ML20245H947
| ML20245H947 | |
| Person / Time | |
|---|---|
| Site: | Nine Mile Point  |
| Issue date: | 02/28/1989 |
| From: | NIAGARA MOHAWK POWER CORP. |
| To: | |
| Shared Package | |
| ML17055E542 | List: |
| References | |
| NUDOCS 8903060104 | |
| Download: ML20245H947 (294) | |
Text
{{#Wiki_filter:- 7 , L 4 NIACARA MOHAWK POWER CORPORATION NINE MILE POINT UNIT 2 POWER ASCENSION TEST PROGRAM FINAL STARTUP REPORT REVISION 1 FEBRUARY 1989 e
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5 '" FINAL STARTUP REPORT Table of Contents PAGES LIST OF TABLES iv. LIST OF FIGURES viii-ABSTRACT ix.
1.0 INTRODUCTION
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' 1.1
. Purpose 1 1.2 Plant Description 1 1.3 Startup Test Program Description 2 t
5 2.0
SUMMARY
OF POWER ASCENSION TESTING 11 , i 2.1 Schedule Summary 11 2.2 Power. Ascension Progress 11 2.3 Startup Test Program Reactor Protection System Actuation History 11 3.0
SUMMARY
OF TEST RESULTS 22
~ 3.1 N2-SDT-1, Chemical and Radiochemical 23 3.2 N2-SUI-2, Radiation Measurements 44
' 3.3 N2-SUT-3, Fuel Load 47 2.4 N2-SUT-4, Full Core Shutdown Margin Demonstration 51 3.5 N2-S"JT-5, Control Rod Drive System 53 3,6 N2-SUT-6, Source Range Monitor Performance 59 3.7 N2-SUT-10, IRM Performance 61 3.8 66 N2-SUT-11. LPRM Calibration Test 3.9 N2-SUT-12 APRM Calibration 68 L
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i FINAL STARTUP REPORT Table of Contents (Cont'd) PAGES 3.10 N2-SUT-13, Process Computer 71 3.11 N2-SUT-14', RCIC System 79 3.12 N2-SUT-16, Selected Process Temperatures and Water Level Measurements 87
, 3.13 N2-SUT-17. System Expansion 95 3.14 N2-SUT-18, TIP Uncertainty 102 3.15 N2-SUT-19 Core Performance 106 3.16 N2-SUT-20, Steam Production 109 3.17 N2-SUT-22, Pressure Regulator 114
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3.18 'N2-SUT-23, Feedwater System 122 3.19 N2-SUT-24, Turbine Valve Testing 139 3.20 N2- SUT-25, Main Steam Isolation Valves 142 3.21 N2-SUT-26, Relief Valves 147 3.22 N2-SUT-27, Turbine Trip & Generator Load Rejection 150 3.23 N2-SUT-28, Shutdown From Outside the Main Control Room 160 3.24 N2-SUT-29, Recirculation Flow Control System 164 3.25. N2-SUT-30, Reactor Recirculation System 180 3.26 N2-SUT-31, Loss of. Turbine Generator and Off-site Power 189 3.27 N2-SUT-33, Drywell Piping Vibration 195 3.28 N2-SUT-35, Recirculation System Flow Calibration 206 3.29 N2-SUT-70, Reactor Water Cleanup System 215 3.30 N2-SUT-71, Residual Heat Removal System 219 3.31 N2-SUT-74, Of f-gas System Performance 225 3.32 N2-SUT-75, Drywell Cooling System 232 . w
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s' I' FINAL STARTUP REPORT l.' Table'of Contents (Cont ' d ) '- PAGES
- i. . 3.33 N2-SUT-76, ESF Area. Cooling 240
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- 3.34 N2-SUT-77, Balance of. Plant Piping Vibration '244 3.35 N2-SUT-78,' Balance of Plant System Expansion 253 3.36' N2-SUT-79,-Reactor Internals Vibration Measurement' 275 q
('( -3.37 N2-SUT-80, Emergency. Recirculation Ventilation' 280. 3.38' N2-SUT-81,:Drywell Penetration Cooling '282 e.
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,.n d FINAL STARTUP REPORT Tahle of contents (Cont'd)-
LIST OF TABLES PAGES s 1.2-1 :Nine Mile Point Unit 2 Power' Station Principal Plantt Parameters 6 1.3-3~ -Test condition (TC) Region Definitions .9 2.1-1 Power Ascension Test Program Schedule Susunary '12 2.2-2' Testing Dates 15 2.3-11 Nine Mile Point Unit.2 RPS Acutations and Associated Outages, and. Planned Shutdowns- 19-
-'3.1-1 Water Chemistry Data. 25
- 3.1 -. Gaseous and Liquid Effluent Data 35
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3.1-3 Chemical and Radiochemical' Test Exception Sumanary. 38 46'
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3.2 Radiation Measurements Test Exception Summary \t 3.3-1 . Fuel Load Test ~ Exception Summary 501
'3.5-1" Four Selected Rod Scram Time Results 57' 3.5-2 control Rod Drive System Test Exception Sununary 58 3.7-1 Overlap Demonstration Data 64 3.7-2 IRM Performance Test Exception Summary 65
' 3.8- 1 LPRM Calibration Test Exception Susunary 67 L 3. 9-1.- APRM Calibration Test Exception Summary 70 3.10-1 Process' Computer Test Exception Sucunary 77-3.11 Susunary of RCIC System Testing- 83 3.11-2 Final RCIC Control System Settings 84
. 3.11-3 RCIC System Test Exception Summary ,
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,3.12-1 Stratification Test Results 89 3.12-2 Water' Level Endpoint Calibrations 90 .'
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FINAL STARTUP REPORT l Table'of Contenta (Cont'd) l LIST OF TABTJM (Cont'd) PAGES 3.12-5 Selected Process Temperatures and Water Level Measurements l Test Exception Summary 094 3.13-3 Thermal Expansion Acceptance Criteria /Results 100 3.13-4 System Expansion Test Exception Summary 101 4 3.14-1 Tip Uncertainty Symmetric TIP Pairs 104 3.14-2 Mathematical Relationships for TIP Uncertainty 105 3.15-1 Core Performance Evaluation 108 3.16-1 Two Hour Average Parameters 111 3.16-2. Actual vs. Warranted Parameters 112 ,
- 3.16-3 100 Hour Run Average Values 113 3.17-l' Pressure Regulator Test Matrix 118 3.17-2 Pressure Controller Settings 119 3.17-3 -Pressure Regulator Test Results 120 3.17-4 -Pressure Regulator Test Exception Summary 121 3.18-1 -Feedwater System Small Step Change Test Results 133 3.18-2 Feedwater System Large Step Change Test Results 134 3.18-3 Feedwater System Loss of Feedwater Heating 135 3.18-4 Feedwater System Feedwater Pump Trip Summary 136 3.18-5 Feedwater System Feedwater Runout Results 137 - 3.18-6 Feedwater System Test Exception Summary 138 3.19-1 Turbine Valve Testing Test Exception Summary 141 3.20-1 Main Steam Isolation Valves closure Times 145 3.20-2 Main Steam Isolation Valves Sequency of Events for MSIV Full Closure TC 6 146 ,
Relief Valves Test Exception Summary 149 Mu 3.21-1 3.22-1 Turbine Trip Test Exception Summary 158 8"
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FINAL STARTUP REPORT Tahle of Contents:(Cont'd) LIST OF TABLES (Cont'd)' PAGES 3.24-2 TC 1 Test'Results.- Position Loop 171
- 3.24-3 TC 3, 6 Test Rasults - Position Loop- 172-3.24-4 TC 3, 6 Test Results - Flow Loop. 174' s
, 3.24-5 .TC 3, 6 Test Results'- Flux Loop 175 3.24 Recirculation Flow Controller System Settings .176
, 3.24 Recirculation Flow Control Test Exception Summary. 177.'
3.25-4. Reactor Recirculation Test Exception Summaary 188 3.26-1 Loss of Off-site Power Sequence of. Events .194 , 3.27-3 Drywell Piping Vibration Steady State Vibration Limits 200 3.27-4 Drywell Piping Vibration Operating Transient Vibration Limits 201 , - 3.27-5 Drywell Piping Vibration Test Results 202.' 3.27-6 Drywell Piping Vibration Test Exception Summary . 205
-3.28-1 Final Recirculation System Flow Calibration Date 208 3.28-6 Rec'irculation System Flow Calibration Test Exception
- Susanary 213 3.29-1 Reactor Water Cleanup System Test Results 218 3.30-1 Residual Heat Removal System Final Controller Settings 223 3.30-2 Residual Heat Removal System Test Exception Summary 224 3.31-1 Off-gas System Design Parameters and Results 228 3.31-2 Off-gas System Test Exception Summaary 230 3.32-1 Drywell Cooling System Test Exception Sununary 237 i
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FINAL STARTUP REPORT 3
-Igble of Contents (Cont'd)'
LIST OF TART.FR (Cont'd) JAGES
'3.33-1 .EST Area Cooling System Test Exception Summary 242 3.34-1 BOP : Piping Vibration Test Description - 246-3.34-2 BOP Piping Vibration Test Exception Summary 250.
3.35-1 Systems Tested During TC HU 256
.3.35-2 Expansion Testing During TO HU. '257 3.35-3 Expansion Testing During TC 1. TC 2, and TC 6 259 3.35-4 System Expansion Test Exception Summary 264
'3.36-1 Reactor Internals Vibration Maximum Vibration Stress 278 ,
a-3.36 Reactor Internals Vibration Measurement Test-Exception Summary 279-3.37-1 Reactor Building Emergency Recirculation Ventilation System Performance. Test Exception Summary 191
. Penetration Cooling Test Results 284
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\ L FINAL STARTUP REPORT Table of Contents (Cont'd) LIST OF FIGURES PAGES 1.3-1 Power Ascension Test Organization 7 1.3-2 Power Ascension Shift Test Organization 8 1.3-4 Plant Operating Control Map 10 2.2-1 Power Histogram 13 3.1-4 Off-gas Retreatment Monitor Calibration 42; 3.12 Core Flow Vs. Delta Level 92 3.12-4 Steam-Flow Vs. Delta Level 93 3.13-1 Recirculation Line "A" Transducer Location 98 , 3.13-2 Recirculation Line "B" Transducer Locations 99 3.24-1 Trade 0ff Curve for Step Sizes 0.2% to 0.5% 170 3.25-1 Reactor Recirculation System Core Flow Vs. Average FCV Position 185 3.25-2 Reactor Recirculation System Loop "A" Drive Flow Vs. FCV "A" Position 186 3.25-3 Reactor Recirculation System Loop "B" Drive Flow Vs. FCV "B" Position 187 . 3.27-1 Recirculation Line "A" Transducer Locations 198 3.27-2 Recirculation Line "B" Transducer Locations 199 3.28-2 TC 3 Loop "A" Normalized Flow Distribution 209 3.28-3 TC 3 Loop "B" Normalized Flow Distribution 210 3.28-4 TC 6 Loop "A" Normalized Flow Distribution 211 3.28-5 TC 6 Loop "B" Normalized Flow Distribution 212 I
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AESTRACT The -Nine Mile Point Nuclear Station ' Unit 2 Power Ascension Test Program began on October 24, 1986 with the conunencement of fuel loading checks. The test program was of ficially completed . March 31, 1988. The test program includes s tatic and dynamic performance tests of the reactor, turbine-generator, j related auxiliary systems and balance of plant systems. Test results were compared to acceptance criteria, and where deviations were identified, a resolution was obtained or corrective actions were implemented. The FSAR, Chapter 14 Tests described are in accordance with Amendment 28 and the following Safety Evaluation Reports 87-021, 87-078, 87-113, 87-126, 87-131, 87-140, 87-143, 88-004, and 88-019.. 1 h
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1.0 INTRODUCTION
1.1 Purnome .l The purpose of this report is to provide a summary of the Power Ascension. Test Program conducted on the Nine Mile Point Nuclear
. Station - Unit Two. This report is intended to satisfy-the reporting l requirements .of Technical Specification Sections 6.9.1.2 and 6.9.1.3 l concerning the startup report. Included in this report are
-descriptions of the general plant, the startup test . program and . a q comparison of actual test results with expected results. '
1.2 ' Plant Description The Nine Mile Point Nuclear Station - Unit 2 owned by Niagara Mohawk Power- Corporation E (Applicant) - and it co-owners (Central Hudson . Gas I and Electric Corporation, Long Island ' Lighting Company. - New York State Electric and Gas Corporation,, and Rochester Gas and Electric i Corporation) is located .on a 900-acre site, owned by Niagara. Mohawk Power Corporation, situated on the southeast shore of Lake Ontario, Oswego County, NY, approximately 6.2 miles northeast of the City of Oswego.' Unit 2 .and support ' facilities occupy about 45 acres, : and share the , site with the existing Unit -1 which has been in commercial' operation since 1969. The Nine Mile Point site is adjacent to the James A. FitzPatrick Nuclear Power Plant owned by. the New York Power Authority; Unit 2 is located 900 f t east of Unit 1, about 2,350 f t west of the James ,A. FitzPatrick Plant. Unit 2 employs a Nuclear Steam Supply System (NSSS) consisting of a single cycle, forced circulating boiling water reactor (BWR). The plant rated core thermal power level is. 3,323 MWt corresponding to a net electrical output of 1,080 MWe. The containment design employs the BWR Mark II concept of over-under pressure suppression with multiple downcomers connecting .the. reactor drywell to- the water-filled pressure suppression chamber. The primary containment is a stainless steel-lined, reinforced concrete enclosure housing the reactor and the suppression pool. The NSSS supplier is the General Electric Company. The balance of the plant is designed and constructed by Stone & Webster Engineering Corporation. Other principal plant parameters are presented in Table 1.2-1. I
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Startuo Test Program Description- ,
. 1. 3.1- Overview of Prorram The Nine Mile Point '- Unit. Two Power Ascension Test Program included pre-fuel load activities, fuel loading. - heatup and power ascension testing. The program tested the reactor, turbine-generator, related auxiliary systems and balance of plant systems. . . This testing was in accordance with the startup. test descriptions given in Section 14 in Unit Two Final Safety Analysis Report (FSAR)
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the Nine Mile Point (including changes made in accordance- with the ~1icense condit1ons),- and Regulatory Guide 1.68. 1.3.2 Power Ascension Organization Thh Power Ascension Organization is shown in Figure 1.3-1.- The Shift Test Organization'is shown in Figure.1.3-2.-
' 1.3.3 Test Plateaus The Startup Test Phase commences with preparation for. fuel ' loading and extends through the Power Ascension Testing Program. The startup test phase is divided into testing plateaus. The plateaus are defined as fo11ews: _
Test' Plateau - Covers preparation for fuel loading, fuel Open Vessel loading, and open vessel testing belew 1%' rated-core thermal power. Test Plateau g- Covers all testing during the initial nuclear Heat Up heatup to rated temperature and pressure (1-5% power). Test Plateau 1 - Covers ~ all testing at test condition 1 (5-20% power) Test Plateau 2 - Covers all testing at test condition 2 (between the 50 and 75% load lines) Test Plateau 3 - Covers all testing at test condition 3 (between the 50 and 75% load line) Test Plateau 4 - Covers all testing at test. conditions 5 and 6 (between the 95 and 100% load lines except during . natural circulation testing)
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1;3.3 '(Cont'd) V , Test Plateau - Covers the nuclear steam supply system Warranty.Run
' warranty demonstration which may be performed;... .
I concurrently or sequentially with Test Plateau 4. Plateau procedures are established i to define - and control; testing to be done within; a -particular test.~ condition or. set of- Ltest conditions. A: test: condition -(TC);is' defined as a reactor operating range - of core thermal power versus. core flow rate. The various:TC's
.are shown on Table 1.3-3 and the power / flow map (Figure 1.3-4).- ,
Test Plateau Review' Ai test plateau review was conducted af ter. the. complet' ion of testing g .in each _ test plateau . prior to - receiving . authorization, to commence l
< Jpower. ascension. testing in the next plateau.~. The reviewLincluded all:
. test results,1 test exceptions, and procedure changes.__ The review was-
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performed by the Power Ascension Manager.. the Site Operations Review Committee ~ (SORC), the Station Superintendent :and the ' General'. Superintendent. 1
- 1. 3. 4 - criteria For Test 4ne To assist'in.the evaluation of proper plant performance from the test
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. '. results obtained. . a set 'of ' criteria for each test- was' developed. - These criteria are a result of a combination . of . factors . such 'asi safety -analysis assumptions, engineering = expectations and contractual comunitments . Level 1 criteria are. based on - safety considerations , while- Level '2 criteria' are based on performance' considerations. Definitions of these TLevel l ' and Level'~2~ criteria .and required actions in the event of a violation are defined as follows: '
. 1.3.4.1 Level'1 criteria If a Level 1_ test criterion is not satisfied, the plant is placed in a hold condition that. is judged _ to: be satisfactory and s'afe,- based =
upon prior ' testing. Plant. operating . or . test procedures' or the Technical Specifications may guide the decision -on the direction taken. Startup_ tests consistent with this holdi condition may be' continued. . Resolution of' the problem is immediately _ pursued by appropriate equipment adjustments or through engineering support . by: off-site personnel if. needed. Following resolution, the applicable test portion is normally repeated to verify that the Level 1 requirement is satisfied.-
- 1.3.4.2 Level 2 criteria
'If a Level 2 test criterion 'is . not satisfied, plant operating or startup test plans are not necessarily altered. The limits stated in this ' category are usually associated with expectations of system
, transient performance whose characteristics 'can be improved by equipment adjustments. An investigation of the related adjustments, .
as well as the measurement and analysis methods, is initiated. 'l Following resolution, the applicable test portion is repeated to g verify that the Level 2 requirement is satisfied, if required.
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~ If! a certain controller-related: Level 2 criterion is not satisfied- 1
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af ter. a - reasonable effort,' then the ' control engineers may - choose ' to
- document - that result with an explanation . of- their recommendation. J This . report discusses: alternatives of= action, -as well- as :the
' concluding recommendation so that it- can be evaluated by all, related parties.
1 i i 1.3.5. Conduct of Teat 4ne j i b 1.3.5.1 Review and Accroval The Site Operations Review Committee (SORC),. the Jon-site ; safety; review conunittee , was responsible for _ reviewing ' test' - procedures,_ l changes, results, deficiencies, plant holds,. and. test. plateau i escalation, as well as reconsnending ! approval of _these- items; as- q appropriate during. the Power Ascension Test Program. The Power l Ascension Manager approved test results, resolutions and subsequent 1, actions of ' all result deficiencies. The Nine . Mile Point Nuclear Station 1 General <-Superintendent approved initiation 'of .the test-program,1 escalation in_ power to the next test pisteau, and plant test- ( hold conditions. -{
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The' Safety Review and _ Audit Board (SRAB) . 'is responsible for. independent review of all test procedures and - results of the4 Power Ascension Test Program. To date, SRAB 'has reviewed the. test. procedures and the changes. Test results for : the _ open vessel and
-'heatup , ' plateaus . have also been reviewed. In '. addition,.SRAB has
]q reviewed :SORC meeting minutes,, reports, .and correspondence with the j
- NRCLregarding the Startup Test Program. j f
.I 1.3.5.2 .. Tent Procedures f Startup test procedure preparation, procedure _ and results ' approval',
procedural changes, . test conduct and test exceptions were governed by the Plant's Administrative Procedures. Inputs to specific startup , , test procedures included the General Electric .Startup Test- -
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' Specification, other - vendor design specifications and the" Nine Mile Point Nuclear Station - Unit 2 Final Safety Analysis Report.
1.3.5.3 Test Exception A test result which did not satisfy an acceptance criterion, was identified-.as a Test Exception, and was documented on a Test Exception Form. Resolution of the deficiency was documented on the form and approved by the Power Ascension Manager. Following , resolution, the applicable test section(s) were repreformed to verify j that the acceptance criterion was satisfied, or accepted as-is, as ! appropriate. The SORC reviewed and approved all exceptions during the results approval process.
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. 1.3.5.4~ Test Data DataRused . in i tiie - evaluation of ' the individual" startup # tests. were..
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4 obtained> primarily from plant instrumentation (recorders, , meters) . l-the plant'. process computer the General ElectricG Transient J Analysis Recording System - l -(GETARS-1) and special test equipment. All' of these were used- to obtain ! steady state- data. . The processi computer. was utilized' primarily fori evaluation of . thermal. power ' and thermal . - l limits ? whereas L the.. GETARS 1 computer ' was employed mainly :. for ~ system .
- performance' demonstrations _and plant response to transients.
? The ' GETARS high speed digital ~ data acquisition '. system can directly 1 digitize measurements every . millisecond : allowing .- data to = be isampled and recorded-in rea11 time at'1000 samples.perlsecond per. channel.- In:
' addition to the . GETARS used ' for data recording,. a~ second GETARS was used - to . perf orm data reduction, statistical analysis', and; scram time p: analysis..
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l q '_.:f: , [ TARLE 1.2-1 A NTNE MILE POINT IINIT 2 POWER STATION PRINCIPAL PLANT PARAMETRES: PARAMETER y.ALilg i NSSS Design BWR 5 Rated Core Thermal Power'(MWt) .3323.
' Rated Core Flow (M1b/hr)' 108.5
- Rated. Reactor Dome Pressure (psia). 1020 14.267 7
, Rated Steam Flow (M1b/br)-
p , Rated'Feedwater F16w (M1b/hr) 14.235 Rated!Feedwater Temperature (deg. F) .
, 420-i -Vessel Diameter.(inches) 251-
' Number of Control Rods. 185- ,
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. Turbine Control Valve' Mode Full Arc
- Number of Turbine' Control Valves ' 4[
p -Turbine. Bypass Valve. Capacity.(% NBR) . 25 Number of Bypass Valves. 5 Safaty Relief Valve (SRV) Capacity'(%NBR) 113.8 @ 1212 psig Nu:aber of SRVs 18 Recirculation Flow Control Moder 2 speed Recirculation' Pump Motor with Variable Flow 1 Control Valve Control Feedwater Flow Control Mode: 3 Motor-driven pumps with 3 Variable Feedwater-Regulation Valves 4
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TABLE 1.3-3 TEST CONDITION (TC) REGION DEFINITIONS
- Test Condition (TC) Power Flow Man Ration and Notes L
1- Before or af ter main. generator synchronization from 5 to .20 percent' thermal power and operating on recirculation pump low frequency power supply. . 2 Af ter main generator synchronization from 50_ to 75 percent control rod lines, at or below; the analytical lower limit of' Master Flow Control Mode and with the lower power comer within bypass valve capacity. 3 From 50 to 75 percent control rod lines above 80 percent. core flow, and within maximum allowed recircuintien ' control valve position. 5' From: ths.100% load line to the 95% load line and between natural circulation core flow to $ 5% above the. analytical-lower limit of master power flow . control, J Also from the , 100% load line to the 80% load line at natural circulation l core' flow. 6 With .0 ' to -5 percent of rated 100 - percent thermal power, . and within 0 to -5 percent of rated 100 percent core flow rate.
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SUMMARY
OF POWER ASCENSION TEST PROGRAM-2.1 Schedule S - -rv The Nine Mile. Point Unit 2 Power Ascension Test Program began on
.0ctober. 24, 1986 with the preparation for fuel loading ' and ..was completed March 31, 1988. Commercial Operation was declared on March
-11.-1988. ]
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The overall power ascension schedule performance is shown on Table 2.1-1. 2.2 Power Ascension Proeress
. A historgram of the power generation history during the . test program j is given on Figure 2.2-1. The completion dates .of -all tests. ='
. performed in the various test conditions are given in Table 2.2-2. i -
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- 2.3 Startup Test Proeram Reactor Protection System Actuation Historv
( Table ' 2.3-1 provides a brief description of each RPS Actuation (i.e. -{ an RPS trip) including the date, scram report number, classification,
,j plant power level, duration of. associated outage and reason for the l actuation. The table also provides a brief description of each planned shutdown. The classification codes are as follows: -1 i
A - An'RPS Actuation that occurred with control rods already fully inserted. g S - An unplanned scram. D PSD - A planned shutdown prompted by the need to correct equipment deficiencies. 1 PS - A planned scram to satisfy startup test program or j surveillance program requirements. The RPS Actuations that occurred between fuel loading and completion ) of the warranty run breakdown as follows: A- 13 events, S - 10 events, PSD - 5 events and PS - 5 events.
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1 i IABLE 2.1-1 , I POWER ASCENSION TEST PROGRAM SCHEDULE
SUMMARY
Test Outage Restart Milestone DAZA DAIA DAIA Comnletion Dates Fuel Load -14 189 0 November 15, 1986 l Initial Criticality- - - - - May 23, 1987 Heatup Test. Plateau. 20 27 10 July 19, 1987
- Rated Pressure Achieved. -
- - June 24, 1987 Initial Generator -
- - August 7, 1987 Synchronization
. Test Condition 1 17 '11 4 August 14, 1987 n Test Condition 2' 25 '39 10- November 2, 1987 .
Test Condition-3 34 39 4 . January 18 1988 Test-Condition 5 6 12 5 February 10, 1988
. Test Condition 6 14 9 6 March 10, 1988 Full Power First Achieved - - - February 25, 1988 Declaration of Commercial - - - March 11, 1988 Operation Warranty Run _.ji ___6 9 April 4, 1988 Total 136 332 48 Test Days - Days spent at required test conditions.
Outage Days - Days shutdown in a test condition or between milestones. Restart Days - Days spent achieving required plant conditions following , startup from a previous outage. ) 1 1
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- I, . .r 2 Test Number- TC- Start Datej Compietion Date
- s 1: OV 10-24-86 10-31-86. 1
, HU 6-15-87 l 7.-02-87.:- -{
l' 8-07 ~
'8-14 3 2 8-26 10-20-87i 3 11-05-87J .1-16-88 5 ::1-19-88
. 1-21-88 '
i
-6 2-26-88 3-11 - -
2 ' OV 10-27-86 11-18-86 ;; HU' '6-24-87 7-06-87. 1
-1 8-04-87 . 8-10-8 7.-
2- 8-25-8 7' :10-19 .3 11-05-87 11-10 6- 2-24-88 3-10-88
+ 3. OV 11-02-87 ~11-15-86 4' HU 5-23-87' 5-23-87 L5- OV . 11-09-86 1-20-87 . . .
'HU 5-26-87 7-09-87
- -1 8-09-87 8-09-87 2 8-24-87. 10-13--87
.6 .2-15-88 3-07-88
~6 HU - 5-23-87 '5-23-87:
10 HU- :5-23 5-24-87 1 8-02-87 9-14-87 11 1 8-01-87 8-01 ' , 2 9-02 '10-07-87 3 11-08-87 11-09-87J 6 2-26-88 2-27-88 l 12 HU 5-24-87 5-24-87 1 7-31-87 8-01-87: 2- 9-02-87 9-02-87. 3 11-08-87 11-09-87
- l. 5 1-18-88 1-18-88 16 2-26-88 2-27-88 13 OV 12-07-86 12-09-86
<- HU. 6-25-87 7-07-87:
1 7-31-87 8-11-87 2 8-27-87 10-08-87. l .- 3 11-03-87 1-17-88 6 2-26-88 3-11-88
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- u. TABLE 2.2-2 TESTING DATES (Cont'd) l
' Test Number -TC Start Date- Completion Date =j 14L HU 6-27-87 7-05-87. "
1- 7-20-87. 8-08-87 2 '8-21-87 8-21-87 16 HU 5-22-87 7-08-87 2 9-02-87 9-02-87' 3 11-08-87 .1-14-88 '! 5 1-20-88 J2-10-88 6 2-11-88 3-02-88 '] 17 HU 5-19-88 7-07-88 18^ 6 2-14-88 2-19-88
. 19 1 8-04-87 8-05 2 9-02-87 9-02-87
- 3. 11-09-87 11-09-87
'S 2-08-88 2-09-88' 6 2-26-88 3-02-88
~
20 W 3-21-88 4-04-88 22 l' 8-03-87 8-04-87 2 10-09-87 10-10-87 3 11-11-87 1-03-88 5 1-18-88 1-23-88 6 2-20-88 3-10-88 23 1 8-02-87 8-03-87 2 10-22-87 1-13-88 3 1-04-88 1-14 5 2-08-88 2-10-88 6 2-11-88 3-09-88 24 5 1-19-88 1-19-88 6 2-13-88 3-01-88 25 HU 7-05-87 7-07-87 3 11-03-87 11-03-87 6 2-15-88 2-23-88 26 1 8-04-87 8-05-87 27 2 10-10-87 10-10-87 6 3-5-88 3-11-88 1 l 28 1 8-09-87 8-09-87 l l 29 1 8-05-87 8-05-87 . 3 11-04-87 1-10-88 6 2-11-88 3-11-88 mm! l
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r ?. Test Number TC Start Date- Completion Date' M -30 -2: 10-10-87 10-10 ,, L3 11-04-47' ;1-14-88' 2-09-88
'5' 2-09 # 6'- 2-21-88; 3-10 , ,
- 31
'2 10-12-87. 13 -y ,
33- 1-8-05-87s ?8-05-87 3- 1-12-88 'l-14-88 h '5 :1-18-88; 1-18-88 6 2-16-88: 3-08-88
' ~
35 3- 11-05-87 111-08-87 g , 6 2-24-88 3-10-88 70' 2' 10-03-87' 10-08-47 71 HU 8-05-87 8-06-87 X ." 1 10-20-87'- 10-30-87 6; 16-88 3-07-88 _ p J74. HU c11-08-87 11-16-87 1' L7-29 8-05 2- 10-09-87' 10-14-87' 3 11-08-87 11-16-87
- 6. 24-88 3-10-88 75' 'HU 5-24 6-15-87 2 10-07-87 10-14-87 6 2-24-88 3-11-88 ,
76 1 '7-29-87 10-20-87 3 11-13-87 3-11 L .6 2-15-88 3-11-88 77- HU 5-20-87 7-08-87' 1 7-29-87 10-30-87 2 8-25-87 11-02 3 11-03-87 1-20-88 5 1-19-88 2-10-88 6 '2-10-88 3-10-88 78 HU 5-16-87 8-11-87 1 7-29-87 10-05-87 2 12-23-87 2-05-88
- 6 2-10-88 3-10-88
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-6 2-21-88. 3-08 '
80 6 3-4-88 3-9-88 81 HU -. 24-8'7 6-i2-87 p_- 3 11-05-87 :11-05-87 6 2-24-88' 2-24 4
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.TARLE 2.3-1 NINE MILE POINT UNIT.TWO RPS ACTUATIONS AND ASSOCIATED OUTAGES, AND PLANNED SHUTDOWNS SCRAM SHUTDOWN DATE REPORT # CT_ARSIFICATION MWTH DURATION RRARON 4
11/5/86' 86-01 A 0 N/A HIGH LEVEL ON IRM D
- 11/5/86 02 A 0 N/A SCRAM DISCHARGE VOLUME (SDV)
HIGH LEVEL 11/9/86 03 A 0 N/A APRM C UPSCALE 11/9/86 04 A 0 N/A APRM C UPSCALE-11/23/86 05 A 0 N/A ' LOSS OF POWER TO SCRAM SOLENOIDS DURING SURVEILLANCE TESTING ON B. REACTOR PROTECTIVE SYSTEM (RPS) & GROUP 2 (GR2). RODS. 12/3/86 06 A 0 N/A LOSS OF POWER TO RPS A TRIP ' CHANNEL WHILE RPS B WAS , DE-ENERGIZED. 12/3/86 07 A 0 N/A LOSS OF POWER TO GP2 A SCRAM SOLENOID WHILE'RPS B WAS DE-ENERGIZED. 12/15/86 08 A- 0 N/A MANUAL INITIATION OF ALL RODS' INSERTED LOGIC (ARI) 12/15/86 09 A 0 N/A SUV HI LEVEL TRIP CH A & B 2/2/87 87-01 A 0 N/A RPS CH A & B DIVISION 3 & 4 , LEVEL 2 REACTOR (RK) WATER LEVEL. 2/7/87 02- A 0 N/A RX WATER LEVEL - LEVEL 3
- 4/22/87 03 A 0 N/A RX WATER LEVEL LO 5/31/87 PSD 33 6 DAYS MANUAL SHUTDOWN (S/D) FROM 1%
l (S/U 6/6/87) POWER DUE TO INTERFERENCE ON-MAIN STEAM LINE 'B' 6/6/87 PSD 10 1 DAY MANUAL S/D FROM 0.3% POWER DUE (S/U 6/7/87) TO RWCU PROBLEMS 6/12/87 04 S 54 2 DAYS SCRAM FROM 1.63% POWER DUE 4 l (S/U 6/14/87) TO IRM CH B, C, D TRIP HI . i 6/15/87 05 S 70 6 DAYS SCRAM FROM 2.1% POWER DUE TO g (S/U 6/21/87) SDV HI LEVEL CH A, B. (ARI)
-19 as
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1 TABLE 2.3-1~ (Cont'd) ( , 1 NINE MILE POINT UNIT IWO RPS ACTUATIONS AND ASSOCIATED OUTAGES, AND PLANNED SHUTDOWNS l.
' SCRAM -SHUTDOWN DATE REPORT # CLASSIFICATION MWTH DURATION RFARON
'6/27/87 '06 ,PS. 55 1 DAY MANUAL SCRAM FROM 2.5% POWER (S/U 6/28/87) FOR TECH SPECS 6/29/87 PSD' 10 5 DAYS MANUAL S/D FROM 0.3% POWER DUE (S/U 7/4/87) TO PROBLEMS WITH RWCU PUMPS 7/11/87 07 S 128 8 DAYS SCRAM FROM 3.84% POWER DUE TO (S/U 7/19/87) DIVISION 1, 3, 4 RX PRESSURE.
HI (EHC SUPPLY LINE CONNECTION BROKE) 7/26/87 08 S 0 1 DAY STARTED MANUAL S/D AND THEN-(S/U 7/27/87) TOOK MODE SWITCH TO S/D (SCRAM) WITH 4 ROD WORTH MINIMIZER GROUPS STILL OUT TO MEET TECH SPEC TIME' _ REQUIREMENTS ON HI LAKE TEMP-8/9/87 09 PS 593 12 DAYS SCRAM FROM 17.8% POWER FROM. (S/U 8/21/87) Rl! MOTE S/D PANEL AS PART OF N2-SUT-28, S/D FROM OUTSIDE CONTROL ROOM 9/2/87' PSD 1376 28 DAYS MANUAL S/D'FROM 41.4% POWER. (S/U 9/30/87) TO DO VARIOUS REPAIRS (CONDENSER, PW PUMP 'B', ETC.) 10/1/87 10 S 92 1 DAY SCRAM FROM 2.7% POWER'ON IRM (S/U 10/2/87)- HI FLUX DUE TO COLD WATER INJECTION 10/13/87 11 PS 776 6 DAYS SCRAM FROM 23 POWER -ON TURBINE (S/U 10/19/87) CONTROL VALVE FAST CLOSURE DUE TO MANUAL TURBINE TRIP FOR N2-SUT-31, LOSS OF TURB GEN AND OFF-SITE POWER 10/23/87 12 S 1184 5 DAYS SCRAM FROM 35.3% POWER DUE TO (S/U 10/28/87) LOSS OF MAIN CONDENSER VACUUM 11/22/87 PSD 1389 30 DAYS MANUAL S/D FROM 41.8% POWER (S/U 12/22/87) FOR REPLACEMENT OF GRAYLOCK FLANGES AND TO FIX FEEDWATER CONTROL VALVES LVC 10A, B, C
'12/26/87 13 S 864 3 DAYS SCRAM FROM 26% THERMAL POWER (S/U 12/29/87) DUE TO LOSS OF CONDENSER 4 VACUUM.
-20
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TABLE 2.3-1 (Cont'd) .. NINE MILE POINT UNIT IWO RPS ACTUATIONS AND ASSOCIATED OUTAGES, AND PLANNED SHUTDOWNS i SCRAM SHUTDOWN DATE REPORT # CLASSIFICATION ~ MWTH L 4 CION RFARON 12/29/87 14 A 0 1 DAY SCRAM FROM 0% THERMAL (S/U 12/30/87) POWER DUE TO OPERATOR ERROR WHEN TAKING MODE SWITCH-POSITION TOO TOO FAR. 1/20/88 88-01 S 1382 13 DAYS SCRAM FROM 41% THERMAL POWER (S/U 2/2/88) DUE TO VALVING ERROR ON THE INSTRUMENT AIR SYSTEM WHILE MARKING UP FOR PREVENTATIVE MAINTENANCE. 2/15/88 02- PS 3157 4 DAYS SCRAM FROM 95.3% POWER AS (S/U 2/19/88) PART OF N2-SUT-25, MSIV FULL ISOLATION. 3/5/88 03- PS 3301 5 DAYS SCRAM FROM 99.6% POWER ^ (S/U 3/10/88) AS PART OF N2-SUT-27 TURBINE
, TRIP / GENERATOR LOAD REJECTION 3/13/88 04 S 3250 3 DAYS SCRAM FROM 98.5% POWER DUE T0 (S/U 3/16/88) TURBINE TRIP INITIATED BY RECIRC PUMP TRANSFER DUE TO STEAM DOME TO RECIRC SUCTION LOW AT LOGIC FAILURE.
3/21/88 05 S 3257 3 DAYS SCRAM FROM 97.3% POWER DUE TO (S/U 3/24/88) LEVEL 8 TURBINE TRIP INITIATED BY VALVING ERROR WHICH ISOLATED 'B' FEEDWATER FLOW TRANSMITTER. Classification Codes A - RPS Actuation S - Unplanned Scram PS - Planned Scram PSD - Planned Shutdown
-21 ,
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-l 3.0 SUfflARY OF TEST RESULTS The individual startup tests - which were performed during the Power
' Ascension Test Program to date are. described in this section.
Each test is presented separately. These sections are further broken down into a Purpose and a Discussion. The Discussion briefly describes the results in comparison with the acceptance . criteria and gives 's-listing of all of the test. exceptions which. were written while conducting the test. e m. * > + + 1 1
-22 _
m As n I i C_______._______________________.____________..____________
l 1 CHEMICAL AND RADI0 CHEMICAL N2-SUT-1 3.1 N2-SUT-1 CHEMICAL AND RADI0 CHEMICAL A. OBJECTIVES
- 1. To secure information on the chemistry and radiochemistry l of the reactor coolant.
- 2. To verify that the sampling, . equipment, procedures, and l analytic techniques are adequate to demonstrate .that the -]
chemistry of all parts of .the entire .r eactor system meet { specifications and process requirements. . .j i
- 3. -Use the' data obtained to evaluate fuel performance and demineralized operations, measure filter performance, confirm condenser integrity, demonstrate proper. steam Eseparator-dryer operation, and measure and calibrate the off-ges retreatment monitors.
B. ACCEPTANCE CRITERIA Level 1
- 1. Chemical factors - defined in the Technical Specifications and fuel warranty are maintained within the limits specified.
- 2. The activity of gaseous and liquid effluents conforms to license limitations.
- 3. Water quality is known at all times and remains within the guidelines of the water quality specifications.
Level 2 Not Applicable C. DISCUSSION Reactor and plant systems water chemistry data was taken prior to fuel loading, at 910 psig reactor pressure in heat-up, and between 5 and 100 percent power, during Test Conditions 1, 2, 3, 5 and 6. The test results for this section are sunnarized in Table 3.1-1.
-23 -
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CIBMICAL AND RADIOCHIREICAL - N2-SUT-1 C. (Cont'd)
' Gaseous and- liquid offluent monitoring ,was- performed in-conjunction with the water ' chemistry testing prior to fuel loading and at TC6. Gaseous ., ef fluent monitoring was perfomed at all other- test points. Gaseous and liquid effluent results collected for-this procedure are summarized in Table 3.1-2.
Off-gas retreatment -monitor calibration data was ' collected between 5 and 100 percent power, during Test conditions 1, - 2, 3, 5 and 6. The test results for this section are summarized in Figure 3.1-4. The moisture carryover test was performed using Na-24 during' Test Condition 6. The calculated average moisture carryover was 0.0026%. The Test Exceptions and their resolutions are summarized- in Table 3.1-3. .
