ln addition, correct operation of the main feedwater pump master speed controller was tested by observing the AP difference between the actualAP and the Program AP was within t25 psid. 3.0 Test Results AllAcceptance/Review Criteria were met or resolved as delineated below. Acceotance Criteria 3.1 Section 6.1 (Main Feedwater Reg Valves) 3.1.1 The indicated Steam Generator Level undershoot was less than 4.0% below the program level setpoint following automatic recovery from increased Steam Generator Level. This criteria was met for allfour Steam Generators. STEP DECREASE s/G #1 slc #2 S/G #3 s/G #4 U ndershoot 2.2yo 2,Lyo 2.3yo 2.20/o L47
7.2.3 Automatic Steam Generator Level Control Transients at 50% Power (2-PAT-6.2) (continued) 3.1.2 The indicated Steam Generator Level overshoot was less than 4.0o/o above the program level setpoint following automatlc recovery from decreased Steam Generator Level. This criteria was met for all four Steam Generators. STEP INCREASE s/G #1 sle *z s/G #3 S/G #4 Overshoot L.7Yo 2.3Yo L.gyo L,9OA 3.1.3 Indicated Steam Generator Level returned to and remained within !2o/o of the program level setpoint within 10 minutes following automatic recovery from increased Steam Generator Level. This criteria was met for all four Steam Generators. STEP DECREASE S/G #1 slc #2 s/G #3 s/c #4 Time 9 min 9 min 9 min 9 min 3.1.4 lndicated Steam Generator Level returned to and remained within t2% of the program level setpoint within 10 minutes following automatic recovery from low Steam Generator Level. This criteria was met for all four Steam Generators. STEP !NCREASE S/G #1 slc #2 S/G #3 S/G #4 Time 9 min 8 min 9 min 9 min 3.1 .5 lndicated Steam Generator Level was within t2o/o of the program level setpoint during steady-state operations. This criteria was met for all four Steam Generators. L42
7.2.3 Automatic Steam Generator Level Contro! Transients at 50% Power (2-PAT-6.2) (conti nued ) 3.2 Section 6.2 (Feedwater Pump Speed Control) 3.2.1 The Main Feedwater Pump Speed Contro! System remains in automatic with pump speed and feedwater pressure not displaying divergent oscillations following test induced pressure transients. (1) Main Feedwater pump speed Control System remains in automatic following a Feedwater Pressure transient. Criteria was met for both Main Feedwater Pumps during a high and low transient. (2) Indicated Feedwater Header Pressure oscillations are less than t 3o/o (t 54.0 psig) within five(s) minutes following a Feedwater Pressure transient. Criteria was met for both Main Feedwater Pumps. PUMP Starti ng above setpoint Starting below setpoint MFWP 2A 1.55 psig (0.1%) 1.7 psig (0.1%) MFWP 28 1.5 psig (0.1%) 1.65 psig (0.1%) (3) Indicated Feedwater Header Pressure oscillations are less than t 3% (t 54.0 psig) which is s 108 psid, during steady state operation. Criteria was met for both Main Feedwater Pumps. PUMP Steady State MFWP 2A 4.5 psi MFWP 28 3.7 psi L43
7.2.3 Automatic Steam Generator Level Control Transients at 50% Power (2-PAT-6.2) (continued ) Review Criteria 3.3 Section 6.1 (Main Feedwater Reg. Valves) 3.3.1 Main Feedwater Reg. Valve position was between the minimum and maximum positions given in the Figure below for the specific loop Main Steam Flow. All Main Feedwater Reg Valve positions were within the requirements. All points fall in the shaded area depicted below. REG VALVE Measurement s/G #1 slc#2 s/G #3 SlGH
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7.2.3 Automatic Steam Generator Level Control Transients at 50% Power (2-PAT-6.2) (continued) 3.4 Section 6.2 (Feedwater Pump Speed Control) 3.4.1 Actual AP was within t25.0 psid of the Program AP during steady-state operation. Criteria was met for both Main Feedwater Pumps. PUMP Actual AP Calculated AP Error MFWP 2A 109.5 psid 1.5 osid MFWP 28 104.5 psid 1.4 psid 4.0 Problems t1l During initial testing of Steam Generator #1 MFW Reg Valve, the MFW Reg Valve failed. Tuning of 2-FlC-348 was performed under WO 117556282. Criteria was subsequently met. 121 CR 1190710 was written to document changes to the procedure through Urgent Change 1. The test methodology was revised for controls recovering from actual plant condition changes to recovering from controlsystem setpoint(s) changes in the Digital Control System (DCS). L45
7.2.4 Calibration of Steam and Feedwater Flow lnstruments at 50% Power (2-PAr-6.3) This test was performed with the plant stable at approximately 50% Power as part of 2-PAT-6.0, Test Sequence For 50% Plateau. The test began on 6124116 and was field work complete onl18116. 1.0 Test Obiectives The objectives of this test were to: 1.1 Collect data for determining the new calibration spans for the steam flow transmitters, and verify the calibration of the feedwater and steam flow transmitters, by comparing indicated flows between the Main Control Board lndicators, the Protection System, and the Control System. 1.2 Satisfy in part the 50% objective in the UFSAR Table 14.2-2, Sheet 21, Calibration Of Steam And Feedwater Flow lnstrumentation At Power Test Summary. 2.0 Test Methods At approximately 50% power, steam generator blowdown and tempering flow were isolated while data was collected. Steam generator blowdown and tempering flow were then reestablished and calculations/comparisons were performed. 3.0 Test Results All Acceptance/Review Criteria were met or resolved as delineated below. Acceotance Criteria None Review Criteria 3.1 The difference between the feedwater flow as measured in the Protection System and the Main Control Board lndicators is within 15.0% of the rated flow. Measured differences (% ERRORS) between -1.38o/o and +1.07o/o L46
7.2.4 Galibration of Steam and Feedwater Flow lnstruments at 50% Power (2-PAT-6.3) (continued) 3.2 The difference between the feedwater flow as measured in the Protection System and the lndicated Computer Feedwater Flow is within t2.Oo/o of rated flow. Measured differences (% ERRORs) between -0.15o/o and +9.967o 3.3 The difference between the feedwater flow as measured in the Protection System and the Feedwater Flow Signa! used for flow control is within 12.0o/o of rated flow. Measured differences (% ERRORs) between -0.25% and +0.56% 3.4 The difference between the steam flow as measured in the Protection System and the Main Control Board lndicators is within 15.0% of the rated flow. Measured differences (% ERRORs) between -1.260/o and +0.96% 3.5 The difference between the steam flow as measured in the Protection System and the lndicated Computer Steam Flow is within x2.0% of rated flow. Measured differences (% ERRORS) between -0.09% and +0.03% 3.6 The difference between the steam flow as measured in the Protection System and the Steam Flow Signal used for flow control is within t2.0o/o of rated flow. Measured differences (% ERRORs) between -0.75o/o and +0.37o/o 3.7 The difference between the feedwater flow as measured in the Protection System and the Steam Flow as measured in the Protection System is within t5.0% of rated flow. Measured differences (% ERRORS) between -2.53o/o and +2.620/o 3.8 The difference between the feedwater flow as measured in the Control System and the Steam FIow as measured in the Control System is within t5.0% of rated flow. Measured differences (Yo ERRORS) betwe en -2.650/o and
+2.650/o L41
7.2.4 Calibration of Steam and Feedwater Flow lnstruments at 50% Power (2-PAT-6.3) (continued) Additionally, a comparison of the conected feedwater flows and steam flows versus predicted design flow is provided: Comparison to Design Flow (50% rescaledl 2 1.8 1.6 A L.4 a 7"2 E, f 81 G o'g E It 0.5 0.4 o 05101520253035im45 Percent Pgwor o Design Flow Rate r -5 Fercent l. +5 [,ercent x conected Fw Flows x steam Flo,rn 4.0 Problems There were no significant problems encountered during the performance of this test. L48
7.3 Test Sequence for 75% Plateau (2-PAT-7.0) This test started on7115116 and was completed on 7129116. 1.0 Test Obiectives The objectives of this test were to: 1.1 ln conjunction with 2-GO4, Normal Power Operation, define the plant operational requirements and ensure those requirements were met in order to permit power escalation from 50% Rated Thermal Power (RTP) to75%. 1.2 Specify the order of test performance at the 75o/o plateau. The following PATs/PETs were sequenced for performance by 2-PAT-7.0: o 2-PAT-1.2
- Load Swing Test o 2-PAT-1.4
- Pipe Vibration Monitoring o 2-PAT-1.5
- Loose Parts Monitoring System o 2-PAT-1.6
- Startup Adjustments of Reactor Control System o 2-PAT-1.7
- OperationalAlignment of Process Temperature Instrumentation o 2-PAT-1.8
- Thermal Expansion of Piping Systems o 2-PAT-1.9
- Automatic Steam Generator Level Control o 2-PAT-1.10. lntegrated Computer System (lCS) o 2-PAT-1.11* RVLIS Performance Test o 2-PAT-1.12* Common Q Post Accident Monitoring System o 2-PAT-3.3 " RCS Flow Measurement o 2-PAT-7.1 Calibration of Steam and Feedwater Flow I nstruments at 7 5o/o Power o 2-PET-301
- Core Power Distribution Factors 2-PET-304 OperationalAlignment of NIS Note:
- lndicates that the test is performed at multiple test plateaus.
The description of the testing is documented in the section (plateau) in which it was completed. 2.0 Test Methods Prerequisite actions for this Power Ascension Test (PAT) started on 7115116 and completed on 7119116. Unit 2 entered Mode 2 onTl17116 and 13:27 with the reactor critical at 13:41. The unit entered Mode 1 at 00:19 on7118116 and synchronized to the grid later that afternoon at 15:24. L49
7.3 Test Sequence for 75o/o Plateau (2-PAT-7.0) (continued) 2-PAT-1.2, Load Swing Test, was originally scheduled for the 50% plateau and delayed due to issues with the turbine IMP lN controls which were originally to be used in the test. The test was revised to use IMP OUT and scheduled during the power increase to the 75o/o Plateau. At 45% power the unit was held to perform 2-PAT-1 .2 onll19l16 and all Acceptance Criteria were met. One Review Criteria, steam header pressure does not undershoot the final pressure by more than 25 psi, was not met. CR 1193637 was written for an undershoot of 28.5 psi. 2-PAT-1.4, Pipe Vibration Monitoring, was also performed during 2-PAT-1.2,Load Swing Test, with no issues. Unit 2 continued to increase power and the power Ievelfor the75o/o Plateau testing power was reached on 7125116. Testing included: o 2-PAT-1.4, Pipe Vibration Monitoring, completed on7126116 with CR 1195665 written on excessive vibration on the Main Steam Line Trap drain line. Temporary repairs to stabilize the line were initiated. All other criteria were met. o 2-PAT-1.5, Loose Parts Monitoring System, was completed on 7125116 with all criteria met. CR 1171424 documents three channels removed from service. o 2-PAT-1.6, Startup Adjustments of Reactor Control System, was completed on7128116 with all criteria met.
. 2-PAT-1.7, Operational Alignment of Process Temperature lnstrumentation, was completed on 7129116 with allAcceptance Criteria met and all Review Criteria met upon the second performance. During initial performance on7126l'16, CR 1196243 was generated for failure to meet Review Criteria, Loop 1 OTDT.
CR 1196245 was generated for Review Criteria failure to meet Loop 2 OTDT. On the second data collection on 7128116, all Review Criteria were met and the CRs closed. o 2-PAT-1.8, Thermal Expansion of Piping Systems, was field work complete on7125116 with no issues noted. o 2-PAT-1.9 Automatic Steam Generator Level Control, was completed on7129116 with allcriteria met. o 2-PAT-1.10, lntegrated Computer System (lCS), was completed on 7125116. CR 119il76 was written for MCR indicator 2-Tl-62-71 comparison to ICS PlDT0127A (Regen Heat Exch Letdown Temp). This failed the Acceptance Criteria of reading within t8"F of each other. The CR was closed after calibrations were completed under WO 118007324. There was no Review Criteria for this PAT. 150
7.3 Test Sequence tor 75Yo Plateau (2-PAT-7.0) (continued) o 2-PAT-1.11, RVLIS Performance Test, applicable sections were completed on7125116 with all criteria met. o 2-PAT-1.12, Common Q Post Accident Monitoring System, applicable sections were completed on 7125116 with all criteria met. o 2-PAT-3.3, RCS Flow Measurement, was completed on 7127116 with all criteria met. o 2-PAT-7.1, Calibration of Steam and Feedwater Flow lnstruments at7io/o Power, was completed on 71281'16. Steam FIow and Feedwater Flow data obtained in Section 6.1 of this PAT on7l26l16 were used to adjust the span of the associated Steam Flow transmitters. Post calibration data was subsequently taken in accordance with Section 6.2 of this PAT on7128116. and all Review Criteria were met. There was no Acceptance Criteria for this PAT. Additionally, Engineering completed the following procedures, or applicable sections, during the steady state period, with no issues, to support their testing at the 75% Plateau: o 2-Tl lncore Flux Mapping o 2-TRl-0-22 -PDMS Operability o 2-Sl-0 Excore QPTR & Axial Flux Difference o 2-PEf-301 - Core Power Distribution Factors o 2-Sl-92 Incore-Excore Cross Calibration Data o 2-Tl-7.020 - PDMS Calibration o 2-Tl-7.023 - PDMS Power Distribution Measurement o 2-PET-304 - OperationalAlignment of NIS o 2-Tl Calorimetric Calibration o 2-Sl-0 Hot Channel Factors Determination o 2-Sl-92 NIS Monthly Recalibration data o 2-Sl-0-22 -lncoreQPTR Details of the performance of each PAT procedure is contained in the individual summaries of the associated procedures as they are fully completed. 3.0 Test Results AllAcceptance/Review Criteria were contained within the tests sequenced by this test. 4.0 Problems Problems encountered are addressed in the following discussions of each test sequenced by 2-PNf-7.0. 1s1
7.3.1 Calibration of Steam and Feedwater FIow lnstruments at 75% Power (2-PAr-7.1) This test was performed with the plant stable at approximately 75o/o Power as part of 2-PAT-7.0, Test Sequence For 75o/o Plateau. This test began on7118116 and was field work complete on7128116. 1.0 Test Obiectives The objectives of this test were to: 1.1 Collect data for determining the new calibration spans for the steam flow transmitters 1.2 Verify the calibration of the feedwater and steam flow transmitters, by comparing indicated flows between the Main Control Board lndicators, the Protection System, and the Control System. 1 .3 Satisfy in part the 75o/o objective in the UFSAR Table 14.2-2, Sheet 21, Calibration Of Steam And Feedwater Flow lnstrumentation At Power Test Summary. 2.0 Test Methods At approximately 75o/o power, steam generator blowdown and tempering flow were isolated while data was collected. Steam generator blowdown and tempering flow were then reestablished and calculations/comparisons were performed. New steam flow transmitter spans were calculated using data collected from 30o/o, 50o/o, and 75Yo power plateaus and provided to Maintenance. All eight steam flow transmitters were re-spanned and calibrated. 3.0 Test Results All Acceptance/Review Criteria were met or resolved as delineated below. Acceptance Criteria None Review Criteria 3.1 The difference between the feedwater flow as measured in the Protection System and the Main Control Board lndicators is within t5.0o/o of the rated flow. As-left data had measured differences (Yo ERRORS) between
-2.21o/o and +0.34o/o.
L52
7.3.1 Calibration of Steam and Feedwater Flow Instruments at 75% Power (2-P AT -7 .1) (conti nued ) 3.2 The difference between the feedwater flow as measured in the Protection System and the lndicated Computer Feedwater Flow is within t2.Oo/o of rated flow. AsJeft data had measured differences (% ERRORs) between
-0.09% and +0.13%.
3.3 The difference between the feedwater flow as measured in the Protection System and the Feedwater Flow Signal used for flow control is within t2.0o/o of rated flow.
- As-left data had measured differences (% ERRORS) between
-0.98% and +0.43%.
3.4 The difference between the steam flow as measured in the Protection System and the Main Control Board lndicators is within t5.0% of the rated flow. As-left data had measured differences (% ERRORS) between
-1.03Yo and +0.80%.
3.5 The difference between the steam flow as measured in the Protection System and the lndicated Computer Steam Flow is within *2.0o/o of rated flow. As-left data had measured differences (% ERRORS) between
-0.07% and +0.04%.
3.6 The difference between the steam flow as measured in the Protection System and the Steam Flow Signal used for flow control is within t2.0o/o of rated flow. As-left data had measured differences (% ERRORS) between
-0.54o/o and +9.61o7o.
3.7 The difference between the feedwater flow as measured in the Protection System and the Steam Flow as measured in the Protection System is within t5.0% of rated flow. As-left data had measured differences (% ERRORs) between
-1 .24o/o ?fid +'l . 07o/o.
1s3
7.3.1 Calibration of Steam and Feedwater Flow lnstruments at 75% Power (2-P AT -7 .1) (conti nued ) 3.8 The difference between the feedwater flow as measured in the Control System and the Steam Flow as measured in the Control System is within t5.0% of rated flow. As-left data had measured differences (% ERRORs) between
-0.27o/o and +1 .160/o.
3.9 The difference between the 100o/o Extrapolated Average Feedwater Flow and the 100% Extrapolated Steam Flow is within t5.0% of rated flow. Applies to 2-PAT-7.1 Section 6.1 only. Measured differences (% ERRORS) between -2.02o/o and +1 .85%. Additionally a comparison of the corrected feedwater flows and steam flows versus predicted design flow is provided: Section 6.2, Comparison to Design Flow 175% rescaled) 3 2.5 x
-+r -a-I 2
o
=IA af, 1.5 t,o (E
G B Ill L 0.5 0 30 40 60 70 Percent Power
- Design Flow Rate I -5 Percent A +5 Percent Corrected FW Flows I Steam Flows 4.0 Problems There were no significant problems encountered during the performance of this test.
L54
7.4 Test Sequence for 100o/o Plateau (2-PAT-8.0) Pre-requisite actions for this PAT started on 7128/16 and the procedure was completed on 1014116. Multiple delays due to plant equipment issues are summarized in the Startup Chronology. 1.0 Test Obiectives The objectives of this test were to: 1.1 Define the plant operational requirements and ensure those requirements were met in order to permit power escalation from 75o/o to 90% Rated Thermal Power (RTP) and subsequent power escalation from g0% RTP to 100% RTP. 1.2 Specify the order of testing to be performed at the g0% RTp and 100Yo RTP plateaus. The following PATs/PETs/RCl were sequenced for performance by 2-PAT-8.0: o 2-PAT-1.2
- Load Swing Test o 2-PAT-1.3 Large Load Reduction Test o 2-PAT-1.4
- Pipe Vibration Monitoring o 2-PAT-1.5
- Loose Parts Monitoring System o 2-PAT-1.6
- Startup Adjustments of Reactor Contro! System o 2-PAT-1.7 " Operational Alignment of Process Temperature lnstrumentation
. 2-PAT-1.8
- Thermal Expansion of Piping Systems
. 2-PAT-1.9
- Automatic Steam Generator Level Control o 2-PAT-1.10* lntegrated Computer System (lCS) o 2-PAT-1.11* RVLIS Performance Test o 2-PAT-1.12* Common Q Post Accident Monitoring System o 2-PAT-3.3
- RCS Flow Measurement o 2-PAT-8.4 Calibration of Steam and Feedwater Flow lnstruments at 100% Power o 2-PAT-8.5 Shutdown From Outside the Main Control Room o 2-PAT-8.6 Plant Trip From 100o/o Power
. 2-PET-301
- Core Power Distribution Factors
. 2-PET-304
- OperationalAlignment of NIS o RCI-159
- Radiation Baseline Surveys Note:
- lndicates that the test is performed at multiple test plateaus.
The description of the testing is documented in the section (plateau) in which it was completed. 155
7.4 Test Sequence for 100% Plateau (2-PAT-8.0) (continued) 2.0 Test Methods Unit 2 was initially at73o/o power at the start of this PAT and a plant equipment issue resulted in an unplanned outage.' During this power reduction 2-PAT-8.5, Shutdown From Outside the Main Control Room was performed. The PAT was completed with all criteria met. Subsequent power increases and shutdowns occurred unti! 8129116 when the unit reached 93% RTP to allow testing. At approximately 98% power the loss of the 28 Main Bank Transformer resulted in a trip and an extended shutdown. This trip allowed 2-PAT-8.6, Plant Trip from 100Yo Power to be evaluated from data gathered from the plant computer. The evaluation validated allAcceptance Criteria was met and one Review Criteria was not met. The unit returned to 100% power ong127116 which allowed completion of the 100o/o Plateau testing. Testing included: o PAT-1.7, Operational Alignment of Process Temperature lnstrumentation, was completed on 8129116. Review Criteria 5.2.8 and 5.2.C were not met but a CR was not written as the 2-PAT-1.7 performance was designed to correct the issue and the Acceptance Criteria were verified at the 100% power plateau. All other Review and Acceptance Criteria were met. o PAT-8.4, Calibration Of Steam And Feedwater Flow lnstruments at 100% Power, performance at 93% was completed on 8129116. All Review Criteria were met for Section 6.1. There was no Acceptance Criteria for Section 6.1. o 2-PAT-1.2,Load Swing Test, was field work complete on9129116 with allAcceptance Criteria met. CR 1218746 was written on the Review Criteria failure for S/G level response on the power decrease and subsequent power increase. Westinghouse evaluated the response and concluded the response was adequate with no further testing required.
