Systems Exam 4 Full Comprehensive Deck for Review Flashcards

Question

MSR Reheat

Answer 1

→comes from inlet of HP turbine →4 passes with drains to 2 drain tanks at the end of 2nd and 4th passes →reheater drain tanks drain to FWH 1

Answer 2

→5 safeties per SG required, Modes 1-3 →ensures secondary system pressure will be limited to within 110% of its design pressure of 1185 psig during the most severe anticipated system operational transient →max relieving capacity associated with turbine trip from 100% coincident with an assumed loss of condenser heat sink One or more SGs with 1 MSSV inoperable and MTC 0 or negative: → <68% power in 4 hrs More than one MSSV inoperable on one or more SG or one inoperable with positive MTC: →4 operable, reduce to ≤61% →3 operable, reduce to ≤43% →2 operable, reduce to ≤26%

Answer 3

→required at all times →both primary and secondary sides shall be >70°F →whenever pressure on either side >200 psig →reduce to <200 psig in 30 mins

Answer 4

→required to have 4 in Modes 1-3 except when MSIVs are closed and deactivated →one out in Mode 1 - restore in 8 hrs or Mode 2 in 6 hrs →one out in Modes 2 & 3 - close in 8 hrs and verify closed every 7 days

Answer 5

→required to have 1 per steam line in Modes 1-3 →one out - restore in 7 days →two out - restore in 72 hrs →three out - restore in 24 hrs

Answer 6

→pressure ≥80 psig →if not met, ARV is inoperable →immediate entry into TS 3.7.4

Answer 7

→required in Modes 1-3 →SG pressure and SG water level indications →one from each SG on RSP

Answer 8

→62,150 lbm/hr →allows plant to maintain hot standby for 4 hrs, then cool plant from no load T-ave (557°F) to 350°F (RHR cut-in) in 5 hrs at 50°F/hr before exhausting CST inventory

Answer 9

saturation pressure/130 = number of turns

Answer 10

→U1 - GS Condenser uses orifice to direct flow thru condenser →U2 - uses valve locked in place, air operator disabled, to throttle flow

Answer 11

→Hi-Hi Hotwell Level 6' →Lo Hotwell Level 1.2' →0.2' Hotwell Lo-Lo Level trips condensate pumps (2/3) →Lo Condenser Vacuum 24" Hg (starts standby CEV Pump) →an SG tube leak will adversely affect vacuum due to an increase in non-condensable gases

Answer 12

→powered by uEB1-3 →200 gpm discharges upstream of CP system for initial system fill →Auto stops on Low Suction Pressure 7 psig →Load shed on SI

Answer 13

→Main Turbine Trip: 21" Hg if >900 rpm (2/3 on either condenser) →Steam Dump Actuation Block (C-9): 12.3" Hg (2/2) →Lo-Lo Level Condensate Pump Trip: 0.2' Hotwell Level →Main Feed Pump Trip: Low Vacuum in Aux Condensers (2/3); 2 sec TDPU → ≤17.5" Hg on 2 detectors OR → <21" Hg on one detector and 17.5" Hg on another detector

Answer 14

→fail closed valves →Lo flow u-LV-2217A (4") opens 4-12 milliamps →Hi flow u-LV-2217B (8") opens 12-20 milliamps →Controller output = 4-12ma for 0-100% on 2217A, 12-20ma for 2217B 0-100% →maintain hotwell level at approx. 3 ft Note: Low flow valve u-LV-2217A immediately goes full open at <1.2' (separate solenoid drives valve full open), independent of M/A station setpoint.

Answer 15

→auto opens at Hi Level 5'6" to allow backflow through u-HV-2484 & 2485 →auto closes at Lo Level 4' →provided w/ seal in circuit (via open LS) to keep valve open after being manually opened; still auto closes on Lo Level. →LV-2211/12 blocked from opening (and will auto close) on any of the following: →PV-2286 is open (>15%) →both Condensate Pumps trip →either HV-2484 or HV-2485 is closed (auto close on AFW start or CST Hi Level) →Condenser Lo Level NPSH for pumps

Answer 16

→motor cooled by TPCW →seal water provided via demin water (gravity feed from DWST)

Answer 17

→trip on Lo-Lo Level in (0.2') hotwell (2/3 coincidence) →discharge valve and pump controlled via same H/S: taking H/S to start opens discharge valve; pump starts once valve is 10% open →if discharge valve doesn't reach 10% open, pump won't start →if pump doesn't start once discharge valve is 10% open, valve auto closes →overcurrent must be reset locally at breaker via keyswitch (normal for most of our non-safety pumps) Note: has been found that >80% RTP, MFPs will trip on Condensate Pump trip

Answer 18

PV-2286 Interlocks: (ref: ABN-302) →auto opens on Lo MFP Suction Pressure (2/3 < 250 psig with generator output MWe > 15%) →will open (indirectly) if condensate pump trips Open Valve Causes: →LV-2211/12 Hotwell Reject Valve to close →FV-2239 Condensate Pump Recirculation Valve to close →alarm on ALB-8B "CNDS LP HTR BYP VLV OPEN" Initial Action if Valve Opens: →Verify Control Rods in Auto and MANUAL Runback to 900 MWe →2286 is sized to provide 96% of rated flow to MFPs

Answer 19

→fails open →auto opens on Hi system D/P: modulates open at 35 psid; full open at 40 psid →auto opens on Lo MFP Suction Pressure <280 psig (2/3) →auto opens on valve misalignment on IN-SERVICE CP Vessel (any IN-SERVICE vessel isolates at power)

Answer 20

→AOVs - fail open on loss of air; fail closed on loss of power →power supplied from uD3 →provided with Trip to Auto Enable or Disable toggle switch on M/A station →in Enable, valve can be manually controlled and auto open can occur →opens <6,000 gpm →closes >12,000 gpm →5 sec lockout TD until valve can be switched to manual after low flow condition →in Disable, only manual control can occur; valve will not auto open on a low flow Interlocks: →auto closes when 2286 opens (<250 psig MFP suction pressure 2/3 and >15% RTP) →<190 psig 2/3 both MFPs trip after 30 sec TD (MFP A) and 45 sec TD (MFP B) →<170 psig 2/3 with 4 sec TD, both MFPs trip

Answer 21

→auto close on Hi-Hi Level in associated heater train →2611A/B for 5A/6A FWH, 6A Drain Cooler →2612A/B for 5B/6B FWH, 6B Drain Cooler →single H/S for both valves in a train →bypass valve LV-2611/2612 opens on close signal to any of these valves →u-LV-2611A/B - uB3-1 →u-LV-2612A/B - uB4-1 →u-LV-2611/12 - uB3-1

Answer 22

SOP-303 Flow Limits for Condensate Pumps: →Do NOT operate two (2) Condensate Pumps until total flow is >8,000 gpm to prevent flow imbalance between the two pumps. →A minimum flow rate of 3,000 gpm per operating Condensate Pump SHALL be maintained. →A maximum flow rate of 14,700 gpm per operating Condensate Pump SHALL NOT be exceeded.

Answer 23

→Minimum level of 53% (244,000 gallons) →applicable in Modes 1-3 → if level OOS - verify SSW backup within 4 hours AND restore within 7 days or, Mode 3 in 6 hrs & Mode 4 in 12 hours →Bases: Volume is sufficient to hold the unit in Mode 3 for 4 hrs followed by a C/D to RHR entry conditions at 50°F/hr for 5 hrs →To satisfy accident analysis assumptions, the CST must contain sufficient cooling water to remove decay heat following a reactor trip from 102% RTP, and then to cool down the RCS to RHR entry conditions, assuming a coincident loss of offsite power and the most adverse single active failure.