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.. CHEMICAL'AND RADIOCHEMICAL = + ,
a. N2-SUT-l' , TABLE 3.1-1 Water th =4stry Accentance Criteria lTha limit 7for Teach parameter 1specified. on Data Sheet 1 is derived from the most limiting ! (value. listed.among the following documents. FUEL WARRANTY -WATER QUALITY REG. GUIDE .. OTHER'
-PARAMETran TECH. SPEC. 2'4A1839 22A2707 1.56 DOC 11MENTS
- . REACTOR WATER
. Conductivity!. I'1.0 (Open.' I'1.0-(Rx. Same as Tech. I 1.0 (>1% N/A:
,(micro-sho/cm) Cond. 1) coolant >212'F) Spec.'except rated' steam-1 2.0 (0 pen. Operational flow)
Cond. 2&3)- 1 2.0 (Rx. Conditions:2 & . 1 2.0 (<1% i(Notes 1,2,3) .1 10.0 (All' coolant 1212*F) '3 are.not. rated steam l flow).
~
. other,. cond) . specified..
< 10.0 (Rx.'
coolant 1212*F) Chloride (ppm) ;1.0.2'(Open. 1 0.1 (Rx. .
'Same as Tech.- -1 0.2 (>1%. ,N/A
~ Cond. 1) coolant >212*F) Spec. except rated steam
. :(Notes l',2,3) .-1 0.1 (0 pen. . Operational flow) . .
Cond.,2&3)- 1 0.1 (Rx. Conditions 2 & l'O.1 (<1% 1 0.5 (All coolant 1212*F) 3 are not = rated steam-
'other cond)- specified. flow)'
< 0.5 (Rx.
coolant 1212'F) pH 5.6-8.6 (open. 5.6-8.6 (Rx. Same as Tech. 5.6 - 8.6 N/A 7 (Notes 1,2,3) Cond.>1). coolant >212*F) Spec. except (> 11 rated
. 5.6-8.6 (open. Operational- Lsteam flow)
Cond.'2&3) 5.3-8.6 (RX' Conditions 2 & 5.3 - 8.6-(RX 5.3-8.6l(All coolant 1212*F) 3 are not' coolant 1212*F)- other cond) specified. Dose Equiva-' 1 0.2 micro- None None None N/A-lent I-131 curies /g (All condi-tions except refueline
'CRD WATER SIL-148.
Conductivity None None None None 0.1 (micro-eho/cm) Omveen'(nob) None None None None 50 + , COND/DEMIN. Cond/demin. j INFLUENT- Spec.#WO14C Conductivity
- (micro- =ha / cm ) None None 0.5 None O.2-0.5 ,
M
-33 aa I
q l CHEMICAL AND RADIOCHEMICAL' N2-SUT-1 TABLE 3.1-1
' Water Chemistry Acceptance Criteria The limit for each parameter specified on Data Sheet 1 is derived from the most limiting value listed among the following documents.
WATER QUALITY REG. GUIDE OTHER PUEL WARRANTY TECH. SPEC. 23A1839 22A2707 1.56 DOCUMENTS PARAMETERS Cond/demin. COND/DEMIN. Spec #WO14C EFFLUENT Conductivity None s 0.065 (>10% None 5 0.1 s 0.1 rated power) (micro-aho/ca) 20-50 None None None Oxygen (ppb) None Q10% power) Silica (ppb) None None None None < 5 las SiO2 ) FEEDWATER None N/A None None 0.1 Conductivity (micro-sho/ca) 20-50 20-200 None N/A Oxygen (ppb) None Q10% power) Soluble & N/A Insoluble None Total s 15 ppba** Total s 15 ppb None Copper s 0.5 ppb Copper s 2 ppb Metallie Impurity Insol Iron s 10 ppb Soluble Iron < 1 pob
*** - Total metallic impurities (soluble and insoluble) limit isThe 15 metallic ppb of which the impurities soluble and insoluble copper may not exceed 2 ppb total.
limit during the first 500 Effective Full Power Hours (EFPH) is 100 ppb at <50% rated power and 50 ppb at >50% rated power (short duration spikes may occur providad corrective actions are taken promptly). l 1
-34 1
1
l
< .. d TARLE 3.1. CIGMICAL AND RADI0 CHEMICAL l N2-SUT-1 z 1
CASEOUS AND LIOUID EFFLUENT DATA Open vessel
-Main Stack Limit Value
' Particulate, pCi/see . 1 30 1.02E-2 Iodine, pCi/sec 1 28 6.48E-3 Noble gas, pCi/see 1 3.8E4 2.99 j C.R. Noble gas,-CPM i 1.8E4 2 ,
Reactor /Radwaste Vent Particulate pCi/see 1 10 1.43E-2 Iodine,-pci/sec' i 11 4.67E-3 Noble gas, pCi/sec I 8.9E3 8.61 C.R. Noble gas 1 1.8E3 2
' Liquid Radwaste Effluent, pCi/cc 1 2.17E-3 LLD
' Tech Spec Items
. Service Water A, pCi/cc 1 1.9E-6 1.48E-6 Service Water B, pCi/cc 1 1.96E-6 1.51E-6 Cooling Tower Blowdown, pCi/cc 1 3.5E-6 1.76E-6 Off-gas retreatment, pCi/cc I 9.6 7.88E-4 Standby gas treatment, pCi/cc 1 1.6E-3 6.11E-8 Liould Radwaste Effluent Test Condition 6 Principle Gamma Emitter
- 9E-6 :0
' Iodine 131 3E-7 0 Dissolved & Entrained Gases + 2E-4 0 !
H-3 3E-3 1.7E-4 Gross Alpha 1E-7 <5.0E-8 Srontium 89 3E-6 <4.0E-8 Srontium 90 3E-7 <5.4E-9 Iron ~55 8E-4 <8.0E-7 Sgrvice Water A/B Effluents A/B Principle Gamma Emitter
- 9E-6 0/0 Iodine 131 3E-7 0/0 Dissolved & Entrained Gases + 2E-4 0/0 H-3 3E-3 (1.9E-6/<1.9E-6 Gross Alpha 1E-7 <5.2E-8/<5.2E-8 l
- Based on CS134 .
+ Total dissolved and entrained Eas activity 9 (noble gases) ~ !'
1s; i
-35 1.
Ami i ,
l l TABLE 3.1-2. (Cont'd) l CIBMICAL AND RADIOCEDfICAL N2-SUT-1 CAREOUS AND LIOUID EFFLUENT DATA
]
Test Condition'6 7 Cooline Tower Blowdown Limit Value Srontium 89 3E-6 <2.2E-8 Srontium 90 3E-7 (6.7E-9 Iron 55 8E-4 <9.4E-7 Auxiliary Boller Pumo Seal and Samole Principle Gamma Emitter
- 9E-6 0
' H-3 ' 3E-3 <1.9E-6 l
- Based on CS134
+ Total dissolved and entrained gas activity (noble gases)
~
-36 _,
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TABLE 3.1-3 CHEMICAL AND RADI0 CHEMICAL N2-SUT-1 3 TEST EXCEPTION SUttfARY Test Test Exception Condition Description 1 OV Condensate demineralized effluent oxygen concentration was above the specified value (actual 8300 ppb, limit 200 ppb). Exception accepted as is, this limit is not applicable to shutdown condition. 2 OV Makeup water treatment ' demineralizers ph value was out of the specified range (actual 5.9, limit 6.6-7.5). Exception accepted as is, this low value was due to CO2 present in the instrument line. 3 OV Spent fuel pool effluent conductivity was above the specified value (actual 0.5 paho/cm, limit 0.2 pmho/cm). Exception accepted as is. This is a self imposed limit that cannot be supported. -The FSAR limit is 3.0pmho/cm. Plant Chemistry Department personnel are. satisfied with the Spent Fuel Pool Filter Demin performance. 4 OV Condenser hetwell conductivity is above the specified value (actual 0.356 pmho/cm, limit 0.2 pmho/cm). Exception accepted as is, the high conductivity was due to no vacuum in the condenser. 5 OV Condensate storage ' tank ph value out of the specified range (actual 5.57, limit 6-8). Exception accepted as is, the low ph was due to 002 Present in CST. 6 OV Demineralized water storage tanks ph value was out of the specified range (actual 5.6, limit 6-8). Exception accepted as is, the low ph was due to CO2 present in tanks. 7 HU CRD water conductivity and dissolved oxygen exceed their limits (actual 0.106 paho/cm, 90 ppb; limits 0.1 and 50). Exception accepted as is, these values will improve at higher steam flow. 8 1 CRD water conductivity and dissolved oxygen exceed their limits (actual 0.366 pho/cm, 1500 ppb; limits 0.1 and 50). Exception accepted as is, CRD i suction supply problem to be evaluated and resolved ,i by plant engineering. (The PCV f rom the Condensate System hs,s been temporarily failed open. A problem '4B report has been written requesting engineering to evaluate a long term solution.) Final resolution is documented on TE14. *
-38 ,
__.._.____________i_
- - - _ _ - _ . - _ _ _ - - = - _ _ _ _ - _ -
a (_
'TARTE'3.1-3 "(Cont'd)'
. CEEMICAL AND RADIOCHEMICAL N2-SUT-1 a TEST EKCEPTION SUlflARY.
1 Test- Test Excention Condition' Description J 9 1 Condensate demineralized . effluent - oxygen, ifinal feedwater oxygen and final feedwater. metals (copper, iron, total) exceed their limits (actual. ' - ~ 15. ppb , .
- 10. ppb , 2.38 ppb,2 7.65 ppb and 20.5 ' ppb; limits. '- -
20/50, 20/50, ~ 0.5, 1.0 and 15 ) . . Exception ' accepted as is, the concentration of' feedwater metals ' is-expected to be.high at times'during startup.
-10 1 Condensates' domineralizer- influent conductivity exceeded' it's limit- (actual 1.37 'paho/ca,'- limit 0.5). Exception' accepted as .is, condenser- tube
. leaks were repaired following testing.
'11 : 2 Final feedwater. oxygen and'. condensate domineraliser-influent conductivity did not' meet Fuel' Warranty and Water - Quality Specification: .(22A2707)~ requirements (Cond. Domin. Infli- Conductivity; ' Actual 1.96.
paho/cm limit 0.5; final'- feedwater; oxygen o actual-15' ppb limit- 20-50). Exception ' accepted las. is,
. oxygen'should increase with power level af ter pipingi oxide layer stabilizes. Condensate domineralizer inlet conductivity. will improve af ter condenser ' tube leak correction. Perform retest at- higher . power level after condenser outage.-
'12 2 CRD water ' conductivity (actua11'0.108 . paho/cm,: .-
limit 0.1) and dissolved cxygen .(actual 60 jppb,- limit 50) did not meet GE SIL ' 148 requirements.. '; Condensate domineralizer influenti conductivity l ! (actual 1.96 paho/ca, limit 0.2-0.5) did ' not meet Condensate Domineraliser -Specification' WO140. Condensate domineralizer effluent: silica concentration analysis does = not meet. specification WO14C sensitivity requirements (actual measurement
< 10 ppb , limit is 5 ppb). Exception accepted as is.
Troubleshoot CRD supply from condensate header. Condensate demineralized inlet conductivity will improve after correcting condenser tube. leaks. Condensate demineralized outlet. silice is below current detectable limits and must, therefore, be considered acceptable. Perform retest at higher power level after condenser outage. -
-39
*e s
~
v -_ ___
TABLE 3.1-3 .(Cont'd) CHEMICAL AND RADI0 CHEMICAL N2-SUT-1 TEST EXCEPTION
SUMMARY
Test- Test Exceotion Condition Description 13 (Retest 1) 2 Final feedwater oxygen did not meet Fuel Warranty and Water Quality ' Spec (22A2707) requirements (oxygen concentration actual 15 ppb , limit 20-50). Final feedwater soluble iron did not meet- fuel warranty requirements (iron. concentration actual 1.12 ppb, limit 1.0). Exception accepted as is. j High iron (and other metals) levels .are normal during startup and should decrease with increased operating time. Oxygen- levels are expected to increase within specification requirements as well (as indicated by subsequent measurements). l i 1 14 (Retest 1) 2 CRD' water conductivity (actual 0.47 paho/cm, limit O.1) and dissolved oxygen (actual 2500 ppb, limit
- 50) did not meet GE. SIL 148 requirements.
Condensate demineralized effluent silica concentration ana'.ysis does not meet specification WO14C sensitivity requirements (actual measurement
<10 ppb, limit is 5 ppb). Condensate supply to CRD pressure control valve was adjusted to function properly and CRD water returned to within GE SIL 148 requirements. Condensate domineralizer outlet silica concentration is below minimum detectable ,
limit and must, therefore, be considered acceptable. l 15 3 The final feedwater oxygen content was outside limits (actual 15 ppb, limit 20-50). Exception accepted as is, the oxygen content should improve after the oxide layer stabilizes. , j 16 3 Soluble and insoluble iron concentration from Heater Drain Pumps exceed their limits. Exception accepted as is, iron concentration should improve with ! forward pump heater drain pump operation. l l 17 5 The condensate demineralized effluent oxygen content was outside limits (actual 15 ppb, limit 20-50). Exception accepted as is, the oxygen content should improve after the piping oxide layers stabilizes.
-40 _
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TABLE 3.1-3 (Cont'd) CHEMICAL AND R&DIOCIEMICAL
-N2-SUT-1 TEST EXCEPTION SUt91ARY Test- Test Excention Condition Description 18 5 Forward ptusped heater drains < were outside their -
limits on conductivity, oxygen and iron. Accepted as. is, since the final feedwater chemistry .is acceptable. 19 6 Condensate domineralizer, effluent oxygen content 'was outside ' limits .- . Exception accepted as is. Chemistry Department to pursue long- term improvements. 20 6- The soluble. and insoluble metallic concentration L in final feedwater exceed their limits; exception ~ accepted as is. Chemistry Department to pursue long term improvements. 21 6 Forward ' pumped heater : drains were outside their limits on conductivity, oxygen, and-iron. Accept as is. Chemistry. . . - . Department to pursue long . term 22 6 Condensste demineralizar effluent silica may exceed ! its limit .(As measurement <10 ppb, Limit 5 ppb) the ! instrument on site 'does not . have 'the sensitivity to measure . silica concentration below 10. ppb. Exception ' accepted as .is. . Chemistry Department to j pursue long term improvements. lj l l l
-41 .
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r-RADIATI(Ni MEASURl!MENTS
~N2-SUT-2 3.2 N2-SUT-2 RADIATION MEASUREMENTS A. OBJECTIVES ,
The purpose of this test is to determine:-
- 1. The background radiation levels in the plant prior to operation for base data on activity build up.
- 2. To monitor radiation levels to assure the protection of personnel during plant operation.
B. ACCEPTANCE CRITERIA Level 1 'l
- 1. The radiation doses and the occupancy times of personnel in radiation zones shall be ' controlled consistent with the requirements of 10CFR20, " Standards for Protection Against Radiation".
Level 2 Not Applicable C. DISCUSSION During open vessel testing a survey of natural background radiation throughout the plant site was made prior to initial fuel loading. Subsequent to fuel loading, these surveys were repeated. Gamma dose rate measurements and, where appropriate, neutron. dose rate measurements were made at various locations in , the drywell. All gamma and neutron radiation levels were within the acceptance criteria limits. All areas surveyed .were verified to be properly posted per NMP2 plant procedure N2-RTF-4 (Radiation Measurements and Shield Integrity Checks) and Radiation Survey 1,og Sheet. 1 During TC Heatup, radiation measurements were made under the ) following conditions: l
)
- a. Steady state operation at rated pressure, approximately 1%
power
- b. TIP System Operation l
l
- c. RWCU System Demineralized Sludge transfer l
-44 .l
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.I N2-SUT-2 IC.- 2' (Cont ' d) t 4 : The'- results indicated that all Lthe' Level 11 acceptance i criteria -
Lwere met.- Radiation levels were'all <.5 MREM /hr neutron.and <.2-MREM /hr gasuna except for 'one'. point . in the ~ RWCU Heat Exchanger, Room which.was 0.5 MREM /hr. d-
'During Test' Condition l', at' 18% powers radiation :surveyJ measurements' were only made .when .RWCU'~ System. Domineralizer
, sludge . transf erl was in progress along the sludge transfer : path.
Thel analysis. indicated , that, all the Level 1 1acceptance ccriteria were met.--All points' monitored were <.2 MREM /hr gamma. ,, During , Test Condition 2' radiation measurements were made~ under -
'the following conditions:
- a. . Steady state operation ~at'24% power b.. .During TIP-Sy' stem operation _
- c. During'RWCU System Domineraliser sludge transfsr.
The analysis indicated that all. the Level 1 acceptance criteriaj were met. The ' highest reading was 'seen in the ,RWCU: Heat: Exchanger Room where a value of ; 35 MREM /hr vs. a limiti of 100 :
' MREM /hr was observed.
During Test Condition 3, radiation, surveys were made atia' steady-state ' power - . level of'-60% and during TIP System operation.- Survey results ; show - that the : highest radiation levels L were 60 mres/hr in the RWCU Heat Exchanger Room (limit' of 100. ares /hr)' and 50 ares /hr. at the .High -- Pressure ' Turbine ' shield wall; ,.Two test exceptions :were generated- and their resolutions are s =marized in Table 3.2-1.- During Test Condition 6, Radiation measurements were made at steady state power level of 100 (+0 -5)%. of rated and during TIP System' 0peration. The radiation doses and the ' occupancy L times of personne1' in radiation zones were controlled consistent with Three Test Exceptions were issued
~
the requirements of 100FR20.
,- and their resolutions are sununarized in Table 3.2-1.
-45 -
~
r A b - - - -.__-_-- ___ ----__--_
- p. y i TARLE 3.2 .. RADIATION MEASUREMENTS y
N2-SUT-2 TEST EXCEPTION SUt9tARY.
> Test . Test
.Excention Condition' Demeription 1 3 The Gesuna reading at RBP# 3-1 (el. 318 .in the Off-Gas Building) is 2 MRDf/hr vs. a : limit of 0.2 MREM /hr. The limit was discovered to be incorrect' and N2-RTP-4 was revised.
2 3 The Gamma reading at REP # 4-12 -- (entrance to inner'
' TIP Room) was 100 MREM /hr af ter TIP' use vs. a limit $
of 5.0 MREM /hr. The limit was discovered ' to be incorrect and N2-RTP-4 was revised.'
-3 6 Level I Criteria radiation- surveys at the base points identified : by the following problem ' reports exceed the Acceptance Criteria.of N2-RTP-4.
Base Point Froblem Report #. T3-12 '07728 T4-1,2,3,4,7 07729 No Base Point assigned 07731 03-1 07730 Areas are to be' administrative 1y controlled in accordance with 10CFR20 . requirements until rezoning or shielding modifications can be implemented per - dispositions to applicable problem reports. 4 .6 During the area radiation measurement, reactor power drif ted slightly below the prerequisite power level of 95 to 100%. . Lowest power level seen was 94.7%. The deviation from the test window was negligible, therefore, the data collected was acceptable. 5 6 Rad!ation surveys performed per N2-RTP-4 around the TIP Room following TIP use at 100% power showed radiation levels in excess of acceptable levels , per N2-RTP-4. Problem Report (#07734) was issued for specifics. Access to this area was administrative 1y controlled in accordance with 10CFR20 requirements. A modification to add shielding as per dispositioned PR. 7734 will be performed at the first refueling outage.
-46 _,
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- i. . . .
FUEL LOAD N2-SUT-3 3.3' N2-SUT-3 FUEL LOAD A. OBJECTIVES The purpose of this procedure is to load the nuclear fuel safely and efficiently to the full core size. B. ACCEPTANCE CRITERIA Level 1
- 1. The partially loaded core shutdown margin demonstration verified that the configuration is suberitical by at least 0.0038 Delta K/K with the analytically determined strongest rod fully withdrawn.
Level 2 Not Applicable _ C. DISCUSSION Load 4na of the First 362 Asammhlies Initial core fuel loading was perfonned following the final verification of all pre-fuel loading prerequisites on November 2, 1986. This included reviewing the operational status of all fuel- loading required systems, reviewing compliance with all required Tech Specs, and ensuring that all systems were lined up to support - fuel loading. Fuel loading commenced in the upper right hand quadrant of the reactor core. The first four bundles loaded surrounded the neutron source located closest to SRM 'B'. SRM 'B' came on scale following the loading of the first fuel bundle. Technical Specification Operability of 3pecial Instrumentation was verified following the loading of bundle 16. Fuel loading continued in a gradually increasing spiral until bundle 362 was loaded on November 8, 1986. Periodically during this section, the various Tech Spec Requirements applicable to fuel loading were verified by surveillance tests and also documented by the fuel load procedure. During one period following the performance of N2-OSP-NMS-@002 (Source Range Monitor Checks for Initial Core Loading), nineteen fuel bundles were loaded in the lower right hand quadrant with the SRM in that quadrant ,
-47
- Am H
FUEL LOAD N2-SUT-3 i C. (Cont'd) (SRM J 'C') bypassed.: Upon discovery of the - error, fuel loading was suspended and the required JIRC notification (within 4 hours) was made. Following a complete teriew of the incident _(including the Site Operations ' Review Commidtee, . Site Manager, Plant Manager,. Technical . , Superintendent 'and 'the- Power- Ascension Manager) a procedural change -was made to the ' aforementioned surveillance procedure to prevent reoccurrence of this oversight and fuel loading resumed.- Part4m11v' Loaded Shutdown Marrin Verification i The partially loaded core shutdown margin check was performed on the 362 bundle configuration thereby ' insuring two on scale SRMs during the test. The.downscale rod block functions of SRMs 'C' &
~
'D' . (the' two not being used .for the test) were bypassed in their respective trip auxiliary units.- The control rods used for the teste were . functionally - tested by SUT-5 (Control Rod System-Open Vessel), all personnel were evacuated from the affected areas, ~~ J and . . final . Tech Spec compliance was verified. The- B saquence.
group 1 control rods were then withdrawn. The' group 2' rods were then bypassed and withdrawn. Once the required control rods were withdrawn, the reactor was allowed to remain in this - condition for 5' minutes. Reactor subcriticality was confirmed and the control rods were reinserted. The Level 1 Criteria associated with this section consisted of verifying the required shutdown margin of 0.0038 Delta K/K with the analytically determintd strongest rod fully withdrawn. This was , performed by demonstrating that the core remained suberitical when. the positive reactivity inserted was greater than: .1) the remaining-fuel to be loaded, 2) the strongest rod out and, 3) the required shutdown margin. nha Renuired Rha Test (demonstration eius taannerature correction)
-0.02171 -0.018983 I
I I
-48 .
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- . . .-u ___-_ _
I 'I .. e. FUEL LOAD N2-SUT-3 l-C. (Cont'd) Lond4ne Asa-h11em 363 throtish 764 > The remaining 402 fuel bundles were loaded into the reactor core, . fo11owing Tech Spec ' compliance reverification, from November 10 through 15,.1986. The: spiral loading continued moving outward radially from the upper central portion of the reactor vessel. Core Verif1' cation The fully loaded core war verified per the Reactor. Physics Startup Testing Procedure N2-RPSTP-5 (Core Post-Alteration Inspection and Verification). The procedure verified-correct orientation, seating and identification. Test exceptions and their resolutions are stumnarized in ~ Table 3.3-1. e I-i 1 J
-49 ~
Ja
4 N - l TABLE 3.3-1 FUEL LOAD N2-SUT-3 TEST EXCEPTION SUPEARY Test Test EEnaption Condition Description 1 OV SRM 'C' was bypassed as . the weekly SRM ' Surveillance was performed. 19 fuel bundles'were loaded into-the
'C' quadrant before it was discovered that SRM ' ' C ' '
had not been unbypassed.- The SRM weekly surveillance was revised to include independent verification for the return to service of all SRM's.
-50 .
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.. FULL CORE SHUTDOWN MARGIN DEMONSTRATION-c*. M2-SUT- 4 3.4 N2-SUT-4 FULL CORE' SHUTDOWN MARGIN DEMONSTRATION. ,
A. OBTECTIVES
< Demonstrate that the' i reactor con be L made 'suberitical with ^ the.
.requiredimargin at any : point throughout 7 the fuel cycle. with' the-7 strongest worth control rod fully withdrawn an( all other control!
rods fully inserted. i /
?' B. ACCEPTANCE CRITERIA Laval l'-
- 1. The shutdown margin of.the fully lo'nded,' cold (68'F or.20*C),-
xenon-free core occurring .- at . the - mest 7 reactive . time during the cycle must be .'at~ least . 0.38%. Ak/k with- the - analytically strongest rod (or its - reactivity ' equivalent) withdrawn. If-
-the shutdown margin is measured:at some time duringJthe. cycle a other than the most reactive time, compliance with the above ~
" criterion is shown by demonstrating that the - shutdown : margin is. 0.38% Ak/k plus an exposure dependent increment L which -
adjusts the : shutdown margin at that , time to the. minimum' shutdown margin. Level 2
- 1. Criticality should occur within gl.0% Ak/k of the predicted critical.
C. DISCUSSION This test was performed by first . achieving criticality in the-B-Sequence.- Criticality' occurred at 2340 notches which is within 1% - Ak/k of the predicted criticality of '2344 notches- (i.e., between 2160 and 2496 notches), thus satisfying the Level 2 acceptance criterion. ll A stable positive period was then established. The period was measured and the control rod pattern and recirc suction-- temperatures were recorded. Reactivity corrections were made for reactor period, the amount of deviation of the reactor coolant temperature from 68'F, and the fact that . the beginning ' of cycle is not the most reactive point in the cycle. The shutdown Margin (SDM) was then calculated to be 2.35% Ak/k which exceeds 0.38% Ak/k, thus satisfying the Level 1 acceptance criterion.
. -51 .
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9 .. 7 e. THIS PAGE INTENTIONALLY LEFT BLANK
-52 ,
~l 4
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p. y . W j , C(MITROL ROD' DRIVE SYSTEE iy ..
.N2-SUT-5 3.5 N2-SUT-5 CONTROL ROD' DRIVE. SYSTEM
.e
?A.. OBJECTIVES
- 1. Demonstrate- that, the Control Red Drive _(CRD): ' System.
operates properly; over the' full range .of primary Lcoolant i temperatures-and pressures fros' ambient-to operating. 9
~
- 2. Determine the initial operating characteristics of the CRD -
System. B. ACCEPTANCE CRITERIA Level 1
.1. Each CRD must have a .- normal withdraw - speed less, than. or equal;to 3.6 inches'per second.. indicated-by a full 12-foot-f stroke in greater than or equal to 40 seconds. .,
. 2. The mean scram ' time .of all operable CRDs = must not ' exceed"
~
the following: times: (Scram time is measured from the time-the pilot scram valve solenoids'are de-energized). Position Inserted from l Fully Withdrawn Scram: Time (Seconds) 45 0.43 39 0.86 25 1.93 ' 05 '3.49
,1
- 3. The mean ' scram time of, the three fastest CRDs in a . two .by two array must not exceed the following times: (Scram time in measured . from the time the pilot- scram valve solenoids' are de-energized).
Position Inserted from Fully Withdraw.-c Scram Time (Seconds) ! 45 0.45 39 0.92 25 2.05 05 3.70
- 4. The maximum scram insertion time of each control rod from -
the fully withdrawn position to notch position 5, based on de-energization of the Scram Pilot Valve Solenoids as time . zero, shall not exceed 7.0 seconds. n
-53 an l______________. _ . _ _ _ _ _ . _ _ . _ _ _
CONTROL ROD DRIVE' SYSTEM. N2-SUT-5'
< B. (Con t ' d).
Level 2
- 1. Each CRD' must have a normal insert or withdraw speed of 3.0' iO.6 inches per second indicated by a full 12-foot stroke- in ,
40 to'60 seconds. l
- 2. - With respect to the Control Rod Drive Friction Tests, if the-differential. pressure variation exceeds 15 psid f or.. ' a continuous drive-in, a settling test must be performed, in which case . the differential settling pressure should not be less than 30 psid, nor should it vary by more than 10 psid over a full stroke.
C.'. DISCUSSION All 185 control' rods were tested for normal 'insert and ~ withdrawal times, coupling checks and ' drive flow rate verification at midstroke during Test Condition Open Vessel. This testing was performed af ter alll four fuel bundles were placed around' the control rod to be tested, to insure that no - binding between control rod and fuel bundle existtd,' as would be evidenced by abnormal insert' and withdrawal- times. Although not an acceptance criteria,- the Rod Position Indication System was verified ' operable on each control rod with the exception of-control rod 18-11 where' notch 26 failed to indicate. A Work Request was initiated to correct. the problem and corrective action was taken. ' All control rod' drive mechanisms were friction tested during Test- Condition Open. Vessel in accordance with N2-IMP-CRD-2.0. The testing was performed for each CRDM once all fuel . was loaded around- the mechanism. Friction testing evaluates . the CRDM operation by evaluacing the differential pressure (magnitude and variation) across the mechanism drive piston during a continuous rod insertion from " full out" to
" full in". All CRDMs met the continuous insert friction test criteria, therefore .no settling friction tests were required to be performed.
All 185 control rods were individually scram time tested in accordance with N24SP-RMC-@001. All acceptance criteria , were satisfied. Control rod 06-35 had a malfunction of the l scram pilot valve. This problem was corrected . and ' the rod retested satisfactorily. Control Rod 02-31 failed to indicate notch position. 25. The next odd notch (23) was . within the specification to notch 25, therefore, the time i
-54 %
' l I L i
,1
,7 _ 3 i x_ylN' M . CGIT10L ROD DRIVE SYSTEM
..N2-SUT-5 1 i.
C.- (Cont'd)-
~
to notch 23 was used,to calculate: scram time to notch.'25.- A Work )
- Request was; written to correct this problem and. corrective action-was taken. . Based upon the' initial start-up 1 sequence ' and L acram timing of all ' CRDs "four ' selected.. rods" were' scram timed at the low accumulator pressure alarm point. Acceptance . criteria- were satisfied for : these rods. All- control ' rods had scram times of between'1.80 seconds and 1.33 seconds to Notch 5.
.The ." four . selected rods", as deterinined by the scram time testing, were. then additionally scram time ' tested in Test Condition Heatup (600 psig and 800 ~ peig . RPV pressure) with , HCU accumulator, pressures.in the normal operating range.-:The maximum-scram . time . to notch position 5. for the "four. select rods" was 3.273 - seconds' and occurred at 800 psig RPV pressure. No, unusual > or abnormal trends were noted for the four selected rods over the range-of RPV pressures tested.'
L Additionally, the "four selected rods" .were satisfactorily
. friction. tested at rated; pressure, with .a maximum' observed; differentia 1' pressure variation of 12.90 paid. Because this E -value was less than the acceptance ' eriterion value 'of 15.0. psid, -
settling friction' tests were not required. At normal' operating . reactor pressure all 185 control rods were scram time tested with HCU accumulator pressures at. normal-operating pressure. The four selected rods were functionally 1 tested satisfactorily. No control rod speed control adjustments were required, nor were any other problems encountered except for an occasional control rod position indication switch not indicating. The scram times for all 185 control rods were satisfactory and were as follows: (The maximum ' individual control rod scram time to each notch is listed.) Maximum Notch Position Elapsed Time Raoufred T4== (Mar.) r (Individual Control Rod) 45 0.427 sec. 1 0.45 sec. 39 0.755 sec. 1 0.92 sec. 25 1.540 sec. I 2.05 sec. 05 2.783 sec. I 3.70 sec. The mean scram criteria and the mean scram time of the 3 fastest CRDs in a two-by-two array criteria were met because the maximum individual scram time (slowest control rod) for each notch position was less than the mean scram time criteria for that notch position. .
-55 n
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C(BITROL ROD DRIVE SYSTEM ) N2-SUT-5 a C.- (Cont'd) ! l The CRD Flow Control ' Valve controller was monitored during pressurization of the RPV from 0 psig to rated pressure to ensure that the CRD System flow as controlled within i 3 - gpm of its setpoint of 63 gpm. The "four selected rods" evaluated during previous scram time testing were monitored for scram times during the following planned reactor scrams: " Shutdown from.Outside the Control Room" (N2-SUT-28), " Loss of Turbine / Generator and Off-site Power" (N2-SUT-31), MSIV Full Isolation .(N2-SUT-25) and Generator Load Rejection (N2-SUT-27). The scram times met the applicable-criteria. The method of initiating the scram during " Shutdown from Outside the- Control Room" (N2-SUT-28), Test Condition 1, precluded measurement of the scram cimes based upon de-energization of the scram pilot valve solenoids as time zero.. The times were ~ evaluated using Notch 45 as time zero and comparing these times to the _ same times of N2-SUT-5-HU single rod scrams at . rated pressure. The times during Test Condition 1 testing were faster-than the Test Condition Heatup testing times and the test exception was closed out. During the " Loss of Turbine Generator and Off-Site Power Test" (N2-SUT-31) in Test Condition 2, the MSIV Full Isolation (N2-SUT-25) amd the Generator Load Rejection (N2-SUT-27) in Test Condition 6, the scram times were within the 7.0 second criteria, based upon de-energization of the scram pilot valve solenoids as time zero. See Table 3.5-1. During system tuning the CRD flow controller response for both
'A' and 'B' CRD Flow Control Valves was verified to meet- all acceptance criteria in Test Condition 2. System oscillatory response to the controller setpoint step changes was verified to demonstrate a decay ratio 1 0.25. No oscillations were noted. .
The final controller settings were a gain of 0.2 and a reset of 15. Test exceptions and their resolutions are summarized in Table 3.5-2.
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I' TABLE 3.5-1 CONTROL ROD DRIVE SYSTDI N2-SUT-5 l-FOUR SELECTED ROD SCRAM TIME RESULTS
. Test: N2-SUT-31 " Loss of Turbine Generator and Off-site Power" C2Dtrol Rod Time (see) to Notch Position
-(mc, yy) 45 39 25 05 42 0.260 0.575 1.306 2.420 26-39 0.264 0.550 1.316 2.480 54-43 0.259- 'O.582 1.350 '2.559 30-59 0.248 0.527 1.250 2.349 Test: N2-SUT-25 "MSIV Full Isolation" Control Rod T4== (see) to Notch Position '
(xx, yy) 45 39 25 05 i 42-31 0.252 0.536 1.211 2.275 26-39 0.256 0.548 1.279 .2.387 54-43 0.256 0.567 1.327 2.460 ' 30-59 0.244 0.528 1.239 2.315 Test: N2-SUT-27 " Generator Load Rejection" Control Rod Time (see) to Notch Position (xx, yy) 45 39 25 05 42-31 0.256 0.567 1.311 2.408 26-39 0. 25 2 0.540 1.287 2.359 54-43 0.248 0.528 1.219- 2.303 30-59 0.244 0.520 1.223 2.283
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IABLE 3.5-2 CONTROL a." DRIVE SYSTBt N2-SUT-5 TEST EXCEPTION
SUMMARY
Test Tes t .. Excention Condition Desce'Dtion_ 1 OV' Notch; position 26 failed to indicate for rod ' 18-11~ during function testing. A. Work. Request was initiated to solve this= problem and corrective-action was taken. 2 OV' Notch position . 25 failed to indicate for rod 02-31 L during. scram time testing. Scram timeL was calculated using reed switch at position' 23. - , v: , 3- OV- The scram pilot valve for rod 06-35. failed . during - scram . time testing. A: retest was . performed af ter th pilot valve was replaced. , m 4 OV. Eyht rods were not evaluated properly during friction testing. These rods were reanalyzed and'- found to have acceptable ~ behavior. _ _5_ 0V Notch position 7 failed to indicate for rod 42 during scram time testing. This was accepted as,is,. as notch 7 is not used to determine scram time. A WR was~ written- to address the deficiency- and corrective. action was taken. , 6 HU Notch position 25 and 45 failed to indicate for rod 46-11. Scram time was calculated using reed switch at position 23. 7 1 During the Remote Shutdown Test (N2-EUT n i le Reactor was scrasused by opening the r2 Srt.4ers 1 supplying the scram pilot valve solenoids, which did-l" not produce a scram timing initiation signal.' Therefore, the scram times from the pickup of notch 45 were utilized to verify acceptable scram time' performance.
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EX, r q SOURCE RANGE M(BlITOR PERFORMANCE
-N2-SUT-6 '
- 3.6' 'N2-SUT-6 SOURCE RANGE MONITOR PERFORMANCE.'
A .- OBJECTIVES a .
- ' 1. Demonstrate that . the neutron sources, SRM ' instrumentation,.
, and control ' rod withdrawal saquence's, provide adequate
' < ' 'information to achieve criticality and increase power in. a safe 1and efficient manner.
'B.- ACCEPTANCE CRITERIA Level'1 1.. There .must be6 a minimum count - rate of 3 counts per second (withia. signal count to noise count ratio ~ of at. least 2:1) or a minimum ? count' rate of 0.7 counts per second : (with a neutron signal count to noise count ratio of'at lesst 20:1) on all' required. operable SRM's.
~
- 2. Each . required operable IRM channel must be on scale before the required operable SRM's exceed their rod block-setpoint.
- Level 2 None-C. DISCUSSION i
Prior. to initial criticality, the signal-to-noise ratio and minimum count rate of . each SRM ; channel were determined ' to be within test criteria limits. In ~ Test : Condition Heatup, the adequacy of SRM - response to control rod withdrawal was verified - during the approach to initial criticality. Following initial-' s criticality, the SRMs were ' demonstrated-' to meet the system J
.non-saturation design-requirements.
To assure that the' SRMs were functioning properly prior to withdrawing control rods to achieve initial criticality...the signal-to-noise ratio of. each SRM channel ' was measured.- -The-signal-to-noise ratio (S/N) was determined by recording the channel readings with the SRM detector fully inserted and also in the ' fully withdrawn position. The results are summarized below.
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4 SOURCE RANCE MONITOR PERFORMANCE N2-SUT-6 C. (Cont'd) i y Signal + Noise fiBM ' Noise Count Rate (ces) fil}[ A 0.1 100 999 B 0.1 60 599 ; u C- 0.1 95 949 l j D 0.1 110 1099
~
The. Signal + Noise count race is the minimum count rate achieved- j with the SRM fully inserted, no control rods withdrawn. i As control' rods were withdrawn to achieve criticality, inverse-multiplication plots (1/m) were updated to assure that. criticality would be achieved in a controlled manner. SRM count
. rate vs. notches withdrawn were recorded to demonstrate.that the .j SRMs' adequately monitored core reactivity changes..
Following initial' criticality, reactor power was increased, with ' the SRMs partially withdrawn, such that the fully inserted SRM neutron flux reading wculd be . greater than 300,000 cps. Each SRM channel was. bypassed and : its detector lnserted individually, until a reading of at least 300,000 . cps .was' indicated and then the detector was withdrawn - to its original' position. All SRM channels were demonstrated not to saturate at up to 300,000 cps. Upon completion of the non-saturation demonstration, the SRM rod block and scram .s e t points were raised to the normal Technical Specification values of 100,000 cps . and 200,000 - cps , respectively.. (Initially, the scram and rod block SRM setpoints had been conservatively set to 1. 8 - 2.8 x 104 cps and 0.8 - 1.6 x 104 cps respectively.) The RPS shorting links remained out throughout these tests and were not installed until both the full core shutdown margin and IRM operability had been successfully demonstrated. 1 1 1
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- j. --IRM PERFORMANCE-N2-SUT-10 J
3.' 7 N2-SUT-10 IRM PERFORMANCE A. OBJECTIVES L1 - g Check IRM Scram Setpoints - and adjust, the continuity between its
~
lower and. upper ranges'(i.e. RangeL6/7).
- 1. - -Ensure that there is an adequate overlap ' in power . level between IRMs and APRMs.
- 2. Reverify adequate SRM/IRM overlap.
B.. ACCEPTANCE CRITERIA
' Level 1 1.. . Each .IRM m . ust provide a reactor . scram' asL apecified in the-
-Technical Specifications with '. the reactor mode switch in -
startup.
- 2. Each APRM must be on scale before the IRMs exceed . their upscale-rod b1'ock setpoint.