. 2-PAT-1.3, Large Load Reduction Test, was field work complete on 9130116. AllAcceptance Criteria was met. CR 1218917 was written for Review Criteria failure of S/G levels to remain within t 15o/o ol the program level. Westinghouse concluded the response was acceptable.
. 2-PAT-1.4, Pipe Vibration Monitoring, was field work complete on 9/30/16 with CR 1208694 written for main steam traps excessive vibration as was noted at the 75o/o Plateau also. Civil Design generated WO 118122821 to design and install a restraint outside the PATP.
o 2-PAT-1.5, Loose Parts Monitoring, was completed on 8/30/16 with all criteria met. CR 1171424 documents three channels removed from service. 156
7.4 Test Sequence for 100% Plateau (2-PAT-8.0) (continued) 2-PAT-1.6, Startup Adjustments of Reactor Control System, was field work complete on 10/3/16. CR 1211020 was written for one failed Acceptance Criteria. The failed criteria was due to full load steam pressure being below the expected value because T"rnwas at its maximum value. However, there is no safety or operational concern. CRs 1211015 was written for failed Review Criteria . 2-PT-1-81 was out of service, therefore, calibrations of the pressure transmitter will be verified when 2-PT-1-81 is returned to service outside the PAT program. CR 1208178 was previously written for this issue. 2-P AT -1. 7, O perational Al g n ment of Process Te m perature i lnstrumentation, was field work complete on 9129116. Acceptance Criteria for Loop 4Tnswas not met with T"r, higher than the Acceptance Criteria. Although a failure in Acceptance Criteria, this was not a safety concern or failure to meet the licensing basis. CR 1211021was written. All other Acceptance Criteria was met. Three Review Criteria were not met. Two Review Criteria associated with AT compared to reactor power at the g0% performance was not met, however, the criteria was met at the 1O0o/o power level. The third failed Review Criteria associated with CR 121 1018 was met on the second performance of the PAT at the 100%o power level. 2-PAT-1.8, Thermal Expansion of Piping Systems, was field work complete on 8/30/16 forthe 100o/o Plateau with all criteria met. 2-PAT-1.9 Automatic Steam Generator Leve! Control, was field work complete on 9128116 with all criteria met. 2-PAT-1.10, lntegrated Computer System (lCS), was completed for the 100% Plateau on 8/30/16. CR 1208754 was generated for failure of 2-T1062-0004 and T0181A. A WO was generated to calibrate and has subsequently closed. 2-PAT-1.1 1, RVLIS Performance Test, was completed on 8/30/16 with all criteria met. 2-PAT-1.12, Common Q Post Accident Monitoring System, was completed for the 100o/o Plateau on 8/30/16 with al! criteria met. 2-PAT-3.3, RCS Flow Measurement, was completed on 9129116 with all criteria met. L57
7.4 Test Sequence for 100% Plateau (2-PAT-8.0) (continued) o 2-PAT-8.4, Calibration of Steam and Feedwater Flow lnstruments at 100% Power, was field work completed on 9129116. All Acceptance Criteria was met. CR 1208875 was written to document the failure of Review Criteria on three steam flow transmitters. Subsequent WOs were used to respan the transm itters and re-performance was successfu l. o 2-PAT-8.5, Shutdown From Outside The Main Control Room, was completed on 8/3/16 with all criteria met. o 2-PAT-8.6, Plant Trip From 100o/o Power, was evaluated from data gathered during the actual plant trip on 8/30/16. All Acceptance Criteria was met. CR 1209770 was written to evaluate the equivalency of data collected by the plant. This CR also addressed one Review criteria for pressurizer Ievel to modulate to no-load setpoint within 30 minutes of the trip. An evaluation of the Review Criteria by Westinghouse concluded the response was acceptable. Additionally, Engineering and Radcon completed the following procedures, during the steady state period, to support their testing at the100% Plateau: o 2-Sl-0 Excore QPTR & Axial FIux Difference o 2-PET-301 - Core Power Distribution Factors o 2-SI-92 lncore-Excore Cross Calibration Data c 2-Tl-7.020 - PDMS Calibration o 2-Tl-7.023 - PDMS Power Distribution Measurement o 2-PET-304 - OperationalAlignment of NIS
. 2-Tl Calorimetric Calibration o 2-T141- lncore Flux Mapping o 2-Sl-0 Hot Channel Factors Determination o 2-Sl-92 NIS Monthly Recalibration data o 2-5!-0 lncore QPTR
. 2-Sl-0 Core Reactivity o 2-TRl-0 PDMS Operability o RCI-159 - Radiation Baseline Surveys 3.0 Test Results AllAcceptance/Review Criteria were contained within the tests sequenced by this test.
4.0 Problems Problems encountered are addressed in the following discussions of each test sequenced by 2-PAT-8.0. 158
7.4.1 Load Swing Test (2-PAT-1 .21 This test was performed during 2-PAT-6.0, Test Sequence for S0o/o Plateau, and during 2-PAT-8.0, Test Sequence at 1o0o/o Plateau. The 50% plateau performance was performed onTl'19l16. The 100% plateau performance was performed on9129116. 1.0 Test Obiectives The objectives of this test were to: 1.1 Demonstrate the ability of primary and secondary side systems, including automatic control systems to sustain 10% step changes in turbine generator load. 1.2 Satisff the requirements of UFSAR Table 14.2-2, Sheet 35, Load Swing Test Summary. 2.0 Test Methods The plant computer was set to monitor plant parameters (e.g., reactor power, RCS temperature and pressure, pressurizer level, feedwater and steam flows, steam generator levels, feedwater pump speed, and feedwater pressure) during the transient. A 10% load reduction was initiated by adjusting the EHC turbine controls to a pre-determined setting and the EHC system was used to initiate the load reduction at 200o/olminute. Plant computer data for specific plant parameters were evaluated until plant conditions had stabilized. Test personnel also recorded initial condition, transient maximum and minimum and final condition data readings for specific process parameters. No manual intervention by Operations personnel occurred during the plant stabilization period. Once stability was achieved, load was rapidly increased by 10% using the turbine-generator control system, and plant parameters were again monitored. Test data was evaluated to determine if contro! system setpoint changes were required to improve plant transient response. 3.0 Test Results AllAcceptance/Review Criteria were met or resolved as delineated below. Acceotance Criteria All Acceptance Criteria were verified to be met during performance of the PAT for both the 50% plateau performance (at 45%) and the 100o/o plateau performance (at 95o/o): r-59
7 .4.1 Load Swing Test (2-PAT-1 .21 (continued) 3.1 Neither the Reactor nor the Turbine tripped. 3.2 Safety lnjection was NOT initiated. 3.3 No Steam Generator Power-Operated Relief Valves lifted. 3.4 No Pressurizer Power-Operated Relief Valves lifted. 3.5 No Steam Generator Safety Valves lifted. 3.6 No Pressurizer Safety Valves lifted. 3.7 Stability was achieved without manual intervention. Review Criteria Review Criteria 3.8, below, was not met for both load changes during the 10oo/o power plateau test. See CR 1218746. Review criteria 3.10, below, was not met for load increase during the 50% power plateau test. See CR 1193637. other Review criteria, below, were verified to be met during performances of the PAT by a review of time-variant plots of monitored plant parameters. The reviews indicate that control systems functioned as designed for both the 50% plateau performance (at 45%) and the 100% plateau performance (at 95o/o). Note: The criteria in parentheses apply to the load reduction transient. 3.8 SG levels remain within t5o/o of the program level. See CR 1218746, below. 3.9 Pressurizer pressure swings are less than t s0 psi from the initial pressure. 3.10 steam header pressure does not overshoot (undershoot) the final pressure by more than 25 psi. See CR 1193637, below. 3.11 Main feedwater header pressure oscillations are less than t 3% (t 39 psi) within 300 seconds after the change in steam flow (load Change). 3.12 RCS Tavg does not undershoot (overshoot) the final Tavg temperature. 150
7.4.1 Load Swing Test (2-PAT-1 .21 (continued) 3.13 Nuclear power does not undershoot (overshoot) the final power level by more than 3% RTP. 3.14 OverpowerAT trip margin increased (reduced) as a resutt of the load decrease. 3.15 Overtemperature AT trip margin increased (reduced) as a result of the load decrease. 4.0 Problems tll CR 1193637 Review criteria not met. The maximum steam pressure exceeded the procedure limit of 25 psig by 3.5 psig during the 50% power plateau performance of the 10% load increase. Westinghouse reviewed the test data and concluded that the results, although greater than the Review criteria, were acceptable and that no re-testing is required at the S0% power plateau. 121 cR 1218746 Review criteria not met. steam Generator revels did not remain within tlo/o of program during the 100% power plateau performance for both the 10% load changes. On the 10o/oload decrease: SG #1 level rose to 5.6% and SG #4 level rose to 6.1Yo. On the 10% load increase: SG #1 dropped to -6.10/o, SG #2 dropped to -5.4o/o, SG #3 dropped to -5.4% and SG #4 dropped to -6.3%. Westinghouse evaluated the Steam Generator(s) level response and concluded that the SG level response during the 10% load swing transients are acceptable with the cunent overshoot and undershoot and no additional testing is required. L61
7.4.2 Large Load Reduction Test (2-PAT-1 .3) This PAT was performed as part of test sequence 2-PAT-8.0, Test Sequence for 100% Plateau. The preparations for testing started on g127116 and testing was field work complete on 9/30/16. 1.0 Test Obiectives The objectives of this test were to: 1.1 Demonstrate the ability of primary and secondary side systems, including automatic contro! systems, to sustain a 50% step decrease in turbine generator load. 1.2 Satisfy the requirements of UFSAR Table 14.2-2, Sheet 36, Large Load Reduction Test Summary. 2.0 Test Methods With plant conditions stabilized at approximately 96% RTP, the following control systems were verified or placed in AUTO: Steam Dumps in Tavg MFW Pumps FW Regulating Valves SG Level ControlValves SG PORVs Pressurizer Level Control Pressurizer Pressure Control Rod Control Main Turbine Control in IMP OUT A 50% load reduction was initiated by adjusting the EHC turbine control lMP OUT sefter value to a pre-determined setting and initiating a load rate reduction at20Oo/olminute. Plant Parameters were monitored until plant conditions stabilized (approximately 23 minutes). 3.0 Test Results All Acceptance/Review Criteria were met or resolved as delineated below. Figures 7.4.2-1 through 7.4.2-12 depicts the performance results of the automatic control systems. The following Acceptance/Review Criteria were verified to be met during performance of the PAT: L62
7.4.2 Large Load Reduction Test (2-PAT-1 .3) (continued) Acceotance Criteria 3.1 The plant can sustain a large step reduction in turbine generator load of approximately 50% (48o/o to 52o/ol as demonstrated by meeting the following requirements: 3.1.1 Neither the Reactor nor the Turbine tripped. 3.1.2 Safety lnjection was NOT initiated. 3.1.3 No Steam Generator Safety Valves lifted. 3.1.4 No Pressurizer Safety Valves lifted. 3.1.5 Stability was achieved without manual intervention. No manual intervention by Operations personnel due to instabilities occurred during the plant stabilization period, however, the #3 Heater Drain Tank Pump was manually stopped by the Operator due to High amps. See CR 1219656. Review Criteria 3.2 Turbine Load was reduced by approximately 621 MWe. (48Yo - 52o/o reduction ranges from 596 MWe to 646 MWe). 450.72o/o load reduction was achieved. Other Review Criteria, below, were verified to be met during performances of the PAT by a review of time-variant plots of monitored plant parameters. (See Figures 7 .4.2-1 through 7 .4.2-12) The reviews indicate that control systems functioned as expected with the exception of 3.3.1, below. See CR 1218917. 3.3 Following a large step reduction in turbine generator load of approximately 50% (48Yo to 52o/o), plant control systems operate to maintain the following conditions during the transient 3.3.1 Steam Generator Levels remained within +15o/o, -15% of the program Ievel. See CR 1218917. 3.3.2 Pressurizer Pressure swings were less than +110, -160 psig from initial pressure. 163
7.4.2 Large Load Reduction Test (2-PAT-1 .3) (continued) 3.3.3 Main Feedwater Header Pressure oscillations are less than t3% within 300 seconds after the change in steam flow (load change). 3.3.4 RCS average temperature (Tavg) did NOT undershoot the finaltemperature by more than 3'F. 3.3.5 RCS average temperature (Tavg) did NOT peak above the initialtemperature by more than 5'F. 3.3.6 RCS average temperature (Tavg) was controlled by the Steam Dump Control System, as demonstrated by the Steam Dump Valves actuating open and modulating closed without recycling to control RCS average temperature (Tavg) oscillations within 2"F (peak to valley). 3.3.7 RCS average temperature (Tavg) was controlled by the Rod Control System, after Steam Dump Valve operation was terminated, as demonstrated by RCS average temperature (Tavg) oscillations remaining within 5"F (peak to valley). 3.3.8 Steam Dump Valve operation was for less than 8 minutes after the load reduction, as demonstrated by valve Demand Signal or valve indication. 3.3.9 The Rod Control System caused rod motion at maximum speed. 4,0 Problems t1] CR 1218917 Steam Generator ll4level did not meet Review Criteria "Steam Generator Levels remained within + 15o/o of the Program Level". The # 4 Steam Generator max level was 17.06%. Westinghouse reviewed the plant data and the controller settings and concluded that the SG level responses on all SG loops are acceptable. l2l CR 1219656 initiated due to 2A and 28#3 HDTP's tripping off and 2C #3 HDTP being removed from service by Operations after the amps reached red line values. The tripping/removal of the #3 HDTP's did not affect the performance or impact the test. The Operator action taken to remove 2C #3 HDTP from service did not aid or inhibit stability of the plants automatic systems. The action was taken to protect the 2C #3 HDTP. L64
7.4.2 Large Load Reduction Test (2-PAT-1 .3) (continued) FIGURE 7.4.2.1 Generator Output vs Time (Large Load Reduction) oatAnnre xlstory 30-5ep-2015 fll:30:ff! to 30-sep-2015 10r03:fil (ror) 20m 1600 I Turtfne SpeeQ(rprnl 160O, 6{0
@nerator OuSut (itulhl 320 I
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7.4.2 Large Load Reduction Test (2-PAT-1 .3) (continued) FIGURE 7.4.2-2 NIS Power vs Time (Large Load Reduction) oatArar rlstory 30-sep-2o16 09:3O:OO ro 3O-Sep-2016 1O;03:00 (EDT)
'*l l 120 I
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(1) n-7536lr,0o49e (P:u2) prR Rxc clt ffiEL 1 (cuAD4) q o 120 x 95.65ilt3 71,66492 49.25395 (2) u2-7542lxOOSOe (r2:u2) pm RilG cHAr{ilEL 2 (quaoZ) q o 120 x 95.53436 71.3tr5 a9.16133 (r> y2-7 (Y2: u2) prB RltG cHAxrEL 3 (qulor) q o 120 x 96.55E31 72.70651 50.34197 (1) tZ-t554ltrOO52A
'4ElltOOSrr (m:u2) paa nre cHAxnEL 4 (quAD3) c o 120 x 97.00159 72.t37t1 49.95752 (5) u2-E22tla034OA (r2:u2) uilrr GErrtERATof, cRoss r{H o 1600 rH 11E7.119 563.1536 565.5776 L66
7.4.2 Large Load Reduction Test (2-PAT-1 .3) (continued) FIGURE 7.4.2-3 Pressurizer Pressure vs Time (Large Load Reduction) DatAHare History 30-5ep-2016 09:30:00 to 30-Sep-2016 10:03:00 (EDT) O9:30:0O EDT 09:35:3O EDT 10:03:00 EDT 3o-sep-2016 3O-Sap-2016 3O-sep-2O16 30-Sep-2016 30-Sep-2015 3O-sep-2016 3O-Sep-2016 ll1: 09:33:27 ll2: O9:34:27 Point ID/Dcscriotion Low-Y xi -v uni ts oglro/L6 a9130/L6 (1) y2-253t5/Dcs0426 (rZ:u2) VALTDATED PRESSURTZER PRESSURE 2100 2300 PsrG 2259.{5 2165.914 (2) V2-25393/DCSO434 (T2:U2) PRESSURIZER PRESSURE SETtrOINT 2100 2300 PsrG 22t6.002 2236.002 767
7.4.2 Large Load Reduction Test (2-PAT-1 .3) (continued) FIGURE 7.4.24 Pressurizer Level vs Time (Large Load Reduction) Dattrrre n{rtory 30-sep-2o16 O9:3O:O0 to m-scp-2016 1O:O3:OO (Eur)
*-l I
I I I I I I Oe:tO:OO EDr O9:tt:t0 Eor 0e:41:ff) strT o9146:30 eur oe:t2:0 ffi O9:t7:!O EUr lO:O3l0O EDT t0-scp-20tl t0-s.p20[6 3O-$cp-IO16 lo-sq-2O16 !O-s.p-20f6 30-5rp-!016 30-sap-2016 x1: O9:33:31 rQ: OO:19:37 n3: O9:46:13 Lon-Y r{-v unltr r,.g,tfitt:i Qf,lro/1.6 o4/ron6 ffi (2) m-2il97/DE5t&J.75 (m:u2) y LrD rE p*Esslr*rzEr LE,EL ,om*
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7.4.2 Large Load Reduction Test (2-PAT-1 .3) (continued) FIGURE 7.4.2-5 Control Bank D Position vs Time (Large Load Reduction) DatAware History 30-Sep-2016 09:30:00 to 30-Sep-2016 10:03:00 (eOr) I T 1 I I t I I ____L 333.0 rir { s 09:30:fl) eoT O9:33:30 EDT q):41:0O EDT 09:a6:3O g)T 09:52:00 EDT lrlr:57:30 g)T 10:03:00 EDT iXFScp-2015 30-scp-2016 3o-scp-20r6 3o-scp-2016 30-scp-2016 3o-scp-2016 30-scp-2016 Low-Y Hi -v Units o 231 STEPS 0 231 srEPs 557 620 DEGF E 72 SPt'l 557 620 DEGF L69
7.4.2 Large Load Reduction Test (2-PAT-1 .3) (continued) FIGURE 7.4.2.6 Teve vs Time (Large Load Reduction) DatAuare nlstory 30-sep-2016 09:30:fi) to 30-Sep-2O16 1O;O3:0O (EDr) l I I
+
I tiri.o iimbr-) O9:3O:00 EDT O9:35:3O EDT 09:'11:OO EDT 0e :{6: m EDT O9: 52:(Xl EDT O9:57:3O EDT 1O:O3:OO EDT 3O-scp-2O15 3O-scp-2O16 30"-Sep-2O16 3O-sq-2O16 3O-scp-2O16 30-scp-2o16 3o-scp-2016 polnt 11: 09:33:0t i{l: 0rl:33:32 il3: 09:39:37 loloescrlptlon Lfi-Y rl-v unlts 09l?al1:6 ogltol1:B 09ltolil6
@ (rz:ut) TREF LA6 FoR Roo crRL 56f MEF 515.93tt tl2.G72 572.10t5 (2) y2-15153/u0052 (lf2:u2) coxr no Br{r D srEp corfirtT o 235 srEPs 215 197.0295 105 (3) r2-15150/uo051 (r2:u2) orr Ro &{K c srEp corJr{T O 235 5TEPS 231 231 22t (a) Iz-l'lalrfTll94l (P:uz) T-f12 TAVE 555 6fiI DCG F 5t5.9556 5E7.6503 573.2t41 (5) r2-11l49/r713rA (wz:ut) r-422 r vE 565 6fi} DG F 5t5 . tt39!, 587.069 t72.t661 (6) YZ-UL86/T71EA (r2:u2) r-432 rA\rG 565 6ff} DCG F 516. 5344 588.336r, 573.56t5 (7) r2-1122uT7526A (H2:u2) r-442 r^vc 56s 600 DEG F 517.1261 5EE.5921 573.71t7 (t) s2-26O95/[rcsO21O (r2:u2) VALTDATED Rcs rA\rG Hr sELEcr 565 6(xl [!EGF 3t7.t732 5EE.t2t5 t71.O:129 L70
7.4.2 Large Load Reduction Test (2-PAT-1 .3) (continued) FIGURE 7.4.2.7 Steam Dump Signal vs Time (Large Load Reduction) DatAHarc ttistory 30-Scp-2016 09:30:00 to 30-sep-2016 09:rt1:OO (EDT) O9:31: 50 Eor i33:4O Err 09: 35: ll0 em O9:37:2U em 09:39:1O ssr O9:41:OO em 3O-scp-2016 3&sap-2O16 3o-scp-ZO16 3O-sep-2016 3O-sep-2016 30-sep-2O16 polnt roloescrlotlon }l1: 09: 33:14 lr2: 09:33:32 ,N3: 09: ?7t26 (1) La,-Y xl -v unl ts @ltolL6 o9ttotti6 09/30/16 rz-ilIjl?m}94^ &2:u2) T-4Ul TAvG 565 6fl) DEG F 5r5.9692 587.71E9 576.6576 (z) rz-rr-rrre-mi3u (rz:uz) r-rz2 rAvG 565 6fi) DEG F 5E5,4m3 5E7.073,[ 576.1!129 (3) r2-11lt6ft7482A (r2:u2) r-{32 rA\rc 565 6fi! OEG F 5E6. 5776 5tE.4306 (,0) r2-r22rfr7526A (r2:u2) r-442 r^tc 565 6fi' T}EG F 5E6.!)017 5EE.5311 '77.0591 (5) r2-25340/FttXl1O103 (rZtu2) sTEAit lrurrp srcNAL To vALvE o 100 I o '71.A315 (6) y2-26O95/DCsO210 (r2:u2) VALIDATED RCs TA\,G Hr SELECT 565 600 DGF 587.1475 5E6.E611 577.17A1 L] L
7.4.2 Large Load Reduction Test (2-PAT-1 .3) (continued) FIGURE 7.4.2.8 Feedwater Pressure vs Time (Large Load Reduction) DatAUere llistory !O-Scp-2016 O9:3O:OO to 30-5ep-2016 LO:03:OO (EOT) O9:!O:OO EDT O9:15:30 EDT O9:41:O0 EDT Ol:45:tO EDT O9:t2lOO EDT O9:57:3O EDT 10rO3:O0 EDT 3O-Sep-2O16 lO-Scp-2O16 lO-Scp-2(}16 3O-Scp-2O16 lO-5cp-2o16 t0-gGp-2016 !O-Scp-2O16 n! ol'slt3l:t E: ot:tt:g B3 0tt3s2:a1 L! to:o:t;7 Lfl.Y rfi-Y lfftt G)lrolts otllfila3 oplfilt3 o'.tfilre ffilur) rrun FEilrr
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(r) u2-2sruDc3011t2 (utu2) !-fc-{f,-2o E^ilnEE{T to loo ?I'ID ltl,.ttl' L73.12L7 aut.2207 l1t.t371 (a) re-2sr3r/tcs0Lr (m:uz) FFlslr 3ETFGilT r too ?!ilD l!ro.?!tot ul2.?o7, 1a7.o503 tlr.@Ir L1 2