Answer 24

→Specific activity of the secondary coolant shall be <0.10 μCi/gm Dose Equivalent I-131 (Modes 1-4) →if not met, Mode 3 in 6 hrs & Mode 5 in 36 hours Bases: →minimizes releases to the environment because of normal operation, anticipated operational occurrences and accidents →limit is lower than the activity value that might be expected from a 1 gpm tube leak of primary coolant at the limit of 1 μCi/gm

Answer 25

→efficiency goes down →RCS T-cold goes down →Steam Pressure goes down →Rx power goes up →SG Level goes up (a.k.a. swell)

Answer 26

→taps for makeup/reject located 23'9" above bottom of tank →ensures 53% (or 244,000 gal) for Aux Feedwater following a Design Basis Accident →ensures capability to maintain hot standby for 4 hrs, then cool down RCS from 557°F to 350°F in 5 hrs

Answer 27

→solenoid valve opens at 194°F with >1340 rpm →sprays condensate into the area to lower temps →happens mostly at low power with low steam flow available to cool area →condensate line taps off header before drain coolers →solenoid valve must be manually closed once temp restored, but will auto close when high temp clears if LP turbine inlet steam pressure ≥7 psia →separate MOV provided if solenoid valve insufficient to maintain temps →if exhaust temp can't be maintained <212°F, turbine is manually tripped

Answer 28

→top of Condenser A →after LEFM →one Condensate Pump running

Answer 29

→bottom of Condenser →before LEFM →two Condensate Pumps running

Answer 30

14,700 gpm

Answer 31

→Unit 1: 67% →Unit 2: 64% →controlled by SGWLC →Level Dominant System

Answer 32

→Unit 1: 38% →Unit 2: 35.4% →causes Rx Trip →causes AFW Auto Start (1/4 SGs for MDAFWPs, 2/4 SGs for TDAFWP)

Answer 33

→Unit 1: 84% →Unit 2: 81.5% →P-14: →MFPs trip →turbine trips →Feedwater Isolation signal →2/3 detectors on any 1 SG (ch 1 not used SGs 1&4; ch 2 not used SGs 2&3)

Answer 34

**→Manual** **→SI** from either train (also trips Main Turbine and causes FWI) **→Low Turbine Bearing Oil Pressure** - U1 ≤5.5 psig, U2 ≤4 psig; (2/3) 2 sec TDPU **→Low Pump Bearing Oil Pressure** - U1 ≤10psig, U2 ≤7 psig; (2/3) 2 sec TDPU **→Low Vacuum Aux Condensers** (2/3) ≤17.5" Hg on 2 detectors OR <21" Hg on one detector and 17.5" Hg on another detector; 2 sec TDPU **→Low MFP Suction Pressure ≤190 psig** (2/3); 30 sec TD MFP A, 45 sec TD MFP B; staggered trip **→Low MFP Suction Pressure ≤170 psig** (2/3); 4 sec TD (trips both simultaneously) **→Thrust Bearing Wear** ≥32 mils (2/3) **→Electrical Overspeed** ≥5600 rpm (2/3) **→Mechanical Overspeed** ≈5720 rpm (5663-5773 rpm, 5720 ± 57 rpm or ±1% tolerance) **→P-14 SG Hi-Hi Level** (2/3 on any one SG); also trips Main Turbine and causes FWI

Answer 35

Loss of uD2 will prevent an electrical trip of the MFPs due to loss of the control system. Quickly shut down the MFPs if: →radial bearing metal temp >225°F →any other bearing metal temp >215°F →any oil temp >215°F →radial bearing vibration >5 mils

Answer 36

→Hi-Hi S/G Water Level (P-14), resettable

Answer 37

Feedwater Isolation Signal (FWI) closes the following valves: →u-FCV-510 through 540 Flow Control Valves →u-LV-2162 through 2165 Flow Control Bypass Valves →u-HV-2134 through 2137 Feedwater Isolation Valves →u-HV-2185 through 2188 Feedwater Isolation Bypass Valves →2-FV-2193 through 2196 Feedwater Pre-Heater Bypass Valves (U2 only) →2-FV-2181 through 2184 Feedwater Split Flow Bypass Valves (U2 only) Valves Close in Order To: →prevent excessive RCS cooldown →prevent uncontrolled SG filling →limit mass addition to CNTMT in event of DBA

Answer 38

→reduce power to <98.6% if lost →LEFM is a high accuracy flow measuring device which uses acoustic energy pulses to determine the final feedwater mass flow, and is used in calorimetric

Answer 39

→turning gear engaged via Instrument Air, driven by motor →starts when speed ≤2 rpm (via low speed switch on MFP turbine) AND adequate lube oil pressure

Answer 40

Feed Water Isolation Valves (u-HV-2134/2135/2136/2137) →hydraulically opened, nitrogen to close, 2040 psig minimum pressure to be operable →pressure less than 2040 may result in exceeding surveillance stroke time →provided with train related solenoids to dump hydraulic pressure and close valves within 5 secs →hydraulic pumps powered from: uEB1-3 for SGs 1 and 3, uEB2-3 for SGs 2 and 4 → **maintain ≥90°F at all times per IPO-002, based on fracture toughness (TR 13.7.38)**

Answer 41

→in Auto, valves throttle to maintain 5,000 gpm suction flow (MFP trip reset will open if in Auto) →driver card failure enables a separate solenoid which causes the valve to open at 4,275 gpm and close at 6,625 gpm →at normal power this would keep it closed →fails open on loss of air →fails closed on loss of signal →fails closed on MFP trip if both HP and LP steam supplies are shut

Answer 42

Feed Pump Discharge Valves HV-2109/2110 Interlocked with MFP status →auto opens on feed pump turbine start signals →auto close on a trip of the feed pump turbine OR closure of both HP and LP steam valves →trip signal overrides start signal →can auto open after trip signal reset

Answer 43

Water Hammer Interlocks are satisfied when: →no Feedwater Isolation signals present →FWIBV full open for 50 minutes →IRC feedwater temp >250°F for 10 minutes AND feedwater ΔT across cntmt penetration <10°F →total feedwater flow is >500,000 lbm/hr per SG →admin limits: SG pressure >605 psig and NR level >5%

Answer 44

Water Hammer Interlocks met causes the following: →allows opening FIV (will auto open if in Auto after Open) →once FIV open, FIBV/FPBV auto close and FSBV opens

Answer 45

Water Hammer Interlocks are removed by any of the following: →Feedwater Isolation Signal is received →both FWIV and FWIBV go full closed →FSBV doesn't have open signal and total FW flow to SG is <475,000 lbm/hr →total FW flow to SG decreasing to <475,000 lbm/hr in conjunction with either IRC feedwater temp decreasing to <250°F OR ΔT across cntmt penetration increasing to >10°F

Answer 46

→any MDAFWP auto start signal →Feedwater Isolation →Water Hammer Interlocks not met

Answer 47

To open FWP flush bypass valves (HV-2122 & 2124): →both FWPs tripped (both HP and LP steam valves closed) →both FWP suction valves (HV-2321 & 2323) closed.

Answer 48

TR 13.7.32 - SG Pressure/Temperature Limitations Establishes the temperature limits for primary and secondary coolants in the Steam Generators when the pressure of either coolant is greater than 200 psig. (requires the temperatures of the Primary and Secondary coolants to be > 70°F when the pressure of either coolant in the SG is > 200 psig)

Answer 49

→2 AC oil pumps and 1 DC oil pump →1 AC pump normally in service →AC pumps are dual stage - 1st stage supplies 55 psig header; 2nd stage supplies 200 psig header

Answer 50

FWIVs close and FWPBVs open due to loss of water hammer interlocks.