Level 2 L 1. Each IRM must be adjusted so that at least a half decade overlap with the SRMs and a one decade ' overlap with the ' APRMs is assured. C. DISCUSSION Test Condit4nn Nantun In Test Condition Heatup two items were accomplished during IRM-Performance Testing.- The first was that the scram setpoint for each IRM was checked and found.to satisfy the Level 1 acceptance criteria of ~ 1ess than . or equal' to 120/125 ths. All IRM scram setpoints were found to be 119/125- ths. The second item accomplished was a verification of proper: IRM Range: 6/7 correlation, i.e., acceptable continuity between the low frequency amplifier (for Ranges 1-6) and the - high frequency amplifier (for Ranges 7-10)' sections for each IRM voltage preamp. This was accomplished by adjusting R44 on the voltage preamp such that Range 7 read one-tenth (11.2/40ths) of. the Range 6 reading. The adjustment on each IRM was made~at steady state conditions between 60/125 the and 80/125 the on Range 6. .
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m .. c.. IBM PERFORMANCE
, N2-SUT-10 C._. (Cont'd)
Test Condition 1 Test -Condition 1. IRM - Performance' Testing : accomplished' three
. tasks. The first was to. again verify that..'thee IRM scram t
setpoints ; met ' the Level .1 acceptance criteria.. The-secondrtask. was. to verify proper IRM/APRM overlap. . The third ' task was to verify. proper SRM/IRM overlap. e The: scram setooint for each IRM was checked and foundL to satisfy ' the Level 1- acceptance criteria-'of ~ less than or equal- to =120/125 ' ( ,
.ths. AllLIRM scram setpoints were found to be 118-120/125 ths.
The - method f used to adjust IRMs inforder to establish the one -
= decade of overlap .with the APRMs was intended to result 'in' the -
, -fo11owing. relationship. '
IRM'nanee 10 n== dine APRM Reading 12.5/125-ths 3% 125/125 ths- .30% The adjustment procedure performed the following steps:
- 1) APRMs were calibrated per- heat balance performed near '20% .
power. L A desired IRM reading (based on the aforementioned IRM/APRM ~ 2)- relationship) was calculated based on the average'APRM reading.' ,
- 3) Each IRM was individually bypassed and' fully inserted.
- 4) The IRM gain was adjusted . (using R1) as required to obtain the desired IRM Range 10 reading (-O, +5/125 ths).
- 5) Once all IRM gains were adjusted, reactor power was reduced and IRM/APRM overlap verified.
At 18% power, . the amplifier alternator module gain on IRMs h A,B,C,D,F and H _were adjusted to - make these IRMs read the { desired IRM reading on Range 10. (Note: All IRMs were set ' to maximum gaJn prior - to initial criticality.) The IRM . E ' reading i was found to - be less than the desired IRM reading. Test Exception 1 was written and later accepted based on the fact that IRM E was capable of tracking reactor flux. IRM G could ' .
~
'not be adjusted at this time since IRM E was tagged out and bypassed (Operations had conservatively decided to declare IRM E g inoperative). Its t, sin was adjusted later at 17% power to the new' desired IRM reading on Range 10.
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IRM PERFORMANCE
- b N2-SUT C. E(Cont'd)
~
Following . the ' gain adjustments, .. deactor ; power - was reduced l to where the highest reading IRM _was reading 'less- than or equal to
' 12.5/125 the on Range 10.. (See Table : 3.7-1. ) The ' reading 'of
- each IRM . and APRM 'was recorded. - Each APRM- was reading on-scale -
while each. IRM'was ' reading less than its upscale? rod - block setpoint' (108/125 'ths .on . Range. 10), thus . satisfying the applicable- Level. 1 acceptance criteria. .While all 'IRMs were l reading less than.or equal to 12.5/125 ths.on_ Range 10s the-APRMs were not reading. greater than ' 3% which indicated. an .'IRM/APRM overlap,of.less than'one decade as previously. defined and did not' satisfy ' the Level 2 . acceptance criteria. Test Exception 2 was: written and later accepted.as'is.- The imethod . utilized ato evaluate 'SRM/IRM overlap was ' t'o' increase-power (duringL a startup) until all IRMs or. at ' lesst 3 ? IRMs ' in each: RPS Trip; Channel had l exceeded the downscale. Technical. i Specification allowable setpoint. (23/125 ths) or : for those IRMs ~ that were .already on ' scale had increased by 3/125? ths of scale. (See Table ' 3. 7-1. )
~
IRMs ' A, D, . E, ' F and H either cleared. their. downscale setpoint D er . increased by at; least 3/125 from their initial reading - before any ' SRM : reading exceeded ; 5 x 10 4 eps, thus . demonstrating 'at - least a half-decade overlap between ; the SRMs and IRMs. .IRMs B, C, and G were initially on scale. but . their readings did not increase by at least' 3/125' before a ' SRM ' reading exceeded 5 x .10 0 cps'. Test Exception 3 was written and accepted as is since these -IRMs were on scale and their readings - did increase, demonstrating a response to neutron flux changes.
~
Test Exceptions and their resolutions are susanarized in Table. 3.7-2.-
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IAELE 3.7-1 IRM PERFORMANCE 1 i N2-SUT-10 g OVERLAP DEMONSTRATION DATA i Readings'11uring IRM/APRM Overlap Demonstration.. IEH** AEBM (%). A 5.0 'A' 1.8 ! B 5.0 B 1.8 C 11.0 0 2.0 D 12.5 D 1.5 E 9.0 E 1.7 F 10.0 F 1.8 G 7.5 H 10.0 Readings During SRM/IRM Overlap Demonstration- . . Initial Final Reading- Reading. SRM (CPS) IRM* IRM* A. 5.0 x 100 A 2.0 A 6.0 B 2.5 x 104 B 7.0 eB 8.0 C 3.0'x 104 C 5.0 ec 7.0 D 4.2 x 104 D 7.0 D 12.5 E 8.0 E 15.0 F 6.0 ~F 12.0-G 5.0 eG 7.5 H 6.0 H 12.0
- Range 1 (0-125) All SRM/IRM readings are " Full In" readings. i
** Range 10 (0-125) e See Table 3.7-2 TE No. 3 i.
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, .g TABLE 3.7-2. ,
- I IRM PERFORMANCE N2-SUT-10 TEST EXCEPTION. Sulf 1ARY j p
Test Test Excention Condition. Description 1- 1 IRM E could not be adjusted to the des 1 red reading.. i a- IRM G.could not be-tested sincel.IRM E was tagged out. and bypassed. IRM E was accepted as :is: since i it does track neutron flux changes. IRM G was
~
satisfactorily tested when the tag out on" IRM E was cleared. 2 1: At least once decade of IRM/APRM overlap could not be demonstrated. Overlap was determined. to be adequate and was accepted as is because:
- 1) Tech Spec requirements for 1/2. decade ]
overlap are satisfied with ample - margin' as ~ ~ '. i demonstrated by N2-OSP-NMS-@001.
- 2) ' Further > IRM gain reduction may require SRM gain reduction and reducing SRM sensitivity is not desirable.
'i'
- 3) The current settings are quite satisfactory for transfer of the reactor mode switch from "Startup" to "Run".
- 4) Several sets of adjustments and ratests might be required to meet both the' overlap requirements with little practical gain.
3 1 The readings of IRMs B, C and G did not increase by at least 3/125 before a SRM reading . exceeded 5x 104 during SRM/IRM overlap reverification. Accepted as is since - the specified minimum increase of 3/125 was an arbitrary number and these IRMs were' on scale. The intent of this step was to . increase power to the point that the IRMs had exceeded the tech spec allowable downscale setpoint prior to overlap data being recorded. For those IRMs that had already cleared the dcwnscale prior to the start of the test, power would be raised to also allow their readings to increase so that it was evident the instruments were- responding to neutron flux at the point overlap data was recorded. The amount of , increase was arbitrarily selected, therefore any increase noted is technically acceptable. g
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[6 LPRM CALIBRATION TEST lN2-SUT-11 3.8' N2-SUT-11 LPRM CALIBRATION-TEST A..
~'
- t. OBJECTIVES
- 1. Verify thAt; the LPRM detectors - are' properly connected . to:
.the rest of the LPRM System.
- 2. Calibrate the LPRM System. u Lp -l B. ACCEPTANCE CRITERIA
.f? Level 1 Not' Applicable
- Level- 2: .;
Each LPRM reading is within 10% of'its calculated value. _. 4 ' C.. DISCUSSION g' In Test - Condition 1 proper connection of.. each LPRM detector was-verified by , examining the. reading .of each deteetor in the LPRM -
, string . being . tested - as an adjacent control rod was withdrawn ' 4 past the . detector and verifying that this reading. displayed an ! :f appropriate- change. All LPRMs displayed ' proper response,-' thus j verifying proper.. connection.
The- LPRMs were calibrated per the site LRPM- calibration
. surveillance procedure in Test Conditions 2,3, and- 6~. In Test' 1
Condition. 2r (at 411 power), ' the LPRM. gain f adjustment factors- > (GAFs)-for all-but 3 LPRMs' were within ~ the 0.9-1.11 range, thus satisfying the Level 2' acceptance : criteria. LPRMs; 08-25A,- 24-25D and 24-57D had LPRM CAFs outside the 0.9-1.1 but this was - acceptable 'since a LPRM calibration was to be performed in Test Condition 3 (see Test Exception 1). In Test Condition 3.(at-66% power), the LPRM GAFs for' all but 2 LPRMs' were within the 0.9-1.1 range, thus satisfying the , Level 2 acceptance . criteria. L ' LPRMs .08-25D and 08-41D had GAFs outside the 0.9-1.1- range due to being bypassed and inoperable (see Test Exception '2). In. Test Condition 6 an .LPRM calibration was performed at 99.4% power. All but 3 LPRMs . were within the 0.9 to 1.1 range, . thus satisfying- the Level 2 acceptance criteria- (LPRMs- 08-41D, 08-25D, and 24-09B were bypassed). Test Exceptions and thejr resolutions are susunarized in Table .. 3.8-1.-
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TABLE 3.8-1
.LPRM CALIBRATION TEST N2-SUT-11 TEST EXCEPTION
SUMMARY
Test Test { Excentlon Condition Description 1- 2 LPRMs 08-25A, 24-25D and 24-57D had. LPRM GAFs outside the 0.9-1.1 range. . Accepted..as is since i test would be repeated in the next test condition.- 2 3 LPRMs 08-25D and' 08-41D had LPRM GAFs outside the was verified- from the i plant. surveillance procedures l to . be riess, than 15%'of rated thermal power.- APRM ' calibrations were , performed again,. in -Test Conditionf ifat - 18% power, . Test ~ Condition': 2 at'.28% power, Test' Condition 3; at 65% power,-Test: Condition;5 at'65% power and Test Condition 6 at-98.1% . power. . In all Test ' Conditions except T.C.2, all Level 1
.and 2 criteria were satisfied.'- In T.C.2, the APRMs were set
.high due to Technical' Specification. requirements-and thus failed the
- Level 2 Criteria. '(See Test Exception ,1;) -(The APRMs read' approxianately 6% higher than actual thermal power.)
In Test Conditions 1, 2, 3, 5 and 6,.the scram setpointsLand. Rod Block Trip Setpoints were_ verified to not exceed.their~ values in
' Technical Specifications,'thus meeting Leve111' Criteria *. ,
Test Exceptions and - their resolutions are summarized in Table. 3.9-1.
- Rated Core Flow was exceeded during ' Test - Conditions 3 and - 6 resulting - in an acceptance criteria violation' in ---RPSP-1. This can be accepted as is based upon the . Supplemental Final Startup Report.
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n, TABLE 3.9-1 j , APRM CALIBRATION N2-SUT-12 TEST EXCEPTION SG MARY Test Test
; Excention Condition ' Description
-1 2 The "As Left" APRM readings were greater than a fraction of rated power by more than 2% as a result-of APRM gain adjustments to- comply with the Technical Specification 3.2.2 action requirement when CMFLPD (Core Maximum Fraction of Limiting Power Density) exceeds FRTP (Fraction of Rated Thermal Power). Subsequent to the performance ~ of this test, CMFLPD dropped below.-FRTP and the APRMS were adjusted to be within 2% of FRTP.
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lIe :l C PROCESS C(EEPUTER !, N2-SUT-13 L 3.10- N2-SUT-13 PROCESS COMPUTER A. OBJECTIVIE~
- 1. Verify proper operation. of the TIP- System / Process. Computer j interface and NSS program OD-1.
.2.- .
Verify proper TIP:- axial alignment .while .-in cold and : hut
' conditions.-
3-. Verify. operability' of. NSS program '0D-8, .Present. LPRM Readings. 4.. . Verify operability . of- most ' of- .the NSS periodic and :- on-demand programs by . performing the - Dynamic System Test-Case.
- 5. - Verify that the ' Process Computer can : correctly calculate _
themal limits between 20 - 100% power. 6., Verify operability , of NSS- programs OD (specified LPRM
' . Substitute Value - and Base Distribution) - and OD-9 (Axial Interpolation Data).-
r 7. Verify that P1 can operate . under : asynsnetrical control rod pattern conditions.-
- 8. Verify proper operation of OD-11 (PCIOMR)0 during steady state conditions.
- 9. Verify proper- operation of- OD-11 during fuel preconditioning ramping.
- 10. Verify that the Process Computer can accurately track large changes in reactor power.
a 4 1
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p f4! PROCESS CGEPUTER N2-SUT-13' B. ACCEPTANCE CRITERIA Level 1
'None Level 2
- 1. The MCPR calculated by BUCLE and the process- computer either:
.a. .Are in ' the same. fuel assembly and do not differ in value by more than 2%, or a
- b. For- the case in which the MCPR calculated' by the process computer 'is in a different assembly than that calculated by- BUCLE, for each - assembly, the MCPR and CPR calculated by the two: methods shall agree within .
.2%.
- 2. The maximum LHGR' calculated by BUCLE and the process computer either* '
gj
- a. Are in the same fuel assembly and do not differ in.
value by more than 2%, or
- b. For the case in which the maximum LHGR calculated by the process ' computer is - in a different assembly than that calculated by BUCLE, for each assembly,. the maximum LHGR and LHGR calculated by the two methods shall agree within 2%. ,
- 3. The MAPLHGR calculated by BUCLE and the process. computer either:-
- a. Are- in the same fuel assembly and do not , differ in value by more than 2%, or
- b. For the case in which the MAPLHGR calculated by the process computer is in a different assembly than that calculated by BUCLE, for each assembly, the MAPLHGR and APLHGR calculated by the two methods shall agree within 2%.
- 4. The LPRM calibration factors calculated by BUCLE and the process computer agree to within 2%.
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T m y. a ... (: . h' PROCESS'CCMPUTER
!. - N2-SUT p C. DISCUSSION Test condition Onen Vessel In: order to perform this - test during. Test Condition Open -Vassel . (i.e. , ' plant shutdown), simulated . signals were input into the Process Computer (P.C. ) for those _ plant parameters - that are -
scannedand used; by the P.C.'s NSS OD-1.' software. OD-1?s responses to various TIP System operational: errors, to various-OD-1 operator errors' and to1 variousi plant conditions 'were checked and demonstrated to be correct. Several problems were found with the ' interface between the P.C. and;the TIP System which required changes'to.the interconnecting wiring and also to the'P.C. NSS software. Problems: were also found with several P.C. - data bank variables and their values were changed accordingly. .
. A cold 'TIP axial alignment :per plant -procedure N2-RAP-4'
-(Sections 7.1.3 thru 7.1.5) to set values of NCCT, NCFI and NCCB was performed.
Test Condition Heatup The value of NCFI for each plumbed channel on each TIP. machine in the hot. condition was determined by hand cranking the TIP to -q the physical top of the TIP Tube and recording the reading on the . TIP . control console - display. This hot value of NCFI was - then compared to the cold value for'each plumbed channel on each. TIP machine and if'they differed by'more than'1 inch, the values of NCCB and NCCT for the TIP channel were adjusted. by . this; difference as long' as this adjustment did not cause: ITURN (NCFI-NCCT) to be less than 2 inches. Adjustments to NCCB and NCCT were performed on 21 of 47 TIP channels. Test Condition 1 The distance between the fourth fuel spacer and NCCB was measured during hot conditions at approximately 18%. power for? each plumbed channel on each TIP - machine. Each spacer .to NCCB distance was measured by first generating a TIP Trace of the channel on the . TIP X-Y plotter, moving the TIP back into the core until TIP X-Y plotter pen was located at the dip on the TIP Trace corresponding to the fourth fuel spacer, - recording - the' reading on the TIP control console display, and subtracting NCCB from it. This measured distance was then compared to the actual .
-73 'em as
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FROCESS C(MPUTER N2-SUT-13. , ;C. Test condition 1 (Cont'd)
. distance and 'if they. differed by more than 1 inch, the: values of-
' ~
- NCCB and. NCCT for . theichannel- were adjusted by - this difference
~ ~
as 'long as, this adjustment did not cause ITURN to be' less than 2 pi inches.. Channels l ': and ' 3 on TIP machine' AL were the ' only: { channels that required adjustments to NCCB and NCCT. Following; the adjustments to NCCB . and NCCT, .' 0D-1 was th'en run
- for channels.1~' and 101 on each . TIP machine and TIP traces:were obtained , for' these traverses. For each of these channels',T the raw TIP fluxes:at the ~ LPRM. levels seen by the . Process . Computer -
andt the TIP ' X-Y plotter .were then compared. = It wasLexpected : that' these. rawf TIP- fluxes would agree: within -10%; however, several differed by more: than 10%. This was L determined ~ not to be a problem.due to the very low power levels.at these LPRMs.'
- Proper operation' 'of OD-8 was verified at 17% power by: comparing the LPRM readings from an OD-8 edit ~with theLLPRM meter readings- .
and verifying that they agreed within 11. All but! three. LPRMs . (24-09A, 40-09A and . 32-57A) had readings that agreed 'within .1%. Troubleshooting on LPRMs 24-09A . and 40-09A'found' no : problems.7 t A . I~ loose: computer board' on LPRM 32-57A was discovered. Upon retest, the ~ OD-8 and LPRM J meter: readings .did agree withini 1%. OD-8 was declared operational upon completion'of'this test. Test Condition 2-The: Dynamic L System Test ' Case was performed during steady state . conditions at 22% power. . Proper operation of most of : the NSS programs was _ verified in this test by comparing their outputs . against manual calculations, off-line - computer calculations, and : outputs from ' other programs. The following - NSS programs ;were q declared operational at the completion of . this test: P2, P3, . ) P4, PS, CD-3, OD-5, OD-7, OD-10, OD-13, OD-14, OD-15, OD-18 and OD-20. Problems were found with NSS programs P4, PS, and OD-20, with the. control rod processing progract NCL -and with the Alarm Processing Analog (APA) program. Appropriate software changes ' were made ' to correct these problems. A problem was also found ? with the P.C. data bank variable CPM and its value was changed. accordingly.
.The' ability of the Process Computer to correctly calculate
~
thermal limits between 20-25% power was demonstrated during steady state conditions at 23% power by verifying that the .I values of MCPR, Maximum LEGR (MRPD), MAPLHGR and LPRM GAFs ' calculated by ' the Process Computer agreed within 2% of those values calculated by the off-line computer program BUCLE. V
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PROCESS COMPUTER N2-SUT-13 C. Test condition 2 (Cont'd) Proper operation of OD-16 was also verified during this' test by
. comparing its output with manual calculations and outputs from other- programs. The following programs were declared operational at the completion, of this test: P1, 0D-1, OD-6 and OD-16.
Proper operation of OD-2 and OD-9 was verified at 43% power by - comparing their outputs with manual calculations and outputs-from other programs. OD-2 and OD-9 were declared operational at the completion of this test. Test Condition 3 The ability of 'the Process Computer to correctly calculate thermal limits between 45-50% power was. demonstrated during-steady state conditions at 48% power by verifying that the , thermal limits calculated by the Process Computer agreed within 2% of the values calculated by BUCLE. The ability of P1 to operate properly with an asynnetric control rod pattern was demonstrated during steady state conditions at 74% power by verifying that the thermal limit and ' bundle power values calculated by an asymmetric P1 agreed within 15% of those calculated by a symmetric Pl. These P1's were both run with the same control rod pattern. Symmetry for P1 was controlled by changing the value of the control rod symmetry flag iqs (CRSYM on P1 edit). The ability of the P.C. to correctly calculate . thermal limits between 70-75% power was demonstrated during steady state conditions at 74% power. Static Testing of OD-11 was conducted during steady state conditions at 74% power. Proper operation of the following OD-11 functions was verified by comparing their outputs ' with manual calculations and outputs from other programs: data editing, envelope updating, predictive overpower model for control rod withdrawals (of 1, 2, or - 3 notches), automatic L alarms and automati: program initiations. One problem was discovered with the control rod processing routine NCL; it was not sending control rod insertion information to OD-11 and the software was corrected.
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\..
b LC.L Test twMtion 6 (Cont'd) . Section . 6.1 of ' Startup Test - 'N2-SUT-16-6,- Dynamic OD-l'1 testing during fuel preconditioning ramps was" deleted as a result of t-difficulties encountered during the initial test attempt.- This-testing will , be . performed at a later date by Special Test TP. 88-10.
~
The thermal L limits calculated by. OD-4 and OD-6 vere compared with each other and those f calculated by; OD-4, - OD-5,1 and OD-6' were compared with P1 during steady state . conditions' at , 60% power.. It was. denkrastrated .that the ' outputs - of these? NSS programs agreed with each other. iNext, core flow was increased
. causing reactor. power to increase from 61%' to: 84%. Once steady state conditions were reached at 84% power, . the thermal ' limits 7 comparisons . described above were repeated and demonstrated ' that the outputs of these : programs . agreed with each other. At ' 98%
power, control rods were- inserted causing reactor power to decrease to !71%. Once steady state conditions were reached at ; ,
- 71% power, the thermal - limits . comparisons '. were ' repeated again and demonstrated that the outputs of these programs agreed with each other. This ~ test verified ' that the Process ~ Computer' can accurately track large power changes.
The ability of the ' P.C. to correctly calculate thermal limits between 95-100% power was demonstrated 'during steady state-conditions.at 98% power. Fuel bundle isotopic data (OD-12) and the values stored in ' Data - J Classes 4 ' through 20 were dumped to magnetic tape during1 steady. state conditions at 99% power. .This information was transmitted . 4 to San Jose for detailed analysis. :The fuel bundle serial - numbers and exposures and batch exposures used by OD-12 were - p verified to be correct. ,, Test Exceptions and their resolutions are summarised in Table 3.10-1.
/
-76 .
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' PROCESS CGEPUTER L
'N2-SUT-13 TEST EICEPTIGf SMWi&RY Test. . Test Excention' Condition Description
-.1 ! OV Initial 10D-1 edit. ' discovered "to be missing during test results revie.w; however, . further _ investigation ~
revealed that. the. edit :was not generated (i.e.,
. procedure step was incorrect).
'2 1 LPRM readings on OD-8 edit- and LPRM meters. did not agree within 1% ' for .3 LPRMs. . Af ter troubleshooting -
and retest, they agreed within 11.
. 3 1 Raw TIP flux seen by Process Computer did not agree :
within 10% of the ' value seen by TIP X-Y plotter : at' several LPRM locations.- Accepted 'as is - due to the . ,
-low power' levels at these LPRM locations..
4- 2 MFLCPR on P1 and OD-6 edits did not agree due to"the existence -of. a temporary software . patch in Pl. Following removal of.the patch and retest, MFLCPR on-P1 and OD-6 edits,did agreel: 5- 2 ATSP values calculated by Process Computer did ' not agree with hand calculated values =due to an 1 inadvertent' operation .of OD-18.: Accepted -as is
.since these ATSP calculations were checked 'again
~
later in the test.
. ~6 2' P1 inadvertently . operated during ' test. Subsequent '
calculations 'affacted by this - were calculated by.
. updated equations. Accepted as is.
7- 2 CT(I) 4 0 for failed sensors 12-15' due to the last
' scanned values being within their reasonable upper and lower limits. Accepted as is since software worked correctly.
- 8. 2 Time between P1 and P2 was not approximately 1 hour. Accepted as is since this time does not r.ffect results or scalysis.
-77 ,
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i y __ TABLE 3.10-1 (Cont'd) FROCESS COMPUTER l
-N2-SUT-13 l 1
TEST EECEPTION SM91&RY ) Test Test Exceotion Condition Description 9 3 OD-11 incorrectly' automatically initiated P1 following control rod insertion. The sof tware was ! corrected and proper OD-11 operation. was observed during retest. 10 6 The values of WLO & WHI were found to be equal to zero and not updating. The computer address checked were not the correct addresses. Retest demonstrated that these values were updating properly. 11 6 Problems encountered with OD-11, Option 8 prevented completion of testing until sof tware troubleshooting ~ is completed. This portion of N2-SUT-13-6 (Section 6.1) ~ was deleted by TCN and deferred until . af ter completion of software trouble shooting. . Temporary Procedure TP 88-10 will complete this ter: ting. TP 88-10 was performed during the plant restart following the spring outage. I
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RCIC SYSTDI I .N2-SUT-14 3.11 N2-SUT-14 RCIC SYST1!M A. OBJECTIVES
- 1. Verify the proper operation of the ~ RCIC System over its expected operating pressure and flow ranges. ,
t
- 2. Demonstrate , system reliability when automatically starting. l from cold standby conditions with the reactor operating at power.
B. ACCEPTANCE CRITERIA Level 1
- 1. The average pump discharge flow must be equal to or greater than the 100 percent rated value after 30 seconds have elapsed from automatic initiation at any reactor pressure ,
between 150 psig and rated.
- 2. The RCIC turbine shall not trip or isolate during auto or manual starts.
Level 2
- 1. In order to provide an overspeed trip avoidance margin, the transient start first and subsequent speed peaks shall not exceed 5 percent above the rated RCIC . turbine speed' (4777 RPM).
- 2. The speed and flow control loops shall be adjusted so 3that the decay ratio of any RCIC system-related variable is not greater than 0.25.
- 3. The turbine gland seal condenser system shall be capable o.f preventing steam leakage to the atmosphere.
- 4. The;AP switches for the RCIC steam supply line . high-flow isolation trip is calibrated to actuate at 300 percent of the maximum required steady-state flow.
i
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f* f RCIC SYSTEM b'.' N2-SUT-14 C. DISCUSSION The RCIC system was tested in Test Condition (TC) Heatup, TC-1 and TC-2 in four different configurations. Those configurations were as follows:
- 1. System flow to the Condensate Storage Tank (CST) via the full flow test line with the Reactor Pressure Vessel (RPV) steam dome pressure at'150 psig.
~
- 2. System flow to the CST via the full flow test line with the RPV steam dome pressure at rated.
- 3. System flow to the RPV with RPV steam dome pressure at 150 psig.
- 4. . System flow to the RPV with RPV steam dome pressure at rated. .
In all, a total of 8 automatic initiation tests were conducted to demonstrate RCIC system . performance. The attached Table 3.11-1 summarizes the results of those tests. Final RCIC controller settings were determined during testing in TC-HU and' all' later test runs were performed with these settings. Table 3.11-2 sununarizes the final RCIC control system settings. The reliability of - the RCIC system was well demonstrated by. neither tripping or. isolating during any of' the manual or automatic initiation tests. Rated pump discharge flow (600 gpm) was achieved within 30 seconds for all RCIC automatic initiations at reactor pressures between 150 psig and 953 psig with one exception. When performing a cold auto start test.with injection into the CST at 153 psig reactor pressure, the time to rated flow was 38.6 f' seconds.- The excess time was attributable to the combination of high fluid resistance provided by the CST test return flow path, the low reactor pressure and the additional time required to pressurize the steam line between the steam admission. valve and the turbine during a cold start. An earlier cold auto start at 161 psig with injection to the RPV achieved rated flow in 28.9 seconds.
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L, RCIC SYSTEM N2-SUT-14 C. -(Cont'd): This L test experience confirmed similar results obtained 'during earlier testing at . low reactor pressure with injection to the CST. Pump discharge- pressure could not be lowered to the specified range, reactor pressure +100 (-0, +20) psig, although the CST test return throttle valve, 2ICS*FV108, was full open. This. situation poses no safety concern and only effects surveillance testing at low - reactor pressure. The FSAR was changed accordingly to allow a higher pump discharge pressure. Peak. turbine speed was less than 4777 rpm for all test runs-except during a cold auto-start with injection to the CST at 923 psig reactor pressure. During this test run, a speed of 4882 rpm was reached. This turbine speed was required to achieve 600 gpm because the discharge pressure reached 1370 psig as a result
.of mispositioning the test return valve at 33% rather than 35%
open. It .should be noted that a margin of 578 rpm to the , overspeed trip setpoint (5460 rpm) was maintained. The decay ratios for RCIC system related variables during flow changes and . steady-state operation were always less than 0.25. However, during an initial test run in TC-HU with the turbine operating in the speed range of 1800 to 2000 rpm ( 200 gpm at rated reactor pressure), the turbine entered into a sustained 2 - to 3 Hz limit cycle which produced a peak-to-peak flow and' speed oscillation.of 12 gpm and 120 rpm respectively. The oscillation was attributable to an interaction between the turbine speed f l pulse signal and the GETARs Validyne Carrier Modulator frequency (3 KHz) being used to monitor turbine speed. Replacing the Validyne Carrier Modulator / Carrier Demodulator pair with a Validyne Buffer Amplifier eliminated the induced speed oscillation. l Several small steam leaks were found at turbine sealing surfaces including the RCIC governor valve and the trip-throttle valve. , The leakage was minimal and did not present a radiological l hazard. Correction of the leakage was made in subsequent outages. The RCIC system steam supply flow element delta P values were measured following an automatic cold start with injection to the CST at rated RPV pressure. A new trip setpoint of 167.2 IN WC was calculated, for which a change to the plant Technical Specifications was submitted. In the interim, the RCIC steam line high flow trip setpoint was changed to the new trip setpoint. This setpoint renge is conservative relative to the -
~
Technical Specification value of 184.5 IN WC. 'qu
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N2-SUT-14
.+ ,
C.i '(Con t ' d ) -- Operation of RCIC from the Remote Shutdown . Panel .(RSP)-; was =
~
successfully demonstrated. . Control of RCIC. was transferred- to the RSP, the turbine wasf auto started andi pump flow varied by . the .' flow controller. Stable operation was verified throughout
, the test run.-
i; , Test, Exceptions and their ~ resolutions are summarized . in Table' 3.11-3. e a .-:o<m m-ma+<-u .m.-rae O
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EK n n SA t o o i T h N N h h .h h h w t h W S N e O l I b T a e 'e a . . . a A t n n n n n n a L n o o a a L I e c N N N N E m h C c S A O E KND) 8 7 2 2 0 0 2 6 AI EM 9 4 6 2 0 0 8 8 EBEP 6 7 6 6 6 6 8 7 PRPR 4 2 2 4 4 4 4 2 US( T O ~ G T ' N DW) 9 1 9' 6 7 9 0 6 I EEOC . T MTLE 3 4 8 4 4 . 4 7 8 - _- S I AFS 2 2 2 2 2 2 2 3 E TR ( T M E 1 M E N? i
- E 4 T CI P 1
T 1 S I BI O O O O O O O O .- 1 S Y CRR N N N N N N N N Y T- S RUT 3 S U T _ S C _ E C - I L I 2 C B C N R KT D T D D D D A R E CR T T L O L L L L T F PFI A O O O H O O O O O YOUT H H C C C C C T QS Y R A M f - U CN S EOO T T V V V V T T JI T S S P P P P S S NT C C R R R R C C I 3 R PE MGE URR) PAUG 0 0 0 5 0 0 0 0 HSI 9 2 7 3 2 6 7 5 CCSS 0 3 2 0 1 0 3 3 I SEP 1 1 1 1 1 CI R( RDP E R) VUC 3 0 1 1 4 5 3 2 3 PSI 5 5 6 2 2 4 5 RSS 9 1 1 9 9 9 9 1 EP R( P C U U 1 1 1 1 1 2 T H H l Y
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TABLE f.11-2 RCIC SYSTEM f l N2-SUT-14
~
FINAL ROIC CONTROL SYSTEM SETTINGS Dial Actual Flow Controller Control Room, E51-R600 Gain 0.2 0.14 Reset, R/M 31 31 Rate 0 0 Remote Shutdown Panel, E61-R001 PB 500% 500% I 0.031 0.029 D 0 0 .. RCIC Speed Loop EGM Gain 7 7 Stability Plot' 7 7 Needle Valve, CCW 1/2 turn 1/2 turn
-84 _
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IT , \; TABLE 3.11-3 RCIC SYSTEM N2-SUT-14 TEST EXCEPTION SUttiARY Test- Test Excention Condition Description i HU Various RCIC related system parameters had decay ratios greater than 0.25 in the speed range of 1300-2000 rpm. Oscillations were found to be caused by interaction between speed control loop and GETARs. A modification to the GETARs signal conditioning eliminated this problem. 2 HU Three steam leaks were observed during CST injection at rated pressure. A Maintenance Work Request was initiated to address this deficiency and corrective action was taken. 3 HU RCIC pump discharge , pressure was 136 psi above reactor pressure during CST hot quick start at rated-pressure, as opposed to' the required 100-120 psi above reactor pressure. An FSAR' change was submitted to resolve this problem. 4 HU RCIC pump discharge pressure was 170 psi above reactor pressure during CST hot quick start at 150 psig vessel pressure. This was the minimum pressur. that could be achieved as the CST throttle return valve was fully open. The test procedure requires ! 100-120 psi above reactor pressure. A FSAR change was submitted to resolve this problem. 5 1 A steam leak was noted on the governor valve during KCIC injection to the reactor at rated pressure. A Maintenance Work Request was initiated to address this deficiency and corrective action was taken. 6 1 A steam leak was noted on the trip throttle valve during RCIC injection to the CST at rated pressure. A Maintenance Work Request was initiated. to address this deficiency and corrective action was taken. 7 1 The RCIC speed peak was greater than the 4777 rpm Level 2 Criteria during the cold quick start to the CST at rated reactor pressure. Accepted as is, due to the CST throttle return valve being mispositioned.
-85 ~ .
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l' I s l TABLE 3.11-3 (cont'd)
~RCIC SYSTEM i
N2-SUT-14 TEST EXCEPTION SUfMARY
. Test Test Exception Condition Description j I
8' 2 The time to rated flow during cold quick start to I the CST at 150' psig reactor pressure was greater than ' 30 seconds. This was accepted as is, due to the. high fluid resistance provided by the CST test - return flow and as during the cold quick start to the Reactor Vessel, at 150 psig, rated flow was' reached in the required time. 9 2 Steam leaks on the RCIC turbine were noted during the CST cold quick start at. 150 psig vessel pressure. A Maintenance Work Request was initiated to. address this deficiency and corrective action'was ,
.taken.
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SELECTED FROCE88 TEMPERATURES AND WATER ~ LEVEL MEASUREMENTS
.N2-SUT-16
-3.12 N2-SUT-16 SELECTED PROCESS TEMPERATURES AND WATER LEVEL MEASUREMENTS 'i A.: OBJECTIVES .{
1.: To ensure that the measured bottom ' head ' drain temperature' corresponds to bottom head.. coolant . temperature Lduring:
;j.7 normal operations.
- 2. To identify any- reactor operating modes. that cause.
temperature stratification.
- 3. To determine. the proper setting of 7' the low flow. con'troli 1
i limiter for the. recirculation. pumps to avoid.-coolant temperature stratification in the reactor pressure vessel-bottom head region. ^ 4.: To familiarize plant personnel with t'emperature differential limitations of the reactor system.
- 5. To measure the reference and variable leg temperatures and '
. recalibrates the instruments if the measured temperatures-are i dif f erent ' f rom the values assumed during the initial calibration.
-B.- ACCEPTANCE CRITERIA Level 1 l'. The reactor. -recirculation pumps shall not' be started, flow-increased, nor power increased unless: the. coolant temperatures between the steam done and bottom head Ldrain .
are-with 145' F.
- 2. The recirculation pump in an idle loop must not be'. started, - '
active loop finw must not' be raised, and power must not .be increased unless the.? idle loop suction. temperature- is within 50'F of - the active loop suction temperature: and the . active loop flow rate is less than or equal to 50 percent of rated loop flow. If two pumps .are idle, the loop- q suction- temperature must be within 50*F of the steam dome ' .t temperature before pump startup. Level 2 . 1
- 1. During- two-pump operation at rated core flow, the bottom -{
head ~ coolant temperature as measured by the bottom drain -1 line thermocouple is within - 30*F of the recirculation loop i temperature.
-87 .
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. szLacrzo esocass TaurEaATURES AND WATER IMEL MEASURBGDrrS
-:. i; - N2-SUT-16 j i
- b ,B. . Level 2 .(Cont'd) 2.- The ' difference .between the actual . reference and. variable leg temperature (s) and the : value(s) asstaned : during" initial ~
.~ calibration shall be - less than that amount which' will>
, , result in a ' scale end point ' error of: 1 percent L of D the .
instrtsoent span for each range. C. "' DISCUSSION This j test was . ' performed ' in' ~ Test Conditions ' Hemtup, . 2,3,5 .and . 6'. During the hestup test phase, thei bottom headL drain : temperature
. -check was . ~ performed,'- stratification checks. were~ performed (during one . and L two recirculation pump operation), and water
--level' instrumentation endpoint calibrations' were - checked. ~ In Test Condition 2, water . level instrtssentation- endpoint calibrations were ' rechecked. In Test Condition ~ 3, water level instrumentation ' vatistion was ' evaluated at 104.5% ~ total ' core-flow : and.':,ay stratification check .was performed .while . in single ~~
loop - operation. In . Test Condition 5 ' stratification checks were - performed ~ during natural- circulation -' testing and - the recovery; to two loop operation. In Test Condition' 6 c the ' difference- between : Narrow andi Wide Range water level indication's were recorded' and - evaluated as a funetion of . total core flow . (see Table" 3.12-3)'. In : addition,- the ' difference -in Narrow. Range and Upset Range water level as a ~ function of Steam ? Flow.:(1001 rod line operation) was 1 evaluated and is shown on Figure; 3.12-4.The @ bottom head drain temperature check was also.reperformed as well' , L as performance of stratification checks' duringlone recirculation pump operation. All Level 1. Criteria were successfully ~ met. Test results for stratification checks ' are summarised on Table 3.12-1.' Test results- for water level instrumentation L endpoint - calibrations are summarized on- Table 3.13-2. ' Test' Exceptions - and their resolutions are simanarized on Table-3.12-5. l 1 l l
-88
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'4 TABLE 3.12-1 SELECTED PROCESS TEMPERATURES AND WATER LEVEL MEASUREMENTS -
L- N2-SUT-16 STRATIFICATION TEST RRRULTS' Maxistan DT
'TC HU- TC 3 TC 5 TC 6 Parameter Criteria 1 Pump. 1 Puen- 2 Pianna 1 Pump Steam Dome'to' Bottom-Head Drain Delta T 1 145'T '37.2'F 38.41'F- '48.88'F 40.84 Active'. Loop to Idle
- Loop Delta T I 50*F 7'F- 2.27'F 3.0*F -3.08'F s Steam-Dome to Idle Loop Delta T'(If two.
pumps idle). 1.50'F N/A N/A 33.9'F N/A h ('
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, TARIE 3.12-2
, SELECTED PROCESS TEMPERATURES AND WATER LEVEL MEASUREMENTS
,N2-SUT-16 1
WATER LEVEL ENDPOINT CALIBRATIONS
- Assumed TC HU E_2 y i
- Upper Drywell. Temperature d
'(Narrow =and Wide Range Reference Leg)' 135 'F .' 154.4*F 132.2*FJ .
-N.trrow Range Variable u i-
' Leg Temperature 135'F 138.9'F. 120. 7.* F -
Wide Range Variable ] Leg Temperature. '135'F .110.35'F. 102.1*F. 3 Upset' Range Reference
-Leg Temperature; 135*F 149.5*F. 144'.1* F
~
Upset-Range' .q Variable. Leg Temperature 135'T 138.9'T 120.7'T l. Avg. Reactor Building
; Temperature; 75'T 88.1*F- 90. 7 'F. ' ,j Narrow Range'High Endpoint. ' a'
. Error: l<1%l' 1) -l.301 -0.9281 Narrow Range Low Endpoint J
Error _ l<11l 1) -1.30%~ ' -0.928%
"L Wide Range.High Endpoint Error l<11l- :0'.996% -0.84% .;
;i Wide Range Low Endpoint Error l<1%l 0.9971 , -0.'84% ],,
Upset Range High Endpoint Error l<1%l -1.29% -1.12%. Upset Range Low Endpoint Error l<1%l -1.29% -1.12% j l 9
*See Startup Test N2-SUT-75.for a discussion of Drywell Temperature Monitoring-
- 1) Actual value after recalculation in TC 2 (See TE 3) l
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- l Assumed TC HU E_2 Shutdown Range Reference
, Leg Temperature- -80*F 90.025'F N/A Shutdown Range Variable Leg Temperature 80*F 87.0'F - N/A Average Reactor Building Temperature 75'F 78.95'T li/A Shutdown Range High-
. Endpoint Error l<1%]- -0.034%~ N/A Shutdown Range Low
- 2ndpoint Error l<1%l WD.157% N/A.