7.4.2 Large Load Reduction Test (2-PAT-1 .3) (continued) FIGURE 7.4.2-9 Steam Generator 1 Level vs Time (Large Load Reduction) OatlHarc History 3O-Scp-2O16 Og:3Or0O to 3O-Scp-2O16 10:03:OO (EDT) llarirnrmr Devidtio{ll O9:10:O0 EDT O9:13:tO EDT 091{1:OO EDT O9:tl6:t0 @T 0O:52:0O EDT 09:57:lO EDf 1O:O3:6 EDT tO-Scp-2O16 tO-Scp-2016 Ul-Sce-2OX6 lo-5cp-2o16 lo-3cp-2o16 !O-SsP-tt016 !O-Scp-1O16 ll1: O9:3t:23 ll2: O9:19:OO )lt: O9:rlt:46 ll{: O9:49:tO Point lDlDarcriotioa tn-Y fli-Y Unitr Ogtr0lli Oglrot,.B o9l! 11:6 urlrolrB (1) Y2-25ott/!csmol 02:U2) SG 1 Y LIOATED m LAIEL 20 to r 63.tt3tE 6t.657t2 /rg . 527!m 45.72t91 (2) r2-ai1il2,/Dcsoo31 O2:u2) sG 1 LEVEL sETForrT 2(} to t 49.1792t 19.rO7L2 4t.9S71t 49.17045 L] 3
7.4.2 Large Load Reduction Test (2-PAT-1 .3) (continued) FIGURE 7.4.2.10 Steam Generator 2 Level vs Time (Large Load Reduction) oatArare rlstory 3o-sep-2o16 09:30:0o ro 3o-sep-2o16 1o:03;o0 (sDr)
'i I
I I t-- I O9:3O:0O Em O9:35:tO EDT U,:41:OO EDT O9:{6:30 EDT O9: 52 : OO Er O9: 57 : 30 EDr 1O : O3 ; 0O EDT 30-sep-2016 !O-scg-2O16 I0-scp-2O15 30-scp-2O16 30-sep-2o16 30-scp-20!.6 t0-scp-2016 polnt ro^/oescrlodon tl1: 09:33:29 tlz: O9:3t:t1 ll3: 09:50:37 (1) E-25733lDcB00{6 (E:uz)
- 2 VALTDATED xR LEI/EL Lor-Y xl-v unlts q?/3011i QPr3o416 oe^ftol16 (z) y2-2r777lEsfi7a (y2:u2) sG 2 LEr/EL SETForxT 20tox u.2t tt g.r,.ila TilE 37 zotot 49.'11125 49.:L906 {9.17t79 L1 4
7.4.2 Large Load Reduction Test (2-PAT-1 .3) (continued) FIGURE 7.4.2.11 Steam Generator 3 Level vs Time (Large Load Reduction) DatAware nlstory 30-sep-2016 09:30:00 to 30-sep-2016 10:03:OO (Eor) Maximum Level and Deviotion 1 1 Y'l r-qr
,V/
\It
\ X) t lF
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Miniml [lm' i minir,-, Devia( ion (undel rshoot) i Level 2 iif.o i{r utai ) o9:30:oo ErDT O9:3t:30 EOT o9:41:OO EDT 09:,16:30 E-rrT O9:t2:00 EDT O9:57:lO EOT 10:O3:OO 3O-3GP-2O16 30-s.p-2016 3O-s.p-2O16 ,O-3.p-2016 3O-3cp-2O1C 30-s.p-2o16 to-3cp-2016 x1: Og:lt:t6 x2: 09:tO:O6 13: O9ttO:55 Polnt lplp.rcrlotlil Ld-y Hl-y unlti oglrolti lmlrol1:i Orltollla (L' J2-2t7t7lBm37 (r2:u2) SG 3 VALTOATED r. LEVEL 20 tO I 6a.22r' 15.2ar76 a5.a195 (2) Y2-25t35/DCS0U5 (Y2:U2) SG 3 LEVEL SErFOrr{T 20 tO I a9.!3a 49.1t59 /t9.136a! 175
7.4.2 Large Load Reduction Test (2-PAT-1 .3) (continued) FIGURE 7.4.2-12 Steam Generator 4 Leve! vs Time (Large Load Reduction) tlrtAlrre nistory 3O-Scp-2016 09:30:O0 to 3O-sGp-2016 1O:03:OO (eDT) ilaximum Deviation 0e:3O:OO ElIf O9;3t:30 Eur O9:41:OO EtrT O9:16:30 EDT 09:52:OO EDr O0:57:30 Etrr 1O:Ol:OO GDT 3O-scp-2O15 3O-scp-2O16 3O-scp-2O16 30-sep-2O16 3O-sq-2O16 3O-sop-2O!6 30-scp-2O16 polnt m/orrcrlotlon 11: oo333:22 ltz: @33t:57 il3: O9:30:56 Lorl-Y xl-v urltg oglrolL; o4lroltB (1) -25t52locB0ul5 (r2:u2) sG 4 VALTDATED xR LEVEL 20to; 56.a0'l0i 66.170C3 -o9tiw1:6 aa.GEX[s (2) n-25t9O,/DCSO15a (r2:U2) 3G 4 LEVEL sETporrr 20tor {9.4tO53 t19.3O947 49.1354 L76
7.4.3 Pipe Vibration Monitoring (2-PAT-1 .41 This PAT started Prerequisite Actions on 1211612015 and performance continued through the 100% test plateau and was field work complete on 9/30/16. 1.0 Test Obiectives The objectives of this test were to: 1.1 Demonstrate vibration levels are acceptable for selected ASME Class 1,2,3 piping, other high energy piping systems inside Seismic Category 1 structures, and high energy portions of systems whose failure could reduce the functioning of any Seismic Category 1 Plant Feature to an unacceptable level. 1.2 Verify selected Balance of Plant (BOP) piping outside Category 1 structures is acceptable under steady state and operational transient conditions. 1.3 Utilize the test methods and Acceptance Criteria as specified in Calculation CDQ002999201 000533 Engineering Requirements for Power Ascension Test, Corrective Action 13 from WBN Condition Report 153545 and deferred tests from 2-PTl-999-01, Operationa! Vibration Testing. 1.4 Satisfy the requirements of UFSAR Table 14.2-2, Sheet 6, Piping Vibration Monitoring Test Summary. 2.0 Test Methods Selected locations at various flow modes and transients were observed to ensure that severe vibrations do not exist. Testing consisted of visual observation of piping vibration, measurements of velocity and displacement (if excessive vibration was observed), and installed instrument measurements at selected Main Feedwater and Main Steam Iocations. This PAT tested systems for steady state and transient pipe vibration for the following systems and operating conditions:
- 1. Mode 5: steady state tests
- a. Condensate Short Cycle Recirc
- b. Condensate Long Cycle Recirc L1 1
7.4.3 Pipe Vibration Monitoring (2-PAT-1 .4) (continued)
- 2. Mode 3 (Deferred tests from 2-PTl-999-01)
- a. Pressurizer Surge Line steady state test
- b. Steam Dump Valves 2-FCV-1-105 and 2-FCV-1-111 transient tests
- c. Main Feedwater Pumps 2A and 28 start transient and steady state tests
- 3. Mode 1: steady state tests at 30%, 50o/o,75o/o and 100% Power
- a. Main Steam
- b. Condensate
- c. Main Feedwater
- d. Extraction Steam
- e. Heater Drains and Vents
- 4. Mode 1 Transient tests
- a. Main Feedwater Pump Turbine Condensate Drain pumps starUstop operation
- b. #3 Heater Drain Tank Pumps starUstop operation
- c. #7 Heater Drain Tank Pumps starUstop operation
- d. 10% Load Swing at50o/o Power
- e. Turbine Trip Coincident with Loss of Offsite Power at 30% Reactor Power
- f. 50% Load Reduction at 100o/o Power
- g. 10% Load Swing at100% Power
- h. 100o/o Turbine Trip (credited for unplanned trip from 100Yo power- See CR 1211196) 3.0 Test Results All Acceptance/Review Criteria were met or resolved as delineated below.
The performance of this test demonstrated that the piping systems operated or operated following corrective actions as designed. Acceptance Criteria were met or were evaluated by Engineering as acceptable, use-as-is or work orders were initiated to perform corrective actions and demonstrate by retest that Acceptance Criteria were met. Measured velocities and displacements were compared to test Acceptance Criteria. Condition Reports were written for Acceptance Criteria that were not met. L1 8
7.4.3 Pipe Vibration Monitoring (2-PAT-1 .4) (continued) Acceptance Criteria 3.1 Visual observations (steady state vibration). Note: The Acceptance Criteria is met if visual observations are acceptable or if the measured vibrations are acceptable.
- a. Observed that no excessive vibrations existed, or
- b. Measured velocities were less than 0.45 in/sec (peak), or
- c. Measured velocities or displacements were less than or equal to the allowable velocities or displacements found in the PAT Appendix C, Contingent Vibration Measurements.
Excessive vibrations were not observed for the majority of piping tested. Excessive vibration was observed and measurements taken on Main Steam Strainer Blowdown lines at 75o/o and 100o/o power. Tie-back supports were added at both power levels to reduce vibration to an acceptable level. (See CRs 1195665 and 1208694) 3.2 I nstru mented Measure ments (Steady State Vi bration
).
Magnitude of steady state instrumented vibration is less than or equal to velocity or displacement values found in 2-PAT-1.4, Appendix B, Vibration Monitoring Program Allowable Limits Steady state velocity and displacement measurements exceeded the allowable value for 28 Main Feedwater Pump (MFP) on recirc. A pipe hanger was adjusted. 28 MFP was re-performed on recirc. and vibration was acceptable. (See CR 1168287) 3.3 Visual Observations (Transient Vibration).
- a. Transient vibrations are acceptable as evidenced by performance of post-transient walk-down which verifies that damage has not occurred.
- b. Pump Start / Stop transient vibrations are acceptable when no excessive vibrations are observed.
Visual observations of transient vibration were acceptable. 3.4 lnstrumented Measurements (Transient Vibration). Magnitude of transient instrumented vibration is less than or equal to the velocity or displacement values found in 2-PAT-1.4, Appendix B, Vibration Monitoring Program Allowable Limits. Velocity and displacement measurements exceeded the allowable values for 2A Main Feedwater Pump Start on Recirc. and for Main Steam Turbine Bypass Valve 2-FCV-1-111 transient. (See CRs 1161783 and 1170319) L1 9
7.4.3 Pipe Vibration Monitoring (2-PAT-1 .4) (continued) Engineering evaluated 2A Main Feedwater Pump Start on Recirc. as acceptable and Main Steam Turbine Bypass Valve 2-FCV-1-111 transient as acceptable following a retest. Review Criteria None 4.0 Problems t1] CR 1161783 - Section 6.5.2, Main Feedwater Pump 2A Start and Steady State Operation on Recirc. Pipe transient vibration exceeded velocity and displacement Acceptance Criteria during pump start on Recirc. Disposition: Engineering evaluated as acceptable as-is. I2l CR 1168287 - Section 6.5.3, MFP 28 on Recirc. did not meet steady state Acceptance Criteria. Disposition: Retest data passed all criteria after hanger adjustment (Related CR 1169753 - for work order initiation only. Hanger 06-2HD-R173 requires adjustment. Adjustment complete and retest data passed all criteria.) t3l CR 1170319 - Section 6.5.5, Turbine Bypass Valve 2-FCV-1-111 Transient, Acceptance Criteria were not met. Disposition: Engineering evaluated acceptable as-is after retest. t4l CR 1180348 - Accelerometer MSV4 was found on floor detached from its test cable. All tests using MSV-4 were complete. Accelerometer was returned for post-test calibration and results were acceptable. l5l CR 1195665 - Section 6.3.1 Main Steam-75o/o Reactor Power, velocity and displacement criteria were not met. CR closed to WO 1 1801 '1792 to install unistrut braces and monitor/observe the vibrations at the 100o/o power plateau. Braces were installed. Observations were performed in 2-PAT-1.4, Section 6.4.1, Main Steam-100% Reactor Power (see CR 1208694 below). 16l CR 1198808 - Sections 6.6.1 through 6.6.4, MFPT COND DRATN TANK PUMP 2A,28 Start and Stop. Request evaluation to delete Sections 6.6.1 through 6.6.4, Operations does not use these pumps. After evaluation it was determined operations may use the pumps and Sections 6.6.1 through 6.6.4 were completed with Acceptance Criteria met. 180
7.4.3 Pipe Vibration Monitoring (2-PAT-1 .4) (continued) 171 CR 1208694 PNf-1.4, Piping Vibration Monitoring, Section, Section 6.4.1, Main Steam-100% Reactor Power. Request Design Engineering evaluate excessive vibration observed and measured on WBN-2-TRAP-001-0200 through -0203 Moisture Traps and associated strainer blowdown lines. Contacted and walked down with Civil Design Engineering. WO 118122821generated for work at100% power. Civil Design Engineering is the owner organization. At 100% power, vibration will be evaluated by Civil Engineering and a restraint designed and installed. t8l CR 1211196 PAf-1.4, Piping Vibration Monitoring, Section 6.6.19, 100Yo Turbine Trip. CR requested Design evaluate 2-PAT-1.4, Pipe Vibration Monitoring, Section 6.6.19, 100% Turbine Trip, to take credit for the 8/30/16 plant trip. Section 6.6.19 was closed based on Engineering walk down evaluation, with no need for an additional 100% trip to validate 2-PAT-1.4 criteria. t9] CR 1218799. three accelerometers and one VibDaq DAS exceeded their calibration due dates during testing before an extension request was processed. Report of Calibration indicated all instruments were within tolerance; no further action required. 181
7.4.4 Loose Parts Monitoring System (2-PAT-1 .5) This test was performed in Mode 2 and during the 30%, 50Yo,75o/o, and 100% reactor power test plateaus. Prerequisite actions for this test began on 5114116. The performance section started on 5124116 and completed on 8/30/16. 1.0 Test Obiectives The objectives of this test were to: 1.1 Collect baseline data from the loose parts monitoring system, which will be available as a baseline for comparison for future use in detection and analysis for loose parts. 1.2 Verify the adequacy of system settings established during preoperationa! testing. 1.3 Satisfy, in part, the power ascension test requirements of Regulatory Guide 1.133 Revision 1, Loose-Part Detection Program for the Primary System of Light-Water-Cooled Reactors. 1.4 Satisfy requirements of UFSAR Table 14.2-2, Sheet 39, Loose Parts Monitoring System Test Summary. 2.O Test Methods Testing consists of documenting gain and alarm setpoints at the initial criticality and low pressure (<5o/o) physics testing, 30o/o, 50o/o,75o/o, ?nd 1O0o/o power test plateaus. Baseline frequency spectrums are recorded for each channel while maintaining system sensitivity with the unit above 90% power. 3.0 Test Results AllAcceptance/Review Criteria were met or resolved as delineated below. The performance of this test demonstrated that the system operated as designed. Three channels have been defeated and will not alarm; however, the system meets the criteria in Regulatory Guide 1.133 for loose parts monitoring system function, in that, all recommended collection points have a loose parts monitoring detection sensor operable and in-service. L82
7.4.4 Loose Parts Monitoring System (2-PAT-1.5) (continued) Acceptance Criteria 3.1 The LPMS background audio signals have been recorded for all sensors with no errors. All channels were recorded in 2-TRl-52-1, Loose Parts Monitoring System Channel Calibration, and 2-PAT-1.5 recorded all channels except 101,102 and 110. No errors were noted. (See CR 1171424) 3.2 The LPMS equipment settings for gain and alarm thresholds have been recorded and the as found match the expected values for both gain and alarm settings. The as-found data matched the as expected data. The setpoints are recorded below. Plant Channel Alarm setpoint Gain setpoint 100 3.00 31.30 101 3.00 27.90 102 3.00 22.50 103 3.00 28.80 104 3.00 26.50 105 3.00 26.50 106 3.00 29.10 107 3.00 28.50 108 3.00 27.40 109 3.00 28.60 110 3.00 31 .60 111 3.00 29.90 Note: Commitment 113997023 to notify the NRC of the alert alarm (alarm and gain) settings was previously met by the Preoperational Test Program. No changes to those settings were made by the Power Ascension Test Program and the as-left settings are the same as those reported to the NRC. 183
7.4.4 Loose Parts Monitoring System (2-PAT-1.5) (continued) Review Criteria 3.3 The audio is functional for each channel. This Review Criteria was met for all in service channels. o Channel 101 audio functions but the channel is excessively noisy due to the "llTA rattle". Channel 102 has no output signal due to a damaged accelerometer. o Channel 110 audio functions but the channel is excessively noisy due to signal convertor/pre-amp malfunction. (See CR 1171424') 4.0 Problems t1] CR 't171424 documents the LPMS channel conditions: Corrective actions consisted of: Prompt determination of Operability, Function Evaluation, Assign Work Orders and Closure Review. Work Orders remaining open are: WO 117845593 - Channel 101 Experiencing excessive noise and is alarming due to'llTA'rattling. WO 117843208 - Channel 102 Accelerometer found damaged WO 117843209 - Channel 110 Suspect preamplifier 184
7.4.5 Startup Adjustments of Reactor Contro! System (2-PAT-1.6) Prerequisites actions for this test began on 3/30/16. The performance sections started on 514116 and were completed on 10/3/16 for all power plateaus. 1.0 Test Obiectives The objectives of this test were to: 1.1 Determine the RCS Tavg program resulting in the highest possible steam pressure and thus the optimum unit efficiency without exceeding pressure limitations of the turbine (as indicated by upstream Steam Generator pressure) or the maximum allowable RCS Ta"s. 1.2 Provide, at the 90% and 100%o power plateau, data for the basis for any adjustments to the Reactor Control System (i.e., full load Tref setpoint and/or full load turbine first stage pressure calibrations). 1.3 Satisfy the requirements of UFSAR Table 14.2-2, Sheet 20, Startup Adjustments Of Reactor Controls Test Summary. 2.0 Test Methods This test was to determine the Tavg program resulting in the highest possible steam pressure and thus optimum plant efficiency without exceeding the pressure limitations of the turbine, or the full load Tavg design limit of 588.2 "F. This procedure collected system pressure and temperature data in Mode 3 at nominal hot zero power temperature and pressure conditions and at the 30%, 50o/o,75o/o, 90%, and 100% power plateaus. Data obtained at 75%o,90o/o, and 100% RTP was extrapolated to full load conditions and evaluated to determine if the full load Tavg design limit of 588.2 'F is consistent with the design requirements of the Reactor Control System. The 90% and 100% power test data provided the basis for any adjustments deemed necessary for the Reactor Control System (i.e., full load Tref setpoint and/or full load turbine impulse calibration pressure). 3.0 Test Results AllAcceptance/Review Criteria were met or resolved as delineated below. Acceotance Criteria AllAcceptance Criteria and Review Criteria were met with the exception of Acceptance Criteria 3.2 below and Review Criteria 3.3 for 2-PT-1-81. Alldesired data has been compiled and delineated below: 185
7.4.5 Startup Adjustments of Reactor Control System (2-PAT-1.6) (continued) 3.1 With the Rod Control System in automatic mode, the actualfu!! load t steam generator pressure was within 10 psi of the design full load steam generator pressure (998 psia). With the Rod Control System in automatic mode, the extrapolated full load steam generator pressure was 994.19 psia on the initial performance and 993.68 psia on the second performance. 3.2 The full load Tavg value (i.e., calculated Tref value corrected for measured RCS auctioneered and design Tavg mismatch error) was less than or equal to the design Tavg value of 588.2'F. A full load Tavg of 588.67 'F (588.73 oF second performance) was required to increase the full load steam generator pressure from 994.19 (993.68 second performance) to 998 psia. This value was greater than the design Tavg value of 588.2 "F which is the maximum allowable value based on the assumptions of the licensing basis safety analyses. Therefore, this Acceptance Criteria cannot be met. Since the full load steam generator pressure was t within the 10 psi of the design full Ioad steam generator pressure, there was no safety or operational concern. CR 1211020 was opened for this issue. Review Criteria 3.3 The actualfull load turbine impulse pressure was within t'10 psi of the design full load calibration pressure: 3.3.1 For 2-PT-1-72 and 2-PT-1-81the design full load calibration pressure was 919.4 psia. The full load first stage pressure for 2-PT-1-72 was 946.57 psia which did not meet the Review Criteria . 2-PT-1-81 data was unavailable during testing because 2-PT-1 -81 was out of service . 2-PT-1 -72 and 2-PT-1 -81 were recalibrated to the extrapolated full load first stage pressure of 946 .57 psia. Following the second performance at the 100o/o power plateau, 2-PT-1-72 was extrapolated to be 948 .02 psia and was within the Review Criteria. 2-PT-1-81 calibration will be verified when 2-PT-1-81 is returned to service. CR 1208178 was opened for 2-PT-1 -81 . 186
7.4.5 Startup Adjustments of Reactor Control System (2-PAT-1.6) (continued) 3.3.2 For 2-PT-1-73 and 2-PT-1-74 the design full load calibration pressure was 918.2 psia. The full load first stage pressure for 2-PT-1-73 and 2-PT-1-74 was 944.54 and 945.67 psia, respectively, which did not meet the Review Criteria. 2-PT-1-73 and 2-Pf 4-74 were recalibrated to the extrapolated full load first stage pressures of 944.54 and 945.67 psia, respectively. Following the second performance at the 100% power plateau, 2-PT-1-73 and2-PT-1-74was extrapolated to be 948.04 and 949.53 psia and were within the Review Criteria. 3.4 Rod insertion Iimits LO-LO setpoint in Computer Enhanced Rod Position lndication (CERPI) was correctly calculated for the tested
%AT power.