Answer 51

→standby AC pump starts at 175 psig header pressure on the 200 psig header →DC pump auto starts at 25 psig bearing header pressure →only supplies 55 psig bearing header; bypasses lube oil coolers and filter

Answer 52

Failures: SG Level High LT-551 →Level error closes FCV which causes MFP speed to decrease →Feed flow decreases →flow error tries to offset level error, but doesn't →SG level decreases until Lo-Lo SG Level causes Rx trip

Answer 53

Failures: SG Level Low LT-551 →Level error opens FCV which causes MFP speed to increase →Feed flow increases →flow error tries to offset level error, but doesn't →SG level increases until P-14 actuates

Answer 54

Failures: Feed Flow High FT-510 →steam flow / feed flow mismatch →flow error causes FCV to close →FCV D/P increases, causing MFP speed to decrease →Feed flow decreases →SG level decreases →as SG level decreases, level error increases until level error = flow error →SG level stabilizes at level < normal

Answer 55

Failures: Feed Flow Low FT-510 →steam flow / feed flow mismatch →flow error causes FCV to open →FCV D/P decreases, causing MFP speed to increase →Feed flow increases →SG level increases →as SG level increases level error increases until P-14 actuates

Answer 56

Failures: Steam Flow High FT-512 →steam flow / feed flow mismatch →flow error causes FCV to open →FCV D/P decreases, causing MFP speed to increase →Feed flow increases →SG level increases →as SG level increases, level error increases until level error = flow error →SG level stabilizes at level above normal Note: if this occurs at lower power levels, then a Hi-Hi Level may occur, causing a Turbine/MFP trip.

Answer 57

Failures: Steam Flow Low FT-512 →steam flow / feed flow mismatch →flow error causes FCV to close →FCV D/P increases, causing MFP speed to decrease →Feed flow decreases →SG Level decreases →as SG level decreases, level error increases →flow error drives to Lo-Lo setpoint, causing Rx trip

Answer 58

Failures: Feed Header High Pressure PT-508 →MFPs speed decreases →Feed flow decreases →SG level decreases →Level error opens FCV fully →Feed flow continues decreasing →SG Level decreases until Lo-Lo level causes Rx trip

Answer 59

Failures: Feed Header Pressure Low PT-508 →MFP feed increases →Feed flow increases →SG level increases →Level error causes FCV to close →eventually, FCV closes enough that feed flow = steam flow →SG level stabilizes a few percent above normal

Answer 60

Failures: Steam Pressure High PT-514 →steam flow / feed flow mismatch →flow error causes FCV to open →FCV D/P decreases, causing MFP speed to increase →Feed flow increases →SG Level increases →as SG level increases, level error increases, thereby offsetting flow error until steam flow = feed flow

Answer 61

Failures: Steam Pressure Low PT-514 →steam flow / feed flow mismatch →flow error causes FCV to close →FCV D/P increases, causing MFP speed to decrease →Feed flow decreases →SG Level decreases →as SG level decreases, level error increases →flow error drives to Lo-Lo setpoint, causing Rx trip

Answer 62

→steam pressure channel fails low causing program D/P to lower →MFP speed decreases to match actual D/P to program D/P →FCVs open to increase flow →steam pressure channel failing low also causes steam flow channel to fail low due to loss of density compensation, causes flow error →flow error wants FCV to close →level channels then fail low, causing level error →flow error and level error are competing effects →system is level dominant →FCV slowly opens to restore level →For uPC1 SGs 1 & 4 affected →For uPC2 SGs 2 & 3 affected

Answer 63

SG Alarms for channel IV will annunciate and then clear. →alarms come in because of channel IV failure →alarms clear due to loss of multiplexer

Answer 64

Level Deviation Alarm: actual level ± 5% from program level

Answer 65

→2/3 logic used for P-14 →Tech Specs require 3 operable channels for P-14. →only channels that don't input into SGWLC can be used for P-14 →the level channel normally used for control does not input into P-14; based on the assumption that the controlling channel will fail, and will likely fail low →SGs 1 & 4 use channel 1 for control, so channels 2, 3, & 4 are used for P-14 →SGs 2 & 3 use channel 2 for control, so channels 1, 3, & 4 are used for P-14 Note: when one of the 3 operable P-14 channels is used as a controlling channel, then the P-14 bistable for that channel shall be placed in a tripped condition within 72 hrs (TS 3.3.2)

Answer 66

Program ΔP is fed via summing circuit that sums steam flow from all 4 generators to equate to a given power level.

Answer 67

→Program ΔP is determined using total steam flow from all 4 SGs and is →Program ΔP is compared to Actual ΔP across FCV using PT-507 (main steam flow) and PT-508 (feed flow). →as FCV opens, ΔP goes down and MFP speed goes up to compensate →as FCV closes, ΔP goes up and MFP speed goes down to compensate

Answer 68

→0-20% power ΔP is 80 psid →Unit 1: 20-100% power the ΔP ramps from 80- 181 psid →Unit 2: 20-100% power the ΔP ramps from 80-193 psid →To solve for new Program D/P: →U1 Program ΔP = (101/80) x (Actual Power - 20%) + 80 →U2 Program ΔP = (113/80) x (Actual Power - 20%) + 80

Answer 69

→pump speed based on maintaining ΔP across FCVs →Program ΔP vs Actual ΔP →actual calculation performed via 7300 system →7300 system feeds signal to T3000 controller Actual Pressure comes from PT-507 Steam Header Pressure

Answer 70

Main Feedwater is at a higher pressure. If it wasn't, we wouldn't be able to inject into the steam generators. Main Feedwater normal operating pressure is approx. 80-180 psig higher than Main Steam normal operating pressure

Answer 71

Steam flow instruments are density compensated using steam pressure instruments. As a result, failure of a steam pressure instrument could cause inaccurate steam flow readings.

Answer 72

Failures: SG Level High LT-551 →Level error closes FCV which causes MFP speed to decrease →Feed flow decreases →flow error tries to offset level error, but doesn't →SG level decreases until Lo-Lo SG Level causes Rx trip

Answer 73

Failures: SG Level Low LT-551 →Level error opens FCV which causes MFP speed to increase →Feed flow increases →flow error tries to offset level error, but doesn't →SG level increases until P-14 actuates

Answer 74

Failures: Feed Flow High FT-510 →steam flow / feed flow mismatch →flow error causes FCV to close →FCV D/P increases, causing MFP speed to decrease →Feed flow decreases →SG level decreases →as SG level decreases, level error increases until level error = flow error →SG level stabilizes at level < normal

Answer 75

Failures: Feed Flow Low FT-510 →steam flow / feed flow mismatch →flow error causes FCV to open →FCV D/P decreases, causing MFP speed to increase →Feed flow increases →SG level increases →as SG level increases level error increases until P-14 actuates

Answer 76

Failures: Steam Flow High FT-512 →steam flow / feed flow mismatch →flow error causes FCV to open →FCV D/P decreases, causing MFP speed to increase →Feed flow increases →SG level increases →as SG level increases, level error increases until level error = flow error →SG level stabilizes at level above normal Note: if this occurs at lower power levels, then a Hi-Hi Level may occur, causing a Turbine/MFP trip.