Water Level Indications _EL E_3 E_1 E_.ft E_fi E1 Average Narrow Range Level 181.7' 183.14 182.9 183.5 183.8 185.1
. Average Wide Range Level 182.1 169.38 183.3 179.2 174.2 170.32 Average Upset Range Level 166 189 192 198 203 210-Total Core Flow (MLB/HR) 33' 112 52 74 '95 112 Total. Steam Flow (MLB/HR) 2.6 9.5 8.0 10.7 -12.6 14.5
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.m TABLE 3.12-5 . SELECTED PROCESS TEMPERATURES AND WATER LEVEL MEASUREMENTS N2-SUT-16 TEST EXCEPTION SIM ERY . Test Test , Exception Condition Description 1 HU Upset Range high and Low Endpoint errors above 1% limit. Exception accepted, as is, pending retest-after drywell cooling air-rebalancing (TC 2). 2 2- . Upset- Range . High and Low . Endpoint' errors . above .1% limit. Exception accepted as. is, endpoint errors are less'than the minimum readable value. 3- 2 A procedural . error was found in the equations used-to calculate the Narrow Range High and~ Low Endpoint ~ errors. The procedural error also 'affected the calculations done in TC HU. Correct calculation ~ showed that a Level 2 criterion violation had occurred in TC HU. Due. to improvements in Drywell Cooling, the Level 2 criterion is now satisfied. i i i 1 I i
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, .N2-SUT-17 t ,
3.131 N2-SUT-17: SYSTEM EXPANSION
'A. OBJECTIVE
- . l To deonstrate that: .
I' . . The piping ~ system during - system heatup and cooldown' is free to expand and.~ move without unplanned. obstruction or
. restraint.
I
- 2. The piping . does shake :down ^ af ter -- a few thermal . expansion cycles..
3.- The measured. values of displacement ' are within the -limits-
~
specified by the responsible piping design engineer. B .- ACCEPTANCE CRITERIA Level 1 _ a
- 1. There shall . be no' obstructions .which' will' interf are - with the. thermal expension of the Recirculation Piping System.
- 2. l The - displacements at ~ the established' transducer locations shall not exceed the. allowable values as provided' by the G.E. Plant Piping Design? Subsection. The' allowable values of displacement shall .be based on not exceeding AS.4E Section III-Code Stress allowables.
. Level'2'
- 1. The displacements at = the established transducer' locations -
shall not' exceed the expected values as ' provided by' the G.E. Plant Piping Design Subsection. C. DISCUSSION i This test consisted of measuring displacement of the Recirculation System Piping as it progresses from' cold, l ambient conditions to rated- temperature conditions. (approximately 528'F). Piping movement was checked 'at l every 50'F increase in piping temperature, starting at 200'F, to verify the piping was moving as predicted and wr.s unrestrained during expansion. During the test, displacement was measured by Lanyard Potentiometers . attached to the Recirculation Piping- at locations specified by G.E. Plant Piping Design.- ~These , locations are shown in Figures 3.13-1 and 3.13-2. A total of 25 Lanyard Potentiometers were used at 9 locations. g Each point monitored ~(except RAS) was instrumented ' with 3 Lanyard Potentiometers in orthogonal directions.
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L I SYSTEM EKPANSION N2-SUT-17 C. (Cont'd) Data from the Lanyard Potentiometers was processed by the GETAR's System and analyzed using ' the ' EXPAND' program. The
' EXPAND' software took into consideration instrument location and lanyard length. The software adjusted the Level 1 and Level 2 limits for actual piping temperature as compared to the criteria assumed piping temperature.
Recirculation Piping hangers, snubbers and whip restraints were evaluated in the- BOP System Expansion Startup Test,. N2-SUT-78-HU. Piping walkdowns for the Recirculation System were conducted under both System Expansion Tests. On May 19th, 1987, cold, ambient data at 106'T recirculation piping temperature was obtained. This data was used as baseline data for all subsequent displacement calculations during the first heatup cycle. A piping walkdown was conducted to identify , any potential obstructions to thermal expansion. Several Recirculation potential interferences were discovered on the 'A' Loop and were reworked to achieve the proper clearance prior to heating up the piping. On May 23rd, the reactor was taken critical. On May 24th, the recirculation system piping was-heated up to 195'F. On May 25th, at a recirculation piping temperature of 260*F, the heatup was secured and a thermal expansion walkdown was performed.- No items of significance were noted. On May 26th, the reactor was heated to a recirculation piping temperature of 330*F. After a delay in testing, the plant-resumed heatup, achieving a recirculation piping temperature of 370*F on June 9th and finally 523*F on June 15th. At all of the above intermediate temperature conditions, expand data was utilized to verify that the piping expansion was trending properly. At the final temperature of 523'F, the monitored point's displacements were compared against the Acceptance Criteria. All points were within Level 1 Test Criteria. Five points were outside of the Level 2 Criteria on the 'A' Loop and five points were outside of Level 2 Criteria on the 'B' Loop. G.E. Plant Piping Design judged these exceptions to be l acceptable.
-96 ~
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-w d' N2-SUT-17
- 1 C.. (Cont'd)'
The rated drywell walkdown was conducted' on June -'23rd- and # June 24th.- One' Level 1 Criteria violation was identified when it was' discovered that: grating 1 was ; in : contact with the i Recirculation ~ ~J ~ Pump ' A' - Motor. This violation was resolved .by cutting -the-grating to achieve the required clearance. t Thermal- Expansion data ~was.'obtained, during two; subsequent heatups in - order to satisfy the test specification requirement . that two to four heatup-cooldown cycles be monitored. 4 The .2nd cycle data was :obtained on' June 23rd at a piping'- temperature of 513*F. Criteria evaluation showed that a11' Level 1 Criteria were met and all but 5' . points on the 'A' Recirculation J Loop - and 4 points ' on the 'B' ' Recirculation Loop . met the Level 2' Criteria.
- The 3rd cycle ' data was obtained on July 5th at 'a -piping
, ' temperature of 524*F. ' All Level 1 Criteria were met .but points failed the ' Level 2 criteria on the 'A Loop' and 5 points failed the' Level 2 criteria on the?'B' Loop. The final, measured-displacement values, as compared to the- temperature ' adjusted-
-Level 1 and Level 2 limits are given in Table 13.3-3..
G.E. Plant Piping Design evaluated the Level 2 Criteria failures for. the 2nd and 3rd cycle and determined that the piping movements were acceptable. , Test Exceptions and their' resolutions are stammarised in Table - 3.13-4. 1
-97 .
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,I .'. ..4 TICURE 3.13-1 sysrsN axPANEION N2-SUT-17 RAS
- C= -cl. .n .
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RECIRC LINE "A" TRANSDUCEE LOCATIONS
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't FIGURE 3.13-7 SYSTEN IIFANSION N2-sut-11 7
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J RECIRC LINE "B" TRANSDUCER LOCATIONS
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. TARLE 3.13-3 j
~: 1 SYSTEM EKPANSION
.N2-SUT-17 l- Thermal Ernannion Accentmace Criteria /Results Lanyard' Pots (Inches) 1 1
J Level 1* Level 2* i i l
~
Test. Measured Criteria l Point Displacement ** Failure RA1X -1.185 .959 .691 .683 .457 Y .428. .098 .013 .150 .480 i
.Z' .471 .171~ .069 .017 .317 RA2X .519 .154 .146 .104 469
- Y -3.659 -2.045 -1.307 -1.546 .068 L2 . 2 .335 .174 .161 .192 .353
- RA3X .521 .550 .523 .756 1.827. L2 Y -2.316 -1.515 -1.108 -1.028 .227 2 -1.162' .201 .497 .503 1.866.
RA4X .124 .176 175 .363 .663 L2 Y. -1.286 .560 .252 .223 .503 Z .295 .501 .505. .777 1.573 RASY N/A N/A .403 N/A N/A RBLK: . 371 .717 .768 .993 1.339 Y .423 .093 .159 .155 .485 L2 Z .391 .019 .004 .206 .616 L2 RB2X .282 .052 .261 .311 .645 Y -3.700 -1.976 -1.460 -1.476 .248 L2 Z .377 .217 .263 .150 .310- L2 RB3X -1.689 .618 .533 .412 .659 Y -2.429 -1.509 -1.207 -1.022 .102 Z -1.702 .428 .457 .127 1.147 L2 RB4X .870 .290 .180 .103 .477 Y -1.396 .560 .240 .223 .613 Z -1.369 .723 .476 .447 .199
- Limits given are adjusted to actual test conditions
**3rd heatup cycle, 524*F
-100 ,.
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l 1
.. 1 1
TABLE 3.13-4 SYSTEM EXPANSION l
, N2-SUT-17 TEST EXCEPTION
SUMMARY
Test Test j Excention Condition Description ; 1 HU 10 Thermal Expansion Points fell outside the Level 2 limits for the first heatup cycle - RA2X, RA2Y, j RA3X, RA4X, RB1Y, RB1Z, RB2X, RB2Z, 'RB3Z, RB4Y. l G.E. Plant Piping Design reviewed the test results l and found them acceptable. 2 HU 9 Thermal Expansion Points fell outside the Level 2 limits for the second heatup cycle - RA2X, RA2Y, RA3X, RA32, RA4X, RB1Y, RB1Z, RB2Z, RB3Z. G.E. Plant Piping Design reviewed the test results and found them acceptable. 3 HU 8 Thermal Expansion Points fell outside the Level 2 j limits for the third heatup cycle - RA2Y,. RA3X, ; RA4X, :tBlY, RB1Z, RB2Y, RB2Z, RB3Z. G.E. Plant Piping Design reviewed the test results and found them acceptable.
~
4* HU Two potential piping interferences ~ were ~d iscovered during cold, ambient walkdowns concerning small bore i recirculation piping. Both interferences were reworked to achieve the proper clearance. 20* HU A Level 1 interference between the Recirculation 'A' Pump Motor and grating was discovered during the rated conditions piping walkdown. The grating was cut to achieve-the proper clearance.
- These Test Exceptions are written against N2-SUT-78-HU.
-101 ,
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.TIP UNCERTAINTY. :I N2-SUT-18 1
I
- 3.14; ;N2-SUT-18 -TIP. UNCERTAINTY
;A. OBJECTIVES
-1. To determine the reproducibility of the TIP System-readings.
B. ACCEPTANCE CRITERIA
' Level 1 Not-Applicable p
Level 2 n 1.- The Total TIP uncertainty (including random noise and geometrical uncertainties) obtained by averaging the
, uncertainties for all data sets shall be less than 6,0 ,
,: percent. C. DISCUSSION i TIP reproducibility consists of a random noise component and a l geometric component. The geometric is due to variation in the water gap geometry and TIP tube orientation from one TIP location to another. Measurement of these components is obtained by taking repetitive TIP readings - at . a single TIP location, and by analyzing pairs .of TIP readings taken at TIP locations which are symmetrical about a core diagonal. The TIP data was taken with the reactor operating with an octant symmetric rod pattern at steady state conditions at 887. of rated power. The total TIP reproducibility is obtained by dividing the ) standard deviation of the symmetric TIP pair nodal ratios i by '2. The nodal TIP ratio is defined as the nodal BASE value of the TIP in the lower right half of the core divided by its symmetric counterpart in the upper left half.
-102 .
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TIP UNCERTAINTY l N2-SUT-18 - p 1 l C. (Cont'd) l l' The random noise - uncertainty is obtained from - successive TIP l
.. l runs made at the common channel, with ' each of the TIP . machines making a minimum -. of six runs. The atandard deviation of the random noise is derived by taking the square root of the average of the variances at nodal levels 5 through 22, where ' the nodal' variance is obtained from the fractional deviations .of the .
successive TIP values about their nodal mean value. The geometric component of TIP reproducibility is 'obtained ' by statistically subtracting the random noise component from the total TIP reproducibility.
. Table 3.18-1 lists the synunetric TIP pair locations in the core. Table 3.18-2 shows the mathematical relationships between random, geometric and total TIP uncertainties.
The uncertainties calculated were:
~
random noise 1.67410% geometric 0.43800% total TIP- 1.73045% All acceptance criteria were' satisfied. 1 1
-103 .
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-TARTJ'3;14-11 l TIP UNCERTAINTY- l
, N2-SUT jl1 SYP9fETRIC TIP PAIRS PAIR ' LOWER-RIGHT' . UPPER LEFT NO. LOCATION LOCATION 1 16-09 08-17 2' 24-09 .08-25 3- 32-09 33 4 40-09 08-41 5 48-09 08-49 6 17 .16-25 ,
7 32-17 16-33 8 '40-17 ~ 16-41 9 48-17 16-49
.10 56-17 16-57 11 32-25 24-33 12 40-25 24-41 13- 48-25 24-49 14 56-25 24-57 15 40-33 32-41 16 48-33 .32-49 17 56-33 32-57 18 48-41 40-49 19 56-41 40-57
-104 .
1' Aus u 1-. . . . . . _ _ - _ _ _ _ _ _ _ _ -
TABLE 3.14_-2 . l TIP UNCERTAINTY
~N2-SUT-18 MATHEMATICAL RELATIONSHIPS FOR TIP UNCERTAINTY TOTAL TIP UNCERTAINTY 22 19 _2 1/2 I E Rj-R K
oT (%) = K-5 4-1 X 100 2 *E*(18*19-1)1/2
, Where:
E = Average BASE ratio for all symmetric pairs 22 19
= 1 E E Rj K
18
- 19 K=5 j=1 RK j = Ratio of BASE values for symmetric pair j at node K BASE value at node K in the lower right LPRM string of symmetric pair
, _i on the OD-10. Ootion 18 edit BASE value at. node K in the upper left LPRM string of symmetric pair j on the OD-10, Option 18 edit RANDOM NOISE TIP UNCERTAINTY 22 6 5 Bgg - BK 1/2 I E I BK og (%) = K=5 M=1 N=1 *100 '
t 18 * (6
- 5 - 1)
Where: 6 5 Bg = 1_ E I BKM 30 M=1 N=1 Bg= K Machine normalized, full power adjusted BASE value for LPRM string 32-33 (reference channel) at node K measured by TIP machine N during i its Mth Traverse.
= BASE value at node K during Traverse M on TIP machine N *Ag on the OD-10, Option 59 edit A2M ,
Ay= i TIP Machine Normalization Constant for TIP machine N on the OD-1 Traverse edit (A(N) on edit). Ag= 2 TIP Machine Normalization Constant for TIP machine N during its M th Traverse on the OD-2 Traverse edit (A(N) on edit). GEOMETRIC TIP UNCERTAINTY W cGE0(I) " OT -ORN
-105 mm
CORE PERFORMANCE 1 l N2-SUT-19. i 3.15 N2-SUT-19 CORE PERFORMANCE j A. OBJECTIVES
- 1. To evaluate the core thermal power and flow. ]
l
- 2. To evaluate whether the. following core performance ,
parameters are within limits:- l
- a. Maximum Linear Heat Generation Rate (MLHGR)
- b. Minimum Critical Power Ratio (MCPR)
- c. Maximum Average Planar Linear Heat Generation Rate (MAPLHGR)
B. ACCEPTANCE CRITERIA Level 1
~
- 1. - The MLHGR of any rod during steady-state conditions does not exceed the limit specified by the plant technical-.
specifications.
- 2. The steady-state MCPR does not exceed the limits specified by the technical specifications.
- 3. The MAPLHGR does not exceed the limits specified by the technical specifications.
4 Steady-state reactor power is limited to rated core thermal power and values on or below ,the rated power flow control line. Core flow does not exceed its rated value. Level 2 Not applicable C. DISCUSSION The Core Performance Test, N2-SUT-19, has been performed in Test Conditions 1, 2, 3, 5, and 6. The test was performed using 3 BUCLE (Back Up Core Limits Evaluation Program - a G.E. off-line J program) in Test Condition 1. In Test Conditions 2, 3, 5, and 6 the process computer was used to evaluate core performance
-106 ,
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. CORE PERFORMANCE N2-SUT-19:
C.: -(Cont'd) parameters. - In . Test Condition'5, core perf ormance . parameters . were evaluated at both forced circulation- and- natural circulation *. In - all test - conditions: the - acceptance criteria was met. Prior to the recirculation system flow.. calibration (N2-SUT-35) the maximum . Kg penalty .(1.32). was administratively imposed due to the ' uncertainty in Total . Core . Flow. Following
'N2-SUT-35 _the function as. defined .by. Technical Kg .
Specification,, Figure 3.2.3-2 was imposed. The core performance results of Test Conditions 1, 2, .-3, 5,- and 6 are summarized on Table 3.15-1.
- In .- tes t conditions 3 and ~ 6 core flow exceeded 'its rated'- value due to core flow ' miscalibration (LER 88-45). This can be accepted as is based upon the Supplemental Final Startup Report.
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4 f . I 'l d PRODUCTL Y h 4 i~ , 1N2-SUT-20 lf L 3.16 N2iSUT-20.: STEAM PRODUCTION-A., OBJECTIVES
' ' 1. To i determinet that the NSSS provides steam sufficient ' t'o -
T: r,atisfy all appropriate. warranties < .as 'definedL in- the
, . contract.
B.. ACCEPTANCE CRITERIA
. Level 1 y
- 1. The NSSS parameters as . determined by using norma 1' operating -
procedures are within the appropriate-license restrictions. Imvel 2
~
- 1. The NSSS , is capable of supplying steam in an amount and
, quality corresponding to the final feedwater temperature and other conditions. shown ~on the rated steam output curve in' the NSSS' technical description. The rated steam output .
curve- provides the warrantable reaccor vessel 'steamioutput. as a Lfunction- of. feedwater temperature,.:as: well as. warrantable ' steam conditions .at . the ~ . outboard ' MSIVs.- Thermodynamic parameters are consistent with the 1967 ~ASME ~ steam tables. Correction' techniquesa.for conditions? that - differ f rom the - contracted' conditions - will - be mutually agreed to prior to the' performance of the test. ' C. DISCUSSION This. test was performed during the WR Test Condition.- At 2227 on March 27, 1988 the final prerequisites.for the procedure were completed and the 100 hour test time commenced. . Fourteen' . hours
~
and 51' minutes into the 100 hour period, .the first of two data l collection periods began. Fif ty hours and 19 minutes into the 1l 100 hours period the second data collection. period began. no . Each data collection period involved collecting various plant process variables at 10 minute intervals- for two hours. The variables collected included' feedwater pressures,- steamline pressures, feedwater venturi differential- pressures, feedwater 4 i
'r temperatures, control rod drive system flow, reactor water cleanup system flow and temperatures, and reactor recirculation pump powers. The two hour - average values of these parameters were used to perform a manual heat balance on the reactor .
system. The results of these manual heat balances are tabulated on Table 3.16-1. g
-109 ,
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. _ _ _ _ _ _ _ _ _ _ _ _ _ _ l
i STEAM PRODUCTION l N2-SUT-20
- - C. (Cont'd)
The heat balance values calculated from the two' data collection
. periods were averaged and compared to the warranted parameters. 1 This ' data is ' tabulated on . Table 3.16-2.- The actual steam flow J and- steam line pressure . at the 2nd MSIV: exceeded the warranted values, thus satisfying the level 2 criteria.-
( At 1440 on March 30, 1988, 64 hours. and 13 minutes into the 100 hour run, an. emergency power reduction was initiated - due to a
~
MSR drain tank. steam. leak. April 2, 1988 at 1000 ~a ll . prerequisites were reverified and at 1025 the 100 hour clock recommenced. The 100 hour run was completed at 2327 on April 3,- 1988 (1 hour correction due to daylight savings time). The average values obtained from all Pls obtained during the 100 hours run are summarized on Table 3.16-3. Review of all Thermal-Limits surveillance performed during the test (7) verified _that i
-all NSSS. parameters were within the appropriate license {
restrictions, thus satisfying the Level I criteria.* , l ,
- Core Flow ' exceeded its rated value due to core - flow miscalibration (LER 88-45). This can be accepted as is based upon the Supplemental Final Startup Report.
-110 .
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- e. .
TARLE 3.16-1 STEAM PRODUCTION N2-SUT-20
'IWO HOUR AVERAGE PARAMETERS' Test Run #1 -Teat Run'#2
'Feedwater A Temp.- 416.6J"F .417.25'F Feedwater B Temp. .
416.56*F 417.17'F Steamline Pressure at 2nd MSIV 992.04 Psia. 991.43 Psia-Recirc'A Flow 16.82 M1b/hr 16.84 M1b/hr-Recirc;B Flow' 16.62 M1b/hr :16.52 M1b/hr. Feedwater A Average Flow 6.895 M1b/hr 6.964 M1b/hr Feedwater.B Average Flow 7.158 M1b/hr- 7.229 M1b/hr Total Feedwater Flow 14.053 M1b/hr 14.193 M1b/hr Steam Flow Rate. 14.085 M1b/hr. 14.225 M1b/hr Reactor Steam Quality 0.9999813 0.9999813 Steam Quality at 2nd.MSIV 0.9985199- 0.9984988 Steam Enthalpy. 1192.2739 BTU /lb '1192.2783 BTU /lb , Power in Steam 4922.08 MW 4970.85 MW Average Feedwater Temp.. 416.595'F 417.21*F Average Feedwater Pressure 1078.115 Psia 1078.115 Psia. Feedwater Enthalpy 393.940 BTU /lb 394.608 BTU /lb Power in Feedwater 1622.61 MW 1641.50 MW Power in Control' Rod Water ~ 0.665 MW 0.665 MW Recirculation Pump Power 11.802 MW 11.830 MW-RWCU. Inlet Enthalpy 523.42 BTU /lb 523.37 BTU /lb RWCU Outlet Enthalpy 441.106 BTU /lb 441.397 BTU /lb' , Cleanup System Power 8.398 MW 8.36'MW' ! Assumed Power Losses: 1.1 MW 1.1 MW ' NSSS Thermal Power 3296.501 MW (99.2%) 3326.315 MW (100.1%)
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.1 TABLE 3.16-2
]
STEAM PRODUCTION N2-SUT-20 ACTUAL VS. WARRANTED PARAMETERS' Average Reactor Pressure- 1017.795 Psia Average Feedwater Temperature 416.903*F. Average Feedwater Pressure 1078.115 Psia Average Steam Quality at 2nd MSIV 0.99850935 Average Steamline Pressure at 2nd MSIV 991.735 Psia Average NSSS Thermal Power 3311.408 MW~ Average Steam Flow 14.1548 M1b/hr Average Feedwater Enthalpy 394.274 BTU /lb Average Steam Enthalpy 1192.2761 BTU /lb Warranted Steam Flow 14.1456 M1b/hr Warranted Steamline Pressure at 2nd MSIV 983.34 Psia e l I { j
-112 -
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~ TABLE 3.16-3 t
STEAM PRODUCTIM N2-SUT 100 HOUR RUN AVF. RAGE VALUES Average Core Thermal Power 3288.73 MW Average Core Flow 112.03 M1b/hr*
- Core Flow exceeded its rated value due to the core flow miscalibration- (LER 88-45). This can be accepted- as is based upon the Supplemental Final Startup Report.-
-113 .
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N2-SUT-22 3.17 N2-SUT-22~~-PRESSURE REGULATOR-
'A. OBJECTIVES
- 1. To determine. the optimum ' settings for the pressureCcontrol '
loop by analysis of the transients ' induced in the reactor pressure control system by meanst of the pressure (regulators.-
- 2. To. determine the takeover capability.of-the backup' pressure regulator- upon- fallure of 'the . controlling pressure regulator and to set spacing between ; the setpoints- at an
~
appropriate value. !lu
- 3. To demonstrate smooth pressure .. control transition between" the: control valves and bypass valves when the reactor steam generation exceeds steam used by-the turbine.
To demonstrate that other affected parameters ; are ' within.
~
4. acceptable limits during. pressure-regulator-induced transient maneuvers. B.. ACCEPTANCE CRITERIA Level 1 cl. The transient response 'of any pressure control
. system-related variable to_any test input aust not diverse.
Level 2
- 1. Pressure control system-related variables ~may contain oscillatory modes of response. In these cases the decay ratio for each controlled mode .'of response mu t be - less I than or equal- to 0.25. (This criterion does not. apply to tests involving simulated failure of one regulator with the j backup regulator taking over.) 1
- 2. .The pressure response time-from initiation of pressure set' L
point change to the turbine inlet pressure peak is 1 10 sec.
- 3. Pressure control system deadband, delay, etc. is small E
l enough that steady-state limit cycles (if any) produce .l steam flow variations no larger than 10.5 percent of rated ! steam flow.
-114 .
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U< FRE88URE REGUIATOR . N2-SUT d
. 6 eft ,
' B. : ' .(Cont ' d )
- 4. . ' For all ! pressure - regulator transients,- the ' peak t neutron
-' flux and/or peak ' vesul pressure shalli remain below ( thei 4 scram setting Eby .' 7.5 ' percent? and 110 psi, respectively.
L
' (Maintain . a plot, of power versus the peak variablei values.
l - along the.100-percent rod--line.)
'5. The . variation -in incremental' regulation 1(ratio ofi~the maximum ~ to' the minimum value .of the quantity,' " incremental' i
change:. in pressure > control' " signal / incremental: change. in.
. steam flow," for.each flow range);shall meet the following:
Steam Flow Obtained , With Valves Wide.Open
'(Percent) Variation
.0 to 85 1 4:1-12:1' 85 to 97 85 to 99 I 5:1 C. DISCUSSION The Pressure Regulator testing was performed in TC1, TC2, / TC3,.
TC5 and TC6 according to the test matrix .given in Table ' 3.17-1. - The dynwaic , performance- of . ^ tho' . pressure - regulators was demonstrated by L inducing setpoint step: changes 1with Lpressure control maintained by control valves. alone, bypass valves alone and both control valves' and bypass valves ~ (bypass valve control initially incipient). All testing-wasiperformed usingL the same controller. settings (see Table ' 3.17-2). ' The responses to 'all dynamic . tests of the pressure regulator system met the applicable criteria. - The steady state tests ' failed . to meet the' applicable criteria but all issues were resolved satisfactorily.
~
1 Pressure regulator dynamic testing in 'all test conditions- ~I demonstrated both ' regulators to be responsive and stable. The decay ratios for step changes were usually much less than the-criterion,10.25; the maximum value of 0.23 was measured during
- a -10 psi setpoint change with the 'A' pressure regulator and control valves controlling in TC-5. A maximum decay ratio for-all dynamic tests of 0.49 (criterion i 1.0) was measured during.
failure of the 'B' regulator to the 'A' regulator with control valves controlling in TC-3.
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$ PRES 8URE REGUIATOR-N2-SUT-22 ~]
.1 e Ci -(Cont'd). J
'1
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. The ' pressure . control ' system responded quickly ? to setpoint atop < 1
' changes with turbine throttle ~' pressure response times : that . were? ,
3 = nominal7 1 ;-3 seconds -(criterion . C 10 seconds). .
> response time wasJ 4^.55 . seconds when a +10 psi L setpoint change-The maximum 1 1
L was made ". to the t'B' regulator with - the bypass' valves incipient. Ll in TC-3. Steam flow variation measurements ranged from t'.0.195% (TC- d to i i 0.93% ' (TC-6) (criteria i 0.5%). The results failed L to meet, the criteria only in TC-6 and: exception 2 (see Table 3.17-4) was written. The : resolution from GE Engineering was that _ the steam flow 1 variation. was acceptable when .' the : ef f acts of core flow!
<, oscillations were disregarded. . The ' purpose '. of 1 the criteria .is .
-to- demonstrate' that the control: system . equipment , would, . not.-
experience - excessive wear . when' other- plant parameters are : not -
' changing significantly. The oscillations ! experienced t were ,
considered for this' test to be a - significant 1 change iin plant parameters and. data analyzed when oscillations are not = present,;
. indicate a satisfactory response, therefore, no furtherf action on this item is' required.
The TC-3 testing with bypass ; valves Lincipient demonstrated T a '- smooth. transition between control valves and bypass.. valves during pressure setpoint step changes. The required margins to ' scram for APRM neutron flux and dome-
- pressure were met . for. all tests. ~ The miniman' margin < to scram f or . '. APRM - neutron flux was 8.6% :(criterion > .7.5%) 'and was measured during' the 'A' regulator . f ailure te's t ' with control valves controlling and the recirculation control system in loop auto ' mode during TC-6. , This . margin value when , extrapolated : to the 100% rod line decreased to 2.41%. The pressure regulator failure tests were performed with a 5 pai bias between the regulators up through TC-5, but a bias of 3.5 psi, the normal bias, was used in TC-6 since test results predicted that margin to APRM neutron flux scram could not be demonstrated with a 5 psi bias.
-116 ;
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y . . - - _ _ _ _ _ _ - - . _ - . - - - - _ _ --_ -
~ PRESSURE REGUIATOR
, -N2-SUT I C. (Cont'd)
The minimum margin to scram for reactor dome pressure was 41.4-- psi (criterion > 10 psi) and was measured . during a ' simulated , failure of the 'A' regulator with the control valves controlling and the Recirculation Control System in loop auto mode during TC-6. During TC-6, . data for ' determining ' control' valve regulation was obtained and is as follows:
~ Flow % % CV Reaulation Criteria Up to 85% 1.96:1 14:1 85 to 97 3.22:1- 12:1 3.22:1 85.to 99 15:1 The test results met the criteria' except in the 85 to 97% valve
~
wide. open steam flow region (criteria 1 2:1). . Exception 1 (see Table 3.17-4) was written for this failure.. The exception was - resolved by a GE review of the data which determined tne results to be acceptable and requiring no further action. The pressure regulator test results are summarized ~ in Table 3.17-3, Pressure Regulator Test ~Results and exceptions are-listed in Table 3.17-4. O
)
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1 1 TABLE 3.17-1 PRESSURE REGUIATOR N2-SUT-22 TEST MATRIX Controlling Test Condition
' Valves Inst 1 2 3 5 6 Control Valves Setpoint Steps No Yes Yes Yes' Yes Yes Yes . Control Valves' Fall to Backup No Yes Yes No No Yes No Bypass Valves 'Setpoint Steps Yes Yes No No Yes Yes Yes.
Bypass Valves Fall to Backup Yes Yes No No No Yes No
-Bypass. Valves 'Setpoint Steps No No Yes. No No .No ,No.
Incipient' Recirculation' Mode MAN MAN MAN FLX MAN MAN FLX MAN = Either Loop Manual or Loop Auto (FLUX CONTROLLER in Manual). FLX = FLUX CONTROLLER in Auto 6
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- . _ . - _ _ . _ - - . . . . - _ S
1
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p' i,.p to TABLE 3.17'-2 i o PRESSURE REGUIATOR N2-SUT 1 PRESSURE CONTROL SETTINGS ' 1 f Pressure Regulator Settings i
'A' 'B' Lead Time Constant 6.19 6.18 Lag Time Constant 2.38 2.76 Steamline Resonance Compensator. Settings
.A' 'B' To, Notch Center Frequency 4.6 4.5 Z/2 2, Notch. Depth 1.82 0.86 2 2 , Notch Width 2.81 3.39 TR2 , Small Lag. Time Constant 3.50 3.50 K, Pressure Regulation 3.06
, )
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-TABLE 3.17-3 PRESSURE REGtJLATOR r'
L N2-SUT-22 L Pressure Rerulator Test Results 1 Valves Non - Maximum Pressure Steam Scrate. Avoidance - In Divergent Decay Response Flow Margin
- T.C. ' Control Oscillation Ratio Time. Sec Variation.1 APRM Pressure.
~
Limit D.R. < 1.0'
. ( 0.25- < 10 see 1 0.5% >7.5 > 10 psi 1 BPV- Y 0.18 3.1 0.195 101.7 100 2 CV Y 0.15 3.1 0.385 65 87.7 2 BPV Y 0.14 3.2 - 65.5 87.0 3 ' CV(1) Y 0 3.55 0.45 46 79.0
'3- .CV(2) Y 0 3.0 - 48 75.7 '
3 BPV(3) Y 0 4.55 - 54 88 5 CV 'Y 0.23 2.9 0.31 45 76. 7. . 5 - BPV - Y- 0.16 3.0 - 47 75.5 1 6 CV(1) .Y 0 4.24 0.93 8.6 41.4 6 CV(2) Y 0 2.32 - 9.8 -47.5 6 BPV(1) Y 0 3.20- - 12.8 44.6 6 BPV(2) Y. 0 2.92 - 1 T. 2 ' ' 5 0 . 2 ' ~ " ~" ~ ~~ A (1) Recirculation Flow Control - Flux Manual (2) Recirculation Flow Control - Flux Auto (3) Bypass values incipient
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. - - _ _ . . ._- . _ - - - - _ - ._ _ - - _ - _ - -- - _ _ ~ _ . - _ - .
TA mt.E 3.17-4 .i PRESSURE REGUIATOR
.N2-SUT-22 TEST EXCEPTION SUfftARY Test . Test I
- Excention Condition Demeriotion 11- ~6 Data taken to demonstrate control. valve regulation showed'a ratio of 3.22:1'in the 85% to 97% steam flow region. This violated ' a Level 2 criteria of 2:1. Following a ' review by G.E. Engineering, it was determined that the regulation was satisfactory sud no further action was required.- .
2 ;6 Steady state data : taken in TC-6, showed a steam flow variation : of t0.93% exceeding a Level 2 criteria . of AO.5%. Following a -review of the da ta by G.E. Engineering, it was determined that the cause of the - - variation' was oscillations in other reactor
. parameters which were larger than expected. . Since the steam ' flow variation at the frequencies of concern are within the criteria, no additional-action ~is required.
I
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a. - J-_.._____.--_---__.---__.. . - . . - - . _ _ - . _ . . _ _ - - _ - . - - - - _ _ - - - _ . - - . . - - . _ - _ . . - . - - _ . . _ - - _ - _ _ . . _ - _ - . ..
FEEDWATER STSTI!M- 'i N2-SUT j a
~3.18 N2-SUT-23 FEEDWATER SYSTEM ,
I A. - OBJECTIVES ,, < The purpose of this test is to: a)- Demonstrate that the feedwater system has been adjusted to provide acceptable' reactor water level' control by inducing small level and flow transients (level step change test). b) . Demonstrate adequate system response to ~a feedwater temperature loss via performance of that event (loss ' of Feedwater Heating Test). c) Demonstrate the capability of the automatic core flow ) runback . feature to prevent a low level scram following a j feedwater pump trip via performance of that event-(Feedpump Trip Test), and d) ' Determine the feedwater flow runout capability via data collection and analysis (Feedwater Runout Test). B. ACCEPTANCE CRITERIA Level 1
- 1. The transient response of any level control system-related variable to any test input must not diverge.
- 2. For the feedwater heater loss test, the maximum feedwater temperature decrease due . to a single f ailure case must be 1 100*F. The resultant MCPR must be greater ' than the fuel thermal safety limit.
- 3. For the feedwater heater loss test, the increase in simulated heat flux does not exceed the predicted Level- 2 value by more than 2%. The predicted value is based on the actual test values of feedwater temperature change and initial power level.
- 4. The maximum valve opening position attained (for pump runout) shall not exceed the position which will give the following feedwater flows with the normal complement of I pumps operating :
a) 155% NBR at 1010 PSIG b) 145% NBR at 1060 PSIG
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[' } l ;f l lj FEEDWATER SYSTEM N2-SUT-23 ! l l* B. (Cont'd) I Level 2
-1. Level' control system related variables may contain oscillatory modes of response. In these cases, the decay ratio for each controlled mode of response must ~ be less than or equal to 0.25.
- 2. The open loop dynamic response of each feedwater control.
valve to small (1 10% NBR) step disturbances shall be:
- a. Maximum time to 10% of a step. disturbance (delay time) 1 1.2 seconds.
- b. Maximum time to 10-90% of a step disturbance (response time) 1 2.1 seconds.
- c. Peak overshoot (% of step disturbance) 1 15%. .
- d. Settling time, 100% i 5% of step disturbance 1 14.0 seconds.
- 3. .The average rate of response of the feedwater control valve too large (> 10%. NBR) step disturbances shall be between 10% and 25% nuclear boiler rated feedwater flow /second.'
This average . response rate will be assessed by determining the. time required to pass linearly through the 10% and 90% . response points.
- 4. At steady state operation for the 3/1 element ' systems ,
input scaling to the mismatch gains should be adjusted such that the mismatch gain output should be within i 1 inch.
- 5. The increase in simulated heat flux does not exceed the predicted L2 value referenced to the actual feedvater temperature change and initial power level on loss of feedwater heating.
- 6. The reactor shall avoid low-water-level scram from one RFP trip by a 3-in, margin from an initial water level halfway between the high and low level alarm setpoints.
- 7. The maximum valve position must be greater than 'the calculated position required to supply:
a) With rated . complement of pumps 115.5% NBR at 1,071 PSIA. b) One feedwater pump tripped condition - 68% NBR at k 1,021 PSIA.
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.gg FEEDWATER SYSTDI i
N2-SUT-23 L !: C. DISCUSSION Test Condition l' The Nine Mile Point Unit 2 Feedwater System utilizes three
'different types of . level contr:,1 valves to modulate feedflow to the' reactor. At low power conditions, prior to a feedpump being put into service, the low-pressure, low-flow valve (LV-137 ) is used to control level. This valve is controlled by the startup level controller. After a feedpump is started, a high-pressure, low-flow valve (LV-55) is put into service. Of the three motor driven feedpumps, A' . and 'B' feedpumps utilize a LV-55 valve at their discharge, while 'C' does not. The LV-55 valves are also contro11ed' by the startup controller. Only one LV-55 valve can be operated in AUTO to control level at any given . time. Both the LV-137 and LV-55 valves are air operated. .
The high-pressure, high-flow valve (LV-10) is put on at 7% power when a second feedpump is started. Initially, the LV-10 valve is operated in manual, while ' level is still controlled by the LV-55 valve associated with the first feedpump started. As power is increased, the LV-10 valve is opened to keep the LV-55 valve at approximately the same position. At 15% power, the LV-55 valve is shut and the . LV-10 valve put into control. The LV-10 valves- are controlled with the Master Controller and are hydraulically operated. LV-55 valve testing was performed at 15% reactor power and consisted of inputting level setpoint changes of 5 inches into the startup level controllar. Two feedpumps were operating during testing, one with a LV-55 valve a: 50% position and the other with a LV-10 valve at 12% position. The LV-10 valve was in manual during the testing. Both the LV-SSA and LV-55B valves were tested. No decay ratios were noted during LV-55 valve testing, thus meeting both Level 1 and Level 2 Criteria. For both the upward and downward steps the LV-55 valve moved approximately 30% until retur! Ping to its original position after approximately 6 minutes. Final settings on the startup controller were a gain of 5 and a reset of 1.1 R/M. I
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FEEDWATER' SYSTEM .- N2-SUT-23' i
- l. C. (Cont'd)
Test Condition 2 The LV-10 valves, controlled by the Master Controller, were initially tuned at 38% power. - This tuning resulted in , system settings of a gain 'of 0.4 and a reset of 0.7 R/M. The gain could not be increased further due to 1 Hertz oscillations in the Feedwater Control System. Open loop step changes (step changes in valve position) . were then : performed under the startup test. 'A step generator was used to input the step changes downstream of the M/A station. These step . changes resulted . in an approximately 3% change in valve position and a - 2.5% NBR change in flow through the LV-10 valve tested. Both the 'A' and 'B' LV-10 valves were tested and met the Level 2 requirements for response time. The testing was performed at 38% power with the valves at 25% position. Closed loop step changes (step changes in level), consisting of 5 inch level ~ steps ' on the master controller in single and three element control, . were then' performed using the 'A' and 'B' feedpumps'. . Both the Level 1 and Level 2 Criteria for stability were met as there were no decay ratios discernable. The 'C' LV-10 valve could not be tested immediately as it had undergone extensive damage due to apparent water haanner. In - addition, the performance of the LV-10 valves already tested was degrading.- The valves in operation were drif ting erratically, apparently due to leaking servo valves and also noise problems with the control signal going to the valves. In a 5 week outsge at the end of 1987, all three LV-10 valves were completely rebuilt. Several n.ajer design changes were implemented on the valves at this time. These included:
- A new seal design for the hydraulic cylinder to prevent leakage of the hydraulic fluid.