The rod insertion limits LO-LO setpoints were within t 1 step of the calculated rod insertion limits LO-LO. CBA CBB cBc CBD Calculated RIL LO-LO Setpoint 211 211 133 17 PLCA RIL LO-LO 211 211 134 18 PLCB RIL LO-LO 211 211 134 18 4.0 Problems I1I CR 1161085 - Procedure steps were removed from Appendix C of 2-PAT-1.6 that were inadvertently included. l2l CR 1208178 The pressure transmitter PT-1-81 was out of service above the75o/o power plateau. Therefore, data was not collected to verify Review Criteria S.2Afor the full Ioad turbine first stage pressure. 2-PT-1-81was calibrated based on the data collected for 2-PT-1-72. Yerilication of the 2-PT-1-81 calibration will be completed when 2-PT-1-81is returned to service outside of the PAT program. t 87
7.4.5 Startup Adiustments of Reactor Control System (2-PAT-1.6) (continued) t3I CR 1211015 - Review Criteria 5.2A for calibration of the turbine first stage pressure calibrations was not met after completion of the first performance of the 100o/o power plateau. Design Engineering updated the turbine first stage pressure calibrations for 2-PT-1-72, - 73, -74, and -81. Following a second performance of the IOOYo power plateau, 2-PT-1-72, -73, and -74 caltbrations met Review Criteria 5.2A. 2-PT-1-81was out of service during the second performance of the 100% power plateau. Therefore, 2 PT-1-81 calibrations must be verified when 2-PT-1-81is returned to service outside of the PAT program. t4l CR 1211020 - Acceptance Criteria 5.1B was not met because a full load Tavg of 588.67 "F would be required to increase the full load steam generator pressure from 994.19 to 998 psia. The maximum oF allowable Tavg is 588.2 and therefore, the steam pressure cannot be achieved and this Acceptance Criteria cannot be met. Note that the full load steam generator pressure was within t 10 psi of the design full load steam generator pressure; Therefore, this condition does not represent any safety concern or operationa! concern. This CR was opened to trend this issue. 188
7.4.6 Operational Alignment of Process Temperature lnstrumentation (2-PAT-1.7) The prerequisites for the Mode 3 performance of this test began on 5/3/16 and field work was completed on 9129116 following the second performance of the 100o/o power plateau. 1.0 Test Objectives The objectives of this test were to:
'1.1 Determine the full power temperature rise across the reactor vesse!, to verify that the full power RCS average temperature does not exceed the maximum allowable, and to ensure that RCS temperature instrumentation is in alignment.
1.2 Satisff the requirements of UFSAR Table 14.2-2, Sheet 16, Operational Alignment Of Process Temperature Instrumentation Test Summary. 2.0 Test Methods Performance of this instruction collected data at the following plant conditions: o Mode 3 at no-load temperature and pressure
. 30o/o power plateau (27.4% Rated Thermal Power (RTP))
o 50o/o power plateau (47.5% RTP) c 75o/o power plateau (73.67Yo and 73.620/o RTP) o 90% power plateau (93.44o/o RTP)
. 100o/o power plateau (98.85% and 99.19% RTP)
Section 6.1 of the test was performed prior to initial criticality with isotherma! conditions established in the RCS. Temperature data was collected and reviewed to ensure that temperature instrumentation was aligned to acceptable limits. Section 6.2 ol the test was performed at each power test plateau. RCS hot and cold leg temperatures, RCS pressure, calorimetric power, and hot leg RTD streaming coefficients were measured. The RCS temperature and pressure were used to determine RCS hot and cold leg enthalpies. A curve fit was performed using these enthalpies and the associated calorimetric power fom several test plateaus to extrapolate the enthalpies at full power. These extrapolated full power enthalpies were converted to the corresponding full power RCS hot and cold leg temperatures. These temperatures were used to determine the fu!! power AT and T"rrfor each RCS loop. 189
7.4.6 Operational Alignment of Process Temperature Instrumentation (2-P AT -1 .7) (continued ) 3.0 Test Results All Acceptance/Review Criteria were met or resolved as delineated below. Acceotance Criteria 3.1 At the 100% power level, the highest value for the Calculated Tavg at 100o/o Power was less than or equal to 588.2 'F. 100o/o Power Plateau Calculated Tavg Loop 1 Loop 2 Loop 3 Loop 4 at 100% Power 587.18 0F 586.59 "F 587.77 "F 588.23 "F Calculated Tavg at 100o/o Power for Loop 4 was greater than 588.2 "F. Loop 4 was the auctioneered high Tavg at each power plateau and therefore Loop 4Tavg was expected to be approximately 588.2'F. Although this represents a failure in this Acceptance Criteria this is not a safety concern or failure to meet the licensing basis in the UFSAR because the plant will not operate at a full power Tavg greater than 588.2 "F. Additionally, the nominal Tavg (T' and T") values for Loop 4 were set to a value of 588.2 oF in accordance with the Technical Specifications. CR 1211021 was written for trending purposes. 3.2 At the 100% power level, the difference between Reactor Power and Vessel AT was less than or equal to 1.0% RTP. This criteria was met. 100o/o Power Plateau Loop 1 Loop 2 Loop 3 Loop 4 T-411 T-421 T431 T-441 AT 98.88% gB.g0% 98.74o/o 98.82o/o Reactor Power 98.85o/o 98.85% 98. B5o/o 98.85% Difference 0.03% 0.05% -0. 1 1o/o -0.03% 3.3 At the 100Yo power level, the difference between Reactor Power and Steam Generator Level TTD AT was less than or equal to 1.0o/o RTP. This criteria was met. 100o/o Power Plateau Loop 2 Loop 3 Loop 4 T421A T-431A T-441A AT 98.961o/o 98.487o/o 99.061o/o Reactor Power 98.85o/o 98.85% 98.85o/o Difference 0.111o/o -0.363% 0.211o/o 190
7.4.6 Operational Alignment of Process Temperature lnstrumentation (2-PAT-1 .7) (continued) 3.4 AtZero Power (Mode 3), the VesselAT was equal to 0.0% RTP (-'1.0 to 1.0yo). This criteria was met. Mode 3 Plateau Loop 1 Looo 2 Looo 3 Loop 4 T411 T-421 T-431 T-441 AT -0.430o/o 0.1 1 4o/o 0.5460/o 0.093% 3.5 AtZero Power (Mode 3), Steam Generator Level TTD AT was equalto 0.0% RTP ( -1.0o/o to 1.0%). This criteria was met. Mode 3 Plateau Loop 2 Loop 3 Loop 4 T-421A T-431A T441A AT 0.034o/o 0.375o/o 0.2120/o Review Criteria 3.6 At the 90% power level, the highest values for the Calculated Tavg at 100% Power was less than or equal to 588.2 'F. This criteria was met. 90o/o Power Plateau Calculated Tavg Looo 1 Loop 2 Loop 3 Loop 4 at 1 00o/o Power 586.99 0F 586.41 "F 587.65 0F 588.03 0F 3.7 At 90% power level, the difference between Reactor Power and Vessel AT was less than or equal to 1.0% RTP. 90o/o Power Plateau Loop 1 Loop 2 Loop 3 Loop 4 T411 T-421 T431 T-441 AT 95.69% 94.75o/o 95.09% 95.00% Reactor Power 93.44o/o 93.44o/o 93.44o/o 93.44o/o Difference 2.25o/o 1 .31o/o 1.650/o 1.560/o This Review Criteria was not met, however, this test instruction resolved the issue by adjusting the nominal loop AT values based on the data recorded up through the 90% power plateau. (See Problem [5]). T9L
7.4.6 Operational Alignment of Process Temperature Instrumentation (2-PAT-1 .7) (continued) 3.8 At the 90% power level, the difference between Reactor Power and Steam Generator Level TTD AT was less than or equal to 1.0o/o RTP. 90% Power Plateau Loop 2 Loop 3 Loop 4 T-4214 T431A T-441A AT 94.49o/o 95.15o/o 95.03% Reactor Power 93.44o/o 93.44o/o 93.44o/o Difference 1.05o/o 1 .71o/o 1.59o/o This Review Criteria was not met, however, this test instruction resolved the issue by adjusting the nominal loop AT values based on the plant data recorded up through the 90% power plateau. (See Problem [5]). Note: For the reminder of the Review Criteria (below) data was collected at all power levels and adjustments were made as needed during power escalation. Only the percent error data from the final measurements are presented in this report. 3.9 At all power levels, the difference between Eagle 21 ICS Points Average values and MCR lndicators for Process Temperature lnstrumentation was within 2.5%. This criteria was not met at the 30% Plateau. CR 1182246was initiated. The maximum absolute error seen during the final measurements was 1,55o/o. 3.10 At all power levels, the difference between Eagle 21 ICS Points Average values and MCR Recorders for Process Temperature lnstrumentation is within 2.5%. This criteria was met. The maximum absolute etror seen during the final measurements was 1 .10o/o. 3.11 At all power levels, the difference between Eagle 21 ICS Points Average values and Computer Points for Process Temperature Instrumentation was within 1.0Yo. This criteria was met. The maximum absolute error seen during the final measurements was 0.35%. L92
7.4.6 Operational Alignment of Process Temperature lnstrumentation (2-P AT -1 .7) (conti nued ) 3.12 ln Mode 3 and at all power levels, the difference between MM! values and MCR lndicators for Process Temperature I nstrumentation was within 2.5o/o. This criteria was not met in Mode 3, 30% Plateau, and the 75% Plateau. CRs 1168641 , 1182246 and 1196243 were initiated for these failures. The test was repeated a second time at the 75% Plateau and the criteria was met. The maximum absolute error seen during the final measurements was 1.620/o. 3.13 ln Mode 3 and at all power levels, the difference between MMI values and MCR Recorders for Process Temperature lnstrumentation was within 2.5To. This criteria was met. The maximum absolute eror seen during the final measurements was 1.1o/o. 3.14 ln Mode 3 and at all power levels, the difference between MMI values and the Computer Points for Process Temperature lnstrumentation was within 1.iYo. This criteria was not met at the 75o/o Plateau and the 100% Plateau. CRs 1196245 and 1211018 were written for these initial failures. The test was repeated and the criteria was met at both of these plateaus. The maximum absolute error seen during the final measurements was 0.63%. 4.0 Problems l1l CR 1168641 (Mode 3 Performance) Review Criteria 5.2G associated with comparison of the MCR indicators to the MMI cart printouts for OTAT were not met. The OTAT setpoints have a full scale output of 150o/o while the MMI values display the OTAT setpoint value. The OTAT setpoints were approximately 172% while the MCR indicators were offscale high and indicating full scale output of 150%. The CR was generated; however, no resolution was required as the MCR full scale output is not adjustable and the MCR OTAT setpoints came onto scale at the higher power plateaus. 193
7.4.6 Operational Alignment of Process Temperature Instrumentation (2-P AT -1 .7) (conti n ued ) l2l CR 1182246 (30% Performance - Review Criteria 5.2D and 5.2G were not met.) Review Criteria 5.2D and 5.2G associated with comparison of the MCR indicators to either the MMI cart printouts or ICS outputs for OTAT were not met. The OTAT setpoints have a full scale output of 150% while the MMI values display the OTAT setpoint value. The OTAT setpoints were approximately 158% while the MCR indicators were offscale high and indicating full scale output of 150%. The CR was generated; however, no resolution was required as the MCR full scale output is not adjustable and the MCR OTAT setpoints came onto scale at the higher power plateaus. t3] CR 1196243 (75o/o Performance - Review Criteria 5.2G was not met) Review Criteria 5.2G associated with comparison of the MCR indicator to the MMI cart printouts for Loop 1 OTAT was not met. The difference between TY-411G and 2-Tl-68-28 was 3.3% which was greater than the Review Criteria of 2.5%. The CR was generated and no instrumentation adjustments were made. A second performance of 2-PAT-1.7 was performed attheTSo/o power plateau and this Review Criteria was met and this CR closed. 141 CR 1196245 (75yo Performance - Review Criteria 5.21 was not met.) Review Criteria 5.21 associated with comparison of the ICS computer point to the MMI cart printouts for Loop 2 OTAT was not met. The difference betweenT(421G and T0430A was 1.25% which was greater than the Review Criteria of 1.0o/o. The CR was generated and no instrumentation adjustments were made. A second performance of 2-PAT-1.7 was performed at the 75% power plateau and this Review Criteria was met and this CR closed. l5l No CRs, (90% Performance - Review Criteria 5.2B and 5.2C were not met) Review Criteria 5.28 and 5.2C associated with the indication of AT power as compared to Reactor Power were not met. This issue was resolved by recalculating the nominalAT using performance steps included in 2-PAT-1.7 prior to power ascension. L94
7.4.6 Operational Alignment of Process Temperature Instrumentation (2-PAT-1 .71 (continued) A CR was not opened as the 2-PAT-1.7 performance was designed to correct the issue and the Acceptance Criteria was verified for the 100Yo power plateau. t6I CR 1207628 (90% & 100% Performance - spurious alarms) Annunciator2-XA-55-5N92F, "Eagle Proc Prot Ch-lll RTD Failure" alarmed intermittently above approximately 75o/o power. The deviation of Loop 3 Tcold RTDs was intermiftently above the DeltaC RSA setpoint of 2.5 'F. Adjustment of DeltaC RSA was not a part of this procedure because a Tcold RTD deviation greater than 2.5 "F was not anticipated. Design Engineering increased the DeltaC RSA setpoint to 3.0 'F which eliminated spurious alarms during power operation. 17l CR 1211018 (100% Performance - Review Criteria 5.21 not met.) Review Criteria 5.21 associated with the comparison of the ICS computer point to the MMI cart printout for Loop 2 OTAT was not met. The difference betweenTY42lG and T0430A was -1.6% which was greater than the Review Criteria of 1.0o/o. The CR was generated and no adjustments were made. A second performance of 2-PAT-1.7 was performed at the 100o/o power plateau and this Review Criteria was met and this CR closed. t8I CR 1211021 (100% Performance - Acceptance Criteria 5.1A was not met) Acceptance Criteria 5.1A was not met. This criteria verified that the highest calculated Ioop Tavg is less than or equal to 588.2 'F. The highest calculated loop Tavg was 588.23 'F for Loop 4 which was primarily due to the lower reactor coolant pump flow in that loop. Loop 4 was also the auctioneered high Tavg value at each power plateau, so it is expected that this loop resulted in a calculated full power Tavg of 588.2 'F. Although this represents a failure in the Acceptance Criteria, this does not result in a safety concern or failure to meet the design basis of the plant because the auctioneered Tavg will be maintained less than or equal to 588.2 'F during plant operation. ln addition, the nomina! Tavg (T' and T") for Loop 4 was set to oF 588.2 in accordance with the technical specifications. This CR was written for trending purposes. 195
7.4.7 Thermal Expansion of Piping Systems (2-pAT-1 .B) This procedure was performed during the performance of 2-pAT-3.0 through 2-PAT-8.0. Prerequisite actions started on 12107115 and testing was conctuded on 08/30/16. Data was obtained to ensure Main steam, Feedwater, steam Generator Blowdown, ChemicalVolume and Control, and Reactor Cootant System piping and components were free to expand and contract without restriction (other than by design) during heat-up and cool-down. Data was obtained at eight (8) temperature and power plateaus 1.0 Test Obiectives The objectives of this test were to: 1.1 Demonstrate that piping systems defined in section g.g.2.1of the UFSAR, with operating temperatures greater than 200oF, experience thermal expansion consistent with design and did not interfere with the pipe thermal growth. 1.2 Re-evaluate the Thermal Monitoring points and support locations which did not meet their Acceptance criteria or were not examined fully during the Hot Functional Testing program. 1.3 Evaluate Thermal Monitoring Points and support rocations which were not examined or could not be examined during the Hot Functional Testing Program. 1.4 Perform visualobservations and take measurements on various Pipe Rupture Protective Devices (PD) to ensure they do not interfere with the pipe thermal growth. 1.5 satisfy the requirements of UFSAR Table 14.2-2, sheet s, Thermal Expansion of Piping Systems. 2.0 Test Methods Data collection measurements were performed at specific supports, Monitoring Points and Protective Devices at the temperature plateaus of Ambient, 360"F, 450"F, 557oF, 30% Power, S}Yo power, 7lo/o power and 100o/o Power to provide assurance that system piping and supports were moving in the correct direction and remained within their acceptable movements and working range per the Stress Analysis. UFSAR Table 14.2-2, Sheet 5 Test Method, refers to an evaluation at finat ambient conditions. This final ambient condition evaluation will be performed later and is tracked by COMMITMENT 118008175. L96
7.4.7 Thermal Expansion of Piping Systems (2-PAT-1.8) (continued) 3.0 Test Results AllAcceptance/Review Criteria were met or resolved as delineated below. Acceptance Criteria 3.1 Piping and components were free to expand and contract without restriction, other than by design, during power ascension heatup and cooldown of the specified systems. All piping and components were able to expand and contract as designed during Power Ascension Heat Up and Cool Down for the specified systems below:
. Main Steam System
. Main Feedwater System
. Steam Generator Blowdown o Chemical and Volume Contro! System o Reactor Coolant System 3.2 The measured therma! movement was within t114 inch or 10 percent of the analytical value, whichever was greater.