Answer 77

Failures: Steam Flow Low FT-512 →steam flow / feed flow mismatch →flow error causes FCV to close →FCV D/P increases, causing MFP speed to decrease →Feed flow decreases →SG Level decreases →as SG level decreases, level error increases →flow error drives to Lo-Lo setpoint, causing Rx trip

Answer 78

Failures: Feed Header High Pressure PT-508 →MFPs speed decreases →Feed flow decreases →SG level decreases →Level error opens FCV fully →Feed flow continues decreasing →SG Level decreases until Lo-Lo level causes Rx trip

Answer 79

Failures: Feed Header Pressure Low PT-508 →MFP feed increases →Feed flow increases →SG level increases →Level error causes FCV to close →eventually, FCV closes enough that feed flow = steam flow →SG level stabilizes a few percent above normal

Answer 80

Failures: Steam Pressure High PT-514 →steam flow / feed flow mismatch →flow error causes FCV to open →FCV D/P decreases, causing MFP speed to increase →Feed flow increases →SG Level increases →as SG level increases, level error increases, thereby offsetting flow error until steam flow = feed flow

Answer 81

Failures: Steam Pressure Low PT-514 →steam flow / feed flow mismatch →flow error causes FCV to close →FCV D/P increases, causing MFP speed to decrease →Feed flow decreases →SG Level decreases →as SG level decreases, level error increases →flow error drives to Lo-Lo setpoint, causing Rx trip

Answer 82

→steam pressure channel fails low causing program D/P to lower →MFP speed decreases to match actual D/P to program D/P →FCVs open to increase flow →steam pressure channel failing low also causes steam flow channel to fail low due to loss of density compensation, causes flow error →flow error wants FCV to close →level channels then fail low, causing level error →flow error and level error are competing effects →system is level dominant →FCV slowly opens to restore level →For uPC1 SGs 1 & 4 affected →For uPC2 SGs 2 & 3 affected

Answer 83

SG Alarms for channel IV will annunciate and then clear. →alarms come in because of channel IV failure →alarms clear due to loss of multiplexer

Answer 84

Level Deviation Alarm: actual level ± 5% from program level

Answer 85

→2/3 logic used for P-14 →Tech Specs require 3 operable channels for P-14. →only channels that don't input into SGWLC can be used for P-14 →the level channel normally used for control does not input into P-14; based on the assumption that the controlling channel will fail, and will likely fail low →SGs 1 & 4 use channel 1 for control, so channels 2, 3, & 4 are used for P-14 →SGs 2 & 3 use channel 2 for control, so channels 1, 3, & 4 are used for P-14 Note: when one of the 3 operable P-14 channels is used as a controlling channel, then the P-14 bistable for that channel shall be placed in a tripped condition within 72 hrs (TS 3.3.2)

Answer 86

Program ΔP is fed via summing circuit that sums steam flow from all 4 generators to equate to a given power level.

Answer 87

→Program ΔP is determined using total steam flow from all 4 SGs and is →Program ΔP is compared to Actual ΔP across FCV using PT-507 (main steam flow) and PT-508 (feed flow). →as FCV opens, ΔP goes down and MFP speed goes up to compensate →as FCV closes, ΔP goes up and MFP speed goes down to compensate

Answer 88

→0-20% power ΔP is 80 psid →Unit 1: 20-100% power the ΔP ramps from 80- 181 psid →Unit 2: 20-100% power the ΔP ramps from 80-193 psid →To solve for new Program D/P: →U1 Program ΔP = (101/80) x (Actual Power - 20%) + 80 →U2 Program ΔP = (113/80) x (Actual Power - 20%) + 80

Answer 89

→pump speed based on maintaining ΔP across FCVs →Program ΔP vs Actual ΔP →actual calculation performed via 7300 system →7300 system feeds signal to T3000 controller Actual Pressure comes from PT-507 Steam Header Pressure

Answer 90

Main Feedwater is at a higher pressure. If it wasn't, we wouldn't be able to inject into the steam generators. Main Feedwater normal operating pressure is approx. 80-180 psig higher than Main Steam normal operating pressure

Answer 91

Steam flow instruments are density compensated using steam pressure instruments. As a result, failure of a steam pressure instrument could cause inaccurate steam flow readings.

Answer 92

→in use above 15% RTP →dead band of 5°F, so Bank 1 starts to open when Ave T-ave is 5°F above T-ref →demand increases by 9% per degree above the 5° deadband →PT-505 feeds T-ref

Answer 93

→P-4 Rx trip on RTB Train B swaps controller from Load Rejection to Plant Trip →controls Ave T-ave to 557°F No Load T-ave temp →no deadband; 2.5% demand increase per degree above 557°

Answer 94

→used when <15% RTP, during plant heat up (startup) and plant cooldown (shutdown) →maintains steam line pressure at setpoint set on the controller →auto normally set at 1092 psig or 6.86 turns to maintain 557°F →PT-507 Steam Header Pressure is used as the reference pressure signal →1.8 psid per percent demand on controller →if an issue exists that prevents SD from closing on Low T-ave taking Selector Switch to Steam Pressure Mode will close SD. Or take one of the interlocks to off.

Answer 95

C-7 is reset by taking STM DMP MODE SELECT to RESET.

Answer 96

→Train A P-4 signal arms the Steam dumps in T-ave mode →Train B P-4 signal swaps T-ave Mode from the Load Reject Controller to the Plant Trip Controller Control fuses to the Reactor Trip Bypass breakers must remain installed even though the breaker is normally not connected. This is because the auxiliary relays powered by these fuses would not indicate proper breaker status if they were de-energized. Likewise, P-4 requires Rx Trip Breaker control power fuses to remain installed even if the breaker is racked out.

Answer 97

Steam Pressure Mode uses reference pressure from PT-507 (200-1500) and PK-507 controller

Answer 98

I/P Supplies: →4 - 8ma or 0 - 25% signal to open Bank 1 0 - 100% →8 - 12ma or 25 - 50% signal to open Bank 2 0-100% →12 - 16ma or 50 - 75% signal to open Bank 3 0 - 100% →16 - 20ma or 75 - 100% signal to open Bank 4 0-100%

Answer 99

→loss of uPC1 - no arming signal for C-7; still available in Steam Pressure Mode →loss of uPC2 - no C-9, so no Steam Dumps

Answer 100

Trip open and arming circuits receive power from uD2-3, not train related.

Answer 101

Load Reject Controller: →5°F deadband →Hi-1 10.6°F - all 6 Group 1 valves trip open (banks 1&2) →Hi-2 16.2°F - all 6 Group 2 valves trip open (banks 3&4) Plant Trip Controller: →no deadband →Hi-1 20°F - all 6 Group 1 valves trip open (banks 1&2) →Hi-2 40°F - all 6 Group 2 valves trip open (banks 3&4) There is no trip open circuitry for Steam Pressure Mode, only goes through I/P converter.

Answer 102

Steam Dumps are armed by meeting C-9 (condenser available) AND one of the following: →P-4, Train A only →C-7, load reject of 10% in 120 sec (PT-506 from uPC1) →Selector Switch in Steam Pressure Mode (ref pressure from PT-507, 200-1500 psig on PK-507 controller) Note: C-7 is reset by taking the Steam Dump Mode Selector Switch to "Reset"

Answer 103

→Setpoint: >12.3" Hg vacuum (2/2; uPC2) →Coincidence: Condenser vacuum plus 2/4 Circ Water Pump **breakers** closed

Answer 104

→LOOP (no CWPs, so no C-9) →Main Steam Isolation (no steam moving through lines to Steam Dumps/Condenser) →ARVs would control RCS temp down to 561°F

Answer 105

→trip open in 3 sec →modulate open in 20 sec →close in 5 sec

Answer 106

→pot setting = (pressure - 200 psig)/130 →setpoint ↑, pressure ↑ (less steam flow), temp ↑, demand likely ↓ →higher temp results in negative ρ at EOL conditions but positive ρ at BOL when MTC is still +

Answer 107

→Loss of Load →Setpoint: 10% with time constant of 120 sec on PT-506 (uPC1) →Coincidence: based on turbine power load reduction

Answer 108

→OFF RESET sends signal to protection solenoids to close venting air, which closes steam dumps →BYP INTLK removes Lo-Lo T-ave 553°F trip block to allow cooldown with Bank #1 valves ONLY

Answer 109

→Lo-Lo T-avg permissive →Setpoint: ≤553 deg F →Coincidence: 2/4 channels

Answer 110

→When met automatically closes all steam dump valves →The 3 cooldown steam dump valves may be opened by using bypass switch.