- Changes in the routing of the cables which carried the control signal to the valve. This was to eliminate noise from the control signal.
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FgEDWATER SYSTIBt N2-SUT l l C. DISCUSSION (Cont'd)
- A strengthening of some physical components of. the hydraulic actuator to mitigate the effects of water hammer. Vents were added to the bonnet of the valve.
The position feedback mechanism was redesigned to improve the stability of the position signal.
- Servo valve units were replaced.
- The operating pressure of the hydraulic cylinder -was lowered from 3000 psig to 2400 psig.
After the outage, the 'A' and 'B' LV-10 valves were retested at 37%' power for both open and closed loop response. All Level 1 and 2 criteria were met. The 'C' LV-10 valve was tested for open loop response at 50% power (35% valve position) and met the , Level 2 criteria. Closed loop testing was performed on the 'A' and 'C' then the 'B' and 'C' feedpump combinations. Again, the control systems response in single and three element control was stable and showed no oscillatory behavior. Test condition 3 The next . testing occurred at 62% power. LV-10 valve position was approximately 50%. The 'A' and 'B' LV-10 valves were checked for open loop response. While the small step changes met the Level 2 criteria, the large step change for the B ' LV-10 valve did not meet the required 10%-25% rate of response, achieving only an 8.8% NBR/Sec. In addition, it was noted that the step in the increasing direction was slower for both the 'A' and 'B' LV-10 valves than the decreasing step. This test exception was sent to G.E. Engineering where the rate of response wee determined to be acceptable. Open loop testing was then performed on the 'C' LV-10 valve, at 68% power, which met all of the Level 2 Criteria for both small and large step changes. Closed loop testing at 68% power was perfomed for the 'A' and
'B' then 'A' and 'C' feedpump combinations. The LV-10 valves were approximately 40% open. All test criteria were satisfied.
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FEEDWATER SYSTEM N2-SUT-23 C. DISCUSSION (Cont'd) Before the Test Condition 3 testing was complete, a test of the Recirculation Runback feature was conducted in N2-SUT-30-3. During the test, the reactor operator had to take manual control i of feedwater level control in order to prevent RPV level from reaching Level 8. Af ter a review of the controller settings on the master level controller, G.E. Engineering determined that the Master Controller gain setting had to be increased in order for the feedwater system to respond adequately to plant transients at higher power levels. Consequently, the syste:n gain was increased to .7 (dial reading) with the reset remaining at .7 R/M. In order to verify the higher gain settings at low power conditions, a retest of the 'C' LV-10 valve was performed at 38% power. The open loop test met all Level 2 Criteria and the closed loop test on feedpumps 'B' and 'C' also met all ' applicable test criteria. The final feedpump combination was tested at 68% power. LV-10 valves 'B' and 'C' met all applicable Level 1 and Level 2 Criteria for stability. Results of the small step change testing is given in Table 3.18-1. Results of the large step change testing is given in Table 3.18-2. Test condition 5 , Subsequent to Test Condition 3 testing at 60% power, additional Feedwater System tuning was undertaken in order to further increase system gain. The previous attempts to increase system gain had not been able to achieve the target gain settings, which were still a factor of 2 higher than the current settings. During the Feedwater System tuning, GE CLI Engineers 4 discovered that there was excessive high frequency noise of 5-20 i Hz on the control signal to the LV10 valves. The LV10 valves rapid rate of response caused excessive cycling of the valves i when given such a noisy signal. l These undesirable duty cycles were greatly reduced by a modification to the Feedwater Control System adding a low-pass , filter at the output of the Master Controller with a time j constant of 0.45 seconds (breakpoint of 0.35 Hz). As a result, ., valve stability was enhanced and the control settings were ] increased to the desired settings of a gain of 1 and a reset of
- 1.0 R/M. j
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FEEDWATER SYSTEM N2-SUT O 'C. DISCUSSION (Cont'd) In February .1988, . Test Condition 5 ' testing _ was conductad l on . the Feedwater ~ System at approxistately 65% power. This consisted of. injecting .4-5 inch : step _.changea to_ the Feedwater Contro1' System forL each-' of the .three combinations . of LV10 valves operating-together. .. No oscillistory behavior was ~ noted - in .'either single or.three' element modes of control.
' Test CanM tion 6
- Level Step Changes Prior to Closed Loop Testing at Test Condition- 6, it' was determined that the noise on the level signal was greater than anticipated.' Consequently, the damping on the Yeedwater Control System - Level Transmitters ' was - increased f rom approximately - 0.1 seconds to-.0.47 seconds. . Closed Loop testing was conducted on the Feedwater - Control System between ' 95-100% power. The usual - ~
- 4-5" level steps _ were input and it was determined that- the.
system response in1 both single and three element ~ control ' met L both the Level _1 and Level 2 criteria for decay ratios. In the-three' element control mode level stabilized' approximately one minute af ter the step change was input, and ~ a slightly quicker - response was seen with single element. Although it was planned to perform closed loop step changes in. Test Condition 6, these-were deleted by SER 88-019.- GE Engineering determined that the requirement to perform manual flow steps . in both Test Condition 3 ' and Test condition 6 was unnecessary, as this requirement applies to a turbine driven feedpump system, not a flow control-valve system. A Test. Exception resulted from a requirement that the Function Generators should be. linear. The slope was obtained by dividing. the change in flow by the change in flow demand for each LV10 valve. This data was obtained at 80% power by placing one LV10
- valve in ' Manual and leaving the other in automatic. The LV10 valve in Manual was opened from approximately_ 50% position in 5%
steps until . it was full open. The valve in Auto responded by closing. This process was repeated in the _ closing direction until the valve in auto was 90% open (this margin was to ensure that level control was maintained). Analysis of the Function Generator data showed that there was a variation of approximately 7 to 1 in Maximum to Minimum slope which exceeded the requirement that the variation be less than 2 to 1. While the slope was fairly linear from 15% to 60% demand, it decreased above 60% as flow could not keep up with demand. . GE Engineering accepted this deviation as the Feedwater Control System functioned well in the region of maximum system gain and W. system stability will not be worse in regions of lower system gain. an
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7 _ 1 q 1 i FIEDWATER SYSTEM ' M2-SUT . [- C. DISCUSSION (Cont'd)
- Loss of Feedwater Heating j
Stone and Webster Engineering - perfonned a parametric study: to determine the single . failure. scenario which would result in the largest - drop - in7 feedwater ~towperature. :This analysis showed
~
that the worstL case single. failure accident- was opening
< < ' 2CNM-A0V101; . the bypass ' valve' around the:. low pressure f heaters. -
'at power, due: to . the loss- of ' flow through the low . pressure heaters and . subsequent. drop in feedwater temperature.- The predicted-drop.in feedwater atL100%' reactor power was 62 degrees Fahrenhelt'. .
This -procedure was performed during Test Condition '6 at: 70% power while the " tes t specification originally called for ~ the test. . to be . performed between 80-90% power.. ..The initial-o conditions were changed to 70% power due to a ' concern over the '
. possibility of a temperatures difference at the inle t' of the '
Sixth Point Heater L of . greater - than 100*F, if 'the test was
, ' performed at power levels higher than 70%. The actual ~ loss - of feedwater heating was initiated by opening 2-CNM-A0V101 manually. .
The results are sumusarized in Table . 3.18-3. Feedwater temperature stayed constant at 394*F for approximately 75 seconds after 2-CNM-A0V101 was' opened and then decreased over the next=seven minutes. The final feedwater temperature was'354 degrees Fahrenheit, giving a total average drop of 40 degrees
-Fahrenheit. This is well below the level one criteria of 100 degrees Fahrenheit .
p The Level 1 Criteria required.that the peak heat flux during the transient be less than 2% below the Level 2 Criteria' for the test (76.6%) conditions. The actual heat flux value (76.4%) did not exceed the Level 1 or Level 2 values. This verified the transient codes developed for analysis of this event. The MCPR value decreased from 2.051 to 1.924 but was well above the Level 1 criteria of 1.06.
-Feedpump Trip Test The Feedpump Trip was initiated by the operator placing the 'A' Feedpump Control Switch to "STOP" at the H13-P851 Control Panel with the Reactor at 99% power. The plant response is sununarized in Table 18-4. -The Feedwater Control System maintained a margin o(12.7 inches to Level 3, well above the Level 2 Criteria of greater than a 3 inch margin. .
R
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FEEDWATER'SYST1!M N2-SUT-23 C. DISCUSSION (Cont'd) The 'A' Feedpump was selected to be tripped since it' -was instrumented for piping vibration. The Recirculation Runback feature was' actuated 7 seconds into the transient as Level dropped below Level 4 (approximately 5 inches below normal level). This ran the Recirculation Flow Control Valves closed from 82% to 15% and reduced the power to 60%, to be within the flow capacity of the remaining feedpump. The flow of the second operating Feedpump, the 'B' Feedpump, immediately increased after the trip as LV10B opened to 95%, resulting in a Feedpump - flow of 22,800 GPM 19 seconds into the transient. As a result of a low steam dome to Recirculation Pump Suction Temperature differential, the Recirculation pumps tripped to slow speed 37 seconds into the transient causing power to drop ) to 40%. This transfer to slow speed was not anticipated to occur during- the runback. This transfer to slow speed did not affect the test since it occurred af ter the Recirculation Flow . ~ Control Valves had runback. The low delta-T transfer . occurred as a result of the rapid power decrease which in turn resulted in a rapid dome pressure decrease, hence dome temperature reduction. Recirculation suction temperature .during this transient does not decrease as rapidly, therefore, the low delta-T trip logic was tripped and the transfer occurred approximately 15 seconds later. Several other uncipected results happened as a result of the Feedgwap trip. Several minutes after the initial transient, all
- three Heater Drain Pumps tripped and the 'C' Low Pressure Heater String Isolated. The resultant loss of feedwater temperature caused Reactor Power to increase and caused upscale alarms on the APRMs. The operators reduced power with control rods and proceeded to restore the plant to a stable condition.
- Feedwater Runout Test Data for the Feedwater Runout Test was taken during Test Condition 6. Various plant process parameters were recorded using GETARS and the process computer at the following power inels and system configurations.
- Between 65 and.100 percent power with a 3-3-2 condensate /feedwater pump lineup (3 condensate pumps, 3 condensate booster pumps,1 feed pumps) and three heater
( drain pumps operating.
- Between 55 and 100%. power for a 2-2-2 system lineup .
~
l (1 condensate pumps, 2 condensate booster pumps, 2 feedpumps) and three heater drain pumps operating. m e .h . 4
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FEIDWATER SYSTEN
-N2-SUT-23
- C.- DISCUSSION '(Cont'd)
This data was utilized. to ' produce . characteristic curves for the-
. individual J components of the . Condensate; and ' Feedwater- systems.
The Condensate system ' included. the . Condensate Pumps, ' the : y.
. Demineralizers, - and ? the Low Pressure Heaters.; up to ' the fourth point. heaters.-- The Feedwater system ' included the Heater Drain Pumps,.'the Feedwater . Control Valves, and-_the Sixth Point Heaters. . For each of these components, a differential pressure -
versus-_ flow curve .was generated. From these curves, plant performance under . the conditions specified- by. the acceptance criteria was predicted. Data. from ' the Function Generator Linearity Testing was used to obtain~ the- full open differential pressure. across' each-
- individual. LV10 valve. Data f rom this sectioni was , also = used ' to
. generate _ accurate ~ Feedpump curves of approximately 25' data points apanning a ' range from 8700 GPM- (Minimum ? flow) to' 22000 :, ~
GPM. l The Level 1 Acceptance Criteria are written in terms of placing - a limit 'on feed regulating valves positions, if necessary,- to - prevent excessive feedwater: flow during a control' system failure.- Data from the 3-3-2 system ' configuration was used for - the pump . curve . portion' of - the analysis. - The . 3-3-2 data . is the-most conservative case in that .it will yield more flow than the 2-2-2' configuration, and was used to . verify Level 1 Criteria. The analytical approach - for this criteria was - to demonstrate that the feed flow with the regulating valves full open meets the criteria, and no position limits are therefore required.- Analysis predicated that the maximum feedwater flow at 1025 PSIA would be 127.5% of rated ' feedwater ' flow . with the feedwater-control valves fully open. This meets the criteria of less than 155% NBR. The predicted feedwater flow at 1075 PSIA is 116% of rated with fully open feedwater. control valves. This meets the criteria of'less than 145% NBR. The Level 2 criteria are control system requirements to ensure adequate .feedwater flow is ~available during certain that transients. They are also written in terms of limiting. Feedwater Control Valve position, but since no position limiting is required, they were analyzed f or the Feedwater Control Valve full open condition.
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I FEEDWATER SYSTEM N2-SUT-23 0
.C. DISCUSSION (Cont'd)
Level 2 criteria was analyzed using 2-2 (and 2-2-1) system configuration data, as this will yield less flow than the 3-3-2 data. With one feedpump.. tripped in the 2-2-2 (i.e. 2-2-1) system configuration, the analysis: predicts a minimum of 72% NBR
'feedwater. flow at 1021 PSIA. This is well above the criterion of greater than 68% NBR. The criterion of 115.5% NBR at 1071
~
PSIA was evaluated for all three. combinations of f eedwater '. pumps. While the combination of ' A ' ' and 'C' Feedpumps met the-criteria of .115.5% (with 115.6% NBR) the other combinations did not. The combination of. 'A' and 'B' Feedpumps yielded an ! operating point of 114.7%, while the combination of 'B' and 'C'~ yielded 115% NBR. This deviation was - mainly due to ' the 'B'- Feedpump'having a lower head curve than the other feedpumps. GE Engineering determined that the feedwater capacity in all cases - would adequately-support the flow controller demand. - The results of the Feedwater Runout Analysis is given in-' Table 3.18-5 for all Feedpump and Control Valve combinations. Test Exceptions are sunnarized in Table 3.18-6. e l 1
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TARLE 3.18-1 ) i remWATEt SYSTEM N2-SUT-23 SMALL STEP CHANGE TEST RESULTS LV10A LV10B LV100
*[C2 +/- +/- +/-
Power Level % 37 37 38% - Time Delay Sec. 0.3/0.3 0.3/0.3: 0.3/0.2 Time Response Sec.. 0.6/0.6 0.6/0.6 0.5/0.4 Settling Time Sec. 1.1/1.0 0.9/1.1 'O.9/0.9 Overshoot % 0/0 0/0 0/8%- TC) Power Level %- 62 62 68% Time Delay Sec. .0.3/0.3 0.3/0.3 0.3/0.3 Time Response Sec. 0.6/0.5 0.7/0.6 0.5/0.4 settling Time Sec. 1.0/0.9 1.1/1.0: 0.9/0.6
.i Overshoot %- 0/0 0/0 0/4.5%
i l l 1.
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TABLE 3.18-2 FEEDWATER SYSTEM N2-SUT-23 LARGE STEP CHANGE TEST RESULTS LV10A LV10B LV10C i Increasing % NBR Step sec 8.5 7.5 8.9 Decreasing % NBR , Step sec - 12.5 10.1 12.5 Average % NBR see 10.5 8.8 10.7 e
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TABLE 3.18-3 FEEDWATER SYSTEM N2-SUT-23. LOSS OF FR'znWATER HEATING IC.=6 PARAMETER PRIOR AFTER Reactor Power (%) 72.3 75.9 Generator Output (MWe) 794~ 789' Reactor Pressure (psig) 970 971
. Total Feedflow (M1b/hr) 9.93' 9.93 Core Flow (M1b/hr) 112.76 111.71 Final FW Temp ('F) 394 354 Limiting MCPR 2.051 1.924 Location of Minimum MCPR 9-40 .. 9-40 MCPR Limit 1.252 1.252
/
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w Au l- , f~ E_____-____ _ _ _ _ _ _ _ _ _ _ _ . _ . _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ __ __________ _____ __ _ _ _
TABLE 3.18-4 FREDWATER SYSTEM N2-SUT-23 FEEDWATER PUMP TRIP
SUMMARY
RFPT Tripped A' Reactor Water Level *
' Initial Level 184.6 INCHES Minimum Level 172.0 INCHES Time 15 SECONDS Margin to. Low Level Scram (159.3 Inches) 12.7-INCHES Time to. reach Recire. Runback Setpoint ,
' 6.9 SECONDS Level at which Runback-Actuated 179.5 INCHES Steady State Level 183.4 INCHES Time.- 300 SECONDS Feedwater System Initial Suction Flows "A" 15224 GPM "B" 15415 GPM '
Max. Flow From Untripped Pump 22837 GPM Time 19 SECONDS
' Final Flow From Untripped Pump 12255 GPM Time 140 SECONDS -l Time For Tripped Pump to Reach Zero or Minimum Flow 5.2 SECONDS Recirculation System
- Initial FCV Positions A 82.0% B 81.6%
Final FCV Positions A 13.9% B 17.0% Time to Final Positions A 20.7 SECONDS B 20.0 SECONDS ' Initial Drive Flows A 45.1 KGPM B 44.8 KGl'M Final Drive Flows: A 4.4 KGPM B 4.1 KGPM > Initial Core Flow 112.65 MLB/HR Final Core Flow 32.18 MLB/HR Miscellaneous
- I Initial Reactor Power 99% Final Reactor Power 44%
Initial Steam Flow 14.7 MLB/HR Final Steam Flow 5.8 MLB/HR Initial APRM Flux 97% Max APRM Flux 102% 0
- Recirculation Pumps tripped to LPMGs 37 seconds af ter the Feedpump Trip. .
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TARLE 3.18-5 FEEDWATER SYSTDI N2-SUT-23 FEEDWATER RUNOUT RESULTS Feedpump and A&B A&C B&C Control Valve Combinations
.3-3-2 Feedwater . at 1025 psia 126% 127.5% 126.7%
System Configuration at 1075 psia 123.3% 124.5%' 123.7% For Level 1 analysis 2-2-2 Feedwater ~ 114.7% 115.6% .115% System Configuration For Level 2 analysis' at 1071 PSIA' , 2-2-1 Feedwater' 73.3% 74.6% 72% System Configuration For Level 2 analysis at 1021 PSIA e
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1 _ - -- . __ __ __ __-____________ _ D
... l TABLE 3.18-6 .
FEEDWATER SYSTEM N2-SUT-23 TEST EXCEPTION
SUMMARY
l
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Test Test Exceotion Condition Description
]
i 1 3 'B' feedwater control valve (LV10B);does not exhibit i the required flow response to large step changes. The Level 2 Criteria is 10-25% of rated feedwater flow /second and the actual response was slightly less than 10% flow /second. G.E. Engineering said this was acceptable per an analysis of water level during transients. 2 6 Maximum Feedwater System flow at a vessel pressure of 1071 PSIA was calculated to be 114.7% NBR for the A and B Feedpump configuration with two condensate and two condensate . booster pumps. The Level 2 requirement is 115.5% NBR. GE Engineering found
~
this deviation acceptable. 3 6 The ratio of the maximum to minimum slope for the function generators ranged from 5 to.7.4. The slope is the flow change divided by the demand . change. The requirement given is that the ratio of the slopes not exceed 2. GE Engineering accepted these results based up Feedwater System performance during prior testing.
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l TURBINE VALVE TESTING j
.N2-SUT-24 1 3.19 N2-SUT-24 TURBINE VALVE TESTING
'A. OBJECTIVES Demonstrate acceptable procedures and maximum power levels for reconsnended periodic surveillance testing of the main turbine control valves and stop valves without producing a reactor scram ,
and violating PCIOMR limits. B. ACCEPTANCE CRITERIA Level 1 - None Level 2
- 1. Peak neutron flux must be at least - 7.5% below the scram ~
trip setting.
- 2. Peak vessel pressure must remain at least 10 psi below the high pressure scram setting.
- 3. -Peak heat flux must remain at least 5%.below its scram trip point.
- 4. Peak steam flow in each main steam line must remain 10%.
below the high flow isolation trip setting. C. DISCUSSION The turbine valve surveillance was performed at the following conditions:
% RATED POWER % RATED CORE FLOW TEST CONDITION 62 51 5 75 70 6 85.7 87 6 88 85 6 88 82 6 95 96 6 ,
I All turbine stop and control valves were individually closed, then reopened and the reactor response was recorded. Portions of the procedure were retested two additional times, following . valve speed adjustments. The required margins to scram for all parameters were met. Extrapolation of test data indicates that *gs ; j
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, N2-SUT-24 j l
C. (Cont'd)- ! acceptable margins 'would exist if the' . testing were ' conducted at 100% power. Howevers bypass valve actuation . occurred during testing: 'at 95% power and since this was judged. to be undesirable no further. testing was conducted. The most limiting effect on reactor parameters from tho' test are: for .TCV -#4 testing l
'1. . Maximum peak neutron' flux, -100.2%, ~
(criterion, < 110.5%).
- 2. Maximum peak wide. range dome pressure, 993.9. psig, for' TCV
#1 testing'(criterion, < '.1027 psig). ;
- 3. ' Minimum' heat iflux trip. margin, 14.8%, . for TCV #4 . testing..
(criterion, 2 5%).
~
- 4. Maximum peak. steam flow, 3.7 M1b/hr. : for TCV #1, . #2 and #4 testing (criterion, < 4.34'M1b/hr).
~
.A test, exception was ~ written. for LPRM signals which were not , v recorded for ' all valve strokes during TC-5. The APRM selection
- switches were inadvertently restored to normal.:during the testing. The test exception was accepted as-is because there is no acceptance criteria associated with the LPRM evaluation. The turbine valve testing in Test -Condition 6 should provide adequate data for PCIOMR evaluation.
Test Exceptions are summarized in Table 3.19-1. >
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n_. .- . - - - TABIJ 3,19_l' 'f TURBINE VALVE TESTING N2-SUT TEST EXCEPTION SUffiARY
. Test Test-Exceotion Condition Description 1 5 LPRM- signals were not recorded for all valve testing. Accepted as is .since there is no criteria associated- with the analysis step for LPRM.
evaluation. 4 l I 4
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[. MAIN STEAM ISOIATION VALVES N2-SUT-25 l l 3.20 N2-SUT-25 MAIN STEAM ISOLATION VALVES A. . OBJECTIVES i _] I The purposes of this test are:
- 1. To functionally check the main steam isolation valves for l proper operation and detemine the valve closure time for d each MSIV. .
- 2. To determine that main steam branch isolation valve closure /
times meet Technical Specification Requirements during. hot operation. l
- 3. To determine the reactor transient behavior that results i I
from the simultaneous full closure of all the MSIV's at near rated power. i I B. ACCEPTANCE CRITERIA ,, Level 1
- 1. The MSIV stroke time (ts) shall not be less than 3 seconds.
- 2. For any MSIV, the total effective closure time (tsol) shall not be greater than 5 seconds.
- 3. In addition, during the simultaneous full closure of all the MSIV's at near rated power the following criteria apply.
a) The reactor must scram to limit the severity of the , neutron flux and simulated fuel surface heat flux transient. b) The feedwater system settings must prevent flooding of , the steam lines. .l 3 c) The positive change in vessel dome pressure occurring within the first 30 seconds af ter a closure of all MSIV's must not exceed the Level' 2 criteria by more than 25 psi. The positive change in simulated heat flux must not exceed the Level 2 criteria by more than 2 percent of the rated value.
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MAIN STEAM IS01ATION VALVES - N2-SUT-25 B. (Cont'd)'
' Level 2 The positive - change nin vessel dome. pressure and' simulated 1.
flux occurring within the first 30. seconds after the
' closure of all i MSIV's must not1 exceed the _ BOL . predicted -
values. Predicted values will be referenced to' actual test conditions of': initial . power level .' and ' dome pressure and ' , will use BOL nuclear data.
- 2. Initial. action of the RCIC and HPCS are automatic when -low
. water level -(L2) is : reached, ' and system ' performance is-within specifications.
- 3. Recirculation' pump . trip. shall ' be . initiated . if low water level-(L2) is reached.-. Recirculation. pump power will' shift-to the low frequency motor generators if ' low water level .
(L3) is' reached. ,
.C. . DISCUSSION During Test. Condition Heatup' and Test Condition 3, an individual-fast closure of each. MSIV was performed: to verify. their
-functional performance, to determine closure times, and to determine the offeet of temperature. and steam flow ' upon these times. - The MSIV isolation ' system response: time . in the : plant surveillance program is- divided up into three portions: 1) the associated transmitter time response, 2) logic system time' delay. '
from the associated trip unit to the de-energization of the air' pilot valve solenoids and 3) time-delay from the air. pilot valve solenoid de-energization through completion :of MSIV closure. The time delay that this startup test evaluates is Part'3 of the plant surveillance as just - described. Within this evaluation two times were determined:
~
(tgol) time from
- 1. Effective closure time -
the de-energization of the MSIV air pilot valve solenoids until the MSIV stroke closed.
- 2. Stroke time (t,) - the time interval from when the valve starts to move until it is 100% closed.
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r MAIN STEAM IS01ATION VALVES N2-SUT-25 C. (Cont'd) The MSIV stroke and' closure times were determined by monitoring the 90% and.10% open limit switches.on the GETARS computer. .The o stroke . time was calculated by . extrapolating the measured ' time between the actual .' 10% and 90% switch positions. The : valve closure ' time. is the time -(on' GETARS) from when the' valve solenoid is de-energized to when the valve is fully closed. Testing was performed-in Test' Condition.Heatup on-the Main Steam Line Isolation valves at 4% Reactor Power and a Reactor Pressure. of 959 psig. The results of the MSIV. testing are shown in Table. 3.20-1. Each MSIV satisfied the Level 1 Criteria for ' both stroke time and effective closure time. Main ' steam line branch isolation valves were- tested per the
' appropriate plant procedures. Three Main' Steam Line Drain Isolation valves were tested per N2-OSP-MSS-QOOL, Main . Steam Drain Valve . Operability Test. . Three RCIC Isolation valves were ' ,
tested per N2-OSP-ICS-CS001, RCIC Valve Operability . Test. All - branch valves met the closure times specified 'in the applicable-procedure. . In Test Condition 3, MSIVs were tested at 49% power at a Reactor Pressure of 9.41_ psig. ,Results are presented in Table 3.20-1. All Level 1 Criteria were satisfied. A full MSIV Isolation was performed in Test Condition 6 with reactor pressure at 995 psig and reactor power at 95.3%. The ' closure of the MSIV's resulted in a reactor scram and the average MSIV stroke time of the fastest value in each steam line was 3.69 seconds. Reactor - water level initially decreased to approximately 126 inches resulting in a Recire Pump transfer to LPNG. Two safety rollef valves (SRVs) lif ted (PSV 128 and PSV 133 whose lift setpoint is 1070 psig) and. reactor pressure reached its peak value of 1086 psig 9.4 seconds after the initiation. Two hundred seconds after the 3RVs automatically lifted, both $RV's malfunctioned, opening and closing 4 times within 30 seconds. Manual control of the SRV's was taken to prevent excessive valve cycling. Lifting of the SRVs caused Level to swell above the Bigh Level Trip Setpoint (L8) and the Reactor *feedpumps tripped. Reactor Core Isolation Cooling (RCIC) was manually initiated to assist in pressure control. An investigation into the excessive SRV cycling revealed that the reset value for these valves was too high and this was subsequently adjusted to give the correct blowdown requirement 3 of approximately 70 psig. The peak upset range level seen was l 223" which is well below the level of the Main Steam lines -l (250"). The changes in vessel dome pressure and simulated flux 'l were well within the Level 2 criteria. %
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TABLE 3.20-1 MAIN STEAM ISOLATION VALVES N2-SUT-25 1 MSIV CLOSURE TIMES I MSIV TC Heatup TC3 TC6 B22-F022A 3.72 3.74 3.74 B 3.86 3.85 3.87 C 3.52 3.54 3.52 STROKE D 3.68 4.02 4.04 TIME (t s ) B22-F028A 3.71 3.68 3.73 B 3.69 3.69 3.74 0 3.20 3.53 3.63 D 3.67 3.71 3.78 B22-F022A 3.98 4.01 4.04 ~ B 4.12 4.11 4.15 C 3.83 3.83 3.85 EFFECTIVE _ D 3.89 4.18 4.23 CLOSURE (tsol) B22-F028A 3.99 3.97 4.01 TIME B 3.99 3.98 3.97 C 3.53 3.84 3.93 D 3.95 3.99 4.07 i
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TABLE 3.20-2 MAIN STEAM ISOLATION' VALVES N2-SUT-25 SEQUENCE OF EVENTS FOR MSIV FULL CLOSURE TC-6 Time (Seconds) Event 0.0 Manual Initiation of Isolation Signal 0.6 Reactor Gcram 3.4 Recire Pumps transfer to slow speed upon reaching Low Level (L3) i 4.2 All MSIVs are shut 5.8 SRVs PSV 128 and PSV 133 lift. 6.0 Reactor level 126" 8.6 Peak Rx. Pressure.1086 psig
'14.8 SRV PSV 133 Seats 16.8 SRV PSV 128 Seats 115.5 Main Turbine Trip 222.0 SRVs PSV 128 and PSV . 133. lift and resent 4 times in 30 seconds. Operator-takes manual control of SRVs to control pressure 253.0 Feedpumps trip on High Level (L8) 474.0 RCIC manually initiated .to . ..as sis t in ,
pressure control.
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RELIEF VALVES- j N2-SUT-26 1
'3.21 N2-SUT-26 RELIEF VALVES
-.o A. OBJECTIVES 1.. Verify that the relief valves function properly (can be
-opened and closed manually).
- 2. Verify that- the relief valves resent properly after operation.
.3. Verify that there - are no major blockages in the relief valve discharge piping.
- 4. Functionally check the operability of the SRVs' from :the-Remote. Shutdown' Panel, and.to ensure proper valve reseating by monitoring SRV tail pipe temperatures- and acoustic monitoring changes of state.
B. ACCEPTANCE CRITERIA , Level 1
- 1. There should be positive indication of steam discharge during the manual actuation of each valve.
Level 2
- 1. Pressure control system related variables may contain oscillatory mode of responas. In these - cases, the decay ratio for each controlled mode of response is less than or equal to 0.25.
- 2. The temperature measured by thermocouple on the discharge side of the valves returns to within 10*F of .the j temperature recorded before the valve was opened.
- 3. During the test the steam fSw through each relief valve shall not be less than 90 percent of the average relief valve steam flow as measured by bypass valve position or the steam flow through each relief valve as measured by MWe shall not be lower than the average valve response by more than 0.5 percent of rated MWe.
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a. i________l__ _ . _ _ __ _ . _ _ _ _ _
RELIEF VALVES N2-SUT-26 C. DISCUSSION The safety relief valves (SRVs) were tested in TC1 with reactor power at 17.6% of rated, steam dome pressure at 952 psig, and _ the main turbine secured (stea:n was routed to the main condenser via the bypass valves). Fourteen SRVs were functionally tested by briefly opening the valves one at a time using their control switches on Control Room panel 601. Four SRVs were operated from controls on both the Division I and II Remote Shutdown J panels. All eighteen SRVs were individually cycled open and closed with f positive indication of relief valve discharge provided by I changes in the Acoustic Monitoring System lights, the tail pipe temperatures, turbine bypass valve position and main steam line total flow. During testing of PSV-126, the acoustic monitor lights did not indicate closed when the valve was cycled closed, i.e., the red open light remained on. This was a Level 1 Criterion failure. The status lights for PSV-126 also indicated , the valve was open during testing of PSV-124. Upon investigation, the acoustic monitor gain for PSV-126 was found to be set too high (7 setting), and was reuet to a lower value (1 setting). Proper valve status indication was demonstrated during a retest. The decay ratios for narrow range dome pressure, total bypass valve position and EHC sensed pressure were much less than 0.25 for all valve operations thereby assuring pressure control system stability. , SRV tail pipe temperatures were recorded at half hour intervals until the tail pipe temperature returned to within 10*F of their initial temperatures. For two valves (PSV-121 and 127), the temperatures did not return to within 10' of their initial values. The temperatures of these two valves did, however, eventually stabilize and remain constant (within 2*F) for at least a one hour period. A reduction in reactor pressure of 30 psig led to the valve tail pipe temperature dropping further and approaching their initial values thus assuring that they were properly closed. Total bypass valve position change for each relief valve opening was 96.8% or greater of the average total bypass valve change (criterion is 2 90%) thus assuring that there were no major blockages in relief valve discharge piping. Suppression pool temperature rose from 77 to 86.3*F during the testing. The Technical Specification limit for suppression pool - temperature during testing which adds heat to the pool is 105'F. I
*w Test Exceptions and their resolutions are summarized in Tabic l 3.21-1.
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i TABLE 3.21-1 RELIEF VALVES N2-SUT-26 TEST EXCEPTION St.Ht9.RY. Test Test Exceotion Condition Description t i 1. During testing of PSV-126, the . acoustic monitoring l-lights did not indicate closed when the valve-clored, ' in violation of Level 1 Criteria. The gain of the acoustic monitor was adjusted and the valve successfully retested.
- 2. 1 After PSV-121 and . PSV-127. were opened and closed, their tail pipe temperatures. did not return to within 10*F of their initial temperature, in violation of the Level 2 Criteria.- The tail pipe temperatures returned to their initial tempera.tures after reactor pressure was reduced slightly. ,
3
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., q v .. q-l I TURBINE TRIP AND GENERATOR LOAD REJECTION N2-SUT-27 3.22 N2-SUT-27 TURBINE TRIP AND GENERATOR LOAD REJECTION A.- OBJECTIVES
- 1. Determine main turbine bypass valve capacity.
- 2. Determine the response of the reactor and its control systems to a turbine trip at turbine steam flows just within bypass valve capacity.
- 3. Demonstrate the response of the reactor and its control systems to a generator load rejection at near rated power.
B. ACCEPTANCE CRITERIA Level 1 For the generator load rejection at near rated power: -
- 1. There should be a delay of less than 0.1 seconds following.
the beginning of control or stop valve closure before the beginning of bypass valve opening. The bypass valves should' be opened to a point corresponding to greater than or equal to 80 percent of their capacity within 0.3 seconds from the beginning of control or stop valve closure motion.
- 2. Feedwater system settings must prevent flooding of the steam line following these transients. ,
- 3. The two panp drive flow coastdown transient during the first three seconds excluding the first 0.25 seconds must be bounded by the limiting curves.
- 4. The positive change in vessel dome pressure occurring within 30 seconds after either generator or turbine trip must not exceed the Level 2 Criteria by more than 25 psi.
(i.e., dome pressure rise should not exceed 122 psi).
- 5. The positive change in simulated heat flux shall not exceed the Level 2 Criteria by more than 2% of rated value.
- 6. The total time delay from start of turbine control valve l motion to the complete suppression of electrical are i between the fully oper. contacts of the RPT circuit breakers I shall be less than 190 milliseconds.
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TURBINE TRIP AND GENERATOR LOAD REJECTION l N2-SUT-27
'B. (Cont'd)
Level 2
- 1. The measured bypass capacity (in percent of rated . power) shall be equal to or greater than that used for the FSAR analysis.
- 2. For the turbine trip within the bypass valve capacity, the reactor shall not scram for initial thermal power values within that bypass valve capacity and below the power level at which trip scram is inhibited.
- 3. For the generator load rejection at near rated powers
- a. There shall be no MSIV closure during the first three minutes of the transient and operator action shall not be required during that period to avoid the MSIV trip.
i,<
^
- b. The positive change in vessel dome pressure and in
. simulated heat flux which occur within the first 30-seconds after the initiation of the generator trip must not exceed the predicted values.
(The predicted values are those specified in the Transient Safety Analysis and Design Report. The predicted values were corrected for actual plant parameters measured during the Startup Test Program.) Low water level recirculation pump trip HPCS and RCIC c. shall not be initiated.
- d. Recirculation low frequency MG set shall take over after the initial recirculation pump trips and adequate vessel temperature difference shall be maintained.
- e. Feedwater level control shall avoid loss of feedwater due to high level (L8) trip during the event.
- f. Main turbine overspeed trip shall not be activated during the event.
( 2
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w;,. , , 4 .. a % i TURBINE TRIP AND GENERATOR LOAD REJECTI(BI-N2-SUT-27 C. DISCUSSION Eva=== Valva cmaneity Deter =4amtion b Bypass ~ valve capacity was determined .'in 6TC2 with the turbine generator synchronized to the grid at 400 MWe. The measurement - was - performed .by opening the five bypass . valves from O to 100% ' in : approximately 20% increments (one valve) using . the - Bypass Opening Jack and recording applicable reactor and turbine operating parameters. 1 Bypass valve ' steam flow- was calculated from measured values of' total steam flow (feedwater + CRD flow) and main turbine steam.. flow.with allowance for auxiliary steam flow. The' measured turbine bypass valve. capacity is 3.26 M1b/hr which
' satisfies the acceptance criterion of : equal to or greater than 3.2 M1b/hr.: A plot of bypass .. flow versus bypass valve - position-confirmed the linearity of the bypass valve . response. =The plot , , was also . used to provide an . estimate of the valve position
. corresponding to 80% valve capacity for use in establishing ther
-initial conditions for the turbine trip test in TC2. g The initia1 bypass capacity calculation' using transient! recorder values for turbine steam flow, resulted in a calculated! capacity.
of only 2.96 M1b/hr. An investigation'showed the-calibration of the turbine steam flow instrument loop was in l error. =The' calibration was based upon a turbine first stage pressure span of O' to 1029 peig~ whereas the correct span is 0 to 942 psig for a steam flow . range of 0 to 18 M1b/hr. After correction, the measured capacity met the acceptance criterion. During the bypass capacity test, first stage turbine pressure ... was reduced to below the setpoint value corresponding to 30% rated core thermal power. In order to maintain L the protective i features 'which are tied to first stage turbine prescure . when h operating. above 30% power, the bypass signal for these features which is actuated below 30% power was disabled for this test. i Turh4a= Trin Within Bramas canacity The turbine trip within bypass valve capacity was performed in TC2 with the turbine-generator synchronized to the grid at 165 MWe and the reactor operating at 21.6% of rated. The turbine i was tripped from the Control Room by depressing the Turbine Trip pushbutton. As the, turbine stop and control valves were closing, three . turbine bypass valves immediately opened and a fourth valve fully opened within 2 seconds of the trip. The ; fifth valve partially opened to its peak position after 3 seconds had elapsed. Within 15 seconds, the bypass valve system
- had closed down such that only 3 valves were full open and the fourth valve was 10 to 20% open.