There were 34 measurements taken with 30 measurements not meeting the Acceptance Criteria (t 114" of their design movement) at the temperature observed at the Plateaus. Civil Engineering evaluated the 30 measurements which did not meet the Acceptance Criteria and found they were moving in the correct direction and were therefore acceptable for all Plateaus. 3.3 Spring hanger movements remained within the hot and cold working range, and snubbers did not become fully retracted or extended. All of the spring hangers remained within the hot and cold working range and all of the snubbers remained within their working range and were not fully retracted or extended. 3.4 Pipe rupture protective devices did not interfere with the free thermal movement of the piping. There was one pipe rupture protective device shim which was found bound. lt was removed, reworked and re-installed. All other pipe rupture protective devices were found to be acceptable. Review Criteria None L91
7.4.7 Thermal Expansion of Piping Systems (2-PAT-1.8) (continued) 4.0 Problems There were four test deficiencies documented on Problem Reports. One CR was generated due to condition adverse to quality and two non-test deficiency CRs were generated during performance of this test. All Problem Reports and CRs have been closed. A description of these deficiencies and resolutions are as follows: t1I Problem Report #1 was written to document that several measurements did not grow as expected during the examinations at the 360'F and 450'F temperature plateaus. There were 34 measurements taken with 30 measurements not meeting the Acceptance Criteria (*, 114" of their design movement) at the temperature observed at the Plateau. Engineering also requested to test snubbers in close vicinity of the deficient locations along with performing a piping walk down of the deficient areas for any physical interferences. All snubbers tested were performing as designed and not locked up. Also, no physica! interferences were discovered during the walk downs. Civil Engineering evaluated the 30 measurements which did not meet the Acceptance Criteria and found they were moving in the correct direction, were inside their working range, were not fully extended or contracted and were therefore acceptable for these Plateaus. l2I Problem Report #2 was written, during the 557'F plateau, due to Protective Device PD07-2 not having a gap as required by the design. Engineering requested that PD07-1 be measured to ensure there was sufficient gap due to it being on the same Protective Device restraint. The shim met the gap requirement. CR 1160934 was written and closed for PD07-2. Work for this CR was compfeted under WO 117755755. The PD was removed, the shim reduced in thickness and the PD re-installed correcting the gap per design. t3I Problem Report #3 was written to document that several measurements did not grow as expected during the examinations at the 557"F temperature plateau. There were 34 measurements taken with 30 measurements not meeting the Acceptance Criteria (t 114" of their design movement) at the temperature observed at the Plateau. Civil Engineering evaluated 26 measurements which did not meet the Acceptance Criteria and found that the piping was either growing too much or not growing enough. Although deficiencies exist the pipe was growing in the proper direction. l- 98
7.4.7 Thermal Expansion of Piping Systems (2-PAT-1.8) (continued) The associated snubbers and spring can supports remained within their working range and snubbers were not fully extended or retracted. The four remaining measurements of Main Steam piping supports located outside of containment in the yard (MS17, MS18, 474400-16 and -24) were required to have further evaluations performed for deficient movements. Severalwalk downs were performed to ascertain the condition of the piping, (i.e., any observed interferences). The walk downs concluded there were no "hard" interferences that would inhibit the thermal movements of the piping. lt was noted that these supports were not moving in accordance with the stress analysis. While the piping is not behaving as intended (free to move) it has been proven that the piping, support and weld will remain qualified during this condition and piping integrity is not jeopardized. Therefore, the current condition of the piping is acceptable. t4I Problem Report #4 was found during the 50% Power level and was written to document supports 01A-2MS-V116 and 01A-2MS-V1175 which were found to be reading -1l16" above the 0 mark. At the Hot Load setting the reading for support 01A-2MS-V1175 should be +1/8" below the 0 mark. At the Hot Load setting the reading for support 01A-2MS-V116 should have been +5/16" below the 0 mark. The spring cans were not topped out but they were slightly above the 0 mark which made them outside their working range. WO 117973327 was used to correct the out of adjustment condition and closed. The two spring can supports were re-measured and found to be acceptable at the 75o/o power level. L99
7.4.7 Thermal Expansion of Piping Systems (2-PAT-1.8) (continued) There were two non-test deficiencies CRs written to document problems which did not affect the final test results. t5I CR 1209496 was written to document not removing Power Ascension Testing Thermal Expansion instrumentation and their supports from inside Containment. This will be performed at the earliest convenience or no later than the Unit 2 Refueling Outage 1. t6l CR 1208437 was written to document two measurements during the 30% Power Plateau taken incorrectly. This did not affect the test results since these were only for reference and the 100% measurements were the ones used to size the shim thicknesses. 200
7.4.8 Automatic Steam Generator Level Contro! (2-PAT-1.9) This PAT was performed as part of test sequences 2-PAT-7.0, Test Sequence For 75o/o Plateau and 2-PAT-8.0, Test Sequence for 100o/o Plateau. The preparations for testing started onTl19l16 and field work completed ong128116. 1.0 Test Obiectives The objectives of this test were to: 1.1 Demonstrate the proper operation of the Steam Generator Level Contro! System during steady state operation and by observing system response at75% and 100% power. 1.2 Satisfy, in part, the requirements of UFSAR Table 14.2-2, Sheet 30, Automatic Steam Generator Level Control Test Summary. 2.0 Test Methods This procedure collects data on Steam Generator Level Control System to verify proper system operation. Measured parameters such as levels, flows, pressures, valve positions, etc. were compared with predicted values and analyzed for stability. Section 6.1 of this test was performed with the plant stable at a pproximately 7 5o/o power. Section 6.2 of this test was performed with the plant stable at approximately 100% power. 3.0 Test Results AllAcceptance/Review Criteria were met or resolved as delineated below. Acceotance Criteria - 100o/o Power Testing Plateau 3.1 The Main Feedwater Pump Speed Control System maintained adequate Feedwater Heater Supply Header pressure such that the Main Feedwater Reg. Valves (2-FCV-3-35, -48, -90 & -103) were not fully open at 100o/o power. Main Feedwater Reg. Valve Percent Open Valve Percent Open 2-FCV-3-35 70.47o/o 2-FCV-3-48 68.18o/o 2-FCV-3-90 69.31o/o 2-FCV-3-103 72.73o/o 20L
7.4.8 Automatic Steam Generator Level Control (2-PAT-1.9) Review Criteria -75o/o & 100% Power Testing Plateaus Al! required Review Criteria for this test at both the 75o/o and 100Yo power testing plateaus were met as delineated below: 3.2 The ActualAP between the Feedwater Heater Supply Header Pressure and the Main Steam Header Pressure was within t25,0 psi of the Program AP during steady state operation. Al75% Power Plateau, measured eror = 2.2 psi At 100% Power Plateau, measured error = 13 psi 3.3 The position for each Main Feedwater Reg. Valve (2-FCV-3-35, 48, -90 & -103) was between the minimum and the maximum positions for the measured Main Steam Flow. Main Feedwater Reg. Valve Percent Open Valve 75o/o Plateau 100o/o Plateau Percent Open Percent Open 2-FCV-3-35 56.7o/o 70.47o/o 2-FCV-3-48 52.4o/o 68.18% 2-FCV-3-90 56.7o/o 69.31o/o 2-FCV-3-103 54.60/o 72.73o/o BO I IO 3C 1' E ro 1r a\i 60 a ft rE i I C t'o ta 3 G no
.s tTo qFtln G
lro I 6 + - frlot ca 3 3,, <-llu i l(} ac 10 bJ io t() liJ Slorm Flowin Pcrc*rr (10ff6 - 3"778 IPPII) 202
7.4.8 Automatic Steam Generator Level Control (2-PAT-1.9) 3.4 The Feedwater Heater Supply Header Pressure oscillations were less than 13.0% (t54.0 psi) during steady state operation. Feedwater Heater Supply Header Pressure Oscillations 75o/o Plateau 100% Plateau Oscillations Oscillations 1.135 psi 0.063% 1.75 psi 0.097o/o 3.5 Demand Signal oscillations for each of the Main Feedwater Reg. Valves (2-FCV-3-35, 48, -90 & -103) were less than t6.0% during steady state operation. Demand Signal Oscillations Valve 75% Plateau 100o/o Plateau 2-FCV-3-35 0.35% -0.2o/o 2-FCV-3-48 -0. 1 5o/o -0.1o/o 2-FCV-3-90 -0.35% -0.36% 2-FCV-3-103 -0.1o/o 0o/o 3.6 Feedwater Flow oscillations to each Steam Generator were less than t6.0% during steady state operation. Feedwater Flow Oscillations Steam 75% Plateau 100o/o Plateau Generator SG#1 0o/o 1 .351o/o SG #2 1.88o/o 1.337o/o SG #3 1.88o/o 1.333o/o SG #4 1.88o/o 1.333o/o 203
7.4.8 Automatic Steam Generator Level Gontrol (2-PAT-1.9) 3.7 Each Steam Generator lndicated Level was within *2o/o of the Average Program Level during steady state operation. Steam Generator Level Error 75o/o Plateau 100o/o Plateau Steam MAX MIN MAX MIN Generator SG#1 0.6% -0.7o/o 1.2o/o -1 .7o/o SG #2 0.5o/o -0.7o/o 0.55% -1 .15o/o SG #3 0.696 -0.5o/o 0.8o/o -1 .60/o SG#4 0.8o/o -0.7o/o 0.7o/o -1 .2o/o 4.0 Problems There were no significant problems encountered during the performance of this test. 204
7.4.9 lntegrated Computer System (lCS) (2-PAT-1 .10) This test was performed as part of test sequences 2-PAT-4.0,lnitial Criticality and Low Power Test Sequence; 2-PAT-5.0, Test Sequence for 30% Plateau; 2-PAT-6.0, Test Sequence for 50% Plateau; 2-PAT-7.0, Test Sequence for 75o/o Plateau; and 2-PAT-8.0, Test Sequence for 100% Plateau. Post critical testing was started on 05/16/16 and was field work complete on 8131116 at the 100Yo plateau. 1.0 Test Obiectives The objectives of this test were to: 1.1 Evaluate the quality and usability of selected ICS monitored points needed for trending during the At Power Testing phase of the Power Ascension Test Program. 1.2 Obtain control room instrumentation readings to compare to ICS readings at steady-state power levels of approximately 0o/o,30o/o, 50o/o,75o/o, and 100% of full power to determine if they were within their Maximum Expected Deviation (MED). 1.3 Provide a comparison of selected ICS calculations to other offline calculation methods at approximately 30% and 100% power to determine if the accuracy was as expected. 1.4 Satisfo the requirements of UFSAR Table 14.2-2, Sheet 29, Process Computer Test Summary. 2.0 Test Methods At each power plateau, selected computer inputs were verified correct by comparing the corresponding ICS data to main contro! board indications. Also at the 30% and 100% power plateaus the Xenon and Calorimetric calculations performed by the ICS were compared to the results of alternate calculation methods to confirm the ICS validity. 3.0 Test Results AllAcceptance/Review Criteria were met or resolved as delineated below. There was no Acceptance Criteria for the first objective. ICS PlDs were evaluated as part of the prerequisites of the test; additional PlDs were added and evaluated, as needs were identified. 205
7.4.9 Integrated Computer System (lGS) (2-PAT-1.10) (continued) Acceptance Criteria 3.1 Selected process inputs, as indicated by main control boards, agree with ICS printouts and/or ICS displays within the accuracy of the instrumentation. ICS points agreed with the main control board indicators within the accuracy of the instrumentation (i.e. specified MED values). Those PlDs outside of their MED were identified in CRs which generated WOs for calibrations. Al! required calibrations have been completed. See CRs below. 3.2 Selected performance calculations are confirmed by alternate calculation methods. ICS performance calculations for Xenon and the Calorimetric Calculation agreed with alternate calculations within the specified MED values. The Calorimetric Calculation differed by -2.91MW at the 30% plateau and by -3.4 MW at the 100o/o plateau. Xenon Worth differed by 4.6 PCM at the 30% plateau and by +7.9 PCM at the 100%o plateau. Review Criteria There were no Review Criteria for this PAT. 4.0 Problems t1I CR 1173586 the ICS indicated quality is BAD for nine points (PlDs: DCS0175, DCS0392, T0410A, T0430A, T0450A, T0470A; T2810A; T2811A; and V9057A); however, DCS0175 quality was good when needed while running 2A MFW pump and the other eight PID qualities became GOOD at higher power levels, when needed. Associated WO was cancelled after75o/o testing passed. l2l CR 1174334 initiated during the post critica! plateau for a deviation between 2-Tl-62-29, RCP 3 LWR RADIAL BRG Temp, and T0457A. However, comparisons at 30%, 50o/o,75o/o and 100% Plateaus passed Acceptance Criteria. Associated WO was cancelled after 7 5o/o testing. 206
7.4.9 lntegrated Gomputer System (lCS) (2-PAT-1.10) (continued) t3l (CR 1181784 and 1181970) to document and correct the Engineering Units on two PIDs (F2250A, MFWP A Flow and F2251A, MFWP B Flow). 2-PAT-1.10 Revision 4 corrected the units in the test and CR 1181970 was closed. The Unit 2 ICS database manager was updated with the correct units. t4l CR 1 195476 for a deviation between 2-Tl-062-0071, Regen HX Out LTDN Temp, andT0127A. This CR was closed to WO 118007324 that performed requested calibrations. 15] CR 1208754 for a deviation between 2-Tl-062-0004, RCP 1 Seal Out Temp, and T0181A. This CR was closed to WO 1181U299 that performed requested calibrations. 201
7.4.10 RVLIS Performance Test (2-PAT-1.111 Prerequisite actions for this test began on 3110116. The performance section started on3125116 and completed on 8/30/16. 1.0 Test Obiectives The objectives of this test were to: 1.1 Collect data during power ascension in order to determine the RVLIS scaling coefficients. 1.2 Satisfy requirements of UFSAR Table 14.2-2, Sheet 38, Reactor Vessel Level lnstrumentation System (RVLIS) Test Summary. 2.0 Test Methods Data was collected from each RVLIS input sensor and output from the control room Common Q displays (i.e., plasma displays) as the plant progressed from Mode 4 to 100% power. The output level displays from RVLIS were reviewed at each plateau. The collected input and output data was used by SE to determine new RVLIS computer scaling coefficients and/or transmitter spans, if required. This test was performed in Mode 4 from approximately 200"F to Mode 3 at 557"F, and in Mode 1 at nominal power levels ol30o/o,50o/o,75o/o, ?nd 100o/o. Data was collected during heatup and in Mode 3 with various RCS pump running combinations. Data was reviewed prior to Mode 2 entry, to confirm no obvious errors were present in RVLIS. Testing at power required the plant be stable. 3.0 Test Results AllAcceptance/Review Criteria were met or resolved as delineated below. 3.1 Acceotance Criteria for RVLIS in Mode 3: 3.1.1 RVLIS level indicated between95.2% and 104.8% at each RCS temperature plateau with all RCPs running. The RVLIS Levelfor all Reactor Coolant Pumps running at each RCS temperature plateau met Acceptance Criteria as shown below: 208
7.4.10 RVLIS Performance Test (2-PAT-1.111 (continued) Temperature RVLIS RVLIS Plateau - oF A Train - o/o B Train - o/o 300 102.0 100.8 350 102.7 101 .3 400 101 .4 100.2 450 101 .4 100.2 500 102.3 100.6 557 102.6 100.1 3.1.2 RVLIS level indicated between 96.8% and 103.2o/o with no RCPs operating. See Chart below. 3.1.3 RVLIS level indicated between 95.2o/o and 104.8% with all RCPs operating. See Chart below. g.1.4 RVLIS level indicated betwee n 95.2o/o and 104.8o/o with at least one RCP operating. See Chart below. The RVLIS levels for the Mode 3 Reactor Coolant Pump Combinations met Acceptance Criteria except those noted (1) below. CR 1171130 was written and RVLIS constants were updated with WO 117509605. RCS Pump Combination Display A-Train - B-Train - Number Mode 3 Output o/o o/o Combination Number 1 RVLIS 102.7 103 .4 (1) RCPs runninq: None Level Combination Number 2 RVLIS 95.2 100.0 RCPs running: 3 only Level Combination Number 3 RVLIS gB.7 81.3 (1) RCPs runninq: 2 and 3 Level Combination Number 4 RVLIS RCPs running: 97.3 100.0 Level 2,3 and 4 Combination Number 5 RVLIS 100.0 90.8 (1) RCPs running: 1 only Level Combination Number 6 RVLIS 100.0 90.2 (1) RCPs runninq: 1 and 2 Level Combination Number 7 RVLIS RCPs running: 99.7 92.1 (1) Level 1,2 and 4 Combination Number 8 RVLIS RCPs running: 101 .8 100.4 Level 1.2.3 and 4 (1) - Acceptance Criteria was not met for these RVLIS levels. CR 1171 130 was written. 209
7.4.10 RVLIS Performance Test (2-PAT-1 .11) (continued) 3.2 Acceptance Criteria for RVLIS at Power: The full power scaling coefficient (A T) for both dynamic RVLIS trains is correctly determined and entered into RVLIS computer as indicated by the following: 3.2.'l RVLIS level indicated between 95.2o/o and 104.8%o for all power levels. Actual data is shown below: Power Level RVLIS RVLIS
% Train A Level Train B Level o/o Yo 30 gg.3 99.1 50 99.0 99.2 75 99.3 100.0 100 100.1 100.4 3.3 Review Criteria for RVLIS at 400"F:
3.3.1 RVLIS Level indicates between 96.8% and 103.2o/o with no Reactor Coolant Pumps operating. See Chart below. 3.3.2 RVLIS level indicated betweeng5.2o/o and 104.8% with all RCPs operating. See Chart below. 3.3.3 RVLIS level indicated between 95.2o/o and 104.8o/o with at least one RCPs operating. See Chart below. RCP Combination #2 RVLIS level readings were missed and ICS-derived readings were recorded at those noted (1) below. CR 1156311 was written. See Chart below. RVLIS levels met Review Criteria at 400"F except those noted (2) below. CR 1156425 was written. 2L0
7 .4.10 RVLIS Performance Test (2-PAT-1.111 (continued) RCS Pump Combination Display A-Train - B-Train - o/o Number - 400oF Output % Combination Number 1 RVLIS 102.4 1 03.1 RCPs runninq: None Level Combination Number 2 RVLIS 100.0 (1) 100.0 (1) RCPs runninq: 2 only Level Combination Number 3 RVLIS 100 98.4 RCPs runnins: 2 and 3 Level Combination Number 4 RVLIS RCPs running: 95.1 (2) 98.4 Level 2,3 and 4 Combination Number 5 RVLIS 100.0 94.8 (2) RCPs runnino: 1 onlv Level Combination Number 6 RVLIS 100.0 100.0 RCPs runninq: 1 and 2 Level Combination Number 7 RVLIS RCPs running: 100 100.0 Level 1,2 and 4 Combination Number 8 RVLIS RCPs running: 102.5 101 .6 Level 1,2,3 and 4 (1) - Data is from lCS, since MCR Display data was missed. cR 1156311. (2) - Below Review Criteria. CR 1156425. 4.O Problems t1l CR 1156311 During the 400'F RCP Combinations, RCP #2 was started before the Combination #2 data could be taken. Data was gathered from ICS for this combination and provided to Westinghouse. The ICS data met the Review Criteria. l2l CR 1156425 During the 400"F RCP Combinations, the Review Criteria was not met for two RVLIS level readings. Data was transmitted to Westinghouse and Site Engineering for evaluation. RVLIS constants were updated in the Common Q system by Westinghouse Letter WBT-D-5653 and WO 117509605 on 4128116. 13] CR 1171130 During the 557'F RCP Combinations, the Acceptance Criteria was not met for five RVLIS level readings. Data was transmitted to Westinghouse and Site Engineering for evaluation. RVLIS constants were updated in the Common Q system by Westinghouse Letter WBT-D-5665 and WO 117509605 on 5114116. 2tL
7.4.11 Common Q Post Accident Monitoring System (2-PAT-1.121 The test started on 3114116 and completed on 8/30/16. 1.0 Test Obiectives The objectives of this test were to: 1.1 Demonstrate the capability of the Common Q Post Accident Monitoring System (PAMS) to accurately process and display signals associated with reactor vessel level, subcooling margin, and in-core thermocouples. 1.2 Verify the reactor vessel level and core exit temperatures (CET) indications on the control room Common Q displays (Operator Modules) for various temperatures, pressures and power levels. 1.3 Verify wide range RCS pressure, wide range RCS hot leg temperature and delta T power from Eagle 21 inputs to PAMS for various temperatures, pressures and power levels. 1.4 Verify the subcooled margin for various temperatures, pressures and power levels. The Saturation Margin Monitor (SMM) portion of PAMS uses the representative core exit temperature, wide range RCS pressure and wide range RCS hot Ieg temperature to calculate saturation margins. 1.5 Verify RCP status to indicate "RUNNING", 'COASTING DOWN',
"STARTING UP'or "OFF" for each pump as it is cycled. When all4 pumps are secured verify the mode shifted to STATIC.