Answer 111

Fails High: →does nothing in T-ave Mode →in Steam Pressure Mode, will cause Steam Dumps to modulate open →SG pressure ↓, SG level ↑, RCS temp ↓, Rx Power ↑ Fails Low: →does nothing in T-ave Mode →in Steam Pressure Mode, will cause Steam Dumps to close →SG pressure ↑, SG level ↓, RCS temp ↑, Rx Power ↓

Answer 112

Fails High: →does nothing in Steam Pressure Mode →in T-ave Mode, Load Rejection Controller, C-7 won't arm, so Steam Dumps won't open →If Trains A & B get P-4 signals on a Rx trip, then Steam Dumps will switch to Plant Trip Controller and work as designed Fails Low: →does nothing in Steam Pressure Mode →in T-ave Mode, Load Rejection Controller, C-7 arms, but with no demand, so Steam Dumps won't open →If Trains A & B get P-4 signals on a Rx trip, then Steam Dumps will switch to Plant Trip Controller and work as designed

Answer 113

Fails High: →does nothing in Steam Pressure Mode →does nothing in T-ave Mode, Plant Trip Controller →in T-ave Mode, Load Reject Controller, results in T-ref being higher than Ave T-ave, so demand goes to zero Fails Low: →does nothing in Steam Pressure Mode →does nothing in T-ave Mode, Plant Trip Controller →in T-ave Mode, Load Reject Controller, results in T-ref being lower than Ave T-ave, so demand goes up, but without an arming signal, Steam Dumps will stay closed

Answer 114

They will not open in any Mode.

Answer 115

→PT-505 - Main Turbine first stage impulse pressure →PT-506 - Main Turbine first stage impulse pressure →PT-507 - Main Steam Header Pressure →PT-508 - Main Feedwater Header Pressure

Answer 116

Fail High: →nothing happens in Steam Pressure Mode →in T-ave Mode, for either controller, demand increases, but nothing happens without an arming signal Fail Low: →nothing happens in Steam Pressure Mode →in T-ave Mode, for either controller, demand decreases, but nothing happens without an arming signal

Answer 117

→T-ave Mode will remain in Load Reject Controller and not swap over →RCS temp stabilizes at 562°F (5°F above 557°F)

Answer 118

The Heater Drains System functions to aid in regeneratively heating feedwater by cascading the higher energy drains through successively lower energy stages of feedwater heaters.

Answer 119

→normal - fail closed →alternate - fail open

Answer 120

→not enough stored energy →located inside main condenser, so have limited accessibility for operation/maintenance →feedwater heaters have anti-flash baffles →condensate side of feedwater heaters provided with auto isolation on Hi-Hi Level

Answer 121

Heater Drain Tank 01: →MSR Separator Drains →MSR Shell Drains →SGBD Drain →HDT-01 drains to HDT-02 Heater Drain Tank 02: →Feedwater Heaters 1, 2, & 3 →FWH 1A/B drains to FWH 2A/B →FWH 3A/B have no alternate drains (dry heater) →U2 only: FWH 3A/B have vent isolations →HDT-02 provides suction to Heater Drain Pumps

Answer 122

→Seal Water and Cold Water Injection both supplied from Condensate →Cold Water Injection provided to prevent cavitation through HDPs & TV-2598

Answer 123

→powered from uA1 and uA2 →oil coolers supplied by TPCW →minimum flow 1400 gpm →if one HDP trips, turbine will runback to <812 MWe (≈70%) at 35% per min Pumps Trip On: →Lo-Lo Level HDT-02 5%, ≤806'6" (2/2) →overcurrent, phase-to-ground →locked rotor →thermal overload (26 relay) →motor DOES NOT trip on motor overload; 74 relay is alarm only

Answer 124

→fail open AOVs →minimum HDP flow is 1400 gpm. →auto open when HDP flow <1470 gpm (both valves open on low flow from either pump) →auto close when HDP flows >1520 gpm (both valves close when both HDP flows above setpoint) →auto close 10 sec after associated pump trip

Answer 125

→close slower than check valves →protect turbine from water induction and high level Auto Close On: 1. Hi-Hi FWH Level 2. Turbine Trip Interlocked With: →associated power assisted check valve →upstream drip pot drain isolation valve →normal drain valve from its associated drains source

Answer 126

→close fast →protect turbine from overspeed due to reverse flow Auto Close On: 1. Hi-Hi FWH Level 2. Turbine Trip

Answer 127

...trip the Main Turbine.

Answer 128

Shut down immediately if: →bearing temp >200°F →lube oil temp >160°F or it doesn't build lube oil pressure

Answer 129

→Hi Level produces Control Room alarm →Hi-Hi Level FWH 1: →closes normal drains from RHDT to FWH 1 →closes Extraction Steam valve to FWH 1 →opens alternate drain valves to Main Condenser →Hi-Hi Level FWH 2: →closes normal drains from FWH 1 to FWH 2 →closes Extraction Steam valve to FWH 2 →opens alternate drain valves to Main Condenser

Answer 130

The goal is to maintain HDT-02 Level at 50%. u-LV-2592: →comes off HDP discharge header; supplies MFP suction →PI Controller, uses auctioneered high level →HDT-02 Level >50% - valve opens further →HDT-02 Level <50% - valve closes further →if level goes too low, valve could close enough that forward flow is lost u-LV-2594: →comes off HDP-02; discharges to Main Condenser Shell B →Proportional Controller; uses auctioneered low level →HDT-02 Level >65% (approx.), valve modulates open →HDT-02 Level >70% (approx.), valve fully open

Answer 131

HDP Common Discharge LV-2592 controlled by auctioneered HI signal from LT-2592A/B: →failing low has minimal impact →failing high will cause 2592 will go full open →could result in HDT level lowering to 2/2 level HDP trip (5%) HDT-02 Alt. Drain Valve LV-2594 controlled by auctioneered LOW signal from LT-2594B/C: →failing high will have minimal effect →failing low will cause 2594 to close if open Note: the Lo-Lo Level HDT-02 5% trip of the HDPs comes off of different level transmitters than the ones that control LV-2592 & 2594.

Answer 132

→ALB-6D Win 1.9 "ANY TURB RUNBACK EFFECTIVE" will be lit →will not be lit if already below runback power setpoint →for auto runbacks, the annunciator on Digital Control System (DCS) is illuminated for **9 minutes**

Answer 133

→HDP Trip: 35% per min to 800 MW (70%) →MFP or Condensate Pump Trip: 35% per min to 700 MW (60%) →C3 / C4: 200% per min for 1½ sec, then off for 28½ sec; repeat until condition clears

Answer 134

→preset buttons available to drive turbine to selected MW load →button provided for 50 MW @ 100 MW/Min; resets in 30 sec →load settings available: 900 and 700 MW at 35% per min →must be manually reset on DCS by turning OFF sub loop controller →for manual runback or load reduction, Runback Annunciator clears once actual load reaches load setpoint

Answer 135

HP Stop and Control valves share common body; MSR heating steam taps off between the two valves.