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TURBINE TRIP AND GENERATOR LOAD REJECTION N2-SUT-27 C. (Cont'd) The reactor did not scram during this test thus satisfying the acceptance criterion. The maximum steam dome pressure increase was 6.7 psig and the APRMs increased by only 3%. Reactor water level increased approximately 3 inches during the fitst 12 seconds after the trip. Although the intent of the test was to perform the procedure at a power level corresponding to a steam flow equal to 80 to 90% of bypass valve capacity, initial steam flow was less than this amount. The initial test conditions were determined from a process computer generated heat balance which showed feedwater flow equal to 2.58 M1b/hr. With that value of feedwater flow added to CRD flow, the sum equaled 88.3% of bypass valve capacity when calculated using the incorrectly calibrated turbine steam flow data (discussed previously). Other plant data taken prior to the test plus the corrected bypass capacity showed feedwater flow was less than 2.58 M1b/hr and that steam flow was about 67% of bypass valve capacity. The performance of this test at the lower power level still met the test objectives of determining the response of the reactor and its control systems to a turbine trip and of demonstrating integrated plant response following a turbine trip, particularly the fast bypass valve action. Immediately following the trip, the reactor water level, steam dome pressure, main steam flow and core flow signals oscillated at a f requency of 4 to 5 hz for about 5 seconds. The maximum wide range water level oscillation was about 67 inches peak-to-peak and reached the level 8 setpoint. In addition, the narrow range water level oscillations caused a recirculation system flow control valve runback when level 4 was reached (only feedwater pump B was operating). A problem report was written to initiate evaluation and correction of this phenomenon. l
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s # s TURBINE TRIP AND GENERATOR 10AD REJECTI(Bf
~
-N2-SUT-27 C. (Cont'd)
A licensing evaluation concluded.that the water 41evel indication
'" ringing" phenomenon was not. associated with; true water: level oscillation 'butL resulted from. fluid oscillation'. in the-instrument lines 1 which was caused by ai rapid pressurization. of-the reactor pressure vessel. The licensing evaluation further -
concluded. that the ringing _ phenomenon';was bounded by FSAR accidenti analyses and would not result in exceeding Technical l Specification safety limits.' Low pass- filters',have been-installed in' the -Master-' Trip Unit . circuit . of 18 RPV level-
. circuits to dampen the. oscillation.-
canarator h ad Re4ection - Rated Power The generator load rejection at rated power was ' performed ' in . TC-6 on March 5,1988 with the turbine-generator synchronized to - thergrid at 1136 MWe and the reactor operating - at. 99.6K of - rated. The generator load rejection . was initiated by tripping open the generator output breakers'R230 and R925 from the Scriba ,
. Station- by simulating a 345 kv. line high -differential voltage / current fault..
~
The turbine-generator power load unbalance (PLU) logic - sensed I the -load- reject and -initiated fast control valve closure.
' Simultaneously, the . f ast acting. solenoid valves in the bypass valve control system actuated . upon high bypass flow demand and ~
caused- the bypass valves to rapidly open. The simulated electrical fault also initiated a turbine trip which es.used fast turbine stop valve closure.- A reactor scram was initiated: by ' the control' valve fast closure and-.the recirculation pumps transferred As the high speed power supply to the low speed-MG sets upon aes.,stion of the EOC-RPT logic. Reactor done pressure quickly rose from an -initial value ' of 1003.4 psig until turned by opening of SRVs 2 MSS *PSV128 and 133 about .2 seconds into the transient. The open SRVs in combinati6n with the full open bypass valves were able to limit reactor dome pressure to a peak value of 1075.2 psig for a total pressure change of 71.8 pai. One SRV (PSV 133) reclosed within 10.8 seconds after opening at 986.6 psig and the other valve (PSV 128) reclosed 3.76 seconds later at 956.6 peig. The first SRV reclosed at the correct vessel' pressure whereas the pressure at which the second SRV reclosed was too low. The ; cause of the late reclosure was thought to exist in the control i block for PSV 128 which vents air from the actuator. The control block for PSV128 was replaced during an outage and a post maintenance test was completed. The removed control block - will' be examined and refurbished by GE - San Jose and Eugen-Seitz. *
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t TURBINE TRIP AND GENERATOR LOAD REJECTION: N2-SUT-27
< C. ' (Cont'd)
The bypass valves closed 23 seconds into the transient at a done pressure of 932.5 psig. Minimum reactor- pressure during the first three minutes of the transient'was.787.psig which provided L- a' 17.5 psi margin to the highestt main steam line low . pressure- ' setpoint, value (769.5 pois) at which the MSIVs would close with the reactor mode switch in the RUN position. Thefpositive change in vessel dome pressure,' which occurred I i within: the first 30 seconds af ter initiation of. the generator trip, 71.8 pai, was much less then the predicted value of 106.6 psi ' (corrected for actual ' plant parameters measured 'during - the test). Simulated heat' flux did not increase during the transient and therefore met the prediction of.a zero rise. Tripping open the generator output breakers caused an auto. transfer o f .. the- station auxiliary power- supply te buses 2NPS-SWG001 and 2NPS-SWG003 from the Normal Station Service Transformer to the Reserve : Station Service Transformers. ' However, instead of a fast auto transfer, the line protection trip logic blocked the fast transfer and caused a residual. transfer which resulted in both feedwater pumps (A : & ' B) - and condensate - booster pumps B and C i to trip. Wide range reactor water level quickly began to decrease. When it reached vessel level 2 setpoint about 24 seconds into the transient, RCIC and
'HPCS (and the .. HPCS emergency diesel-generstor) started and limited the vessel level decrease to a minimum of - 104.5 inches.
Reaching vessel level 2 also isolated the primary : containment, including the RWCU system, and caused: the- reactor recirculation ' pumps to trip off from the LFMG sets. As a consequence of the residual transfer of auxiliary power and
- the subsequent feedwater pump trip, several- test criterion were not met. These included verifying that 1) ' feedwater system settings will prevent flooding the main steam lines, 2) feedwater control shall avoid loss of feedwater due to high I level (L8) trip, and 3) that the low water level (L2) recirculation pump trip. HPCS and RCIC initiation shall not occur. A review of the water level and ' feedwater flow response to a full isolation, single reactor recirculation pump trip, and single feedwater pump trip performed previously in the test !
program indicated that these feedwater criteria for the generator load rejection test would have been met if power to the feedwater/ condensate systems had not been lost. g A modification to the Scriba Station line protection logic has been implemented so that fast transfer of the station auxiliary l power supply is not blocked by the backup protection package . (residual transfer) at the Scriba Station. w
-155 as
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.j f - WEs G E TRIP;AND GENERATOR' LOAD REJECTION -
~
N2-SUT-27 l C. . (Cont'd)' .j i The two recirculation pump drive flow coastdown following - the j EOC-RPT actuation was .not bounded by the : limiting - criterion I
- curves. Both recirculation.- loops A: and B.-drive flow coastdown
' curves slightly exceeded the : upper limiting (transient) . curve during . the first 1.25 - seconds of. the transient. . Both' . loops - :
easily l met the coastdown rate limits specified by the lower'LOCA l limiting. curve.- '
.l 1
CE Nuclear EnergyJ has performed 'a 're-evaluation of .the ' h end-of-cycle turbine trip / generator load rejection' drive flow 1 coastdown. The analysis shows that the drive ' flow coastdown characteristic is: acceptable and that no- MCPR ' limit.. adjustments are required. a The time' from . start of control valve closure to start of bypass ' < valve ' opening was- less than 0.011 seconds' which easily met - the q
' test criterion ~ of < 0.1 second. As these results show, the
' bypass valves began their ' opening stroke just ' slightly- before -
the control? valves began to ' close. The- time for the ' ' bypass .i
' valves to : reach .80% of their capacity was 0.14- seconds, which I also . easily- met the' test criterion of < 0.3 second. The total
- time " delay from. start of turbine control valve motion to complete suppression of electrical are between the . fully open
. contacts of .the RPT circuit breakers was 144.9 milliseconds which. met the EOC-RPT response time requirement of < '190 milliseconds.
Main turbine. speed peaked at'1883 rpm (104'.6%) and therefore did
- not. exceed the overspeed trip setpoint of 1980 rpm (1101).
4 Immediately following' the main turbine'. trip, the condensate domineralizer bypass valve (2CNM-A0V109). and. the low pressure heater string bypass valve (2CNM-A0V101) were expected 'to automatically open. (These valves open in order to ensure an
. adequato supply of condensate flow for the feedwater system during the ensuing reactor water level transient.) Both valves failed to automatically open following the turbine trip. 'The failure of these valves to open did not impact the ability to control reactor level since the feedwater pumps hed already tripped.
An investigation of the valve control logic for these two valves found a loose lead to the turbine first stage pressure switch in the valve opening logic. In addition, the power supply input leads to the pressure switch were found to be reversed. After correction, ' testing verified that the valve control logic properly opens the valves. ._ w
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L _ _ _ _ _ _ - - . _ _ _
j.g TERBINE TRIP AND GENERATOR LOAD REJECTION.
- j N2-SUT-27 c.
C.- L(Cont'd) a Upset range- reactor 'wat'er level indication exceeded 250 inches ', during the load rejection transient. The maximum recorded upset level -indication was 272.6- inches and occurred; immediately following the '. load rejection.- In contrast, narrow range level t indication linnediately . decreased following the load . reject ands , the . wide : range indication momentarily . spiked upward ; about 'l inches before decreasing. The' upset level indication - exhibited: the " ringing" behavior. .seen previously during ' fast-pressurization - transients on both the narrow and wide range'- level indications.- Filters installed in the Master Trip Unit circuits of the narrow , and ' wide range ' RPV level' circuits have successfully, dampened -these oscillations. (See~.'writeup on Turbine Trip within Bypass ~ Capacity.).. A. request to .NMPC-Engineering ,was made to evaluate increasing. the upset level transmitter dampening. Actual ' maximum wide range . water ' level
' indication following the load reject ' was 199 inches. which was
- reached . in about 2 minutes when RCIC and HPCS restored vessel
, level. .
Test . Exceptions. and their resolutions are ' summarized in Table - 3.22-1. .
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TARLE 3f 22-1. TURBINE TRIP AND. GENERATOR LOAD REJECTION N2-SUT-27 TEST EXCEPTION
SUMMARY
Test Test Exceotion Condition Description 1 2 The measured 1007,' open bypass steam ' flow did not meet the Level 2 Criteria. This was discovered to be due to the improper calibration : of the turbine steam flow instrumentation. A reevaluation of the, test data, using the "As Found" settings, showed that the Level 2 Criteria was met. 1 6 The condensate demineralized bypass valve and the low pressure heater string bypass valve did not automatically open following the main turbine trip from near rated power. A loose lead and reversed power supply input leads to the turbine first stage , pressure switch (2 MSS-PSHX104) in the control logic for the valves were found to prevent the switch from-activating. After correction, testing of valve control logic simulating auto open ' signals resulted in the valves opening as designed. 2 6 Reactor upset range level indication exceeded 250 inches during the load' reject transient and exhibited the ringing behavior seen previously during fast pressure transients. Actual reactor ' water level decreased after the load reject until it was restored by RCIC and HPCS. A request was made to NMPC to evaluate increasing the upset range level transmitter dampening. 3 6 The two recirculation pump drive flow coastdown transient following the EOC-RPT actuation was not bounded by the limiting Level I criteria curves. The measured coastdown curves slightly exceeded the upper limiting curve during the first 1.25 seconds of the transient. GE Engineering has re-evaluated the drive flow coastdown data and concluded that the flow coastdown characteristics did meet the Level 1 acceptance criteria. No adjustments to the Technical Specification MCPR limits are required.
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r TABLE 3.22-1 (Cont'd) TURBINE TRIP AND GENERATOR LOAD REJECTION N2-SUT-27 TEST. EXCEPTION
SUMMARY
Test Test Exception Condition Description 4 6 A low water level recirculation pump trip, HPCS and RCIC were initiated during the load reject transient. In addition, the recirculation pumps were tripped from the LFMG sets and the RWCU System was isolated. These Level 2 criterion ' violations were caused when vessel level reached L2 as a result of the feedwater pump trip. The results were accepted as-is because of the unanticipated residual transfer of house loads. See Test Exception #7 for details on the residual transfer. 5 6 An evaluation and verification of feedwater control . , adequacy in avoiding a loss of feedwater due to high ! level (L8) trip during the load reject transien t-(Level 2 criterion) was not possible because of the feedwater pump trip during the residual transfer of house loads. The results were accepted as-is because the feedwater system performance had been adequately demonstrated by previous testing. 6 6 A verification of feedwater control settings to i prevent flooding the main steam lines following the load reject transient (Level 1 criterion) was not possible because of the feedwater pump trip during the residual ' transfer of house loads. The results were accepted as-is because the feedwater system performance had been adequately demonstrated by previous testing. 7 6 Fast transfer of station auxiliary loads did not occur as expected following initiation of the generator load rejection test. An investigation found that the type of fault used to initiate the load reject simultaneously blocks the fast transfer and allows the residual transfer. The residual transfer initiates a load shedding scheme, which trips feedwater pumps, condensate booster pumps and ; recirculation pumps. A modification was implemented ) to remove the fast transfer block signal during actuation of the Scriba Station line protection package. _ w
-159 mm
-SHUTDOWN FROM OUTSIDE THE MAIN CONTROL ROOM N2-SUT-28' 3.23 N2-SUT-28 SHUTDOWN FROM OUTSIDE THE MAIN CONTROL ROOM A'. OBJECTIVE
'To demonstrate that the reactor can be brought from an initial normal steady-state power level down to the point w%re cooldown is initiated and under control with reactor vessel pressure and water level controlled from outside the Main Control Room.
B. ACCEPTANCE CRITERIA Level 1 Non Applicable Level 2 , .During a simulated Control Room evacuation, the reactor must be
' brought to the point where cooldown is initiated and under-control, and the reactor vessel pressure and water level are controlled using equipment and controls outside the Control Room.
C.- DISCUSSION This test was performed at the end of Test Condition 1. The test ' was performed in two sections, Hot Shutdown and Cold
. Shutdown Demonstration, in accordance with the Plant Operation. '
procedure for the Remote Shutdown System. This test demonstrated the capability to: Shutdown the reactor from 17.8% rated thermal power with the main turbine generator on-line.
- Achieve safe shutdown of the plant with a minimum shift crew as defined in Technical Specifications.
Maintain a stable hot shutdown condition for more than 30 minutes using the Reactor Core Isolation Cooling- (RCIC) system and Automatic Depressurization System Safety Relief Valves (ADS SRVs) to control the reactor's pressure and level.
- Transfer heat from the suppression pool to the ultimate heat sink using the Residual Heat Removal (RHR) system in the Suppression Pool Cooling Mode of operation.
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I SHUTDOWN FROM OUTSIDE THE MAIN CONTROL ROOM N2-SUT-28 1 l C. (Cont'd) 1 Control. the cooldown rate . of the reactor coolant using the Residual Heat Removal system in the Shutdown' Cooling Mode.
- Ensure adequate remote shutdown equipment ' and procedures
-for above mentioned operation.
- Hot Shutdown Demonstration Plant Condition: Initial Final Date: Aug. 9, 1987 Aug. 9, 1987 Time: 12:23 13:28 Reactor Power: 17.8% Rated Shutdown Reactor Pressure: 950 psig 630 psig Reactor Level: 183 in.NR 199.5 in.NR Core Flow: 35.9% N/A Generator Output: 115 MWE O -
The test was initiated with an evacuation of the Control-Room by the Remote Shutdown Crew. The reactor was scrammed by opening the breakers for logic power to the Reactor Protection System. The Main Turbine was then manually
. tripped at the front standard. Following. the reactor scram, the reactor level rapidly decreased to 165 inches and then began rising. The Reactor feedwater pump was secured from the local control panel and the MSIVs were shut from outside the Control Room as reactor level reached ,
200 inches. All four ADS SRVs were cycled from the remote shutdown panel to lower reactor water level and to reduce the reactor pressure. RHR 'A' was started in the Suppression Pool Cooling Mode operation to remove heat from the suppression pool and control the suppression pool water temperature. The RCIC System was manually initiated and injected into the vessel for about one minute to demonstrate the ability for reactor level control. Due to the high water level (186"), the RCIC Turbine was manually tripped after it reached 600 gpm to minimize the amount of water injected into the vessel. The thirty minute requirement for stable control of reactor pressure and water level was met and the hot shutdown demonstration was terminated after successfully transferring the system's control back to the Main Control Room. m
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SHUTDOWN FROM OUTSIDE THE MAIN CONTROL ROOM N2-SUT-28 C. (Cont'd) Cold Shutdown Demonstration Plant Condition: Initial Final Date: Aug. 9, 1987 Aug. 9, 1987 Time: 17:45 19:58 Reactor Pressure: 100 psig 10 psig Reactor Level: 186" NR 204" NR Moder~ator Temp: 340'F 250'F RHR A System Flow: N/A 7400 gpm RER A SW Flow: N/A 7600 gpm RHR B System Flow: N/A 7400 gpm RHR B SW Flow: N/A 5000 gpm The test was initiated with an evacuation of the Main Control Room by the Remote Shutdown Crew. The control of the RCIC, ADS SRV, RHR, and Service Water Pumps (SWP) were transferred to the Remote Control Panels. RER "B" was placed into Shutdown Cooling operation in accordance with the Remote Shutdown Operating Procedure. Reactor water temperature was lowered from 310'F to 250'F in approximately 24 minutes before the completion of cold shutdown demonstration was declared. Control transfer of the RER/SWP/ ADS /RCIC systems back to the Main Control Room was completed in accordance with the operating procedure. Problems and Resolutions
- Some of the indicating lights of the SRVs were found blown and have been replaced. Spare light bulbs are now stored inside the Remote Shutdown Room.
- When hot RER warmup water was discharged to Radwaste, it caused the fire detection system to actuate. A precaution statement has been added to the operating procedure.
- When transferring control back to the Main Control Room, RHS*MOV113 closed due to an isolation (NSSSS) signal in the Main Control Room which was not reset.
A precaution statement has been added to the operating procedure.
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SHUTDOWN FROM OUTSIDE THE MAIN CONTROL ROOM N2-SUT-28 C. (Cont'd) The nomenclature for the RHR Minimum Flow Valve breaker cubicle in the operating procedure was incorrect and the procedure did not provide steps for the proper return of control of the Reactor Recirculation Pump Discharge Blocking Valve bach to the Main Control Room. In addition, the remote Shutdown Procedure did not provide a contingency to
. allow tripping the Condensate Booster Pumps, if required. Tr.e Operating Procedure has been revised.
- The radwaste tanks are only rated to 165'F and cannot accept the hot RER flush / warmup water. A modification which will be implemented at the first refueling outage will remedy this problem by adding a flow path for discharging water from the RHR piping directly to the suppression pool. ..
- Due to crosstalk, the Acoustic Monitoring System for-PSV 126 actur.ted on opening of PSV 127. This situation has been corrected.
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l; . . . L l RECIRCUIATIM FLOW CMTROL N2-SUT-29 3.24- N2-SUT-29 RECIRCULATION FLOW CONTROL A. OBJECTIVES i
- 1. To demonstrate the core flow system's control capability-over the entire flow control range.
- 2. To determine that all electrical compensators and controllers are set for desired. system performance and stability.-
B. ACCEPTANCE CRITERIA Position Loon Criteria Level 1 1.- The transient response of any recirculation system-related _ variables to any test input must not diverge. Level 2
- 1. Recirculation system-related variables may contain oscillatory modes of response. In these cases, the decay ratio for each controlled mode of response must be less than or equal to 0.25.
- 2. Maximum rate of change of valve position shall be 5 (+1, '
.5) percent /second.
During TC-3 and TC-6 while operating on the high , aeed (60 Hz) source, gains and limiters shall be set to satisfy We criteria i of items 3, 4, and 5.
- 3. Delay time for position demand steps shall be:
For step inputs of 0.5 percent to 5 percent 1 0.22 sec.- 1 For step inputs of 0.2 percent to 0.5 percent (See Figure 3.24-1)
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RECIRCULATION FIM CGITROL g-N2-SUT-29 B. Level 2 (Cont'd)
- 4. Response time for position demand steps shall be:
For step inputs of 0.5 percent I to 5 percent. 1 1.05 sec. For step inputs of 0.2 percent t to 0.5 percent (See Figure 3.24-1)
- 5. Overshoot after a small position demand' input (1 to - 5 percent) step shall be < 10 percent of magnitude of input.-
Flow Loon Criteria Level 1
- 1. The transient response of any recirculation system-related variable to any test input must not diverge. ,
Level 2
- 1. The decay ratio of the flow loop response to any test inputs must be 1 0.25.
~~ ~
- 2. The flow loops provide equal flows in the two ' loops 'during steady-state operation. Flow loop gains should be set to correct a flow imbalance in about 20 i 5 sisc.
- 3. The delay time for flow demand steps (15 percent) must be 0.75 see or less.
- 4. The response time for flow demand steps (1 5 percent) must be 1.8 see or less.
- 5. The maximum allowable flow overshoot for demand steps of 1 5 percent of rated shall be 2 percent of rated.
- 6. The flow demand step settling time must be 1 25 sec.
' h.'AY
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RECIRCUIATIGE. FLOW CGITROL N2-SUT-29 B. (Cont'd) Flur Loon Criteria Level 1
- 1. The flux loop response to test inputs must not diverge.
. Level 2
- 1. Flux overshoot to a flux demand step must not exceed 2 percent of rated for a demand step of 120 percent of rated..
- 2. The delay time for flux response to a flux demand step - (1 20% of rated) must be 1 5 seconds.
- 3. The response time for flux demand steps (1 20% of - rated) must be 130 seconds.
- 4. The flux settling time must be 1 60 seconds for a flux demand step 1 20 percent of rated.
- 5. The flow . control system shall be adjusted to limit the maximum core flow to 102.5 percent of rated by limiting the flow control valve opening position.
Scram Avoidance and General Criteria Level 1 , Not applicable Level 2 For any one of the above loops' test maneuvers, the trip avoidance margins must be at least the following:
- 1. For APRM 1 7.5 percent.
- 2. For simulated heat flux 2 5.0 percent.
Flur Est4== tor Test Criteria Level 1 Not applicable
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n l RECIRCUIATIGt FL0lf CGtTROL i N2-SUT-29 B.: .(Cont'd) Level 2'
- 1. Switching between estimated and sensed flux should not.
exceed 5 times /5 minutes at steady state.
- 2. During flux step - transient there should be no switching to- j sensed flux or if switching does occur, it should switch-back to estimated flux within 20 seconds of the start of the transient.
Flow Control Valve Duty Test Criteria Level'1 Not applicable Level 2 ,
- 1. 'The Flow Control Valve (FCV) duty cycle in any operating mode must not exceed 0.2 percent - Hz. Flow control valve duty cycle is defined as:
Interrated valve mov== ant in cercent G Hz) 2 x time span (in sec) C. DISCUSSION , During Test. Condition 1 (TC-1) the position control loops were tuned and evaluated for satisfactory stability and response to step changes-(i 5% FCV position). During this testing, the loop controllers were in Manual and the recirculation pumps were in slow speed (15 Hz). d Step changes were inserted using a step generator test box which i inserted a biasing circuit into the actual control signal. All step changes satisfied delay and response times, overshoot limits and decay ratios. The valve speed for the FCVs was within the 10% i1% criteria as well for both positive and j negative step changes. Test data for TC-1 is summarized on Table 3.24-2. 1 i
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1 RECIRCUIATIG( FLOli CGITROL N2-SUT-29 C. (Cont'd) During TC-3 and TC-6 testing, the loop position controller eettings, with the loop controllers in Manual, were again tested for stability and. response to step changes.- This was done with the recirculation pumps in fast speed (60 Hz), at minimum ~ FCV position, 65% core flow and 98% core - flow. The results of the TC-3 and TC-6 position loop testing can be found on Table 3.24-3. The position loop testing performed in Test Conditions 3 and 6 < demonstrated that both position loops are very stable. In fact, decay ratios could only be calculated -in 7 out of 96 position loop step changes pe rformed. All calculated decay ratios met the 0.25 acceptance criteria. All other position loop criteria was met except as documented by Test Exceptions 1, 2,- and 8 on Table 3.24-7. Other testing in TC-3 and TC-6 included the Loop Auto (Flow) mode response to flow step changes. (i 5% in TC3, t 3% in TC6) at . 50% and 100% core flow. Scram avoidance margin was analyzed while in the Loop Auto mode at both 50% and 100% core flow. The results of the TC-3 and TC-6 flow loop testing can be found on Table 3.24-4. In all but one case, the decay ratios of FCV position, Narrow Range Level and Pressure, APRM, Jetpump Loop Flows, Drive Flow and Core Flow were indeterminable (no decay ratio observed). The lone exception was Narrow Range Pressure which demonstrated a decay ratio of 0.15 for the + 5% step at 50% Core Flow in TC-3. All decay ratios met the applicable acceptance criteria. All other acceptance criteria. for flow loop testing were met except as documented by Test Exceptions 3, 5, 6, 7, 9 and 10 on Table 3.24-7. In TC3, a flow loop decreasing then increasing flow demand ramp test was performed to demonstrate stable flow loop control. A 15% decreasing flow ramp was initiated from 64.5% power, 102.8% core flow utilizing the manual drive switch on the Flux Controller in the double detent position. Once conditions had stabilized an increasing flow ramp of the same magnitude was initiated in the same manner. The minimum APRM neutron flux trip margin (extrapolated to rated rod line) was calculated to be -0.52% at 103.3% core flow during the increasing flow ramp test. The minimum heat flux trip margins were 20.52% and 20.91% during the increasing and decreasing flow ramps. All acceptance criteria for this test was met except as documented by Test Exception 12 on Table 3.24-7.
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o q lRECIRCUL&TIGE FIDi CGITROL , ) q N2-8UT-29. / p
, C.: (Cont'd)
-1
. Flux controller testing was performed in.TC3 and TC6.at 68%' core flow and 100% core flow. ' At" 68% ' core flow t ' 8% . flux ' demand' steps were inserted into' the flux controller with the! estimator both in ~ service and ' in: bypass. At 100% core flow i L 511 flux 1
demand steps were inserted , into . the flux ' controller 'with ' the estimator both in service and in : bypass. ? Test results for flux - controller testing ' can he found on L Table 3.24-5. . All decay-ratios met the applicable acceptance criteria. All other flux - loop criteria. were : met except 'as documented' by Test. Exceptions
~ 4, 11, 13 ' and .14 ' on Table 3.24-7. ' The flux estimator switching-met all of its' criteria with no switching 'at isteady'~ state and satisfactory switching during transients.
In TC6 . a decreasing flux demand ramp test, was . perf ormed. to - demonstrate. stable flux loop control. A 20% . decreasing - flux
. ramp was ' initiated from 97%' power, 103% core flow utilising the ~
manual drive switch Jon the Master Controller in the double- . detent. position. The ' minimum heat' flux trip margin L was 12.9% A111 acceptance criteria for . this
~
(at the start of the ramp). test were met.
' In : order - to . evaluate the recirculation flow control systems-ability . to limit core flow to' less - than or equal to 102.5% of :
rated steady state system , data was collected in 10% core flow increments from 50% core flow to 100% - rated flow. .A plot.of total core flow vs drive flow A/B feedback (volts) was' made. An extrapolation of this data to 102.5% core flow conditions 'shows that the setting of the drive flow limiter (K649) is. adequate to limit " flux controller drive flow demand to no' more than .102.5%, thus meeting the acceptance criteria associated with this limit.- Final controller actual settings ere given in Table 3.24-6. Test Exceptions and their resolutions are summarized in Table 3.34-7. 4 .j
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*O FIGURE 3.24-1 RECIRCULATION FLOW CONTROL N2-SUT-29 4 TRADEOFF CURVE FOR STEP SIZES 0.2% TO 0.5%
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i 0.46 8.4 AAEA OF AASA 0F ACCEPTASLR ASSPOte88 UttaCCEPTASLE AtSP00sSE Iu \ I . I e e 8,1
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TABLE 3.24-2 RECIRCULATION FLOW CONTROL N2-SUT-29 TC-1 TEET RRRULTS - FOSITION LOOP Decay Ratios Valve Response Delay Response Step FCV Drive Time Time Overshoot
= Valve Size Position APRM Flow Velocity (in see) (in see) (1)
-5% <<.25 <<.25 <<.25 9.08%/sec 120 450 0.2 A
+5% <<.25 <<.25 <<.25 9.58%/sec 120 450 0.2-
-5% <<.25 <<.25 <<.25 9.33%/sec 120 400 0.0 B
+5% <<.25 <<.25 <<.25 10.41%/sec' 120 500 0.2 a
a-
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I&BLE 3.24-3 RECIRCULATION FLOW CONTROL N2-SUT-29 TC-3 TEST RESULTS - POSITION LOOP Delay Response Step Velocity Time Time Overshoot Flow Valve Size (%/see) (sec) (sec) (%)
+.5 2.08 .36* .20* 0.38 Min .5 -3.6 .24 .12 0.00 FCV _A 5 5.85 .33* .68 0.25 Position -5 -4.5 .30* .88 0.12
'+.5 0.25 .48* .32* 0.00 A .5 -0.06 .56* 1.20* 0.00 65% +5 5.0 .32* .80 0.10
-5 -4.12** .28* .96 0.00
_i,j_ 2.0 .11 .20 0.04 _ 45 -2.5 .18 .16 0.04 98% +5 4.35** .24* .92 0.04
-5 -4.17** .24* .98 0.00 Delay Response Step Velocity Time Time Overshoot Flow Valve Size (%/sec) (sec) (sec) (%)
+.5 2.00 .16 .20 0.29 Min .5 -4.28 .28* .14* 0.08 FCV +5 5.13 .33* .78 0.31 Position -5 -5.08 .36* .80 0.00
+.5 3.84 .16 .13 0.08 B .5 -3.60 .13 .12 0.00 65% +5 4.35** .16 .92 0.00
-5 -4.35** .20 .92 0.00
+.5 3.20 .14 .12 0.08
.5 -4.80 .12 .08 0.08 98% +5 4.80 .26* .82 0.00
-5 -4.50 .28* .84 0.08 Position Loop FCV Duty Cvelg FCV 'A' O.142 %-HZ FCV 'B' O.000 % - HZ
- See Table 3.24-7 Test Exception 1
** See Table 3.24-7 Test Exception 2
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TARLE 3.24-3 (Cont'd) RECIRCULATION FLOW C(NfTROL N2-SUT-29 TO-6 TEST nRRULTS -. POSITION LOOP Delay Response Step Velocity Time Time Overshoot Flow Valve Size (1/see) (see) (see) (1)
+.5 3.4 0.180 0.320 0.3 Min .5 -3.9 0.08 0.250 0.2
.FCV +5 5.92 0.371 ) 0.670 0.42
' Position -5 -5.5 0 321 ) 0.810 0.24
+.5 4.0 0.12- 0.190 0.15 A .5 -4.0 0.14 0.175 0.12 65% +5 6.0 0.251 ) 0.720 0.14
-5 -5.1 0.2751 ) 0.825 0.14
+.5 3.4 0.140 0.14 0.09
.5 -3.15 0.130 0.13 0.09-98% +5 5.5 0.241 ) 0.73 0.14 ,
-5 -5.1 0.22 0.77 0.18 Delay Response Step (%/Sec) Time Time Overshoot Flow Valve Size Velocity (see)' (see) (1)
+.5 4.90 0.22 0.18 0.3 ,
Min .5 -5.20 0.15 0.21 0.11 FCV +5 5.80 0.351 ) 0.69 0.18 , Position -5 -5.00 0.251 ) 0.79 0.07 )
+.5 5.30 0.12 0.18 0.12 B .5 -5.40 0.10 0.13 0.12 65% +5 5.90 0.281 ) 0.75 0.12
-5 -6.00 0.261 ) 0.80 0.00
+.5 4.86 0.13 0.10 0.12
.5 -4.90 0.11 0.09 0.09 98% +5 5.24 0.231 ) 0.76 0.14
-5 -5.15 0.21 0.76 0.00 Position Loon FCV Duty Ovele FCV 'A' O.029 % - HZ FCV 'B' O.000% - HZ i
- 1) See Table 3.24-7 Test Exception 8 l
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TABLE 3 14 .!i RECIRCULATION FLOW CONTROL N2-SUT-29 TC-3 TEST RESULTS - FLOW LOOP Core Step Delay Response Overshoot Trio Avoidance % Balance Flow Size A/B Time A/B Time A/B % APRM Bt Flux Time 50% +5 .4/.55 .6/.65 3)2.1/0 16.06 17.49 N/A
-5 .45/.35 .9/.85 1.4/1.4 N/A 16.08 4)5.8 100% +5 .65/.35 1.7/1.5 1.8/3.0 )3 -0.08 20.09 N/A
-5 .7/.35 1.55/1.45 1.7/1.8 N/A 20.66 4)26.0 E0.IE: - Settling time could not be evaluated because the steady-state noise on the drive flow signals was greater than 5% of the step size. See Table 3.24-7 Test Exception 6.
- All time recorded in seconds.
- 2) See Table 3.24-7 Test Exception 3
- 3) See Table 3.24-7 Test Exception 5 ,
- 4) See Table 3.24-7 Test Exception 7 Flow Loon FCV Duty Cvele FCV 'A' O.016 % - HZ FCV 'B' O.029 % - HZ TC-6 TEST RESULTS - FLOW LOOP Core Step Delay Response Overshoot Trio Avoidance 1 Settling Flow Size A/B Time A/B Time A/B % APRM Ht Flur Time 50% +3 0.3 /0.52 0.64/1.22 0.60/0.35 35.47 16.43 2.2 / 3.0
-3 0.65/0.45 0.80/0.65 0.38/0.28 N/A 16.90 2.22/ 1.56 100% -3 0.31/0.24 1.01/1,24 1.40/1.50 N/A 11.60 9.34/11.41
+3 0.80/0.22 0.40/0.88 2.50/1.50 2.74 9.60 9.10/ 6.85
- 5) 6)
Core Step Balance Flow Size T4 =a 501 -31 1.64 see 1001 -31 11.41 see Flow Loon FCV Duty Ovele FCV 'A' O.013 % - HZ FCV 'B' O.019 % - HZ
- 5) See Table 3.24-7 Test Exception 9 ,
I
- 6) See Table 3.24-7 Test Exception 10
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TABLE 3.24-5 RECIRCULATION FLOW CONTROL' N2-SUT-29 TC-3 Test Results - Flur Loop Core Step Settling Delay _ Response _ Overshoot Trip Avoidmace 1 Flow Size- Est4mator Time T4== Time 1 APRM Mt Flux
+8 IN 41.8 7) 1.5 29.2- 9) 0 18.57 18.94 68% OUT 23.5 1.2 16 0 23.92 19.26
-8 EN 29.9 2.0 24.5 0 N/A 18 85 OUT 52.5 0.9 22.5 0 N/A 18.85
+5 IN 38 1.93- 30 0- 3.77 20.78 100% OUT 34.2- 1.4 13.6 1.2 8.55 20.37
-5. IN 32.5 2.9 16.5 0 N/A 20.79 OUT 34.8 2.2 22.05 0 N/A 20.79
- 7) See Table 3.24-7 Test Exception 13
- 8) See-Table 3.24-7 Test Exception 4 9)= See Table 3.24-7 Test Exception 14 Flur Loop FCV Duty Ovele Flux Estimator in Service: FCV 'A' O.013% - HZ FCV 'B' O.006% - HZ Flux Estimator Bypassed: FCV 'A' O.110%.- HZ FCV 'B' O.085% - HZ TC-6 Test Results - Flur Loop-Core Step Settling Delay Response Overshoot Trio Avoidance 1 Flow Size Est4mator T4mm Time Time 1 APRM Ht Flux
+8 IN 36.35 0.30 22.95 0 27.22 16.19 68% OUT - 17.05 1.28 15.45 0 31.08 14.82
-8 EN 30.60 1.05 17.85 0 N/A 18.60 .
OUT 19.55 0.875 18.40 0 N/A 16.85
+5 IN 11.00 1.15 9.00 0 14.45 10.21 100% OUT 13.60 0.50- 11.60 0 14.26 10.66
-5 04 16.00 1.25 14.20 0 N/A 11.18 OUT 17.75 2.28 10.00 1.0 N/A 11.42 Flur Loon FCV Duty Cvele Flux Estimator in Service: FCV 'A' O.033% - HZ FCV 'B' O.026% - HZ Flux EstLnator Bypassed: 10) FCV 'A' O.229% - HZ FCV 'B' O.207% - HZ
- 10) See Table 3.24-7 Test Exception 11 1- -All times recorded in seconds.
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1 l TARTR 3.24-6 i RECIRCUIATIN FLOW CMTROL N2-SUT-29 RECIRCULATION FLOW CONTROT.T.ru SYSTDI SETTINGS Loop "A" Loop "B"
~ Velocity Controller Gain Settings:
- Proportional Gain 0.56 0.25
- Derivative Gain 0.0 0.0
- Integral Gain 1.1 1.3 Position Controller Gain Settings:
- Proportional Gain 27.0 30.0
- Derivative Gain 0.0 0.0 .
- Bias 5.0 5.1 Flow Controller Gain Settings:
- Integral Gain 0.33 0.33
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i TABLE 3.24-7 RECIRCULATION Flaf CONTROL 1 N2-SUT-29 TEST EXCEPTION S3 MARY Test Test Exception Condition Description 1 3 Delay times and response times for position loop steps did not meet Level 2 Criteria (See Table 3.24-3) under all conditions. Exception accepted as is. Delay and response times will be reevaluated after TC-6 tuning. 2 3 FCV velocity did not meet Level 2 Criteria (see Table 3.24-3). Exception closed following adjustment of velocity controllers via a Maintenance Work Request. This will be retested in TC-6. 3 3 APRM trip avoidance found during +5% flux step at - . 100% Core flow, with the estimator in service, did not meet Level 2 Criteria. Exception accepted as is, as APRM oscillations caused criteria failure. 4 3 APRM trip avoidance found during +5% flux step at 100% Core flow did not meet Level 2 Criteria. Exception accepted as is, as APRM oscillations caused criteria failure. 5 3 overshoot analysis of flow steps did not meet Level 2 Criteria (see Table 3.24-4). Exception accepted as is since the steady state flow signal peak to peak noise is greater than the overshoot _ limit. Evaluation with these conditions is inconclusive. 6 3 Settling time could not be measured for flow steps (see Table 3.24-4). Exception accepted as is since steady-state peak to peak noise on drive flow makes setting time measurement inconclusive. 7 3 Balance time for flow steps does not meet Level 2 Criteria. Exception accepted as is since the intent of criteria (balance in 125 seconds) is met within 1 second. i
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4 TARLE 3.24-7 (Cont'd) l RECIRCULATION FLOW CGITROL N2-SUT-29
]
TEST EKCEPTIGi SGelAEY l Test Test l Excention Condition Description 8 6 Delay times for FCV A & B did not meet the 0.22 sec. requirements, during POS testing. Accepted as in per GE San Jose evaluation. Valve response demonstrated acceptable stability, there was no indication of abnormal valve response, and the delay times measured will have no adverse effect upon the recirculation flow control system. 9 6 Delay time for loop Flow A did not meet the 1 0.75 see criteria for the +3% flow step at 100% core flow. Accepted as is due to vortex shif t occurring just prior to the step. Flow control valve response . indicates that the criteria would have been met without the vortex shift. 10 6 Overshoot for Loop A flow did not meet the criteria for the +3% flow step @ 100% core flow. (2.5% vice 1 2.0%). Accepted as is per reasons of T.E. #9 of TC-6 above. 11 6 Flow control valve duty cycle for both valves exceeded the 1 0.2% -Hz criteria. Accepted as is-since the failure did not result from mechanical or control system problems. The valves were attempting to correct a large flux error signal due to APRM noise. Violation only occurs during FLX mode with the flux estimator bypassed. San Jose advised not to place the recirculation flow control system in ' this configuration to limit the duty cycle on the
-valve. Plant proce2ure OP-29 (Reactor Recirculation System) was changed to prevent operation in this i mode. j i
12 3 The APRM extrapolated neutron flux trip avoidance margin calculated during the increasing flow ramp test was found to be -0.52% instead of the required margin of 7.5%. This is a Level 2 criteria. The resolution was to accept as is since the 7.5% margin requirement is not applicable to a positive change in flow of this magnitude and rate. ,
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TABLE 3.24 7 (Cont'd) RECIRCUIATIGE FLOW CGfTROL N2-SUT-29 TEST EECEPTIG( SGel&RY Test Test Excention Condition Description 13 3 Settling time for the +8% flux step while in Flux Auto with the Flux Estimator in operate at 68% core flow was approximately 106 sec. which exceeds the 60 see Level 2 criteria. Settling time for -8% step change with these conditions was 36' seconds. Retest
- #3 was perfonned and the . settling time measured met the acceptance criteria.
14 3 Overshoot was calculated to be 2.4% during flux loop testing at 68% core flow, +8% step change with the flux estimator in service which exceeded the 2% of rated acceptance criteria. Retest #3 was performed and the overshoot results met the acceptance criteria. l l l l l y
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REACTOR RECIRCUIATI(El SYSTEM N2-SUT-30
> 3.25 'N2-SUT-30 REACTOR RECIRCULATION SYSTEM A. OBJECTIVES
- 1. -To obtain recirculation system performance data during' recirculation pump trip, flow coastdown, and pump restart transients.
- 2. To verify that the feedwater ' control system can satisfactorily control water level without a resulting turbine trip / scram.