1.6 Verify the Unit 2 Subcooled Margin Digita! Panel Meters (DPMs) (2-Tl-68-105 and 2-Tl-68-115) indicate consistent with the Common Q displays for various temperatures and pressures. The SMM will provide input to the Unit 2 Subcooled Margin Digital Panel Meters (DPMs) (2-Tl-68-105 and 2-Tl-68-1 15) located on 2-M4. 1.7 Satisfy requirements of UFSAR Table 14.2-2, Sheet 40, lnadequate Core Cooling Monitoring System Test Summary, that were not previously validated as part of Factory Acceptance Testing (FAT) or Site Acceptance Testing (SAT). 2.0 Test Methods Monitor Common Q panel and digital meter indicators in the main control room during varying reactor coolant system conditions for changes in hot leg and CET temperatures, RCP status, vessel level and subcooling margin. 2L2
7.4.11 Common Q Post Accident Monitoring System (2-PAT-1.12) (continued) Observe key pages of the screen displays to verify operability. Simulate malfunction conditions to veriff malfunction alarms on the Common Q main control room panels. Simulate loss of subcooling margin to verify the Common Q main control room alarm is initiated. This test procedure is performed at steady state temperatures of 250"F, 350'F, 400"F, 450"F and 557"F and at nominal power levels of 30o/o,50o/o, 75o/o and 100o/o. The test includes several RCP status changes at 400"F and 557'F. 3.0 Test Results Al! Acceptance/Review Criteria were met or resolved as delineated below. Acceotance Criteria 3.1 Main Control Room (MCR) indicators including key pages of the screen displays, respond to changes in reactor coolant system conditions. This Acceptance Criteria was met because MCR Common Q readings responded to changes in RCS conditions as required. 3.2 The MCR Common Q panel alarms are initiated for Common Q PAMS simulated malfunction conditions as required by approved design and vendor information, for both trains. Both MCR COMMON Q SYSTEM TROUBLE annunciators actuated when the Function Enable Switch was placed in ENABLE; and both annunciators actuated as a reflash when the DP2 breaker was turned off. 3.3 The Common Q Main Control Room alarm panel is initiated for simulated loss of subcooling margin as required by approved design documents. Both MCR Common Q Control Room pane! alarms initiated upon simulated loss of subcooling margin. 3.4 WINCISE Core Exit Thermocouples (CET), as read from Common Q PAMS, are within +l- 10'F of the narrow range RCS average temperature at 557'F. CET temperatures read from Common Q PAMS were within 10'F of the narrow range RCS average temperature at 557"F. 2L3
7.4.11 Common Q Post Accident Monitoring System (2-PAT-1.12) (continued) For Train A: The four narrow range RCS average temperatures were: 553.7'F, 553.9'F, 59.0'F, 554.1 "F The Highest CET was 555.6'F The Lowest CET was 552'F For Train B: The four narrow range RCS average temperatures were: 556.0'F, 556.1 "F, 556.0'F, 555.9'F The Highest CET was 560.3"F The Lowest CET was 553'F 3.5 The difference between the individual CET temperatures and the average cold leg temperature shall be greater than or equal to 10'F at 100 % power. This Acceptance Criteria was met because the Average cold leg temperature was 559"F and the Lowest CET was 587"F. 3.6 Main Control room indicators for Unit 2 Subcooled Margin (2-Tl-68-105 and 2-Tl-68-115) respond to changes in reactor coolant system conditions. This Acceptance Criteria was met because 2-Tl-68-105 and 2-Tl-68-115 readings responded to changes in RCS conditions as required.
- 1) Each indicator was less than the previous reading as the plant progressed from Mode 3, to 30%, 50o/o,75o/o, ?nd 1 00o/o power cond itions.
- 2) Both indicator readings were within 15"F of the CET and RCS subcooled margin indications at 250'F, 350'F, 450'F, and 557'F.
Review Criteria None 4.0 Problems There were no significant problems encountered during the performance of this test. 2L4
7.4.12 RCS FIow Measurement (2-PAT-3.3) Prerequisite actions for this test began on 4115116. The performance section started on 5/3/16 and was completed on9129116. 1.0 Test Obiectives The objectives of this test were to: 1.1 Determine the RCS flow rates (prior to initial criticality) via calculations using the three installed elbow tap differential pressure transmitters in each of the RCS loops. 1.2 Determine the RCS flow rates in Mode 1 during 2-PAT-6.0,2-PAT-7.0, and 2-PAT-8.0 test plateaus using data from secondary plant calorimetric and primary loop temperatures. 1.3 Satisfo the requirements of UFSAR Table 14.2-2, Sheet 14, RCS Flow Measurement Test Summary. 2.0 Test Methods Section 6.1 was performed with the plant in Mode 3 at normaloperating pressure and temperature, prior to initial criticality, as directed by 2-PAT-3.0, Post Core Loading Precritical Test Sequence. This section of the test determined the RCS flow rates via calculations using the three installed elbow tap differential pressure transmitters in each of the RCS loops. Sections 6.2, 6.3, and 6.4 perform calculations only to determine RCS flow from a secondary plant calorimetric and the RCS hot and cold leg enthalpies using data from 2-PAT-1.7, OperationalAlignment of Process Temperature lnstrumentation. These performances were conducted at the 50o/o,75o/o, and 100% testing plateaus respectively. 3.0 Test Results AllAcceptance/Review Criteria were met or resolved as delineated below. Acceotance Criteria 3.1 The RCS flow determined by calorimetric measurement at or above 90% power was equal to or greater than the Technical Specification limit of 380,000 gpm. The 100Yo power plateau test data was evaluated against this criterion. At the 100o/o power plateau the total RCS flow was 398,346 gpm. 2L5
7.4.12 RCS Flow Measurement (2-PAT-3.3) (continued) 3.2 The RCS flow determined by calorimetric measurement in Mode 1, 75% test sequence plateau was equal to or greater than the Technica! Specification limit of 380,000 gpm. At the 75o/o power plateau the tota! RCS flow was 401,750 gpm. Review Criteria 3.3 The RCS flow determined by elbow tap Ap prior to criticality is equal to or greater than 335,160 GPM, which is 90% of the Thermal Design flow. RCS flow in Mode 3 prior to criticality was 385,093 GPM. 3.4 The RCS flow determined by calorimetric measurement in the Mode 1, 50o/o test sequence plateau, is equal to or greater than 372,400 GPM, which is the Thermal Design flow. RCS Flow at 50o/o power plateau was 404,836 GPM. 3.3 The RCS flow determined by calorimetric measurement in the Mode 1, 100o/o test sequence plateau is less than or equal to 420,000 GPM, which is the Mechanical Design Flow. RCS Flow at 100o/o power plateau was 398,346 GPM. 4.0 Problems There were no significant problems encountered during the performance of this test. 2L6
7.4.13 Calibration of Steam and Feedwater FIow Instruments at 100% Power (2-PAr-8.4) This test was performed with the plant stable at approximately 90% and 100% Power as part of 2-PAT-8.0, Test Sequence For 100% Plateau. The test began on 8/8/16 and was field work complete on9129116. 1.0 Test Obiectives The objectives of this test were to: 1.1 Collect data for determining the new calibration spans for the steam flow transmitters, and verify the calibration of the feedwater and steam flow transmitters, by comparing indicated flows between the Main Control Board lndicators, the Protection System, and the Control System. 1.2 Satisfo the 100% objective in the UFSAR Table 14.2-2, Sheet 21, Calibration Of Steam And Feedwater Flow lnstrumentation At Power Test Summary. 2.0 Test Methods ln Section 6.1 at approximately 90% power, steam generator blowdown and tempering flow were isolated while data was collected. Steam generator blowdown and tempering flow were then reestablished and calculations/comparisons were performed. ln Section 6.2 at approximately 100% power, steam generator blowdown and tempering flow were isolated while data was collected. Steam generator blowdown and tempering flow were then reestablished and calculations/comparisons were performed. New steam flow transmitter spans were calculated using data collected from 75o/o,90o/o, and 100% power plateaus and provided to Maintenance. Three of the eight steam flow transmitters were respanned and calibrated. ln Section 6.3 at approximately 100% power, steam generator blowdown and tempering flow were isolated while data was collected. Steam generator blowdown and tempering flow were then reestablished and calculations/comparisons were performed to verify the new spans. 2Ll
7.4.13 Calibration of Steam and Feedwater Flow Instruments at 100% Power (2-PAT-8.4) (continued) 3.0 Test Results AllAcceptance/Review Criteria were met or resolved as delineated below. Acceptance Criteria 3.1 The span for each steam flow transmitter has been normalized to feedwater flow such that there are no steam flow / feedwater flow mismatch alarms. No steam flow / feedwater flow mismatch alarms were received during the performance of either Section 6.2 or Section 6.3. 3.2 The span for each steam flow transmitter has been normalized to feedwater flow such that the Steam Generator Water Level Control can remain in automatic Steam Generator Water Level Control remained in automatic during the performance of both Section 6.2 and Section 6.3. Review Criteria 3.3 The difference between the feedwater flow as measured in the Protection System and the Main Control Board lndicators is within t5.0% of the rated flow. As-left in Section 6.3 with measured differences (% ERRORS) between -2.34o/o and +0.03% 3.4 The difference between the feedwater flow as measured in the Protection System and the lndicated Computer Feedwater Flow is within !2.0o/o of rated flow. As-left in Section 6.3 with measured differences (% ERRORS) between -0.06% and +0.20o/o 3.5 The difference between the feedwater flow as measured in the Protection System and the Feedwater Flow Signal used for flow control is within t2.0% of rated flow. As-left in Section 6.3 with measured differences (Yo ERRORS) between -0.83o/o and +0.49o/o 2]-8
7.4.13 Calibration of Steam and Feedwater Flow lnstruments at 100% Power (2-PAT-8.4) (continued ) 3.6 The difference between the steam flow as measured in the Protection System and the Main Control Board lndicators is within t5.0% of the rated flow. As-left in Section 6.3 with measured differences (% ERRORS) between -2.38o/o and +0.30% 3.7 The difference between the steam flow as measured in the Protection System and the lndicated Computer Steam Flow is within t2.0o/o of rated flow. As-left in Section 6.3 with measured differences (% ERRORS) between -0.05% and +0.11o/o 3.8 The difference between the steam flow as measured in the Protection System and the Steam Flow Signal used for flow control is within t2.0o/o of rated flow. As-left in Section 6.3 with measured differences (% ERRORS) between -0.610/0 and +0.38% 3.9 The difference between the feedwater flow as measured in the Protection System and the Steam Flow as measured in the Protection System is within t5.0o/o of rated flow. As-left in Section 6.3 with measured differences (% ERRORS) between -1.670/o and +0.71o/o 3.10 The difference between the feedwater flow as measured in the Control System and the Steam Flow as measured in the Control System is within t5.0% of rated flow. As-left in Section 6.3 with measured differences (% ERRORS) between -1.91% and +0.47o/o 3.11 The difference between the 100Yo Extrapolated Average Feedwater Flow and the 100% Extrapolated Steam Flow is within t1.O% of rated flow. This Review Criteria applied only to Section 6.2 with measured differences (% ERRORS) between -1.53o/o and -0.2Oo/o. Three flow transmitters failed the Review Criteria. (CR 1208875) 2L9
7.4.13 Galibration of Steam and Feedwater Flow lnstruments at 100% Power (2-PAT{.4} (continued) Additionally a comparison of the corrected feedwater flows and steam flows versus predicted design flow is provided: Section 6.3 (100%1, Comparison to Design Flow 4 3.5 3
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7.4.14 Shutdown From Outside the Main Control Room (2-PAT-8.5) This Power Ascension Test (PAT) was performed at the 100% test plateau as directed by 2-PAT-8.0, Test Sequence for 100o/o PIateau. Preparations for testing commenced on 812116 and field testing was completed on 813l'16. 1.0 Test Obiectives The objectives of this test were to: 1.1 Satisfy the objectives of Regulatory Guide 1.68.2,lnitial Startup Test Program To Demonstrate Remote Shutdown Capability For Water-Cooled Nuclear Power Plants, as follows: 1.1.1 Demonstrate the capability to safely shutdown the unit from outside the Main Control Room (MCR). 1.1.2 Demonstrate the capability to maintain Hot Standby (Mode 3) conditions from outside the Main Control Room for at least 30 minutes using the minimum shift crew. 1.1.3 Demonstrate the unit can be safely cooled from Hot Standby to Cold Shutdown conditions from outside the Main Control Room. This PAT only cooled down approximately 50"F. 2-PTl-068-13, Shutdown From Outside the Main Control Room, demonstrated the cooldown to Cold Shutdown conditions from outside the Main Control Room. 1.2 Satisfy the requirements of UFSAR Table 14.2-2, Sheet 32, Shutdown From Outside the Main Control Room Test Summary. The objective statement for this test per sheet 32 is: 1.2.1 To demonstrate that the unit can be taken to and maintained in the hot standby condition from outside the control room. This test will be performed during the 100% power testing plateau and will be initiated from approximately 30% power. 2.0 Test Methods lnitial conditions started with reactor power at approximately 30.7% RTP with the turbine generator in operation and synchronized to the TVA transmission grid, feedwater flow established to the steam generators through the main regulating valves, and other systems in automatic. The reactor was tripped from outside the Main Control Room and Operations then entered Aftachment2,2-AOl-27 TEST, Main Control Room lnaccessibility - Unit 2 for performance of the test. 22L
7.4.14 Shutdown From Outside the Main Control Room (2-PAT-8.5) (continued) 2-AOl-27, Main Control Room lnaccessibility - Unit 2, Revision 0 was modified and added as Attachment 2 with lD Number 2-AOl27 TEST. The attachment modifications were to not require components associated with Unit 1 to be operated since Unit t had no involvement with this test. The test was performed with the minimum shift crew compliment as defined in OPDP-1, Conduct of Operations, and the WBN Dual Unit Fire Protection Report. 3.0 Test Results AllAcceptance/Review Criteria were met or resolved as delineated below. Acceotance Criteria 3.1 The unit has been tripped from outside the Main Control Room (MCR) and was controlled at Hot Standby Conditions from outside the MCR for at least 30 minutes using the minimum shift crew compliment. As demonstrated by Figure 7.4.14-1, Unit 2 was successfully tripped from outside of the MCR and stable Hot Standby Conditions were maintained for at least 30 minutes. 3.2 The ability to cool the unit down from outside the Main Control Room approximately 50"F using 2-AOl-27 TEST, Main Control Room lnaccessibility, has been demonstrated. As demonstrated by Figure 7.4.14-2, Unit 2 was successfully cooled by approximately 56"F from operator actions outside of the MCR. Review Criteria 3.3 The following parameters were maintained within the respective limits for at least 30 minutes after the trip, using only the controls and indication available outside the Main Control Room: 222
7.4.14 Shutdown From Outside the Main Control Room (2-PAT-8.5) (continued) (1) RCS Hot Leg temperature (547"F to 585'F and changing at a rate Iess than 50"F in one hour) (2) Pressurizer level (17Yo to 50%) (3) Pressurizer pressure (2000 psig to 2350 psig) (4) Steam Generator levels (5% to 83% narrow range and either constant or trending toward 38% on narrow range) As depicted in Figure 7.4.14-1, each of the parameters listed above were maintained within their respective limit for at least 30 minutes. 3.4 The following parameters were maintained within the respective limits during the cooldown demonstration, using controls and indication available from outside the Main Control Room: (1) RCS cooldown did not exceed the Technical Specification limit (100"F in a one hour period). (2) Pressurizer cooldown rate did not exceed the Technical Specification limit (200'F in a one hour period). (3) Pressurizer level maintained between (17o/o to 80%) (4) Pressurize pressure maintained within the limits of the RCS Pressure and Temperature Limits Report (PTLR). This was validated through successful performance of WO 1 1 803431 1, 2-5l-6844 RCS Temperature/Pressure Limits and Pressurizer Temperature Limits (5) Steam generator levels (5% to 83% narrow range) As depicted in Figure 7.4.14-2, each of the parameters listed above were maintained within their respective limit during the cooldown. 4.0 Problems There were no significant problems encountered during the performance of this test. 223
7.4.14 Shutdown From Outside the Main Control Room (2-PAT-8.5) (continued) FIGURE 7.4.14-1 Main Control Room Abandonment 30 Minute Stability
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7.4.14 Shutdown From Outside the Main Control Room (2-PAT.5) (continued) FIGURE 7.4.14-2 Main Control Room Abandonment Gooldown
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7.4.15 PIant Trip Evaluation for Equivalency of Test Performance of 2-PAT-8.6, PIant Trip From 100% Power (Turbine Trip) This PAT was not performed because the plant sustained a Turbine/Reactor Trip resulting from a fault in the B Phase Main Bank Transformer while operating at greater than 98% rated thermal power. An evaluation of this transient was made for equivalency with the planned test 2-PAT-8.6 and it was determined that all of the Acceptance Criteria were met with the transformer fault being the initiating event. For reference CR '1208823 documents the Unit 2, B Phase Main Bank Transformer failure event and CR 1209770 documents the plant trip evaluation for equivalency of test performance for 2-PAT-8.6. 1.0 Test Obiectives 1.1 To demonstrate the ability of primary side systems to bring the unit to stable conditions following a plant trip resulting from opening of the generator output breaker. The transient provided the same intent, but the version of the UFSAR at the time of the unplanned trip only specified opening the generator output breaker. An UFSAR change to add a statement for equivalent means has been made. 1.2 To determine the overall response time of the RCS narrow range hot leg RTDs. 1.3 To satisfy the test requirements described in UFSAR Table 14.2-2, Sheet 37, Plant Trip From 100Yo Power Test Summary. The version of the UFSAR at the time of the unplanned trip specified the PAT would open the generator output breaker as the initiating event. A change was processed to the UFSAR to allow an equivalent transient initiation. 2.0 Test Methods At 21:09 on 8/30/16 with Watts Bar Unit 2 at approximately 98% power, the plant tripped due to a main bank transformer failure. (For future reference, the transformer event is documented under CR 1208823) This plant trip was evaluated to credit the PATP for demonstrating the ability of primary and secondary plant systems, including automatic control systems, to sustain a plant trip from full power and determined the response time of the narrow range hot leg RTDs. 226