Answer 136

Turning Gear is supplied from 2 valves: →requires both valves to be open to initially roll the turbine →speed varies between 80 and 190 rpm dependent upon whether vacuum established →auto close if thrust bearing LO pressure 25# →alarm actuated if EITHER valve is open AND <9 rpm on main turbine →neither valve will open if generator breakers are closed u-HV-6554A Turning Gear Valve #1: →auto opens at 230 rpm decreasing →auto closes at 260 rpm increasing →manually operated <50 rpm due to lack on fine control at low speed u-HV-6554B Turning Gear Valve #2: →used to initially roll the turbine →auto closes at 15 rpm increasing →can be manually opened <15 rpm

Answer 137

Temperature in MTOT is maintained between 90°F and 100°F via heaters installed in the side of the tank.

Answer 138

→solenoid valve opens at 194°F with >1340 rpm →sprays condensate into the area to lower temps →happens mostly at low power with low steam flow available to cool area →condensate line taps off header before drain coolers →solenoid valve must be manually closed once temp restored, but will auto close when high temp clears if LP turbine inlet steam pressure ≥7 psia →separate MOV provided if solenoid valve insufficient to maintain temps →if exhaust temp can't be maintained <212°F, turbine is manually tripped

Answer 139

→3 pumps, A, B, & C →powered from uB1, uB2, uB3 →A and B auto start at 110 psig →C auto starts at 103 psig →during normal startup, Aux Lube Oil Pumps can be shut off around 1700 rpm because Main Oil Pump will have developed enough pressure

Answer 140

→powered from uD2 →auto starts at 32 psig bearing header pressure →only supplies bearings

Answer 141

→used to prime the Main Lube Oil Pump →turbine driven; supplied from main header

Answer 142

→auto starts at 510 rpm decreasing →auto stops at 540 rpm increasing

Answer 143

→3 lube oil coolers, 2 normally in service →cooled by TPCW →not normally shifted at power due to potential loss of lube oil and resulting Main Turbine damage

Answer 144

→located in HP turbine front pedestal →driven by gear attached to HP turbine shaft →provides all the lubrication needs of the Main Turbine / Main Generator once turbine reaches 1800 rpm →during normal startup, Aux Lube Oil Pumps can be shut off around 1700 rpm because Main Oil Pump will have developed enough pressure

Answer 145

→initially supplied from Aux Steam; as turbine power increases, turbine becomes self-sealing at ≈40% turbine power →Gland Steam supply header maintained at 4” WC via AOVs (supply and leakoff); valves fail as is on loss of air or power →leakoff directed to FW Heaters 5 and 6 →leakoff header from Gland Seals and leakoff from stop and control valves is directed to Gland Steam Condenser →Gland Steam exhaust uGS-0141, 0142 vented to PPV to ensure monitoring if SG tube leak →opening the emergency bypass to atmosphere on either the Main or Auxiliary Gland Steam Condenser will result in an unmonitored release to atmosphere

Answer 146

→3 dual stage pumps; stage 1 (LP) 114 psig, stage 2 & 3 (HP) 455 psig →normally 2 pumps in service; standby pump auto starts at 398 discharge pressure →powered from uB1, uB2, uB4 →red handswitches on CB-09 →114 psig control fluid supplies: →Main Turbine Control →tripping (protection) →HP Stop Valve actuators →455 psig control fluid supplies: →LP Stop Valve actuators →HP/LP Control Valves

Answer 147

→EHC fluid maintained at 131°F ± 9°F to maintain constant viscosity for proper operation of turbine valves →Fyrquel is used because of its high flashpoint (475°F)

Answer 148

→114 psig fluid directed to Startup Fluid Solenoids, Trip Block Valve and EHC Converter →used to control the overall hydraulic system.

Answer 149

→114 psig fluid supplied from the Startup Fluid Solenoids and directed to Test Valves, which are used to stroke test stop and control valves →essentially used to reset the system for power operation.

Answer 150

→114 psig fluid supplied from the Trip Block Valve and directed to the EHC Converter, Test Valves, Reset Valve, Trip Test Valves and HP/LP Stop Valves →used to open the HP stop valves and is the source for Secondary Fluid. →Trip Fluid also ports 445 psig fluid to open the LP Stop valves

Answer 151

→114 psig fluid coming from the EHC Converter and supplied to HP and LP Control Valves →used to control the HP and LP Control Valves by porting 455 psig fluid to actually operate the valves

Answer 152

converts electronic control signal from the controller to hydraulic pressure and amplifies the pressure before sending it to the control valves

Answer 153

→designed to prevent overspeed of turbine in event of load rejection →initiated by: →any power level, load rejection >290MWe per second →lower loads, IF actual load drops below 160MWe, AND actual load is 160 Mwe lower than load target →when circuit initiated, EHC will transfer from load control to speed control →speed control setpoint automatically set to value ≈ current actual load →reset C-7 as required once desired load is reached to prevent instrument failure from causing spurious steam dump actuation

Answer 154

Valves close to prevent overspeeding of the turbine. LP Control Valves only throttle down on large loss of electrical load to help overspeeding of the Main Turbine. Note: during normal operation at power, HP & LP Stop Valves are normally open with LP Control Valves fully open and HP Control Valves 50% open.

Answer 155

→total of 8 speed probes (6 used, 2 installed spares) →3 probes provide input to software overspeed →3 probes provide input to hardware overspeed →each of the six speed channels (3 for hardware overspeed, 3 for the software overspeed) is automatically tested once every 24 hours when turbine >40 rpm →tests verify that speed channels trip when speed is simulated >1980 rpm

Answer 156

if bearing temp >245°F, turbine must be tripped immediately

Answer 157

→simulated shaft mid-wall temp (in TSE) is used during Main Turbine Startup for "Soak Time" determination while at 500 rpm shaft speed →if mid-wall temp <120°F, turbine must soak for ≈20 minutes at 500 rpm prior to increasing speed

Answer 158

...the control system will drive the turbine back to 500 rpm automatically.

Answer 159

Hardware Overspeed Sub-system utilizes a set of three dedicated speed channels, each of which provides a trip signal to the Relay Protection System. Upon receipt of trip signals from any two of these speed channels, the relay logic de-energizes all three output relays which subsequently de-energize all three Turbine Trip Block solenoid valves, causing the turbine to trip.

Answer 160

→provided to keep Trip Solenoids energized while preventing actual trip signals from de-energizing the trip solenoid →should only be used during outages while on turning gear →only local manual trip available →revision keys block trip inputs into AGF cards →local manual trip still works

Answer 161

TR 13.3.33 Turbine Over Speed Protection At least one Turbine Overspeed Protection Sub-system shall be OPERABLE Applicable in Modes 1-3, except when the MSIVs are closed in Modes 2 and 3 →Provided to ensure that the Turbine Overspeed Protection instrumentation and the Turbine control valves are operable and will protect the Turbine from an excessive overspeed condition →Protection from Turbine excessive overspeed is required since excessive overspeed of the Turbine could generate potentially damaging missiles which could damage safety related components, equipment or structures.

Answer 162

→Hardware / Software Overspeed >1980 rpm →Low lubricating oil pressure (2/3) 25 psig (2 sec time delay) →Condenser A (or B) (2/3) 21" Hg AND 900 rpm →Excessive shaft displacement (2/3 probes) > ± 39 mils →Trip Fluid Pressure <29 psig → **P-14 Hi-Hi SG Level** 84% U1, 81.5% U2 (2/3); controlling level channel not used → **P-4** → **PW Head Tank Lo Level** (2/2) <78% (if turbine >1710 rpm) → **PW Lo Flow to Stator** (2/2) <610 gpm (if turbine >1710 rpm) → **PW Lo Flow to Rotor** (2/2) <580 gpm (if turbine >1710 rpm) → **PW Low Flow to Bushings (A, B or C)** (2/3) <23.3 gpm (if turbine >1710 rpm) → **PW Hi Temp** (2/2) >140°F (if turbine >1710 rpm) → **MSR A or B Shell Level Hi-Hi** (2/3) → **Main Condenser Vacuum** <21" Hg (if turbine >900 rpm) →Generator terminal box high water level (2/3 level switches) →MSR A or B Separator Level Hi (2/3) →Generator Lockout 86-1 →Loss of Field →TG Protection →SSPS / AMSAC →Manual from MCB →Manual Local PB →SI (indirectly; not a direct trip)

Answer 163

HP turbine

Answer 164

rupture disc at 1 psia

Answer 165

→AFW Auto Start, Train B →HELB, Train B (120,000 lbm/hr, 240 gpm) →valves fail closed on loss of power or air →powered from uED2-1 HELB & SGBD Isolation - "AH, PHART."