- 3. To record and verify acceptable performance of the recirculation two-pump circuit trip system (RPT).
- 4. To record recirculation system parameters during the power test program.
- 5. To verify' the adequacy of the recirculation runback to' prevent a scram on loss of- one feedwater pump. and, subsequent level 4.
- 6. To verify that no recirculation system cavitation occurs in the operable region of the power-flow map.
B. ACCEPTANCE CRITERIA Level 1
- 1. The reactor shall not scram during the one pump trip recovery. .
- 2. The two-pump drive flow coastdown transient during the first 3 sec., excluding the first 0.25 sec., must be bounded by limiting curves.
Level 2 l
- 1. The reactor water level margin to avoid a high level trip is greater than or equal to 3.0 inches during the ' one-pump trip.
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- 2. The simulated heat flux margin to avoid a scram is greater than or equal to 5.0. percent during the one-pump trip and during pump trip recovery.
- 3. The APRM margin to avoid a scram is greater than or equal ,
to 7.5 percent during the one-pump trip recovery. y w
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>M REACTOR RECIRCULATION SYSTEM N2-SUT-30 B. Level 2 (Cont'd)
- 4. The measured core DP. shall not be r 3 psi above prediction. ]
- 5. The recirculation flow control. valve shall runback to 45 [
percent drive flow upon a trip of the runback circuit. q 1
- 6. Runback logic settings are adequate to prevent operation in 1 areas of potential cavitation. k C. DISCUSSION Reactor Recircuintion System Sinele Ptunn Trip The 'A' Recirculation Pump was tripped' from 73.3% power, .103.0%
core flow by turning the Recirculation Pump Breaker SA control switch to " Pull-to-Lock". The pump was allowed to coastdown to a stop. The reactor water level margin to a high level trip was analyzed and found acceptable (criteria limit 1 3.0 inches,- . actual 10.9 inches). .The simulated heat flux margin to avoid a trip was analyzed and found acceptable (criteria 5.0 percent, actual 30 percent on trip, 16.3 percent on restart). The APRM margin to avoid a scram on the pump restart was also evaluated and found acceptable (criteria 7.5 percent, actual.41.6 percent). The 'B' Recirculation Pump was tripped from 98.2% power, 104.0% core flow by turning the pump motor breaker 5B control switch to
" Pull-to-Lock". The pump was allowed to coastdown to a- stop.
The operating Recirculation Loop 'A' drive flow was adjusted to 100%, 90%, 80%, 70%, 60% and 50% of the initial Loop 'A' drive flow prior to the pump trip (45.17 KGPM). At each-step system. performance data was recorded. The Narrow Range and Wide Range Reactor water level margins to a high level trip were analyzed and found acceptable in a Narrow Range instrument channel (limit greater than or equal to 3.0 inches, actual 13.3 inches) but failed in a Wide Range level channel (actual -4.87 inches, see Table 3.25-4 test exception 6). The simulated heat flux margin to avoid a trip was analyzed and found acceptable (criteria 5%, I actual 14.66%). The APRM margin to avoid a scram on the 'B' pump restart was evaluated and found acceptable (criteria 7.5%, actual 39.01%). Therefore, all criteria for the single pump trip were satisfied except the Wide Range level trip margin (test exception 6). The Reactor did not scram on the pump restart thus satisfying the Level 1 criteria.
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L , , I REACTOR RECIRCULATION SYSTEM N2-SUT-30 C,. (Cont'd)- , Reactor Recire System RPT Trio of Both Pumns
.The two pump RPT was performed from 66.4% power, 104% core flow I by means of a temporarily installed test switch. When the test ]
switch was closed both recirculation pumps tripped from high j
. speed to off. An RPT normally transfers the recirculation pumps to slow speed. Due to an error in the test procedure the test switch was installed such - that the RPT trip circuit logic was activated but not the high to low speed transfer logic. On-site analysis for this test consisted of plotting the individual drife flow coastdown versus the GE supplied criteria curves.
Neither Loop A or B met .the applicable transient analysis bounding curve. The test data was provided to GE Engineering for further analysis. The GE review questioned whether or not the flow transmitter time delays utilized in the analysis could be accurately determined in ~ the field considering the magnitude of ~the estimated delays. The damping circuits for these transmitters were set at maximum resulting in estimated time { delays of 1.6 and 2.2 seconds. Since the accuracy of the time delay measurements was in question no final analysis of the drive flow coastdown data could be made. GE's assessment was that plant operation could continue until the test ~ could - be repeated so long at the conservative EOC-RPT inoperable MCER limit per Figure 3.2.3-1 in the Technical Specifications was imposed. During the TC5 outage prior ~ to TC6 the flow I transmitter damping circuits were adjusted to achieve time constants of approximately 420 ms. The two pump RPT was subsequently retested in TC6 during N2-SUT-27.- The two RPT coastdown was acceptable. Further details can be found in Section 3.22, N2-SUT-27. Reactor Recirculation System Flow Control Valve R,mhack Test The recirculation system flow control valve runback test was i performed from 59.6% power, 101.3% core flow by means of a temporarily installed test switch. The temporarily installed test switch simulated a reactor feed pump trip and Level 4 reactor water level. Throwing the test switch initiated a flow control valve runback. Analysis for this test verified that the recirculation drive flows in both loops runback to 1 45% of rated drive flow. Water level margin to avoid a high level trip could not be evaluated because the A Recire Pump transferred to , slow speed during the runback. Test Exception 2 was written and I resolved to accept as is since the feedwater control system would be tested further in TC6.
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4' c REACTOR RECIRCU1ATI(El SYSTBI N2-8UT-30 a C.- (Cont'd) Rameter Recirculation Evatem Non-Cavitatina Verification Tem t -
- S t = == P-- - - "acirculatinn P - Suction T - rature DT ,s The recirculation ' system pump cavitation- interlock verification >
test was performed : by inserting control rods from n. starting point of 58.71 power, 97.4% core flow until the first' Steam - Dome-Recirculation Suction Temperature DT .interlockEtripped. The Recirculation Pump Transfer to slow speed. . which would. have . occurred when the interlock tripped, was prevented by use of-the, bypass switches. During the power decrease . plant parameters were monitored to ensure that cavitation' did .not occur. . The-A; g and B ' interlock logic changed states- at a DT of 10.45: and 11.25
'F. The test was stopped at . this point, af ter, it was verified -
that - no cavitation existed.' The A interlock logic did not-change state within the specified_ tolerance' (10.7 t 0.13 'F). . Test Exception 4' was written- to document this situation. , . Subsequently, the DT's at : which ' the . interlocks activated were
. recalibrates to the more ' conservative specified value.. This provided verification - that - the logic settings- were adequate to prevent operation in areas of, potential cavitation.-
R==etor Recirculation Swatan Non- Cavitat 4 nn Verificat4nn Tant - Total Feedwater Low Flow Interlock The recirculation system total feedwater low flow interlock verification test was performed by inserting control rods from a starting point of 393 power, 48% core flow until both of the low feedwater flow interlock relays' tripped. The Recirculation Pump ~ Transfer to slow speed, which would have occurred when the interlock tripped was prevented by use of bypass switches. During the power decrease, plant parameters were monitored to ensure that cavitation did not occur. Both low feedwater flow interlock relays changed state at 4.033 MLB/HR which was greater than the 4.0 MLB/HR setpoint. Successful completion of this section verified that the low feedwater flow interlock logic settings were adequate to prevent operation in areas of potential cavitation. 4
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s REACTOR RECIRCULATION SYSTEM N2-SUT-30 C. (Cont'd)
'Rametor Recirculation System Perfo m nce M===urement-Standy l:
gj; ate'100 Percent Load Tine-Flow Control Valve - (FCV) Position Vs. Core Flow The Reactor . Recirculation system performance was measured,: along
. the 100% load line . 'at minimum FCV position, 50% core , flow.. 75%
core flow .and 100% core flow- respectively. The. plots. of averaged FCV position versus core flow (Figure 3.25-1), FCV 'A'- position versus Loop A drive flow (Figure 3.25-2), and FCV 'B'
. position versus ' Loop B drive flow (Figure 3.25-3), were completed using the data recorded. The corrected core' flow shortfall 'is 2.50%. which is less-L than the maximum 5% (see Table '
3.25-4 Test' Exception 5)*.. The calculated drive ficw shortfall
' is 0.07% ' for Loop A and -0.95% for Loop' B which are -less than the maximum 5%.- The measured core plate DP.is 20.518 psid which is less than the predicted value (21.81 ' psid) . The esiculated recirculation pump efficiencies are 95.5%-/.95.8% which are 4.5%'
/ 4.8%. higher than the vendor tested efficiency.(91%).
Test Exceptions and. their' resolutions are summarized in Table 3.25-4.
- The corrected core flow shortfall (correction due to core flow '
miscalibration LER 88-45) is within the Level '3 criteria ' making Test Exception 5 not'necessary.
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c:> f . 1 I TABLE 3.25-4 REACTOR RECIRCULATION SYSTDI N2-SUT-30 TEST EXCEPTION SINEWiRY Test. Test Excention Condition Description 1 3 'A' and 'B' drive flow coastdown during. two pump RPT was not within criteria ' limits. Exception' closed by implementing the specified Minimum Critical Power Ratio penalty administrative 1y. The drive flow l coastdown will be evaluated-again in TC 6. 2 3 Water level margin to avoid a high level trip cannot be evaluated from Recirculation System Flow Control Valve Runback due to the 'A' Recirculation Pump transferring to low speed during the test. Exception accepted as is since water level control system response will be evaluated again in TC6. . 3 3 RPT test resulted in recirculation pumps tripping to off. Exception accepted as is since there is no dif ference between the events over the first 3 seconds. 4 3 Recire Pump Cavitation interlock (Steam Dome to Recirculation Loop Suction Temperature) did not change state within calibration limits. Exception accepted as is, no cavitation was detected and setpoints were adjusted to the specified values.
*5 6 The corrected core flow short fall was 2.50% which is within the criteria limit of 5%. Exception accepted as is.
6 6 Wide range level indication failed the level 2 criteria for margin to high level trip following the
'B' reactor recirculation pump trip. Accept as is since the narrow range level instrumentation which provides the level 8 trip meets the acceptance criteria.
- Test Exception 5 is not necessary, corrected core shortfall is within criteria limit of 5%.
l
-188 -
An '
,l 1
L ! IDSS OF TURBINE-GENERATOR' AIG OFF-SITE POWER N2-SUT-31 l; 3.26. N2-SUT-31 LOSS OF TURBINE-GENERATOR AND OFF-SITE POWER A. OBJECTIVE a
- 1. Demonstrate the electrical equipment transient performance .I and reactor system transient performance during a loss of I l
' auxiliary power.
l
- 2. Demonstrate adequate reactor support system response to a turbine-generator trip and loss of off-site power.
B. ACCEPTANCE CRITERIA Level 1
- 1. All safety systems such as the Reactor Protective System
-(RPS), diesel generators, and High Pressure Core Spray (HPCS) must~ function properly without manual assistance, and HPCS and/or the Reactor Core Isolation Cooling (RCIC) system action, if necessary, shall keep ' the reactor water level above the . initiation level of the Low Pressure Core Spray (LPCS), Low Pressure Core Injection (LPCI) Automatic Depressurization System (ADS), and Main Steam Isolation Valve (MSIV) closure. Diesel generators' shall start and' load automatically.
Level 2
- 1. Proper instrument display to the reactor operator shall be demonstrated, including power monitors, pressure, water level, control rod position, suppression pool temperature, and reactor cooling system status. Displays shall not be dependent on specially installed instrumentation.
C. DISCUSSION A preliminary loss of off-site power test was performed with the plant in cold shutdown ou 9/23/87 to identify equipment. and design problems that would need to be resolved to support successful completion of the official test. The following problems were identified during this test and corrected prior to performance of the 10/13/87 test.
-189 .
~
l as Jam
IA88 0F TURBINE-GENEEATOR AND OFF-8ITE POWER N2-SUT n ~C. .(Cont'd) 1.. Temporary Modification. 2257 wasLinstalled to permit use Lof - a temporary nitrogen' supply ~inside ~ the - drywell to _ - supply reactor recirculation. pump sealL staging valves -- 2RCS*A0V45A -
& B. These ; valves fail open1 on loss,- of 125 VDC. power or pneumatics and? are 'normally open fduring pump operati'on toL
- atage ~. pressure across the two pumpJ seals.. ~ If pumps 1 are -
b secured with no seal injection-flow, seal staging: flow will' overheat; and destroy the seals. Pneumatics to - 2RCS*A0V45A
&-B are .. normally - isolated, . as .- A0Vs for E.the drywell'~to suppression chamber vacuum breakers are ' supplied . by ' the same . pnetsnatic supply header.. These vacuum breaker. A0Vs -
' are not environmentally ; qualified and thus = pneumatics 1to them must be normally. isolated. The temporary modification enabled 2RCS*A0V45A & B . to close upon loss ofJpower to protect- the . recirculation pump. seals. Permanent':-
Modification 87-184: is being implemented to: replace 2RCS*A0V45A &- B with .SOVs that will close - upon loss of. CRD ~ pumps coincident with recirculation pump trip. .
- 2. Standby Gas Treatment (SBCT) Train B failed-~to start automatically as hydraulically " crerated inlet and - outlet valves 2GTS*MOV2A,, 2B, 3A. and 3b close inumediately due to loss of power. Solenoid valves de-energize on a loss - of .
power to enable ~ hydraulic accumulators to close the MOVs. The SBGT initiation signal is maintained for about 30 seconds. If the train inlet - and outlet valves are not. opened within this time, the SBGT train will ' not auto start. Modification 87-206 was implemented which installed a 15 second minimus ' time delay on the de-energization of the solenoid which would cause.2GTS*MOV2A, 2B, 3A and 3B to' , fail closed on a loss of power, to allow diesel generators time to automatically start and energize' emergency buses.
- 3. In the event that venting of the primary containment would be necessary to depressurize the containment due to loss of drywell cooling, a flow path from the containment . vent and purge system to SBGT Trains would be necessary. Valve 2GTS-80V102 would have to be cpened to establish this vent path. This valve would have been de-energized during a loss of off-site power as it is energized- from a non-essential power supply with no reliable alternate feed. Modification 87-212 was implemented to provide reliable power to 2GTS-SOV102.
-190 .
4 JW m
s g ' IDS 8 0F TURBINE-GNERATOR AND OFF-8ITE POWER
-N2-SUT-31 C.- (Cont'd)
- 4. Drywell. Unit Cooling. Trains could not'be started during the..
. shutdown demonstration test c to restore the Drywell Cooling System. as control power' to these : circuits was not f rom a reliable source. Modifica. tion ~ 87-205 .was . implemented to provide' reliable power.to Drywell' Cooling fan control power circuits.
The loss. of off-site- power test ' was. conducted during . Test - Condition' 2 on 10/13/87. The test' 'was initiated by simultaneously tripping the Main Turbine , and. opening the NMP2 -' of f-site . supply . breakers R50 and ' R60 at the 'Scriba Switchyard
. isolating . all power to the plant ' from off-site for at least 30 minutes. ' All acceptances criteria were satisfied. The sequence of- events for the Loss of Off-Site Power Test is summarised in
- Table 3.26-1.
~ + . Prior to initiating the test, it.was noted that'the Turbine Stop. ,
cValve (TSV) and Turbine Control Valve (TCV) scrams were enabled as turbine . first stage pressure had ; exceeded the- setpoint for-these scrams. Thus the cause of the scram was - anticipated.~ - Main Turbine Trip and loss of ' off-site. power initiated turbine - control valve fast closure to cause a reactor scram. . No- APRM neutron flux or - heat flux spikes. were : observed following the-
-scram.- The peak values were the initial values observed.-
.approximately 24% Reactor Power.
All Emergency Diesel Geners, tors , functioned = satisfactorily, L starting and -loading ~ automatically, and met all'._ Tech Spec L surveillance requirements which could be evaluated.with the test-data. Starting times (normal feed' breaker open to diesel generator output breaker ~ closure) for ' Division 1, 2 and 3-Emergency Diesel Generators were 10.9, 10.8 and 12.2 seconds respectively. Load shedding and sequencing of service water pumps was satisfactory. Wide range water level decreased to a minimum value of 142 inches during the test, following the last Safety Relief Valve (SRV) lift. All Level 3 logic tripped _ as expected. No automatic RCIC. initiation occurred as ' the temporary setpoint of 134.6 inches 6 inches was not reached. (During this test, the RCIC setpoint was raised above its normal Level 2 setpoint to avoid a HPCS Emergency Core Cooling System (ECCS)' Injection. ) This temporary setpoint change was approved by Safety Evaluerion 87-127. HPCS was manually started in the CST to CST teer flow path mode about 9 minutes af ter the test was initiated to lead the Division 3 Emergency Diesel Generator and was never used to .
~
inject water to the reactor vessel. Maximum narrow range water
-191 w L. ,"
2
IDSS OF TURBINE-GENERATOR AND OFF-SITE POWER N2-SUT-31 C. (Cont'd) level observed was 203.7 inches . immediately af ter initiation 'of. g the test due to level instrumentation ringing caused by the 3 turbine' trip. pressure transient. RCIC .was not operated to control reactor vessel level or pressure until the test was declared complete. The. peak average drywell temperature observed during the test was 107'F, well within the Tech Spec limit of 150*F. Drywell Cooling was restored within 10 minutes of test initiation.- The peak average suppression pool temperature observed . during the test was 73*F, well within the Tech Spec limit of 120*F. Peak reactor pressure observed was 1073 psig and was terminated by automatic operation of SRVs B22-F013A and B. All subsequent pressurization transients were controlled by manual operation of SRVs in accordance with Emergency Operating Procedures. An immediate MSIV isolation was not expected and none was observed. MSIVs were manually shut about 26 seconds after test i initiation in accordance with the test procedure Turbine bypass valve operation was observed to control the initial pressure transients until the steam lines were manually isolatna, The following systems were restored during the performance of this test: Stub Buses 2NNS-SWG014 and 2NNS-SWG015, service water to Reactor Building Closed Loop Cooling Water, Control Rod Drive System for Reactor Recirculation pump seal injection, Drywell Cooling, Instrument Air and RPS Motor Generator sets to permit reset of the scram. During the performance of the Loss of Off-site Power Test on 10/13/87, the following equipment and design problems were identified. (
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- - - - - - _ - _ _ _ - - - - - 0
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[ IDSS OF TURBINE-GENERATOR AND.OFF-SITE POWER ; N2-SUT-31 .! l l i C. (Cont'd) ]
- 1. Emergency. Response Facility / Safety' Parameter Display. '
System analog computer ' points failed downscale during the loss of of f-site power as the optical isolator power supply f or these points was not reliable. This problem ' was also noted during the 9/23/87. test _- when { attempting to read suppression pool temperature ~ and ' drywell . temperature indication on - the Emergency Response Facility computer. Modification , Request. l
. I20288 has been. submitted and is scheduled to be performed during the first refueling outage.
- 2. Emergency lighting in ECCS equipment areas inside the secondary containment ' was inadequate during the loss' of power test. Modification Request I20280 has been-submitted. This is a low priority mod and has not been scheduled for implementation.
- 3. A temporary modification was necessary. to provide
- reliable power to the oscillograph in the Switchgear
. Building to monitor Main Generator 115KV. 13.8KV, 4.16KV parameters and protective relaying for Meter and Test. This temporary modification has been cleared and the system restored to normal.
- 4. A FSAR change was submitted by Licensing based . upon the test results, as Section 15.26 and Section 15A of the FSAR assume MSIV closure in 2 seconds due to loss of power in the Loss of AC Power Analysis. The analysis is conservative as the MSIVs will eventually close due to low reactor pressure or low condenser vacuum, but not within 2 seconds due to loss of control power.
-193 ,
gs An'
} TARLE 3.26 i.- .I l LOSS OF TURBINE-GENERATOR AND OFF-SITE. POWER l N2-SUT-31
, LOSS OF OFF-SITE POWER'SEOUENCE OF EVENTS nu EvENr
- 0. Main Turbine . Trip, loss ~ of off-site power - manually- )
initiated. . 1 0.20 sec. Reactor Scram on TCV Fast Closure. 0.33 sec. Bypass valves-begin to open. 1 0.34 sec. Division 1 Bus normal feed breaker trips, loads shed. 0.35 sec. Division 2 Bus normal feed breaker trips, loads shed. 0.36 sec. Division 3 Bus normal feed breaker trips. j 0.83 sec. Bypass valves at 76.7% open. ' 8.8 sec. Reactor vessel low Level 3 achieved (<159.3 inches). 11.15 sec. Division 2 diesel generator breaker shut.
'11.19 sec. Division i diesel generator breaker shut.
12.54 sec. Division 3 diesel generator breaker ' shut. 26 sec. Manual closure of MSIVs initiated. ,
.)
i 27.6 sec. Feedwater Level Control setpoint setdown enabled. 44.5 sec. B Service Water Pump Auto starts (33.4 see TD). 46.5 sec. A Service Water Pump Auto starts (35.4 sec.TD). 2 min.(approximate) 2NNS-SWG014 energized from Division: 1 Bus. 2NNS-SWG015 energized from Division' 2 Bus.. Service Water restored. to the Reactor Building. 2 min. 37 sec. C Service Water Pump manually started. ' 4 min.(approximate) Drywell Cooling fans started. RBCLCW pumps 2CCP-P1B, 2CCP-P2B started. 5 min. 22 sec. Reactor vessel high pressure trip achieved (>1037 Psig). 7 min.(approximate) Instrument air compressor 2IAS* CIA started. RBCLCW pumps 2CCP-P10, 2CCP-P2C started. 9 min. 12 sec. HPCS pump manually started in CST to CST test flow path to load the Division 3 diesel generator. 9 min. 20 sec. CRD pump 2RDS*P1A started. 9 min. 57 sec. Peak reactor pressure of 1073 psig achieved. SRVs 1 B22-F013A. B auto open (normal setpoint 1076 psig). ] 10 min. 7 sec. SRVs B22-F013A, B auto close. 13 min. 8 sec. SRV P,22-F013D manually opened. 13 min. 40 sec. SRV B22-F0130 menually closed. 18 min. 18 sec. SRV B22-F013V manually opened. , 18 min. 39 sec. SRV B22-F013V manually closed. ' 21 min. (approximate) Instrument air compressor 2IAS*C1B started. 23 mia. 59 sec. SRV B22-F013E manually opened. ! 24 min. 21 sec. SRV B22-F013E manually closed. ? 2S min. (approximate) Opened 2IAS*SOV184 2IAS*SOV166 to restore instrument j air to the SRVs (valves fail shut on loss of power). j 29 min. 29 sec. SRV B22 4013J manually opened. y 29 min. 30 rec. HPCS pump secured. . 29 min. 52 sec. SRV B22-F013J manually closed. ' sin; 32 min. Test complete, j l
-194 i am
.. _ _ _ _ _ - _ l
DRTWELL PIPING VIBRATION N2-SUT-33 3.27 N2-SUT-33 DRYWELL PIPING VIBRATION A. OBJECTIVE
- 1. To verify that the vibration of the reactor recirculation piping is within acceptable limits.
- 2. To verify that stresses are within code limits during operating transient loads.
B. ACCEPTANCE CRITERIA Level 1
- 1. Operating Vibration: Level 1 limits on piping displacements are prescribed in Table 3.27-3. These limits are based on keeping piping stresses and pipe mounted equipment accelerations within safe limits. If any one of the transducers indicates that the prescribed limits are excoeded, the test is placed on hold.
- 2. Operating Transients: Level 1 limits are prescribed in Table 3.27-4. These limits are based on keeping the loads on piping and suspension components within safe limits. If any one of the transducers indicates that these movements have been exceeded, the test shall be placed on hold.
Level 2
- 1. Operating Vibration: Acceptable levels of operating vibrations are prescribed in Table 3.27-3. The limits have ,
been set based on consideration of analysis, operating experience and protection of pipe mounted components.
- 2. Operating Transients: Transducers have been placed near points of maximum anticipated movement. Where movement values have been predicted, tolerances are prescribed for differences between measurements and predictions.
Tolerances are based on instrument accuracy and suspension free play. Where no movemente are predicted, limita on displ acement have been prescribed. Table 3.27-4 tabulates allowable movements or novement tolerances for each t.ransducer.
-195 .
Am
DRYWELL PIPING VIBRATICM N2-SUT-33
'l C. DISCUSSION Reactor Recirculation Piping was monitored for vibration using -
Lanyard Potentiometers . during steady state and transient plant conditions throughout the testing program. The location of' these transducers on the Recirculation Piping is given in Figures 3.27-1 and 3.27-2. ~A total of .4 locations in each Recirculation Loop were instrumented. Each location was monitored in 3 directions (X,Y&Z). An' additional point was monitored on the 'A' Loop center jetpump riser for informational-purposes. The GETARS computer was used to analyze the peak-to-peak displacement values for each Langard Potentiometer location. Test Conditions and results of the testing are summarized in Table 3.27-5. STEADY STATE VIBRATION TESTING Steady state test data was taken during Test Conditions 1, 5 and
- 6. In general, the results show that levels of vibration were slightly higher at higher reactor powers than at lower power conditions. The final test results were well within the acceptance criteria.
TRANSIENT VIBRATION TESTING Transient test data was taken during Test Conditions 3 and 6. Single recirculation pump trips and subsequent restarts were performed in conjunction with N2-SUT-30. The highest vibration reading on the Recirculation Pump "A" test occurred during the pump restart in Test Condition 3, 0.051 inch peak to peak displacement at point RA4Y. The highest vibration level on the Recirculation Pump "B" test occurred during the pump restart in Test Condition 6, 0.059 inches peak to peak displacement at Point RB1Y. All single pump trip and restart vibration data fell within the Level 2 acceptance criteria. The two recirculation pump trip vibration test was performed in Test Condition 3 in conjunction with N2-SUT-30. Piping vibration levels were found equivalent to those for single pump trips. The test was originally written to obtain data during a Recirculation Pump Transfer to slow spe<td, however, a procedural I error in N2-SUT-30 resulted in the recirculation pumps being tripped to off (i.e., natural circulation). Test Exception 1 was written and the resolution wits to accept as is based on the fact that actual test provided a mort severe transient than a -1 Recirculation Pump Transfer to slow speed. i -196
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IRDfELL PIPING VIBRATIW -j
- 1 N2-SUT-33 C. (Cont'd).
The ~ two recirculation pump. transfer . (EOC-RPT) was performed /in Test Condition .6 in; conjunction with N2-SUT-27. . All recorded vibration values were within Level 2 Acceptance . Criteria except~ point -RB4DK. which indicated- .167 inches ( ' peak to peak'
. displacement.. Test Exception ' 3 was written and the resolution was tos accept as is._ ' The langard potentiometer at this location-was malfunctioning.
RER SHUT DOWN COOLING TEST Steady ' state and . transient : pipe vibration data for RER ' A and B operation in the' shutdown' cooling < mode were collected separately following plant shutdowns _ in Test Condition ' 6. Steady state data was recorded with' the RHR pump operating at ' 100% flow. Transient data. was recorded during RER
- pump ' start and stop transients. ' All . vibration values met the ' acceptance criteria ,
except . sensor. RA4Y which exceeded the Level ' 1 criteria limits.- Test Exception 2 was written and'the resolution was to accept as-is. GE Engineering concluded that - the lanyard potoniometer at this - location . was malfunctioning and that, based on. . vibration levels recorded at the adjacent locations. 'the- acceptance criteria had not been exceeded at RA4Y. ,__ _ __ _ _ Test ' Exceptions and their' resolutions are summarized in Table 3.27-6. a l '
-197 -
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FIGURE 3.27-1 DRYWELL PIPING VIBRATION 4 l-N2-SUT-33 RECIRC LINE "A" TRANSDUCER LOCATIONS
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TABLE 3.27-3. DRYWELL PIPING VIBRATI(E N2-SUT-33' STEADY STATE VIBRATION LIMITS PIPELINE SENSOR LEVEL 1 LEVEL 2 DESCRIPTION ID. DIRECTION (in. omsk to nank)- (in. neak to cank Recire RA1 DX 0.100 0.050 Loop A DY 0.110 0.056 DZ 0.120 0.060 RA2 DX 0.090 0.044 DY 0.220 0.110 DZ 0.060 0.030 RA3 DX 0.160 0.080 DY 0.200 0.100 ' DZ 0.350 0.176 RA4 DX 0.180 0.090 DY 0.130 0.066 DZ 0.230 0.116 RA5 MY N/A N/A Recire RB1 DX 0.110 0.056 Loop B DY 0.100 0.050 DZ 0.120 0.060 RB2 DX 0.090 0.044 DY 0.180 0.090 > DZ 0.060 0.030 RB3 DX 0.260 0.130 DY 0.220 0.110
]
DZ 0,320 0.160 RB4 DX 0.200 0.100 i DY 0.130 0.006 ; DZ 0.240 0.120 J e
-200 im na
l I. 'f TABLE 3.27-4 I DRYWELL PIPING VIBRATIM a N2-SUT-33 ] ! OPERATING TRANSIENT VIBRATION LIMITS PIPELINE- SENSOR LEVEL l' LEVEL 2 DESCRIPTION ID. DTRRCTION (in. n==k to namk) (in. neak to omak) Recire RA1 DX 0.100. 0.060 Loop A DY 0.110 0.060 DZ 0.120 0.060 RA2 DX 0.090 0.060 DY- 0.220 0.110 DZ 0.060 0.060 RA3 DX 0.160 0.092 DY 0.200 0.100 , DZ 0.350 0.176 RA4 DX 0.180 0.090-DY 0.130 0.092 DZ 0.230 0.116 RAS MY N/A N/A. Recirc RB1 DX 'O.110 0.060 Loop B DY 0.100 0.060 DZ 0.120 0.060-RB2 DX 0.090 0.060 DY 0.180 0.090 DZ 0.060 -0.060 RB3 DX 0.260 0.130 DY 0.220 0.110 D2 0.320 0.160 RB4 DX 0.200 0.100 DY G.130 0.108 DZ 0.240 0.120 I
*t
-201 w
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' TABLE 3.27-5 DRYWEI.L PIPING VIERATIN .]
N2-SUT-33 TEST RESULTS
.. STEADY STATE **
l .i Condition El* ICA Ird Ird Date 8/5/87 1/18/88 2/22/88 2/26/88
% Core Thermal-Power 13% :64% 82.2% 99.3%-
% Core Flow 23% 57% 77.0% -104.1%.
RA1 X- .0041 .009 0.011 0.013 Y .004 .011 0.018 0.016 Z' .002- .004 0.004 0.004 RA2 X .004 .005 0.005 0.005 Y .004 .005 0.004 0.005 . Z .004 .005 0.005 0.005 RA3 X .004 .009 0.005 -0.009 Y .004 .005 0.004 0.015 Z .004 .015 0.015 0.016 RA4 X .004 .005 0.005 0.011 Y .002 .024 0.007 0.011 Z .004 .009 0.013 0.016 RAS Y .005 .013 0.009 0.011 RB1 X .005 .020 0.038 0.016 Y .007 .031 0.040 0.046 Z .007 .005 0.007 0.005 RB2 X .004 .005 0.005 0.004 Y .002 .000 0.004 0.002 Z .006 .006 0.006 0.006 RB3 X .002 .005 0.007 0.005 Y .002 .011 0.005 0.007 2 .002 .007 0.009 0.013 RB4 X .004 .011 0.015 0.013 Y .002 .018 0.007 0.005 j lt .004 .007 0.005 0.013
- Recirculation Flow Control Valves at Minimum Position, Recirculation Pumps on ";
slow rpeed. ,
** Vibration Readings are in inches.
-202 an 1
TABLE 3. 27-5 (Cont'd) . DRYWELL PIPING VIBRATION N2-SUT-33 - TEST RESULTS TRANSIENTS ** _ Condition TC 3- TC 6
'A' Recire - 'A' Recirc" Dual Recire 'B' . Recire 'B' Recirc' Two Pump-Pump Trip Pump Start Pump Trip Pump Trip Pump Start- Transfer D;te. 1/14/88' 1/14/88 1/12/88 3/1/88 3/1/88 3/5/88'-
~% Core Thermal Power. 73% 36% 63%- 99.3% '44%- 99.4%
% Core Flow 102%~ 34% 104% 104.3% 25% 103.5%'
RA1 X .016- .009 ' 016
. 0.022 0.009. .0.022 Y .015 .020 .011 0.020 0.022 0.015 Z .005 .007 .004 0.007 0.004 0.005 RA2 X .007' .007 .007 0.005 -0.005 0.005 Y .005 .015 .004 0.007 .0.007 0.004~
Z .005 .005 .005 0.004 0.004. 0.005. RA3 X .020 .038 .020 0.009- 0.005 0.026' Y: .007 .031 .009 0.027 0.004- 0.005 Z .029 .046 .026 0.020 0.011 0.051 RA4 X- .009 .013 .007 0.015 0.004 .0.011 Y .024 .051 .018 0.018 0.011 0.011-Z .015 .020 .015 0.027 0.009 ' O.026
' RA5 Y ' .011 .015 .015 0.016 0.011 0.011.
~RB1 X .031 .015 .029 0.029 0.011 0.031-Y .040 .035 .033 0.046 0.059 0.049
'Z .013 .007 .007 0.009 0.009 0.007 1 RB2 X .005 .005 .007 0.007 0.007 0.007 Y .005 .002 .004 0.005 0.005 0.005 Z- .007 .009 .007 0.006 0.011 0.006' RB3 X .009 .007 .013 0.013 0.024 0.018 Y .022 .013 .020 0.037 0.022 0.015 Z. .024 .009 .029 0.035 0.051 0.053 l RB4 X .024 .007 .024 0.027 0.009 0.167 Y .026 .022 .018 0.013 0.020 0.005 I .016 .007 .013 0.018 0.024 0.020 ,
4W.
*dVibration Readings are in inches.
-203 am;
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i TABLE 3.27-5 (Cont'd) - DRYWELL PIPING VIBRATIONe N2-SUT TEST RESULTS TRANSIENT ** , Condition ~ Tc6 RER Pump .RHR Pump RHR Pump RER' Pump RER Pump RHR Pump.
'A' Start 'A' 100% 'A' Trip- 'B' Start- 'B' 100%- 'B' Trip:
' Flow- Flow D:ts 2/16/88 2/16/88 '2/16/88 3/5/88 3/5/88- 3/6/88 1
%: Core Thermal Power 0 0 0 0 0 0
% Csre Flow .9% 11% -11% '9% ' ZL 8%
;RAl-X' O.013 0.007 0.005 Y 0.009 0.005 0.004 2' O.009 0.004 0.005 RA2 X 'O.007 0'.005 0.007 Y 0.0071 0.005 0.005 Z 0.007 0.005 0.005'
'RA3 X- 0.009 'O.005 0.007 Y. 0.029 0.007 0.011 Z- 0.015 0.007 0.004 RA4 X 0.007 0.005 0.005 Y 0.247 0.232 0.159 a
.Z 0.011 0.005 0.005 RAS Y' O.009 0.005 0.005 RB1 X. 0.013- '0.007 0.009' Y' O.009 0.005 0.007 Z 0.009 0.009 0.011 RB2 X 0.009 0.004 0.004-Y: 0.064 0.004 0.002-
-2 0.011 0.006 0.006)
'RB3 X 0.024 0.002 0.002 Y 0.067 0.009 0.005-Z~ 0.027 0.002 0.004-RB4'X 0.027 0.007 0.007 Y 0.071 0.007 0.005 Z 0.049 0.004 0.004 '. -
*tVibration Readings are in inches. j am
-204 .!
TABLE 3.27-6 DRYWELL PIPING VIBRATION N2-SUT-33 TEST EXCEPTIGi SIMIARY Test Test Exceotion Condition Description 1 3 The test Procedure was written to obtain vibration data during a Recirculation Pump Transfer from Fast Speed to slow speed. The actual event monitored was a dual Recirculation Pump Trip. ' GE Plant Piping Design determined that the. Recirculation Pump Transfer did not have to be reperformed as the Dual Pump Trip was the more severe transient. 2 6 Displacement reading for RA4Y (Recire "A" discharge pipe riser) exceeds its Level 1 criteria during RER shutdown cooling operation. GE Engineering concluded that the data for RA4Y taken during RHR shutdown - cooling mode is erroneous for the following two reasons: a) The rest of the sensors in the same discharge pipe line appear to be behaving as predicted. Additionally, RA4X and Z are responding per the predicted limits. b) The limit violation is greater than the predicted ) limit by 2 times which would have affected the { other sensors in the Y direction. It is GE's ' reconsnendation to replace RA4Y sensor. Since the data was erroneous, the exception was accepted as is. Lanyard potentiometer RA4Y was replaced and used in subsequent testing. 3 6 Sensor RCS-RB4DX has large peak to peak signal noise as indicated from the off-line plot. The max peak to peak vibration indicated during the load rejection I test is 0.167 in, which exceeds the Level 2 criteria of 0.100 in. . The resolution is accept as is per GE Engineering's evaluation. It appears that this sensor is reading high compared to the adjacent sensors RSADY and RB4DZ. It is GE's position that RB4DX lanyard potentiometer has a malfunction since the vibre. tion levals in both the Y and Z directions at the same location are within predicted limits. In addition, RA4DX in the 'A' Loop including RA4DY and RA4DZ were all within the acceptable limits compared to Loop B. Therefore, the test did not fail the Level 2 criteria . for the reasons stated above. es
-205 km n
RECIRCULATION SYSTEM FLOW CALIBRATION i N2-SUT-35 I i 3.28 'N2-SUT-35 RECIRCULATION SYSTEM FLOW CALIBRATION j A. OBJECTIVES
- 1. 'To perform complete. calibration of the installed i Recirculation System Flow Instrumentation. {
B. ACCEPTANCE CRITERIA Level 1 Not Applicable Level 2
- 1. Jet Pump Flow instrumentation is adjusted ' in such 'a way that the jet pump total flow recorder provides a correct core flow indication at rated conditions.-
- 2. The APRM/RBM flow-bias instrumentation- is adjusted'- to.
function properly at rated conditions. 3.- The calculated jet pump M-ratio shall not be < 0.2 points below prediction.
- 4. The nozzle and riser plugging criteria shall not be exceeded.
C. DISCUSSION In both Test Conditions 3 and 6 the Recirculation System flow calibration test performed consisted of three discrete parts. Part 1 consisted of collecting and analyzing the input. and output values of all electronic components associated with Recirculation System flow indication. All components were checked for calibration accuracy and operability. (In Te'st Condition 3 performance of this part identified several out of calibration components. In Test Condition 6, all components were within calibration limits.) Part 2 consisted of collecting L the necessary data to enable sn independent calculation of core l flow using the JR Pump Program. If the initial set of test data indicated that the jet pump loop flow summers would require gain changes then two additional sets of data were to be obtained, l the three sets of data were to be averaged, and the new gains implemented. Part 3 of the test involved attaining rated core - [< flow and obtaining data to confirm the gain change implemented I in Part 2. l
-206
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{.' C_____n________._____________________._.______.__ _ _ , _ . .
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'I RECIRCULATION SYSTEM FLOW CALIBRATION N2-SUT-35 C. (Cont'd)
The last part of the TC 6 ' test ' adjusted the flow reference signal to the APRM/RBM following determination of 100% drive
, flow. This change was implemented via permanent plant procedure.-
Jet pump nozzle plugging criteria'was exceeded. Per GE San Jose engineering evaluation the resultsiin. both TC 3 and TC 6 were. accepted.as is. The > final results ' are tabulated in Table 3.28-1.- The ' jetpump distribution observed in TC3 is shown in Figures - 3.28-2 "and 3.28-3. The jet pump distribution observed in TC 6 is shown in Figure 3.28-4 and 3.28-5. Test Exceptions and' their resolutions are summarized in Table 3.28-6.
-207 y m-
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TAMR 3,28 6: ] RECIRCU1ATION SYSTEM FLOW CALIBRATION a C' 8 d N2-SUT .Il. \ i TEST EXCEPTION SINtuRY Test- Test Excention' Condition Description 1 '3 Jet pump square. rooter : expected outputs were not
- within the required specified values. Jet pump square.
rooters were recalibrates to resolve this exception. 2' 3 APRM flow unit square rooter's gain adjustment factors were not within the required specified ..value. This Exception was accepted. as is since- the individual. flow units drive flow met. the last surveillance . test
. requirements.