7.4.15 PIant Trip Evaluation For Equivalency Of Test Performance for PIant Trip From 100Yo Power (Turbine Trip) (2-PAT-8.6) (continued) The plant was at steady-state near ful! power conditions with control systems in automatic. A full load rejection was initiated by the transient which was determined equivalent to the planned "manual opening of the generator output breake/'. The turbine tripped as a direct result of the loss of load which was determined equivalent to the planned "opening the generator output breake/', and a reactor trip followed the turbine trip. Primary and secondary plant parameters were monitored, via the plant lCS computer, throughout the transient until stability was achieved. Operators took manual control of the plant systems as directed by the operating procedures which would have been allowed by the planned test. 3.0 Test Results All Acceptance/Review Criteria were met or resolved as delineated below. The unplanned trip took a different, but equivalent route in regards to the Reg Guide 1.68, Revision 2 requirements that the turbine-generator will be subjected to the maximum credible overspeed condition. From the WBN Drawing 2-75W1550 it was determined that the unplanned trip actuated the 263TXB relay due to abnormal transformer pressure (the first alarm on the first out alarm report), which would energize the 286C relay (or redundant 286G8 relay), which in parallel would open the generator output breakers, close the turbine stop valves, and result in an instantaneous turbine trip. Figu res 7 .4.1 5-1 throug h 7 .4.1 5-1 6 support Acceptance/Review Criteria evaluations and show the systems performance results and prove that the transient demonstrated the ability of primary and secondary plant systems, including automatic control systems, to sustain a plant trip from full power and show the response time of the narrow range hot leg RTDs met the test criteria. 3.1 A safety injection was not initiated as a result of the plant trip. 3.2 The steam generator safety valves did not lift as a result of the plant trip. 3.3 The pressurizer safety valves did not Iift as a result of the plant trip. 3.4 The reactor tripped, and all RCCAs released and dropped as a result of the plant trip. 221
7.4.15 Plant Trip Evaluation For Equivalency Of Test Performance for Plant Trip From 100o/o Power (Turbine Trip) (2-PAT-8.6) (continued) 3.5 The overall response time for the RCS narrow range hot leg RTDs was less than or equal to 8.1 seconds. The actual measured response time was 7.7 seconds. 3.6 Nuclear flux decreased rapidly, as demonstrated by indicated NIS power decreasing to less than or equal to 15o/o within 2.0 seconds after the turbine trip. The actual measured time for NIS power to reduce to < 15% was 1.985 seconds. 3.7 The main turbine did not trip as a result of overspeed. During normalsteady state operation, such as the time when the unplanned trip occurred, there is no appreciable difference in the trip times between opening the generator output breakers and a sudden pressure/transformer differential trip. Therefore they have an equivalent probability of challenging the turbine mechanical overspeed. There was no turbine trip as a result of overspeed. The required Review Criteria of the planned test were met, except as delineated below: 3.8 Steam Generator Levels remained within the span of the Narrow Range lndicators during the transient. 3.9 Pressurizer Pressure did not peak above the initial pressure as a result of the Plant Trip. The maximum Pressurizer Pressure was slightly greater than the initial pressure. This slightly increased pressure was the result of the pressurizer control system rather than a result of the plant trip. An evaluation from Westinghouse concluded that this Review Criteria was met. Westinghouse reviewed the Watts Bar Unit 2 transient results and confirmed that at the initiation of the transient, the reactor was tripped within 1 second of the turbine trip and the pressurizer pressure initial response was a decrease in pressurizer pressure. Therefore, the plant responded as designed and this Review Criteria was met. 228
7.4.15 Plant Trip Evaluation For Equivalency Of Test Performance for Plant Trip From 100Yo Power (Turbine Trip) (2-PAT-8.6) (continued) Note that pressurizer pressure recovery occurs late in the transient when the pressurizer pressure control system returns the pressurizer pressure to the control setpoint o12235 psig. The recovery of pressurizer pressure resulted in an overshoot of the pressurizer pressure setpoint (i.e., the initialcondition of the transient). This is a normal and expected response for a proportional-integral controller and this response does not represent a failure in this Review Criteria. Pressurizer pressure contro! back to setpoint is separately verified in a separate Review Criteria which was met. 3.10 Pressurizer Pressure did not drop below 1950 psig as a result of the Plant Trip. 3.11 Pressurizer Pressure Controller output automatically modulated to return Pressurizer Pressure to the setpoint of 2235 psig (2220 to 2250 psig) within 30 minutes of the PIant Trip. 3.12 Pressurizer Level did not drop below 20o/o level as a result of the Plant Trip. 3.13 Pressurizer Level did not rise above TOYo level as a result of the Plant Trip. 3.14 Pressurizer Level Controller output automatically modulated to return Pressurizer Level to the no-load setpoint of 25o/o (23 to 27Yo) level within 30 minutes of the Plant Trip. This Review Criteria was not met since the controller was not controlling at the no-load setpoint due to steam dumps 0F. controlling Tivo slightly above the no load temperature of 560.4 An evaluation from Westinghouse documented acceptability of the results. Westinghouse concludes that the pressurizer level response following the generator trip was acceptable based on the following evaluation. The pressurizer level program is a function of the RCS average temperature to minimize the duty of the pressurizer level control system by accounting for density changes in the RCS inventory. Therefore, the pressurizer level control system is generally tuned to be slow responding to allow for density changes in inventory to account for a majority of the pressurizer level control. The pressurizer level response for Watts Bar Unit 2 demonstrated that the changes in RCS inventory density changed pressurizer level initially during the transient and then the pressurizer level controllers returned pressurizer level back to setpoint. The total time that pressurizer level returned 229
7.4.15 Plant Trip Evaluation For Equivalency Of Test Performance for Plant Trip From 100o/o Power (Turbine Trip) (2-PAT-8.6) (continued) to setpoint was almost 2 hours. A review of the pressurizer level controller tuning constants was performed. The level controller has a gain of 3 gpm lo/olevel deviation with a reset time constant of 30 minutes. The flow controller has a gain of 0.333 o/o valve demand / gpm deviation with a reset time constant of 30 seconds. The level controller dominates the flow controller because the level controller has a low gain and a very high reset time constant which results in very sluggish control. Westinghouse reviewed the leveland flow controller inputs and output responses during the transient and the results are consistent with the tuning constants installed in the field. Also note that 2-PTl-068-15, Pressurizer Pressure and Level Control, performed a step change in pressurizer level and the controllers took over 2 hours to return the pressurizer level program to target. Therefore, the pressurizer level control is acceptable for the turbine trip transient because the control is stable and consistent with the controllers' tuning constants. No controller tuning is recommended based on the transient response. 3.15 After the plant trip, RCS average temperature (Tavg) did not drop below 547'F as a result of the Plant Trip. 3.16 After the plant trip, RCS average temperature (Tavg) stabilizes at approximately 557"F (> 554'F) within 10 minutes of the Plant Trip with Steam Dump Control in the Tavg Mode. 317 After the plant trip, the Steam Dump Valves modulated towards close in the Tavg Mode as RCS average temperature (Tavg) decreased in value. 3.18 After the plant trip, Main Feedwater flow was automatically shutoff (as a result of Feedwater lsolation) before RCS average temperature (Tavg) fell below 557"F. 230
7.4.15 Plant Trip Evaluation For Equivalency Of Test Performance for Plant Trip From 1O0% Power (Turbine Trip) (2-PAT{.6) (continued) 4.0 Problems 11l CR 1209770 documents the plant trip evaluation for equivalency of test performance for 2-PAT-8.6, Plant Trip From 100Yo Power (Turbine Trip). Review Criteria 5.2[B]: The initial Pressurizer Pressure ranged between 2233.5 psig and 2237.5 psig, the maximum Pressurizer Pressure was2244.7 psig, which was slightly greater than the initial pressure. An evaluation from Westinghouse concluded that this Review Criteria 5.2[B]was met. This slightly increased pressure was the result of the pressurizer control system rather than a result of the plant trip. Review Criteria 5.2[G]: ICS data indicated that 30 minutes after the trip, the Pressurizer Level Controller had automatically returned level to a range of 28.5 to 30.1% which was slightly greater than the required 23 to 27%. Westinghouse reviewed the transient results of pressurizer level. After the trip, pressurizer level returned to the pressurizer level setpoint in about 30 minutes. At approximately sixty one minutes after the trip, the Pressurizer Levels ranged from 26.0Yoto27.5o/o. An evaluation from Westinghouse concluded that the pressurizer level response following the generator trip was acceptable. Review Criteria 5.2[G] was not met since the controller was not controlling at the no-load setpoint due to steam dumps controlling Tavg slightly above the no load temperature of 560.4'F. 23L
7.4.15 Plant Trip Evaluation For Equivalency Of Test Performance for Plant Trip From 100o/o Power (Turbine Trip) (2-PAT-8.6) (continued) FIGURE 7.4.15-l Representative RCCA Position vs Time (100% Trip) DatAIJare History 3O-Au9-2O16 21:O9:12 to 3O-Att9-2O16 21:O9:19 (EDT) Acc Crit: 5.f .4 i Shutdown Ennlt - A Rod Posithn Rod Position SD.A t
-l I
I I 1/36 c'lr;o iilcaa;+ 21:O9:Ul EDT l:At EDT 21:Oll:L EIIT 2l:o9:16 CDT 21,:019117 EXIT 21:O9:11 EDT 21:O9:19 l0-Aue-2016 rg-t016 tO-Augr2O16 !o-Atg-2O15 tO-Arrg-2O16 t0-Aue-2O16 3O-Au9-2O16 ll1:21:Gl:Li ll2: 11c09:1.1 ll!:21:09!17 Poi nt IDlDcscription La-Y Hi -Y Uaitr ot/10/16 ot/ralL6 otltolL6 (1) v2-L721p/trx.lo3T (E rua) ALL NOOS Ol{ EOTTIII ALII PLC A 10- xomnL IORXAL I ALAftiI (2) W2-2t27lrvGOoogA (Y2;U2) SBA GROUP 1 FOSTTIO}I DOz PLC A o 21' STEPS l.tE.5t79 18E.4363 o. t5747 (3) Y2-ZE}VA-COOI'OA (Y2:Uz) SEA GROI'P 1 POSITTOfi 812 PLC A o 24' STEPS 1E9.7034 1E9.55E1 (s.277272) (4) v2-ztl5/LCO(ILIA (r2:U2) SBA GRq'P 1 FOSITIOII X1'} PLC A o z.t 5TEP5 1!r{.4156 19a. t49a (+.6t5a96) (s) v2-2tr9/A_COO1zA (H2:U2) S8A GR(I'P 1 FOSITIOI'I FO4 PLC A o 243 STEPS I.tE.9332 1tt.7t94 o.2519 (6) Y2-281r/LCOO14A (E:U2) SBA GRq'P 2 FOSTTTOil EO4 PLC A O 243 STEPS 190.2543 1!Xr,IL23 o.930092 (7) v2-2817/A_COol.sA (r2:U2) SEA GROiTP 2 FOSfTIOfiI D1/r PLC A o 243 STEPS 1!}4.79t3 1!t4.656 (5. 3671EE) (E) Y2-2t51/LCOO16A (Y2:U2) S8A GRq'P 2 FOSTTTO}' Pl? PLC A o 24t STEPS 1E5.6t41 1t5.5169 o.71t325 (e) u2-2t55,/LCOO17A (tJ:l:U2) S8A GRqJP 2 FOSITIOT' }IO2 PLC A o 2{3 STgrS 1r5- 3t93 1t6.236 o.77120,1 232
7.4.15 Plant Trip Evaluation For Equivalency Of Test Performance for Plant Trip From l00o/o Power (Turbine Trip) (2-PAT4.6) (continued) FIGURE 7.4.15-2 Main Turbine Speed vs Time (100% Trip) oatAwar xistory 30-Aug-?016 2f :09:00 to 30-Aug-?016 2l:09:30 (eor1 E M1: Slcady ll? ll3:Hu RPil Ml: No Tuthc S:trE fiip Orerrpccd Turblm Speod (rp4) l f
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7.4.15 Plant Trip Evaluation For Equivalency Of Test Performance for PIant Trip From 100% Power (Turbine Trip) (2-PAT-8.6) (continued) FIGURE 7.4.1 5-3 Safety lnjection Alarm vs Time (100% Trip) DatAhlarc History 30-Aug-2016 2L:O9:OO to 3O-Aug-2O16 21:O9:3O (EDT) Acc Crit: 5.1. Safety lnfect Ml: Steady M2. T s:tate T 1:O9:OO EDT 21:(X):O5 EDT 2 1: (X) : lO EDT 21:O9:15 EDT 21:G):2O EDT 21:O9:25 EDT 21:O9:tO EDT 3O-Aug-2O16 3O-Aug-2016 3O-Au9-2O16 3O-Aug-2O16 lO-Ang-2O16 3O-Au9-2O15 3O-Aug-2Or.6 ll1: 21:O9:OO llil: 21:O9:l-3 X3: 21:O9:3O Point IDlDcrcriotion Lou-Y Hi-Y Units oE/rol,tB o,al"ol,t6 o.alrolr6, (1) I2-1O.1E7/*NO7OA (v2:U2) R(I{Ail ALART TIilTXT O7O-A -1O 1(t iTORIiAL MORilAL O 234
7.4.15 Plant Trip Evaluation For Equivalency Of Test Performance for Plant Trip From 100% Power (Turbine Trip) (2-PAT-8.6) (continued) FTGURE 7.4.154 Steam Generator Safety Valve Position Loops 1 &2 vs Time (100% rrip) DatAljare H'i story 3O-Aug-Acc Crit:5.1.D SG Safetles Loops I & 2 I M3: No chilqe Ml: Steady h SG Selbty State M2. Turbine pooititrr Tnp
- 4O:OO EDT 2OrSt:2O EDT 21:06:4O EDT ?LtZO:OO EDT 21:33:2O EDT 21:46:lO EDT 22rOO:OO EIIT 2010 3O-Aug-2O16 3O-Aug-2O16 3O-Ars-2O16 tO-Are-2O15 tO-AtrF2O15 t0-Aug-2O16 ll1: 2Or4O:0O ll2s 21r09r1! lll: 22:0O:O0 LorY }fi-Y Unitr ot/rol16 08/to/a6 aalro/L6 (E I uz) SG'1 SAFETY VALVE S FqiITIOI -1O 10 CLOsED CLOSED o
- 2) Y2-1777 / Frre3o4 (Yz : u2) SG'1 SAFETY VALVE 4 FOSITI(r{ -1O 10 CLOSED CLOSED o
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- 5) V2-175t/FDg315 (r2 : U2) SG'2 SAFETY VALVE 5 POSITT$I -1O 10 CLOSED CLOSED o a2-1782lFDg314 (m : U2) SG'z SAFEW VALVE 4 FOSITI(}T -1O 10 CLOSED CLOSED o Y2-17iL/FDe313 (r2:u2) S6i,E SAFETY VALVE , FO6ITI(I{ -1O 1(, CLOsED CLOSED o e) rP-Qn/ FDgrur (r2:UZ) SG*2 SAFETY VALVE 2 POSITICN -1O 10 CLOSED CLOSED o
- 10) Y2-{779/9'O91L1, (E : Uz) SG'z SAFETY VALVE 1 FOgITIOI .1O 1(, CLOGED CLOSED o 235
7.4.15 Plant Trip Evaluation For Equivalency Of Test Performance for Plant Trip From 100% Power (Turbine Trip) (2-PAT{.6) (continued) FTGURE 7.4.15-5 Steam Generator Safety Valve Position Loops 3 & 4 vs Time (1OO% Trip) DatAl{are History 3O-Arg-2016 20:4O:OO to 3O-Aug-2O16 22IOO:OO (EDT) Acc Crit: 5.1.D SGLoops3Al SG Safeties I M2. Turhne M3: No ctmnge Ml: Stea0 Trh [t SG Safiety SfaE positicr
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,t2-17E6/ FD9323 (Y2:U2) SG'3 SAFETY YALVE 3 FOSITIO{ -10 10 CLOSED CLOSED o w-l7tslFDttt22 (E:u2) SGi;3 SAFETY VALVE 2 FOSITISI -10 10 CLO6ED CLOSCD o Y2-17UlFrrg121 (r2:Uz) SG'3 SAFEfi VALVE 1 FOSITIC{ -10 10 CLOSCD CLOsCD o Y2-179r/ FIrg335 (r2:U2) SG,/t SAFETY VALT/E 5 FOSITI(II -10 10 CLOsED CLOSED o n,-092/ FIx)334 (Y2:U2) 5G'4 SAFETY VALVE 4 FOSITIOH -10 10 CL(ECD cLoSEI) o w-179L/FDgt3t (Y2 : UZ) 5GI4 SAFETY VALVE 3 FOcITISI -10 10 CLOEED CLO:iED o 12,-171n/ FIXI332 (Y2:UZ) SG'4 SAFETY VAI-VE U FOSITTOI -10 10 CLO6ED CLOSED o
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7.4.15 PIant Trip Evaluation For Equivalency Of Test Performance for Plant Trip From 100% Power (Turbine Trip) (2-PAT-8.6) (continued) FIGURE 7.4.1 5.6 Pressurizer Safety Valve Outlet Temperature vs Time (100% Trip) DatAlJarc History 3O-Aug-1O16 2O:4O:OO to 3O-Au9-2O16 22:OO:OO (EDT) Acc Crit:5.1.E PZR Safeties
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7.4.15 PIant Trip Evaluation For Equivalency Of Test Performance for Plant Trip From 100% Power (Turbine Trip) (2-PAT-8.6) (continued) FIGURE 7.4.15-7 NIS Power vs Time (100% Trip) DatAl*are History 3O-Aug-2O16 21:O9:OO to 3O-Aug-2O16 ?t:O9:30 (EDT) Acc Crit: 5.1.F NIS PowEr M2: Turbine M3- NIS Poi,er tsss Trip 2r:09:13,2 man 15% by 21:09:15 21:O9:OO EDT 21:O!l:O5 EDT 21:Oll:1O EDT 21:O9:15 EDT 21:019:20 EDT 21;Oll:25 EDT 21:O9:3O EDT 3O-Aug-2O16 tO-Aug-2O16 3O-Aug-2O15 3O-Aug-2O16 3O-Aug-2O16 l0-Aug-2O16 3O-Aug-2O16 ll1:21:O9:OO lrl2:21rO9:13 ll3:21:O9:15 Ls-Y 0t rto^/16 Point IDlDcrcriotion 2:U2) PIR RIIG clt IritEL 1 (QUAD4) (2) Y2-7112/NoosoA (Y2:Uz) PUR RllG GrAilirEL 2 (QUADz) ao ao Hi -Y 12(} 120
;xUnits otlrolilE, 97.6169 97.335t 0c/to/16 94.65524 97.22161 7.71L92t 9.Ot6109 (3) I2-754t,/t{oos1A (U2:Uz) mR RilG clrAr{rrtEL 3 (0ue[}1, (4) Y2-7st4liloo52A (rz:Uz) FUR RIIG cHAr{ilEL 4 (QUAD3) ao ao 120 120 x
x 99.03722 98.94t44 99.13123 9t.91327 9.1/13965 t.962395 238
7.4.15 PIant Trip Evaluation For Equivalency Of Test Performance for Plant Trip From 100o/o Power (Turbine Trip) (2-PAT-8.6) (continued) FIGURE 7.4.1 5-8 Hot Leg RTD Response vs Time (100% Trip) DatAhlare xi story 30-aug-2016 21:O9:O0 to 3O-Aug-2O16 21:09:30 (EDT) Aec Criteria: 5.1.G RTD ReSponse Time 53(}J1 21:O9:0O EDT 21:O9:05 EDT 21: O9 : I-O EDT 21:O9:15 EDT 21: O9: 2O EDT 21: O9: 2 5 EDT 21: O9: 3O ED'l 3O-Ar9-2016 3O-Aug-2016 3O-Attg-2016 30-tus-2016 30-Aug-2015 3O-Aug-2O15 3O-Aug-2O16 H2:21:O9:13 ll3:21:O9:21 Poi nt ID^/Descri pti on Low-Y Hi -Y Units o8l?o/L6 0,E/301L6 (u2:u2) T-411 TFUAvE (2) u2-14163/T7453A (w2:u2) T-42L TFUAVE Erf,- 650- ErF 53O 650 DEG F 614.1552 ffire 614.0252 593 .2504 (3) w2-1420O/T7497A (rZ:uZ) T-431 TFr,tAvE 53O 650 DEG F 615.069 614.99t 595 . 1204 (4) Y2-L4237 /T754A (s2 : u2) T-441 TFI{AVE 530 650 DEG F 616. 3302 616. 4442 593.3026 239