Answer 166

→Train A uED1-1 →Train B uED2-1 →fail closed on loss of power or air →failure of either train solenoid will result in closure of valves Valves Close On: →P - Phase A (train related solenoid) →H - HELB, Train A (120,000 lbm/hr, 240 gpm) →A - AFW auto start (train related solenoid) →R - Rad Hi SGBD Sample Rad Monitor (RE-4200), Train A →T - Temperature Hi >150°F downstream of SGBD HX, Train A HELB & SGBD Isolation - "AH, PHART."

Answer 167

→360 gpm per filter before resin beds →both filters normally in service

Answer 168

20 gpd primary to secondary leak with RCS activity equivalent to 1% fuel defect

Answer 169

→150 gpm →600 gpm

Answer 170

→Unit 1 - 104 gpm →Unit 2 - 35 gpm Difference is due to difference in SG material wear properties.

Answer 171

→flow after HX throttled to ~200 psig through PV-5180 →manually controlled at CB-08 →this is what starts/stops flow when aligning

Answer 172

Each line has three valves: →SGBD Isolation Valves (CIVs) u-HV-2397-2400 ("PHART" Valves) →HELB Isolation Valves u-HV-2397A-2400A ("HA" valves) →flow balancing valves HV-5175-5178

Answer 173

→not always required to be open for U1 since bottom blowdown rate is much higher →fail open AOVs →position indication from ZL lights on MCB →no auto functions

Answer 174

→SG pressure/temp rises (provides more steam to main turbine) →turbine control valves would close due to control circuit sensing that load has increased with no change in steam demand →amount of energy removed by Main Turbine remains the same; RCS temp would increase →Rx power would go down due to negative reactivity from temp increase →600 gpm flow ≈2.5% Rx power

Answer 175

→HX Outlet Relief SB-0040 lifts at 1200 psig →relief downstream of PV-5180 (controls flow) lifts at 280 psig (alarm at 159 psig) →both relieve to main condenser

Answer 176

→HX outlet filter Hi D/P 25 psid →cation resin trap Hi D/P 50 psid →mixed bed resin trap Hi D/P 50 psid

Answer 177

→when flow is directed back to HX (to Heater Drains via HDT-01), Condensate = SGBD flow (preferred) →when flow is not directed back to HX (going to Main Condenser, CST, or Turbine Bldg Sump), Condensate = 2x SGBD flow →maintain condensate temp 35°F below Heater Drain Tank temp →prevents flashing to steam

Answer 178

→outlet temp from SGBD HX should be maintained <130°F to protect demin resin from damage

Answer 179

Turbine Speed ≥1710 rpm **AND** one of the following: →Stator Flow Lo <650 gpm (2/2) →Rotor Flow Lo <580 gpm (2/2) →Phase Flow Lo <23.3 gpm (2/2 on any phase) →Inlet Hi Temp >140°F (2/2) →Head Tank Level Lo <78% (2/3)

Answer 180

→Normal Band 90-94% →Hi Level alarm 97% →Lo Level alarm 85% →Turbine Trip 78% Makeup is from Demin Water

Answer 181

Gas temp should always be colder than Primary Water temp to prevent condensation on the stator bars/current carrying components within the generator. →Primary Water temp should not fall below 77°F →Primary Water temp maintained ≥9°F above H2 temp →alarm when PW and H2 temps get within 5.4°F to alert that condensation is possible →alarm when temps get within 1.8°F to manually unload and de-excite the generator

Answer 182

→rotor →stator →terminal bushings →phase connectors

Answer 183

→delayed for 30 seconds →extends RCP coast down time →minimizes chance of Main Turbine overspeed

Answer 184

→TPCW →6 total, 5 normally in service (20% capacity each)

Answer 185

Fans are provided on each end of the rotor to provide motive force for moving the hydrogen.

Answer 186

→detects aerosols in hydrogen that are indicative of insulation breakdown →provides early detection of abnormal heating by →monitoring H2 environment for thermally produced particulates →interlocked with turbine speed →provides local alarms only at >1690 rpm

Answer 187

→Turbine trip →opens Generator output breakers 8000/8010 (U1) or 8020/8030 (U2) →Exciter Field Breaker opens →trips non-safeguards normal supply breakers to 6.9 kV from UTs →stops MT cooling →stops UT cooling →stops Isophase Bus Duct cooling →enables transformer fire protection deluge valves

Answer 188

The following events will initiate a generator lockout: **1. Total loss of field** 2. 345 KV system voltage less than 85% in conjunction with a total loss of field 3. Field ground 4. Pilot exciter short **5. Generator phase differential** 6. Stator ground **7. Distance protection/ Main transformer ground: the distance protection or a ground on either main transformer has a 1.4 second time delay; trips make up step 2 in the ground fault protection scheme** 8. Main transformer sudden pressure 9. Unit auxiliary transformer phase differential 10. Primary trip signal for generator output breaker 8000 or 8010 (8020 or 8030) 11. Volts per hertz **12. Generator-transformer phase differential** 13. Unit auxiliary transformer sudden pressure 14. Unit auxiliary transformer over current 15. Backup trip signal for generator output breaker 8000 or 8010 (8020 or 8030) **16. Generator negative sequence** 12% 17. Generator terminal box water level high or PW Head Tank Level <78%; coincident with a reverse power

Answer 189

→1 in service, 1 in standby →79 gpm PDP →Pump A powered from uB3-1 →Pump B powered from uB4-1 →normal seal oil pressure maintained at 12-15 psid →standby pump auto starts on low system pressure of 10 psid

Answer 190

→powered by uD2-2 →auto starts on low system pressure of 5 psid →if no seal oil pumps can be started within an hour, shut down the unit and reduce H2 pressure to 2 psig (per ABN-402) →recirc solenoid valves auto close on loss of seal oil pressure (<1.5 psid) to prevent H2 leakage

Answer 191

→provided to permit continued operation in the event of a cooler failure →louvers in the hot (lower compartment) and cold (exciter enclosure) air compartments are automatically opened by actuators admitting air from outside the exciter enclosure and discharging the hot air through openings below the coolers. →Setpoint: 122°F

Answer 192

→consists of the pilot exciter, the voltage regulator, the main exciter and the rectifier wheels →overall, we control DC amperage to the Main Rotor in order to control Main Generator output voltage Sequence: →AC - Pilot Exciter induces 3-phase AC in the Pilot Stator via permanent magnets mounted on the exciter shaft →DC - Voltage Regulator (TVR) provides variable DC current to the stator of the main exciter by rectifying/controlling 3-phase AC current from the Pilot Exciter using thyristor sets →AC - variable DC is then applied to the Main Exciter Stator, which generates 3-phase AC →DC - 3-phase AC from the Main Exciter is then sent to the Rectifier Wheels, which convert it to DC →AC - Rectifier Wheels then send DC to the Main Rotor to generate a magnetic field which in turn causes 3-phase AC to be generated in the Main Generator Stator Note: Rectifier Wheels, housed in their own enclosure, act as fans to draw air in at the ends and expel the warmed air to a compartment beneath the exciter.

Answer 193

...take speed to 500 rpm until operator resumes startup. If Upper TSE Margin stops the Main Turbine prior to 1765 rpm, the Main Turbine should immediately be lowered to 500 rpm.

Answer 194

...stop ALL running Auxiliary Oil Pumps and place in Auto.

Answer 195

→Pilot Exciter: permanent magnets send AC to TVR →TVR sends variable DC to Main Exciter stator →Main Exciter Stator sends AC to Main Exciter Rotor →Main Exciter Rotor sends AC to to Rectifier Wheels →Rectifier Wheels send DC to Main Generator Rotor (a.k.a. field winding) →Rotor rotation feeds AC to Main Generator Stator →Main Generator Stator feeds AC to electrical system grid

Answer 196

→unbalanced generator loading = unequal phase currents →can induce negative phase sequence current component →can result in localized heating of the rotor →Main Generator is capable of continuous operation with a negative sequence current of 5% →alarm comes in at 4% →Turbine Trip at 12%

Answer 197

When Instrument Air is not in use, it is physically disconnected, so there is no flow path into the generator.

Answer 198

→normal is SSW if CST Level <6%, unit is in ERGs, and with Shift Man approval →if SSW is unavailable, then provisions provided to fill CST with Fire Protection water

Answer 199

→FSBV closes on AFW Pump Start →U2 AFW connects to MFW before CTMT penetration, same line used by FSBV and AFW to feed SG

Answer 200

→designed to cool down RCS from 557°F to 350°F for RHR use →can provide normal cooling load up to 7% RTP

Answer 201

→response to ATWT →AFW is required to be >860 gpm to ensure sufficient decay heat removal →normally 460 gpm is sufficient since normal S/D decay heat is lower

Answer 202

TDAFWP is tripped on the MCB to prevent overfeeding the SGs when a SFGDs Bus is deenergized at the RSP.

Answer 203

570 gpm at a maximum developed head of 1370 psig

Answer 204

→minimum flow recirc line with orifice 200gpm →close on >200gpm →open <227gpm →fail open on loss of air or power →normally maintained open in standby →common line back to CST →valves have an accumulator to allow 2 strokes for 30 mins (from same air accumulator as MDAFW Pump flow control valves)

Answer 205

Each associated flow control valve provided with a safety class air accumulator sized for five full cycles, plus leakage and steady state consumption for 30 minutes (same accumulator as recirc valves).

Answer 206

→normally open AOVs →fail open on loss of air or power →PV‐2453A & 2453B for train A to SGs 1 & 2 →PV‐2454A & 2454B for train B to SGs 3 & 4 →air accumulators for 5 full cycles for 30 minutes (shared accumulator with pump min flow valve) →on start of MDAFW Pumps, M/A stations trip to auto and go 100% open →after 10 sec time delay, manual operation can be selected →each feed line has an orifice to limit flow to 700 gpm

Answer 207

→1145 gpm at 4075 rpm and a maximum developed head of 3236 ft (1433 psig) →overspeed occurs at 4750 ± 50 rpm (116% rated speed) →overspeed mechanism will reset itself at 3000 rpm →Trip & Throttle Valve will need to be locally reset →on loss of air or electrical power, turbine speed governor will fail to max speed

Answer 208

→powered from 125VDC uED1‐1 →local panel shows valve position T&TV and turbine speed →SI on Train A removes control power to local panel →prevents the following remote indication and control (on MCB): →indication of turbine speed →turbine overspeed light indication →no annunciator for turbine overspeed →T&TV position indication →cannot trip the turbine from the control room →turbine will still start and come up to speed, just without indication →can locally trip pump OR close steam supply valves from MCB to stop the turbine →power to local control panel can be restored after SI on Train A is reset by depressing OPEN push button 2452H on CB‐09 →this restores full functionality of the turbine

Answer 209

Per ABN-305, once TDAFWP trip issue is fixed u-SK-2452A is adjusted to 0% prior to opening the T/T valve and at this time the speed will go to 2000 rpm and can be adjusted by the operator

Answer 210

Each associated flow control valve provided with a safety class air accumulator sized for five full cycles, plus leakage and steady state consumption for 30 minutes

Answer 211

→each SG has ONE handswitch that controls BOTH the MDAFW & TDAFW MOV isolation valves →MOVs powered from opposite train from FCVs →opposite train power supplies ensure that we can still isolate flow to an SG on loss of one train

Answer 212

→500,000 gal tank →53% (244,000 or 249,100 gals, depending on reference given) reserved for AFW per revised TS 6-30-2011 →10-inch line to suction of both MDAFW pumps →a second 10-inch line to suction of TDAFW pump →CST minimum volume (53%) ensures that water is available to maintain the RCS in Hot Standby for 4 hours followed by a cooldown to 350°F at a rate of 50°F/hr for 5 hours

Answer 213

BLA →B - Blackout-OL opens MS supply valves #1, B Train; #4, A Train →L - Lo-Lo Level 38% U1, 35.4% U2 in 2 SGs (2/4 Level Transmitters) →A - AMSAC "There's no T in turbine."

Answer 214

BLAST →B - Blackout (Train related) →L - Lo-Lo Level 38% U1, 35.4% U2 in 1 SG (2/4 Level Transmitters) →A - AMSAC →S - SI in conjunction w/ SI Sequencer →T - Trip of both Main Feed Pumps

Answer 215

→SG Blowdown isolates →SG Sampling isolates →CST discharge valves HV-2484/2485 (Makeup/Reject Valves) close →Split Flow Bypass Valves (U2 only) close →Motor Driven AFW flow control valve trip to Auto 100% open

Answer 216

1) Manually reset the overspeed trip linkage by physically repositioning the trip linkage. The overspeed device plunger mounted on top of the turbine bearing casing should drop back into the plunger housing. 2) Depress clutch lever to engage handwheel. Clutch must remain depressed through steps 3 and 4 below. 3) Turn handwheel CW until the latch mechanism is fully engaged. 4) After latch mechanism is fully engaged, turn handwheel CCW until actuator is fully up. 5) Release the clutch lever. Note: the turbine on the TDAFW pump must be at rest for 15 seconds before resetting governor speed setting

Answer 217

→130 gpm on mini flow line →limited to 20 min to prevent pump damage

Answer 218

→TDAFW speed control and BOTH steam supplies →both MDAFW pump breakers →FCVs to all four SGs from MDAFW and TDAFW pumps →M/A stations on RSP set in Auto allow MCB operation of FCVs from MDAFW and TDAFW Pumps to all 4 SGs

Answer 219

Power Excursion. We send cold water to the SGs, which needs to be heated up, raising Rx power without additional steam demand. Operator response is to lower load by 50 MWe.

Answer 220

→we remove fuses that send MFP trip signals to start MDAFW Pumps →Train A comes through BOP Aux Relay Rack #1 →Train B comes through BOP Aux Relay Rack #2

Answer 221

→supplied by Main Steam lines #1 & #4 before MSIVs →normally closed AOVs with accumulators to allow isolation on loss of air →accumulators allow isolation within 30 mins + 7 more hrs to keep valves closed →valves fail open to ensure turbine acceleration to rated speed in 85 sec

Answer 222

Do not exceed 800 gpm flow on any MDAFW Pump.

Answer 223

Three AFW trains shall be operable in Modes 1-3. If three AFW trains are inoperable: →initiate action to restore one AFW train to operability immediately. →LCO 3.0.3 and all other LCO Required Actions requiring Mode changes are suspended until one AFW train is restored to operable status (LCO 3.0.4b is NOT applicable) Note: SR 3.7.5.2 verifies developed head of each AFW pump. For TDAFW Pump, it is NOT required to be performed until 24 hours after ≥ 532 psig in the steam generator.

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