7.4.15 PIant Trip Evaluation For Equivalency Of Test Performance for Plant Trip From 100% Power (Turbine Trip) (2-PAT-8.6) (continued) FIGURE 7.4.1 5.9 Steam Generator Levels vs Time (100% Trip) ort^I,rrc Htstory !o-Aug-2or.6 20:{o:oo to 3o-Aug-2o16 22:oo:oo (EDT) 20:{o!d, EDT 20:53!20 CDT 21!O3:{O EDT 21i20300 EDT 21313:20 EDT 2t !{3!{O EDT lz!oo:@ EgT 3O-Aug-2015 3(FAllgFZOrrS ,o-Alrg-2015 3O-At 9-2016 ,o-firg-zo15 to-Alle-2016 to-Aug-2or.3 Itl! 20:4030 p,i 2130t:I3 13: 21363a1, ll: l13t{:14 Polilt IDlDcrcrlstton LC.Y HI-Y m{tr ot/tol13 artrofls ot rtollr oil.l3ol,.:3 (a) rz-23o$/Dcr3ooo3 (I23u2) sG 1 VAI.IITATE n LEyEL olm r @.oot56 gt.ot73a t3.3tt13 {O.lt3illl (2) r2-257rC/ACs,x,46 (r2:U2) S 2 VALTDATED XR LE\,EL o1oo r sr.l7&17 ft.l/}teG 2.1.31751 3t.3642 (r) r2-257r7/rcW.7 (Y2:U2) sti ! LIDATED rt LEVEL o 100 r 39.4a41t 5t. s5t!}ll 17.3tot 41.4at3r (.) r2-25a32/Dcvr125 (r23UZ) 36 . YALTDATED Xt LA,EL o 100 I St.ta'5Os 5t.t7]r!, 2r.r1r32 41.4!3aa 240
7.4.15 PIant Trip Evaluation For Equivalency Of Test Performance for Plant Trip From 100o/o Power (Turbine Trip) (2-PAT-8.6) (continued) FIGURE 7 .4.1 5-1 0 Pressurizer Pressure vs Time (1) (100% Trip) DatAHarc )listory 3O-Aug-2O16 20:4O:OO to 3O-Aug-2OL6 22:OO:OO (EDT) Review Criteria: 5.2.8 and 5.2.C Pressurizer Pressure Ml. Steady State PZR Pressure 2O:4O:OO EDT 2O:53:2O EDT 21:O5:4O EDT 21:2O:OO EUf 21:33:2O EDT 21:t6:4O Ef 22:(Xl:@ EDT 3O-Aug-2O16 3O-Arg-2016 l0-Aug-2O16 3O-Aug-2O15 30-Aug-2O16 3O-Aug-2O16 l0-Aug-2O15 ill.: 2O:4O:OO ll2: 2L:O9:13 ll3: 21:O9:tl t4: 2lzl.2:tl1 Point ID./Dercriotion Lc-Y lfi-Y ttnitg otltaf,-B o,atrot,.6 o,tfrot1:6 oal'{IlL6 (1) Iz-7TlolssasoA (r2:uz) Hn, t PREssrnE 17oo zsoo PSIG 2211.476 223t.L5 2036.O3t 22a2.5a7 (z) vz-t772/wt A (rr2:U2) frZP. 2 PRESSURE t70rJ 25fi) PSIG 2237.527 2216.707 20?'7.919 2244.662 (3) U2-7774/P$82A Orz:Uz) UR 3 FREssrrRE 17oo 25oo PSIG 2236.726 2215.212 203t.O14 2214.061 (1) Y2-7776/FutlA (Iz:Uz) HZn 1 PRES$rIE 17Oo 25oo PsIc 2233.45t 22?l.SU 2031.563 2241.O31 24L
7.4.15 Plant Trip Evaluation For Equivalency Of Test Performance for Plant Trip From 100% Power (Turbine Trip) (2-PAT-8.6) (continued) FIGURE 7.4.15-11 Pressurizer Pressure vs Time (21 (100Yo Trip) DatAulare xi story 3O-Aug-2O16 20 :40: OO to 3O-Aug-2016 22 : O0: OO (em) Review Criteria: 5.2.D PZR Prcssure to 25O psig 2O:4O:OO EDT 2O:53:2O EDT 21:O6:4O EDT 21:2O:0O Elrr 21:33:2O EDT 2L:46:4O EDT 22:OO:OO EDT 3O-Au9-2015 30-Aug-2O16 3O-Aug-2016 iX)-Aug-2016 3O-Aug-2O16 iX)-Aug-2016 3O-Aug-2O15 ltl: 20:{0:fi} illl: 21:Gl:13 il3 : 21: 39:13 L*Y mi -v uni ts OEISOILG Ot/?Of LG otl?o11:6
- UZ) PZR 1 PRESSURE ilm- Zffi PSrG 22}+.t76 2235.1t4 ffi PZR 2 PRESSURE 1700 2500 PSrc 2237 .527 2237.544 224L. O53 t3]
(4) v-illilw,j#, fi3:u3l Y2-7776/poa,s3a (w2:u2) PZR 3 PZn 4 PRESSURE 17(x) 25OO PRESSURE 17OO 25OO PSrG PSrG 7236.726 2233.45E 2217 .224 2213.463 2240.269 2276.962 242
7.4.15 Plant Trip Evaluation For Equivalency Of Test Performance for Plant Trip From 100o/o Power (Turbine Trip) (2-PAT-8.6) (continued) FIGURE 7.4.15-12 Pressurizer Level vs Time (100% Trip) DatAhlarc History 3O-Aug-2O16 2Or4O:OO to 3O-Au9-2O16 22rOO:OO (EDT) Revrew Crit: 5.2.E & 5.2.F Pressurizer Level O:40:OO EDT 2O:53:2O EDT 21:O:tlo EDT 21: lO:O0 EDT 21:33:2O EDT 21:16:tlo EDT 22:0O:OO EDT 3O-Arg-2O16 }O-Aug-2O15 lo-Aug-2O16 3O-Aug-2O16 lo-firs-2O16 3O-Aug-2016 3O-Arg-2O15 ll1: 2O:lO:OO llil: 21:O9:lil ll3: 21:19:Ol ll4: 22 : @: OO Point IDlDcrcriotion Lry-Y ]ri -Y Unitg otl3ioflr6 OtrSO/16 os/30/16 oElrotL6 (1) r2-6to1/Lo4EoA (r2ru2) frzR L LEVEL o 100
- 60.714t4 60.6tt95 14.61075 2t.rt32t (2) rz-55o3/Lo{t1 (Hz:uz) frZa, 2 LEVEL o 100 r 59.01172 5E. !N575 t2.9653t 26. 5507t (3) u2-65o5/Lo4t2l (Y2:U2) PZR 3 LEVEL o 100 x 59. to469 59.21761 13.1r.O44 26.777t1 243
7.4.15 Plant Trip Evaluation For Equivalency Of Test Performance for Plant Trip From 100olo Power (Turbine Trip) (2-PAT-8.6) (continued) FIGURE 7 .4.1 5.1 3 Pressurizer Leve! Controller Output vs Time (100% Trip) DarAu{are ni story 30-Aug-3016 20;.10 :00 to 30-aug-2016 ? I :15 :00 (eOr) 100 @ @ Revrew Crrterra Ml SEacly M2 Turbine Trip StaE 20: rl0:00 EDT 21:05:50 Esr 21:31:40 EtIt 21:57:30 EoT 27:23:20 Eor 22i49:10 EEn 23:15:00 EDT 30-rug-2016 30-aug-2016 3O-eug-?016 30-eug-2016 30-lug-2016 30-eug-2016 30-Aug-2016 t{1: 20:40:@ it2: 21:Ofl:13 rrr3 : 21: 39:13 n4 : 22 : 10:25 ffitB o2:u2) pREss{rRrzER (2) r2-65O1/LOatO^ (t2:u2) Pzr 1 LEVEL LEvEL sgrForirr bgg* ot00r Ie' rllr 08/30/16 59.44913 60.714t4 -t8/#f*$ 60.64117
--#{+gtt 10.0613{
--#+tt#8 27.44446 (3) rt?-51o3/u0il1r lrZ:uZ) p:r 2 LEYIL 0toox t9.0117e 5r.961t5 2E.11773 25.969tt
({) rz-ssos/LodSz^ (w2:u2) PzR , LEVEL o100/ 59. 30469 79.24077 2E.726t1 26.163rt 244
7.4.15 Plant Trip Evaluation For Equivalency Of Test Performance for Plant Trip From 100% Power (Turbine Trip) (2-PAT-8.6) (continued) FIGURE 7.4.15-14 RCS Average Temperature (Auctioneered) vs Time (100% Trip) OatAlJare History 3o-tuig-2o16 2O:4O:OO to 3O-Aug-2O1.6 22:OO:O0 (EOT) Review Criteria: 5.2.H and 5.2.1 Illinirnum TAVG & Stable TAVO i I T Trip 21:09: t.2 10 mhutes Po6fi Trlp (21-.1 hrs). TAVG Stable 2O:4OrO0 EDT 2O:53:2O EDT 21:06:/00 EIIT 2f-:2O:OO EDT 21:!3:2O EDT 21:46:40 EDT 22:OO:O0 EDT 3O-Aus-2O16 3O-Aue-2O16 3O-AuO-2OL6 3O-Aue-2O16 3O-A.rg-2O15 tO-Aus-2Oa6 irc-Aug-2016 Itt[:21:(}9:13 ll2:21:1il:56 ll3:21:19:O1 Point lDlDcrcriotion Lory-Y ili -Y Units OAISO/LG Ott3OlI6 0!'30116 (1) r2-131O5,frO49!)A (U:Uz) RCL HIGIIEST TAI/G (AlrCTrOflEER) 53O 630 DGF U87.5336 555.3222 560.1',21 245
7.4.15 Plant Trip Evaluation For Equivalency Of Test Performance for Plant Trip From 100o/o Power (Turbine Trip) (2-PAT-8.6) (continued) FIGURE 7 .4.1 5-l 5 Steam Dump Demand and Tavg vs Time (100% Trip) DatAhlare Hi story 3O-Aug-2016 2O:4O: OO to 3O-Aug-2016 22 : OO: OO (eOr) Review Critcria: 5.2.J Stcarn Dump Drmand
+
I I I I Turbi 21:O9 TAVG=560. F TAVG=56O.6 Demard = 13.96% r 5301 2O:4O:OO EDT 21:46:4O EDT 22:OO:OO EDT 3O-Aug-2016 3O-Aug-2016 3O-Aug-2016 3O-Aug-2016 3O-Aug-2O16 3O-Aug-2016 3O-Aug-2016 H1:21:O9:13 Poi nt ID^/Descri oti on Low-Y Hi -Y Uni ts 08 /30 /16 (H2 : u2) RCL }IIGHEST TAVG (EUCTTOUEER) (2) w2-25336/DcsO4O2 (H2: u2) STEAI{ DUIIIP DEIIIAND E0-o 630 100 DEGF 587.5285 246
7.4.15 Plant Trip Evaluation For Equivalency Of Test Performance for Plant Trip From 100o/o Power (Turbine Trip) (2-PAT-8.6) (continued) FIGURE 7 .4.15-1 6 Main Feedwater Pump Flows and Tavg vs Time (100% Trip) DatAhlare Nistory 3O-Aug-2O16 2O:4O:OO to 3O-Aug-2O16 22:0O:OO (eOr) Review Criteria: 5.2.K FTV Flow lsolation Feechriater Fkrw ( J 53OJr _ 2O:40: fi) EIrr 2O:53:2O EDT 2I-:O6:40 21:20:OO eor 21:33:2O EDT 2L:46:4O EDT 22:OO:OO EDT 3O-Aug-2016 3O-Aug-2016 3t)-Aug-2015 30-Atrg-2016 3O-Aug-2016 3O-Arg-2016 3O-Arg-2016 l{1: 21:O9: LI A2: 21:11:52 Poi nt IDlllescri otion L*-Y lri -Y uni ts otl?ol1:6 otl30/L6 (P:u2) RcL HrGHEsr rA\rc (AlrcTrotEEn) 53O 630 DEGF 5t7.555t 557.0(X,4 (2) h[}-4ZEL/F2?SOA (wZ: u2) Fx, pHP 2A DrSCU FLtr O 72 iiPPH 7.597451 0 . 012673 (3) ,t2.-4253/rZZStt (w2: U2) Fr pr.tp 28 Drsctt FLtr O 12 HPPH 7 .152L35 -0. 019214 241
7.4.16 Core Power Distribution Factors (2-PET-301) This PET was performed at each power escalation testing plateau, spanning the 30% plateau on 6114116 through the 100% plateau on 9129116. This test was performed utilizing data from normally performed plant procedures under normal operating conditions to confirm core performance parameters. 1.0 Test Obiectives The objectives of this test were to: 1.1 Confirm core performance parameters such as heat flux hot channel factor (Fo'), nuclear enthalpy rise hot channelfactor (FNon), and QPTR are within specified limits. 1.2 Verify proper reactor core performance and provide assurance that the plant can be operated at design full power within the limits imposed by the plant Technical Specifications. 1.3 Satisfy the requirements of UFSAR Table 14.2-2, Sheet 27, Flux Distribution Measurement Test Summary. 2.0 Test Methods This test was performed utilizing data from normally performed plant procedures under normal operating conditions to confirm core performance parameters. This test was performed at the 30o/o,50o/o,75o/o, and 100% test plateaus. lncore flux map data taken at each test plateau was reviewed to veriff proper reactor core performance and provide assurance that power escalation to the next test plateau could proceed safely. 3.0 Test Results All Acceptance/Review Criteria were met or resolved as delineated below. Acceotance Criteria 3.1 The measured incore quadrant tilt is <1.04. Actual measured results are shown below: Test 30o/o 50% 7 5o/o 100o/o Plateau Measured 1.0129 1 .0135 1 .0123 1 .01 15 Tilt 248
7.4.16 Core Power Distribution Factors (2-PET-301) (continued) 3.2 The measured hot channelfactors (peaking factors) are within their respective Technical Specification limits. The measured values for the limiting FNaH srd the limiting Fco(Z) (Transient) along with their associated Technical Specification limits are shown below: Test 30o/o 50% 75% 100% Plateau F*on Limit 2.009 1 .913 1.790 1.657 rN rAH 1.502 1.481 1.450 1.419 Measured F"o(Z) 5.000 5.000 3.399 2.535 Limit F"o(Z) 1.882 1.811 1.794 1.760 Measured 3.3 The measured Technical Specification QPTR is 31.02, when reactor power <50o/o. Actual measured QPTR results are shown below: Test 50o/o 7 5o/o 100o/o Plateau Measured 1.0154 1.0026 1 .0015 QPTR 3.4 Hot Channelfactors are evaluated to ensure that limits would not be exceeded before reaching the next power plateau. N/A for 100o/o Plateau. The high flux trip power level that the measured hot channel factors (peaking factors) can support was determined, and the impact to the 100% testing plateau was evaluated. There was no impact on the power plateau of 100o/o RTP. Hot channel factors supported operating at 100% RTP. Test Plateau 30o/o 50o/o 75o/o 100o/o FNDH Extrapolated 129.9o/o 134.1o/o 140.4o/o N/A Power Level FQ Extrapolated 265.7o/o 276.1o/o 188 .8o/o N/A Power Level 249
7.4.16 Core Power Distribution Factors (2-PET-301) (continued) 3.5 The absolute value of the difference between predicted and measured core reactivity (Core Reactivity Balance) at HFP is less than 1000 pcm. Actual measured core reactivity difference was 622.9 pcm. Review Criteria Three Review Criteria were not met. All other Review Criteria were met. 3.6 The measured incore quadrant tilt is <'1.02. Actual measured results are shown below: Test 30o/o 50% 7 5o/o 100o/o Plateau Measured 1.0129 1 .0135 1 .0123 1 .01 15 Tilt 3.7 The absolute values for the assembly power M-P differences for measured core locations are less than or equal to 0.1 Relative Power Density (RPD). Actual measured M-P results are shown below: Test 30o/o 50o/o 7 5o/o 100o/o Plateau M-P 0.062 0.049 0.035 0.031 3.8 The excore quadrant power tilts are consistent with the incore quadrant power tilts. Note: Differential lncore Power Tilt were calculated in 2-Sl-0-22, lncore QPTR. Test Plateau 30o/o 50o/o 75o/o 100o/o Differential Incore Power 1 .01651 1.0041 1 .0014 1.0005 Tilt Indicated 1.017 1 .0152 1.0026 1 .0013 Excore Tilt 250
7.4.16 Core Power Distribution Factors (2-PET-301) (continued) 3.9 The HFP ARO critical boron concentration measurement is within 500 pcm equivalent boron (Design Based) of the predicted boron endpoint. The HFP ARO critical boron concentration measurement was not within 500 pcm equivalent boron of the predicted boron endpoint. See CR 12'17909. 3.10 The HFP ARO critical boron concentration measurement is within 50 ppm (Measurement Based) of the predicted boron endpoint. The HFP ARO critical boron concentration measurement was not within 50 ppm of the predicted boron endpoint. The actual value was 65.3 ppm. See CR 1217909. 3.11 The difference between the measured ARO HZP boron endpoint and the ARO HFP boron endpoint is within 10o/o of the predicted difference. The actual difference was 8.0 ppm or approximately 1.9% of the predicted difference. 3.12 The BEACONTM core monitoring system mixing factor for individual Core Exit Thermocouples (CETCS) should be 1.0 t0.2 at HFP. The BEACONTM core monitoring system mixing factor for individual Core Exit Thermocouples (CETCS)were not 1.0 *:0.2 at HFP. See CR 1217904 4.0 Problems t1] CR 1217909: The HFP ARO critical boron concentration measurement was not within 50 ppm of the predicted boron endpoint. The actualvalue was 65.3 ppm. The HFP ARO critical boron concentration measurement was not within 500 pcm equivalent boron of the predicted boron endpoint. The actualvalue was 622.9 pcm. The Westinghouse evaluation (NF-TV-16-32) concluded there is sufficient margin in the reactivity assumptions of the current W2C1 safety analysis relative to this reactivity bias. Furthermore, the evaluation concluded that the reactivity bias is expected to improve throughout the remainder of this fuel cycle. 25L
7.4.16 Gore Power Distribution Factors (2-PET-301) (continued) l2l CR 1217904: The BEACONTM core monitoring system mixing factor for individual Core Exit Thermocouples (CETCS) was not 1.0 t0.2 at HFP. Only 50 of the 58 CETCs met the criteria and the mixing factors were all between 1 .12105 and 1 .50718. The preliminary Westinghouse evaluation has concluded the measured mixing factors were expected and should be considered satisfactory. The Review Criteria provided by Westinghouse in WBT-D4709 did not incorporate the expected bias between the Unit 2 CETCs that are encapsulated in the lncore lnstrumentation Thimble Assembly (llTA) and the typical CETC arrangement in the upper internals. Westinghouse document WBT-D-2697 documented that a 1SoF temperature differentia! could exist. Westinghouse will assess these results to confirm the validity of established uncertainty values associated with the sub-cooling monitoring functions in accordance with the actions described in CR 1217904. lt must be noted that the CETC indications do not affect the Unit 2 Power Distribution Monitoring System (PDMS), nor do they reflect an unexpected core power distribution. 252
7.4.17 Operational Alignment of NIS (2-PET-304) This PET was started on 5112116 and was completed on 9/30/16. 1.0 Test Obiectives The objectives of this test were to: 1.1 Ensure proper alignment or adjustment of the NlS. 1.2 Govern the conservative setting of power range high flux trip values in support of Power Ascension Testing. 1.3 Verify overlap between source range and intermediate range as well as between intermediate range and power range channels. 1.4 Verify the linearity of the power range channels in relation to reactor power. 1.5 Satisfy the requirements of UFSAR Table 14.2-2, Sheet 17, Operational Alignment Of Nuclear lnstrumentation Test Summary. 2.O Test Methods This test was performed utilizing data from normally performed plant procedures under normal operating conditions and utilized normally performed plant procedures to adjusUcalibrate the NIS channels. 3.0 Test Results AII Acceptance/Review Criteria were met or resolved as delineated below. Acceotance Criteria 3.1 Power Range (PR) high flux trips are set less than or equal lo 20o/o RTP above each power plateau prior to continuing up to the next power plateau. Actual Power Range (PR) high flux trips are given below: POWER PLATEAU PR HIGH FLUX TRIPS 5o/o 24o/o 30o/o 49o/o 50o/o 69% 75% 94o/o 100o/o 105o/o 253
7.4.17 Operational Alignment of NIS (2-PET-304) (continued) 3.2 At least two decades of overlap exists between the SR and lR channels. Actual overlap was over 2.5 decades between the SR and lR channels. 3.3 Overlap exists between the lR and PR Channels. Actual overlap was 100% of RTP between the lR and PR channels. Review Criteria 3.4 PR instrument linearity to power exhibits a correlation coefficient of greater than 0.98. The actual values are shown below: Channel N-41 N-42 N-43 N-44 Correlation 0.9997 0.9998 0.9997 0.9998 Coefficient 4.0 Problems There were no significant problems encountered during the performance of this test. 254
7 .4.18 Radiation Baseline Surveys (RCI-I 59) The baseline survey was started 1213115 and was field work complete on 09t27t16. {.0 Test Obiectives The objectives of this test were to: 1.1 Determine the effectiveness of the shielding by measuring radiation doses at preselected locations throughout the plant. The locations were selected using the UFSAR radiation zone maps and Unit-1 RCI-1 26, Radiation Baseline Surveys. 1.2 Satisfy the requirements of UFSAR Table 14.2-2, Sheet 18, Radiation Baseline Survey Test Summary. 2.0 Test Methods Baseline gamma and neutron dose rates were monitored at preselected locations throughout the plant at ambient conditions after fuel load and at various power levels (Pre-fuel load, post-fuel load, <10o/o,50%, & 100%) during the PATP. 3.0 Test Results All criteria were met or resolved as delineated below. The procedure did not used the terms "Acceptance or Review Criteria the procedure used the term "criteria". All radiation levels were within design limits as specified in the UFSAR as shown below. Location Criteria Highest Result Auxiliary Building <1000.0 mRem/hr. 0.1 mRem/hr. Control Building <0.050 mRem/hr. 0.01 mRem/hr. Reactor Building <100.0 Rem/hr 240 mRemlhr. Service Building <0.050 mRem/hr. 0.01 mRem lhr. Turbine Building <0.050 mRemlhr. 0.01 mRemlhr. 255
7 .4.18 Radiation Baseline Surveys (RCl-t 59) (continued) Milestones 3.1 Pre-fuel load RCI-159 Baseline surveys were completed on 12t3t2015: o General area dose rates observed were .004 - .180 mrem/hr. 3.2 Post-fuel load RCI-159 Baseline surveys were completed on 1211212015: o General area dose rates observed were .004 - .225 mremlhr. 3.3 <10o/o power RCI-159 Baseline surveys were completed on 513'll'16 o General area dose rates observed were .009 mrem - 22 mrem/hr. o No entry inside the containment bio-shield was made due to ALARA considerations at this power level and above. 3.4 30% power RCI-159 Baseline surveys were completed on 6116116 o Generalarea dose rates observed were .009 - 70 mrem/hr. o 30% power was conducted due to the uncertainty of holding the Unit at 50% power for any length of time. 3.5 100Yo power RCI-159 Baseline surveys were completed on 9127116 o Generalarea dose rates observed were .009 - 240 mrem/hr. ln support of the surveys and maintaining personnel exposure ALARA, electronic dosimetry was placed inside the bio-shield wall above 3% power. General area dose inside the bio-shield @ 100% power were 5.0 - 9.0 Rem, the highest reading was 12.1 Rem/hr. by Ioop #2 RCP. A comparison of the survey results and the UFSAR radiation zone maps in section 12.3.8 reveled the station is wellwithin the established parameters. In general the design and construction of Unit-2 is equivalent to that of Unit-1, the baseline surveys did not reveal any abnormalities compared to Unit-1. 4.O Problems There were no significant problems encountered during the performance of this test. 255}}