3 -3 Jet . pump loop flow summer gain adjustment factor for - N602A was not within the- required specified value. The Jet pump loop flow summer gain was adjusted and rechecked to resolve the exception. 4 3 APRM flow unit gain adjustment factors, process computer . loop drive flow and process computer total core flow gain adjustment factors were. not within the' required specified value. The exception was accepted as is, limitations were self imposed and data collected showed that these instruments . were functioning correctly. 5 3 Jet pump nozzle plugging criteria was exceeded. Per - GE San Jose engineering evaluation the results were accepted as is pending further evaluation in TC 6. In TC 6 GE San Jose engineering revaluated the data and determined the deviations were satisfactory. 6 6 APRM flow unit square rooter's gain adjustment factor did not fall within the 1.00 to 1.01 range specified by the procedure. This exception was accepted as is since this requirement was self imposed to evaluate the square rooter and could not be adequately evaluated with the high peak to peak oscillations experienced.
~
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TABLE 3.28-6 (Cont'd) RECIRCULATION SYSTEM FLOW CALIBRATION N2-SUT-35 TEST EXCEPTION SIN 9tARY Test Test Exceotion Cor.*ition Description 7 6 Process Computer total core flow and the JRPUMP calculated core flow did not agree within 1%.- This exception was accepted as is since it is impossible to compare a single computer point value ' with a JRPUMP value calculated from 10 minute averaged data. JRPUMP value agreed within 1% with the 10 minute averaged value for core flow from GETARS. 8 6 APRM flow unit gain adjustment factors for units A, B, and, D did not meet the required value (2 1.00 and i 1.01). This exception was closed by verifying that - after the 100% drive flow adjustment was made that the flow units were calibrated correctly. 1
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N2-SUT-70 REACTOR WATER CLEANUP SYSTEM 3.29 N2-SUT-70 REACTOR WATER CLEANUP SYSTEM A. OBTTCTIVES The purpose of this test is to demonstrate specific aspects of the mechanical operability of the Reactor Water Cleanup System (RWCU). B. ACCEPTANCE CRITERIA Level 1 Not Applicable Level 2
- 1. The temperature at the tube side outlet of Non-Regenerative Heat Exchanger shall not exceed 130*F in the blowdown mode and shall not exceed 120*F in the normal mode.
. 2. The pump available NPSH should be at least 13 ft during the hot standby mode is as defined in the process diagrams (If measurements and calculations made during the system preoperational test show that NPSH requirements for this mode can be met, then this requirement need not be addressed during startup testing.)
- 3. The cooling water supplied to the Non-Regenerative Heat Exchanger shall be less than 6% above the flow corresponding to the Heat Exchanger capacity as determined from the process diagram (1520 GPM). The outlet temperature shall not exceed 180*F.
- 4. Pump vibration shall be less than or equal to 2 mils peak-to- peak (in any direction) as measured on the bearing housing, and 2 mils peak-to-peak shaft vibration as measured on the coupling end.
C. DISCUSSION This test was originally intended to be performed during Test Condition Heatup. However, due to the RWCU System alignment requirements caused by Feedwater piping thermal stratification concerns, full RWCU System flow could not be achieved during Test Condition Heatup which prevented taking RWCU normal mode performance data. In addition, problems with the RWCU blowdown _ flow instrumentation prevented performing the blowdown mode section of the test. Due to these problems, the test was
- rescheduled for TC 2. Subsequently, RWCU System performance data
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N2-SUT-701 h REACTOR WATER. mJEANUP SYSTWI C. (Cont'd) was ' taken _ with' the . reactor operating ( at . 32% power, after ~the" blowdown flow instrumentation had been . redesigned, and at . ..a
. power 1 level' high enough to . preclude thermal stratification in -
feedwater piping. b Nomat Mode Tent 4ne The normal = mode of . the RWCU system is utilized toz maintain-reactor ' water. quality when the. reactor is under. normal power; operation. 'The system is designed - to process ; 2%1 of ' nuclear boiler flow. This acde. - determines the Regenerative . Heat Exchanger's design basis. During this mode jof operation - the
-system's maximum flow is limited by ' the Non-Regenerative Heat Exchanger' performance as measured by the cooling water's maximum -
- allowable flow and outlet temperature. System performance data was taken at a system flow rate of 910 GPM with- both RWCU pumps and all 4 filter domineralizers on-line. -All Level . _ 2 System Performance Criteria were satisfied, as shown in Table 3.29-1.
Vibration readings were also taken on both - RWCU. pumps. - The maximum vibration on the 'A' pump. was .21 mils, . measured vertically on the outboard bearing. The maximum vibration on the 'B' pump - was .41 mils, measured vertically on the inboard bearing. Both of these values are well L.within the Level - 2 ' criteria of 2 mils. Blowdown Mode Test 4ne , The blowdown mode of RWCU is used to remove excess water from the reactor vessel. .The blowdown flow path to the condenser contains a restricting orifice in parallel with a bypass line. 2WCS-fl0V108 is the valve in the bypass line and 2WCS-Fv135, ~ the Reject Throttle valve is upstream of the orifice. During the first attempt to obtain RWCU' blowdown performance data, all of the blowdown flow was through the orifice. This limited total system flow to 140 GPM, although the procedure required that 170-200 GPM be achieved initially, prior to increasing the flow to it's maximum. As the intent of this section was to determine the maximum blowdown flow and verify system parameters against the process diagram, it was necessary to revise the procedure and perform a retest. During the retest, 2WCS-MOV108 was opened, permitting flow to bypass the restricting orifice. Maximum System Flow was measured as 350 GPM on 2G33-R609 and the maximum blowdown flow was measured as 270 GPM on 2G33-R602. All of the system flow -j
-216 m
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N2-SUT-70 1-- REACTOR WATER CLEANUP SYSTEM C. (Cont'd) was being rejected, however, since the ' two flow transmitters are calibrated . for different conditions they read differently at' the same flow ' rate (the system flow transmitter is calibrated for
' hot' conditions and the blowdown flow transmitter is calibrated for ' cold' conditions). All Level 2 System Performance Criteria were satisfied as shown in Table 3.29-1.
Since the preoperational test showed that the NPSH requirements were met for the Blowdown Mode, Level 2 Criterion number 2 was not tested during the startup test. s
-217 _.
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[ -. TABLE 3.29-1 N2-SUT-70 REACTOR WATER CLEANUP SYSTEM REACTOR WATER CLEANUP SYSTEM TEST RFRULTS Normal Mode Blowdown Mode Parametar ' Limit Measured Value Limit Measured Value RWCU Tube Side Outlet of Non-Regenerative Heat <120 100 <130 100 Exchangers Temperature (*F) Non-Regenerative Heat Exchangers Cooling Water (180 123 (180 175 discharge Temperature (*F) Non-Regenerative Heat Exchangers Cooling Water . <1520 1404 <1520 1396' Flow (GPM)
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$l N . RESIDUAL REAT RMOVAL SYSTM
'N2-SUT i- ,3.30 .N2-SUT RESIDUAL HEAT RDIOVAL' SYSTEM -
. -A. OBJECTIVE
'p To ( demonstrate the ability of1 the = Residual' Heat Removal: (RHR) System tos-1 l'. - - Remove heat from the reactor system so that .' the refuellng and nuclear system servicing can be performed.
- 2. Condense steam from the' reactor.
B. ACCEPTANCE CRITERIA Level 1-
- 1. .The transient response of any system related - variable 'to ,
any test input must not diverge. -- Level 2
- 1. System-related variables may contain oscillatory modes of response. In these cases, the decay ratio .:for each controlled mode of response must be . less . than or equal to 0.25.
- 2. The Residual Heat. Removal- System. shall be capable of~.
operating in'.the suppression pool cooling mode at ' the heat exchanger capacity equivalent to or. greater than the values specified on the process diagram (41.6'x 106 BTU /hr).
- 3. yor the RHR steam condensing mode, the . steam. condensing rate shall be equivalent to or greater than that shown on the process diagram-(136,383 LBM/HR) and the temperature of the RHR heat exchanger condensate discharge shall be less than 140*F.
- 4. The Residual Heat Removal System shall be capable-. of operating in the shutdown cooling mode at a heat exchanger capacity equivalent-to or greater than the values specified on the process diagram (41.6 x 106 BTU /hr).
L
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3,- M , .. e 'i _ RESIDUAL.EIAT RBIOVAL SYSTEM
- N2-SU".-71
-C.: DISCUSSION
.RER ^ Suppression Pool.. Cooling . Testing' was- scheduled ' to be-
' performed in Test Condition Heatup. - This L testing was ._ deferred ! >
until ' Test Condition 1 however,; due: toi several ' problems. . The: first' of these was an instrumentation problem with the~ RER Heat =
' Exchanger, _(H/X).. . temperature , recorder in- which ~ temperature [
readings were determined to be . inconsistent cwith ' expected processDdata.- The ? problem fwas identified to be1-that, the r recorder, point numbers were . one point f of f1 f rom ' the . actual ~ point .
. .being sensed.
t This problem was corrected. and verified during1 subsequent : testing. . The. second problem encountered wasJ the~ inoperability .of the . Redundant Reactivity Control System which
~
required , that. the bulk ' Suppression. Pool _ tempe.:sture be' limited : to- 90*F or less. :As this. test requires _4 20*F to 30*F-
- temperature difference to exist between service water . and the bulk Suppression' Pool ; temperature, it was not possible'.to- -
perform _this test in Test Condition Heatup. Testing for- Suppression Pool _ Cooling' was performed in . Test' Condition 1 at ' 17% Reactor Power. With ' the Suppression; Pool initially ' at 68*F and the. service. water temperature ' at 55'Fr s first the ' A' ; Loop of - RER and then - the 'B' Loop' of RHR was - tested. . Analysis _ of the test data ' showed - that the Level -2' Criteria was met as shown below: Heat Exchanger Heat Rw hanner canacity (MBTU/HR) Process Diagram Test Data A 41.6- 84.9
.)
B 41.6 95.3 RER Steam Condensing Testing was scheduled ' to be performed in Test Condition 1, however, this testing was _ deferred to Test Condition 2 due to several' plant problems. When steam condensing was initially put into service, isolations-of the heat exchanger steam supply occurred due to a very i- conservative setpoint for the RHR/RCIC (Reactor Core _ Isolation l' Cooling) steam flow - high downscale trip. This setpoint was reset from -20 inches of HO 2 to -275 inches of H2 0. .After steam condensing had been initiated successfully, the tuning of the. pressure controller could not .be completed ' due - to the 'B' H/X pressure control valve sticking. The reactor was shutdown per N2-SUT-28 to end TC-1 before tuning on either - RHR Heat Exchanger could be completed.
-220 ;
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I[ h .... RESIDUAL HEAT REMOVAL SYSTEM N2-SUT C. (Cont'd) The RHR Steam Condensing Testing was performed in Test Condition
- 2. During initial tuning of the 'A' H/X, the 'A' H/X Pressure
. Control Valve locked up, making tuning impossible. Tuning was-then attempted on the 'B' H/X but'the 'B' H/X pressure control valve also exhibited binding. This problem was considered' generic to both valves and was determined to ' be - related . to thermal expansion of the valve plug, resulting.in binding.
. The ' B ' H/X pressure control valve plug was milled to increase clearances to correct the' binding problem during a plant outage. Tuning on -the 'B' H/X was completed successfully.
During actual testing, to determine heat exchanger performance, the 42*F temperature limit on service water delta-T was achieved. This was due to thermal stratification on service water outlet temperature elements. Local contact pyrometer readings at various locations .around the circumference of the piping were used to verify that stratification existed and these . were then averaged for the test data. The 'A' H/X pressure control valve plug was milled to increase clearances during another plant- outage. 'The ' A' H/X tuning and testing was then completed. Heat exchanger capacity data was taken at conditions specified by the process diagram. A heat balance on the heat exchangers were then calculated. The results for H/X performance are as follows: ! PER HX H/X Capacity in Steam Condensina (LBM/HR) Process Diagram Test Data A 1.36 x 105 1.38 x 105 B 1.36 x 105 1.42 x 105 Heat exchanger pressure, level and RCIC suction pressure' step changes were performed on each heat exchanger for both open and closed loop response. No divergence occurred on any setpoint changes, however, heat exchanger pressure and pressure controller output exhibited decay ratios 1 0.25 on both heat exchangers. These test exceptions were considered acceptable because further tuning would cause undesirable ef fects on level setpoint steps. The final controller settings are give in Table 3.30-1. Engineering is evaluating the relocation of the 'B' RHR H/X service water outlet temperature thermocouple further away from the heat exchanger to resolve temperature indication problems caused by Thermal Stratification. Data was taken on the , RRR/RCIC high steam flow isolation elbow taps to determine new isolation setpoints. .New setpoints have been calculated and a technical specification change for these setpoints has been Kj approved. i l
, -221
RESIDUAL BEAT REMOVAL SYSTEM l N2-SUT-71' I/ C. (Cont'd) RHR Shutdown Cooling.-Testing was performed in Test Condition,6.
'A' Loop was tested following; the MSIV. closure scram from rated power for N2-SUT-25-6. 'B' Loop was tested following the Generator Load - Reject scram from rated power for N2-SUT-27-6.
Analysis of the test data showed that ' the Level 2 criteria was met.as shown below:- Heat Exchaneer IIeat Exchaneer Capacity (MBTU/hr.) Process Diagram Test Data-
'A 41.6 110.5 B 41.6 106 Test Exceptions and their - resolutions - are summarized ' in Table 3.30-2.
9 9
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- - . _ _ - . . ._. ---.--._.----.---______d
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'l TABLE 3.30-1 f l
RESIDUAL' HEAT REMOVAL SYSTEM .)
.I N2-SUT-71 ' 1
)
FINAL CONTROLLER SETTINGS Description Actum1-
\
D4m1 a
.y Heat Exchanger. A Loop K = .9 1.1 l Pressure Controller I = .5 R/M .3 R/M B Loop K = .75
- I = .5 R/M
- Heat Exchanger A Loop K = 1.5 1.8 Level Controller- I = 1.5 R/M- 1.65 R/M B Loop K = 1.2- 1.4 I = 1.1 R/M 1.21 R/M RCIC Suction K =~.4 .6 Pressure Controller I = 10.0 R/M 9.5 R/M
- B H/X Pressure Contro11er' changed without dial calibration.
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TABLE 3.30-2 RESIDUAL HEAT REMOVAL SYSTI!M N2-SUT-71 TEST KKCRIlWLEptlARY Test Test Exceotion Condition Description 1 HU Instrumentation problems were identified based upon service water outlet temperatures of the RHR Heat Exchangers during the Suppression Pool- Cooling demonstration. The test procedure was changed to i I collect additional data and- the test was reperformed in TC-1. 2 1 During the Steam Condensing demonstration testing, the decay ratios could not be determined for the RCIC Discharge Flow and Suction Pressure parameters due to.
. process noise. Decay Ratios were evaluated during RER Loop 'A' testing after the process noise was eliminated.
3 1 The Level 2 Criteria requiring that decay ratios be less than 0.25 was' not met during RHR Loop 'B' Steam condensing demonstration for Heat ' Exchanger inlet pressure and pressure controller output. This deviation was accepted as is. 4 1 The Level 2 Criteria requiring that decay ratios be less than 0.25 was not met during RHR Loop 'A' Steam , Condensing Demonstration for Heat Exchanger inlet pressure and pressure controller output. This deviation was accepted as is.
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_-f'4 0FF-GAS SYSTEM PERFORMANCE
.I~
N2-SUT-74 3.31 N2-SUT-74 0FF-GAS-SYSTEM PERFORMANCE A. OBJECTIVES
- The purpose of this - test is to verify the proper operation of the.0ff-Gas System over its expected operating range.
B.. ACCEPTANCE CRITERIA Level 1
- 1. The release of radioactive gaseous and particulate effluents must not exceed the limits specified in the Site Technical Specifications Sections: 3.11.2.1, 3.11.2.2, 3.11.2.3, 3.11.2.7 Level 2 ,
- 1. . The system flow, pressure, temperature , and dewpoint shall comply with the process data sheets supplied to the site.
2.. The catalytic recombiner, hydrogen analyzer, freeze-out dryers, activated charcoal beds and- f11ters .shall be working properly during operation, i.e. , ~ there shall be no gross malfunctioning of these components. 1 C. DISCUSSION The Off-Gas System Test was performed at steady state conditions during Test Conditions 1, 2, 3 and 6. All Level 1 Criteria were satisfied at each testing level. .Because several parameters i were outside the system design specifications, not all of the Level 2 Criteria were met. The Off-Gas System parameter results are listed in Table 3.31-1. Throughout the test program, dryer outlet temperature and system flow were consistently just above the system design parameters. In addition, equipment problems hindered testing of the hydrogen analyzers and the dewpoint measurement equipment. l L
-225 m
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. OFF- GAS ' SYSTEN- PERPURMANCE 1
N2-SUT-74 1 h q . ; .
^
, C. '(Cont'd)s. 1 During Test Condition 1,. at 41 reactor power on J7/29/87, initial' .
t' testi data was j taken. : . Due to- an leaky f relief ? valve, ' preheater -
~
1
, steam .' supply 'was _ unavailable. Also both recombiner; trainsiwere
.in service. The data collectedEshowed that;the' majority ofTthe:
i system parameters werei within the specified . limits. During? the testing,-the moisture- analyzere wascinoperative: and --: various; g system parameters were outside Level 2 limits as shown on Table; 3.31-1. q-
- A' second J test was: run during TC-1 at ' 18% I Reactor. power ion
- 8/8/87; - This' . test . was ' performed ' af ter the - off-gas : system i was -
shut down and started back'up-in order to eliminate:wateriin.the ; piping and correct .other operational': problems ~. ..'During the-testing,. Preheater Steam Supply l' was 'still , unavailable, .the. hydrogen analyzers , and moisture analyzers were inoperative, and - various 'other system parameters were outside Level 2. limits as a delineated'in Table 3.31-1. - During Test Condition 2, . at .441' reactor power on 10/12/87', test data was taken, with the 'off-Gas- System; in a normal configuration. During the n testing, . the. hydrogen 'analyzersn and b moisture analyzers were inoperative, outlet flow to .' the stack was outside- specific limits; flow meters within system. did; noti agree, and holdup times for krypton and xenon .. did not - meet. specified limits. System 1 parameters- are 1 delineated. in Table 3.31-1. During Test Condition. 3, st 66% reactor power on 11/8/87,1 test data was taken with both recombiner : trains - in' service. During. j, the testing, hydrogen analyzers.-and moisture analyzers were inoperative. A dryer ' differential. pressure -instrument was. q inoperative and flow meters within system'did not agree. System ' parameters are delineated in Table 3.31-1. During Test Condition 6, Data was collected on 2-24-88, with the -) reactor at 96% power. The systein was lined up in the following . configuration: "A" Recombiner Train 'in ~ Service, "A" Freeze Out Dryer in Service, activated charcoal beds lined up in parallel, "A" HEPA Filter and "A" Vacuum Pump in Service. Test results were within specified limits, with exceptions in two. areas. 1
-226 w
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~+ w. OFF-G&S SYSTEM PERFORMANCE N2-SUT-74 C. (Cont'd) The - first problem -noted was that hydrogen levels in .the off-gas system exceeded. both the Normal Operating Limit of 0.5% fand the Design Limit of 1~.0%' with a measurement of 1.35% hydrogen. concentration by volume. The hydrogen monitors associated with
.the Off-gas system have~ historically read.-high. 'due. to the-moisture content- and erratic. flow- of' the Off-gas sample.- .
Returning the hydrogen monitors . to service following . calibration with . dry gases of know hydrogen concentration: has resulted in . . higher (factor of ten) readings when compared to the Chemistry Grab Sample . Analysis performed by the .. Chemistry Group. . Per Engineering, the hydrogen monitors in- their current configuration are . considered- acceptable for off-gas ' system operation -and. chemistry grab sample analysis for hydrogen concentration are no longer required. , The second problem was that flow meters within the system do not - agree. - System flow meters read 61 SCFM, the outlet flow to the Main Stack meter read 80 SCPM, as opposed to normal operating limits of 34.5 and 30 SCFM respectively. As the outlet flow meter - has historically. read high in comparison with the system flow meters, the latter 'will' be used~ for operations. Per Engineering, the System Flow Monitoring devices in their current - configuration are considered acceptable for off-gas- system operation. Engineering will continue to investigate the outlet flow to the Main Stack Meter. The high system flow rates have been caused by high condenser in-leakage. Per Engineering, high system ' flow rates will be addressed by efforts to reduce the high condenser in-leakage. As the operating experience with the off-gas system continues, the system performance improves. Test Exceptions are summarized in Table 3.31-2. I r
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ky o ll TART.R 3.31-2 0FF-GAS SYSTEM PERFollMANCE i N2-SUT-74 TEST EXCEPTIGi SIEMARY Test Test Excention Condition Description j 1 1 -Moisture analyzer inoperative due to moisture element being saturated during _ initial system startup. Accepted as is ' to retest in the next test conditions. 2 'l Various system parameters were outside. normal operating limits for system. Accepted as is to retest in the next test condition. 3 1 Hydrogen analyzers inoperative _ due to inability of I&C to calibrate. Accepted as is per-chemistry grab sample results to retest at' the , next test condition. 4 1 (Retest) Various system parameters were outside normal-operating limits for system. Accepted as is to retest in the next test condition. 5 1 (Retest) Moisture analyzer inoperative - moisture element cannot be repaired on-site - a new moisture element has been ordered. Accepted as is to retest in the next test condition. , 6 2 Hydrogen analyzers still inoperative due to l inability to calibrate analyzers. Accepted as is l to retest in the next test condition. : I 7 2 Moisture analyzer is still inoperable' - new moisture element still on order. Accepted as is to retest in the next test condition. l 8 2 Flow to the main stack is outside normal limits. Accepted as is to retest at the next test condition. 9 2 Flow through the system as measured by the system flow elements and the outlet flow to the main stack flow element do not agree. Flow to stack is consistently 30-35 SCPM higher than system flov. Accepted as is to retest at the j next test condition. ,q
-230 4 I
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.l TABLE-3.31-2 (Cont'd) .
l OFF-GAS SYSTEM PERFORMANCE .) N2-SUT-74 ' TEST EXCEPTIGi SIE98&RY l \a
-Test Test Excention Condition Description 10 2 Hold up times for Xenon and Krypton were outside FSAR specified limits. Accepted as - is per' )
. chemistry grab sample results to retest at the d next test condition. l i
11 3 Hydrogen analyzers. were inoperable - problem. tracked to lack of sample flow through sample lines. Discharge valve on sample line has been reversed. Analyzers now have sufficient flow, have been recalibrates and will be retested in the next Test Condition. 12 3 Moisture analyzer was . inoperable . - new moisture element has been installed, recalibrates and.will be retested in the next Test Co:.dition. 13 3 Dryer differential pressure- indicator . was inoperable - has since been recalibrates and will be tested in the next Test Condition. 14 3 Flow meter to the main atack- is still 30-35 SCPM higher than system flow elements.. The flow meter to the main stack has been recalibratett and will be retested in the next Test Condition. 15 6 System flow rates as read by System . Flow Meters versus the Outlet riow to the Main Stack ~ Meter do ; not agree with each other and both sets' of l readings are outside expected normal range of J system performance. Plant engineering is pursuing an inleakage reduction program. Flow rate readings were accepted as ' is since they're conservative. 16 6 System hydrogen levels exiting the recombiner trains are high as read by the individual hydrogen monitors and the System Hydrogen Monitor due to high moisture content and the erratic fluid flow of the sample. A modification to add ' sample pumps and moisture removal elements will - be implemented to correct these problems. ,
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DRYWELL' COOLING SYSTEM N2-SUT-75 3.32 N2-SUT-75 DRYWELL COOLING SYSTEM
'A. OBJECTIVES
. Verify the capability of . the Drywell Atmosphere Cooling System =
l -(DRS) to maintain the Primary Containment environment within the design limits during operating conditions. B. ACCEPTANCE CRITERIA Level 1 Drywell average air temperature shall not exceed 150 degrees Fahrenheit.- Level 2
- 1. The maximum air temperature in any area . of the drywell shall not exceed 150 degrees fahrenheit.
- 2. The reactor preasure vessel skirt area temperature shall' not be less than the 70 degrees Fahrenheit _ minimum design limit specified in FSAR table - 9.4-1 and shall-be greater than or equal to 100 degrees Fahrenheit _with the vessel exterior surface at the normal operating temperature (528'F to 544'F).
C. DISCUSSION The Drywell Cooling test was performed during the Heat Up (HU) Plateau. Test Condition 2 and Test Condition 6. In each test condition data was taken with the reactor ' in a steady state condition and in TC-2 and TC-6 data was also taken during transient conditions. For TC-2 the steady state data was ' taken at approximately 21% reactor power and the transient data was taken in' conjunction with the scram for N2-SUT-31 (loss of turbine generator and off site power). TC-6 steady state data was taken at approximately 98% reactor power and the transient data in conjunction ~with the scram for N2-SUT-27 (generator load rejection). The test recorded data from a variety of instrumentation, including twelve (12) permanent plant thermocouple, forty-seven (47) temporary thermocouple and twenty-eight (28) RTD's.
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i IRYWELL COOLING SYSTEM N2-SUT-75
- C.. (Cont'd)
In Test ConMtion - HU For HU testing the vessel . was at rated temperature and pressure -
~
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3 with reactor power less than 5 percent. 4 t The Level 1 criterion that, "the'drywell average' air temperature shall not exceed 150 degrees Fahrenheit'?, - was met 'on the arithmetic average of. the . general ~ drywell area, . with a' temperature of 103 degrees Fahrenheit. Level 2 criteria _ of having the vessel ' skirt area greater than the minimum design temperature of 70 degrees Fahrenheit was met, with readings of 89,88, and 88 degrees Fahrenheit. There were :two (2) Level 2 violations. -The first violation was on .the requirement that the vessel skirt area- temperature be greater than or equal to 100 degrees Fahrenheit when the ' vessel.
~
' exterior . surfaces are .at . normal operating. temperature.' .- The -
values of the three thermocouple points monitoring that - area were 97.7. 93.1, and 93.9.- As a result of the violation of the undervessel skirt area criteria the HVAC balance was checked and. corrected to the design flows. The second violation was on the
~
requirement that the maximum air temperr.ture of the drywell not exceed 150 degrees Fahrenheit. Four monitoring points exceeded the 150 degrees Fahrenheit limit. All four points were at l- elevation 320, which is the. elevation of the top of the-l biological shield wall, and the values of the . points were 161, 169, 162 and -176 degrees Fahrenheit. An investigation of the hot spots were checked to see if the thermocouple - had been - installed in an area that had an unusual ' or' abnormal air flow that would' cause the problem. It was determined that there was , l a gap in the vessel insulation at the 320 elevation that was ! l identified as the problem. A comparison of the temporary thermocouple and the permanent plant thermocouple shows that the permanent plant thermocouple are giving an accurate indication of the general air temperature and that the unit coolers were keeping the drywell air temperature below the FSAR limit for the general area.
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DRYWELL COOLING SYSTEM N2-SUT-75 C. (Cont'd)
.In Test Condition - 2.
At a reactor power level of 21 percent, a' set of data was-taken with the plant in a steady state. condition. ! The Level 1 criterion, that the "drywell average air temperature shall not exceed 150 degrees. Fahrenheit", was met with a temperature of 105 degrees Fahrenheit. j
- There were two (2) Level 2 violations. in Test Condition 2. The first' was a violation on the requirement that reactor' pressure vessel skirt area air temperature be greater than 100 degrees Fahrenheit. One point was below 100 degrees Fahrenheit, j however, the average of the three points on the skirt - area was -
greater than 100 degrees Fahrenheit and since GE analysis sets J the minimum vessel skirt . area temperature. as 90 degrees : Fahrenheit, this was acceptable to engineering. The 'second violation was on the requirement that. the- maximum air temperature of the drywell not exceed 150 degrees . Fahrenheit. Only one point exceeded the 150 degree criteria, and that was by
- 0.4 degrees. Engineering evaluated the- instrumentation and accepted the value as within the accuracy of the instrumentation.-
A . second set of data was taken in TC-2 during the scram in conjunction with N2-SUT-31,- Loss of Turbine Generator .snd , Off-Site Power. Data was taken prior to the scram to determine I initial conditions and then every five (5) minutes for> ) thirty-five (35) minutes after the loss of off-site power. ]; The Level'1 criterion, that the "drywell average z.ir temperature shall not exceed 150 degrees Fahrenheit", was met with a peak temperature'of 107 degrees Fahrenheit. After the loss of power, the operations department restored power to the unit coolers
, within three (3) minutes in order to avoid high drywell temperatures.
There were two (2) Level 2 violations in Test Condition 2 in conjunction with the loss of power scram. The first was a i violation on the requirement that reactor pressure vessel skirt j area air temperature being less than 100 degrees Fahrenheit I during the initial conditions. The two low points were 98.7 and 99.2 degrees Fahrenheit. This was acceptable to engineering based on the GE analysis that sets the minimum vessel skirt area I temperature as 09 degrees Fahrenheit. The second violation was . on the requirement that the maximum air temperature of the drywell not exceed 150 degrees Fahrenheit. Five points exceeded
- the 150 degree limit; however, engineering stated that the 150 degree maximum was for steady state conditions and not for transient conditions. y
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DRYWELL COOLING SYSTEM N2-SUT-75.
"C. .(Cont'd),
Test Condition - 6 Data was taken with the - reactor - at approximately 98%f reactor. -
. power at rated temperature and pressure. d 1
The . Level 1 criterion, that the "drywell average air temperature shall not -exceed 150 degrees . Fahrenheit", was met- with .a1 temperature of 108 degrees Fahrenheit. .. Ther'e were two (2) Level 2 . violations ~ in Test. Condition: 6. The-first was a viciation on'. the requirement that. reactor' pressure vessel skirt area air temperature be. less than._100 degrees Fahrenheit. One point was below 100 . degrees Fahrenheit,'.
'however, the' average of the three points in the skirt area;was greater - than 100 degrees Fahrenheit . and - since .GE analysis L sets the minimum vessel skirt area temperature as ; : 90 -- degrees .
Fahrenheit, this was acceptable to . engineering.: The second violation was on the requirement that. the maximum air. temperature of the drywell - not exceed 150 ~ degrees Fahrenheit.; There were- five temperature elements that exceeded the =150-degree'. limit. Three (3) were the intake temperatures ~ for Unit Coolers, UCIA, UC1B .and UCIC- on elevation 320 indicating 152, 155, and 159 degrees Fahrenheit respectively and - two (2).were temporary temperature elements on the 320 elevation, ' TE-DW-09 i and TE-DW-12 (azimuth 0 and 270 with temperatures of 152 and 168 degrees Fahrenheit respectively). Engineering analysis shows that ~ the equipment in this area (320 elevation) is operable for the elevated temperatures, however, the qualified life of the ; equipment in . the area may be -decreased. This is being d reevaluated. The cause of the high intake temperatures . is . that 1 the intake is'from the 320 elevation for the three unit' coolers.- 2 I; A second set of data was taken in TC-6 during the scram in conjunction with N2-SUT-27. Data was taken prior to the scram j and then every 5 (5) minutes for thirty-five (35) minutes af ter 1 the generator load rejection. l The Level 1 criterion that, "the drywell average air temperature ) shall not exceed 150 degrees Fahrenheit", was met on the l arithmetic average of the general drywell area, with a [ temperature of 114 degrees Fahrenheit. This was the high l-temperature during the- transient, the temperature for the initial conditions was lower than the 114 degrees.
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, n IRYWELL COOLING' SYSTEM n~
N2-SUT-75 il y C. (Cont'd); t1 j There ': was " one ';(1) Level E 2. violation' in Test . Condition 6:; in-
-j
. conjunction. with the turbine generator 11oad :. reject scram.' .The J violation was in 'the initial conditions, -just~ prior to= the H
< scram. There were two : (2) points ' above ;.150 degrees, TE-W-09, .
elevation- 320' -(azimuth; - 0 ' degraes),' and i at TE-W-12, ' . at elevation -- 320' -(azimuth 275 degrees) reaching ..154.9 and 172.4.
. . degrees respectively. . TE-N-09 and . TE-N-12 ; were evaluated by .
engineering: as -acceptable,- but. the . equipment: lifeD is 'being: reevaluated .due .to the; ' higher- temperatures. . Additional thermocouple are being.. Installed.- to better." identify the v boundary of the temperature zone.: _
-Two; of the points, TE-W-09 and ;. TE-W-12, increased . ' in temperature, to 226 degrees and 236 degrees respectively, during.
the'; load reject scram transient. The ' points ~ that rose'. during the . transient were accepted as is since the 150 degree criteria
, was intended to apply - to steady ' state conditions and ' not to-transients.
;. Test' exceptions'are summarized in Table.3.32-1.
)
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L . TARLE 3.32-1 DENELL COOLING SYSTEM N2-SUT-75 TEST EXCEPTIN SGMARY Test Test t Exception Condition Description
'l HU During testing thermocouple TE-W-29 was inoperable.
This was acceptable as' adequate. information was available . f rom numerous other . thermocouple. A work request was issued to repair / replace the thermocouple. 2 HU Two area temperatures exceeded' 150 degrees Fahrenheit. Air flow balance adjustments and ventilation duct ' modifications were made at the next unit outage and area temperatures were evaluated again ) at TC 2. 3 HU . Level 2 criteria violation of the following. i thermocouple:- TC TEMP LIMIT TE-N-09 160.7 F < 150 F TE-W-10 168.5 F ~< 150 F TE-W-11 161.5 F < 150 F TE-W -12 176.3 F < 150 F TE-W-01 97.7 F > 100 F TE-W-02 93.1 F > 100 F TE-W-03 93.9 F > 100 F Air flow balance . adjustments and ventilation duct modifications 'were made at the next outage. The temperature at these locations was evaluated again at TC 2. l 4 HU Unit cooler UC2A outlet air temperature was greater ! than the inlet air. The temperature element was repaired 'at the next unit outage and the cooler performance was again evaluated at TC 2. 5 HU The following unit coolers did not equal or exceed the design heat transfer coefficient per unit area (UAd) ! values as specified by the procedure: 2DRS-UC1A, j 2DRS-UC10, 2DRS-UC2B, 2DRS-UC2D, 2DRS-UC3A. Accept as : is, measure for cooling water flows for all coolers and evaluate performance at TC 2. 1
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TARTR 3,32 1 (Cont'd) DRYWELL COOLING SYSTEM N2-SUT-75 d TEST EXCEPTIGi SIERIARY
, Il q
' I Test Test '
Rveantion Candition Description-6- TC2 Thermocouple. TE-DW-Ol' exceeded the Level 2 criteria ? of 150 ' degrees Fahrenheit with a - value of 1504. degrees Fahrenheit. This was~ acceptable as- the value of 150.4 ' degrees Fahrenheit is within -the accuracy of the instrumentation. , 7' TC2 During N2-SUT-31 maximum air temperature: .in 'the drywell exceeded the Level 2 criteria of 150 degrees Fahrenheit. The vessel skirt area temperat.ures were less than the- Level 2E criteria: of 100' degrees.- Fahrenheit. This- was . acceptable. as .the maximus design temperatures are not specified . for L loss of power conditions but only for ~ normal operating mode and GE analysis sets the ' ainimum vessel skirt . area temperature as 90 degrees Fahrenheit..
'8 TC2 The following unit coolers do not equal or exceed the UAd values as specified by -the procedure:
2DRS-UCIA, 2DRS-UC10, 2DRS-UC2D,'2DRS-UC3A. This is acceptable as these coolers are not Engineered Safety . Feature unit coolers and drywell cooler performance is adequate to' maintain suitable air space-temperatures. _ 9 TC6 The following thermocouple violated Level 2 criteria during the steady state conditions at 98 percent power: TC TEMP LIMIT TE-DW-09 152.4 < 150.0 TE-DW-12 168.2 < 150.0 2DRS-TE8A 151.92 < 150.0 2DRS-TE8B 154.68 < 150.0 lT. 2DRS-TE8C 159.1 < 150.0 Exception accepted as is since analysis shows that the equipment within these zones are operable for the observed elevated temperature. The qualified life of this equipment is being reevaluated and .
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additional thermocouple are planned in order to define the temperature boundary zones. 4
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TABLE 3.32-1 (Cont'd) DRYWELL COOLING SYSTEM N2-SUT-75 TEST EECEPTIGf SWWi&RY Test = Test Excention Condition Description
-10 TC6' The following skirt area temperatures ~are < 100 degrees Fahrenheit in violation of Level 2 criteria:
TC TEMP LIMIT TE-W-01 107.4 > 100.0 TE-W-02 99.9 > 100.0 TE-W-03 100.2 > 100.0 Accept as is, the average. of the three points is greater than 100 degrees Fahrenheit. .. 11 TC6 The following thermocouple violated Level 2 criteria'during N2-SUT-27-6: TO TEMP LIMIT TE-DW-09 154.9 < 150.0 TE-DW-12 172.4 > 150.0 TE-DW-09 increased to 226 degrees Fahrenheit five minutes after the scram and TE-DW-12 increased to 236 degrees Fahrenheit five minutes. after the scram. This is acceptable as the 150 degrees criteria was intended to be for steady state conditions and not for transients. The two high temperatures are accepted as is listed in Test Exception 9 above. 12 TC6 Unit cooler performance data collection was intended for performance evaluation purposes, but is not required for acceptance criteria. Earlier testing showed that the information from this data was not meaningful for evaluating the performance of the unit coolers and therefore this data was not collected. l
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- - ESF AREA COOLING SYSTEM N2-SUT-76, L
3.33 ' N2-SUT-76 ESF' AREA COOLING SYSTEM-f.
- A. OBJECTIVE To : verify the capability of the Engineered Safety Feature '(EST)
Unit Coolers . to maintain ~ the ' room temperatures below . the maximum design ' limits under postulated _ accident conditions and .to compare the actual heat removal rates to design' values. l L' B. ACCEPTANCE CRITERIA Level'1-
' All ESF area ' air space . temperatures measured shall not exceed-the design 11mits specified in the FSAR..
' Level 2 Evaluation of test data shall demonstrate that the ESF Area Unit Coolers are capable of removing their design heat load.
C. DISCUSSION p During Test Condition 1, the following ESF Area Unit Coolers were tested: Residual Heat . Removal System (RHR) Heat Exchanger
'A' Room Cooler, RHR Heat Exchanger 'B' Room Cooler and Reactor Core Isolation Cooling (RCIC) Pump Room Coolers. The ESF room temperatures were well below the Level 1 Acceptance Criteria of 120 degrees F, the maximum being 97 degrees F. While the Unit Cooler for the RHR Heat Exchanger 'A' met the Level 2 Acceptance Criteria, the other Unit Coolers did not. The cooler coils were flushed and then were retested numerout times. Cooler performance data was evaluated by Stone and Webster Engineering and accepted as is per a Test Performance Evaluation Report.
A Test Exception was written to document that relative humidity-data did not fall within the range specified in the FSAR fer the RHR Heat Exchanger 'A' Room Coolers. This data was accepted as is per analysis from Engineering.
~.f
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ESF AREA COOLING SYSTEM U I .N2-SUT-76 C. (Cont'd). a
. During ' Test Condition 3, the following unit coolers were tested and passed the Level . 2 Acceptance Criteria: Low . Pressure ' Core Spray Pump Room Coolers, North MCC Area Coolers, RHR 'C' Ptamp Room Unit Coolers and' Diesel Generator EG2. Unit Cooler. Service Water Ptssp Bay Unit Coolers ' met the Level- 2 Acceptance' Criteria'~
with the provision that the valve- line-up 'is in agreement with the design valve . line-up . such that ' tha t service water valves ~'to the redundant Unit Coolers are closed.. All ESF room temperatures were well- below Level 1 Acceptances Criteria of; 120 degrees. F and 104 degrees F with ~ the . maximum-room temperature being 86 degrees F for the HPCS. Pump Room. During Test Condi~ tion 6, unit cooler testing from Test' Condition 3 was completed. Diesel Generator EG1 unit cooler did not' meet' # Level 2 acceptance criteria with the - service .' water discharge valve . positioned to 75 degrees : - closed. - .The valve was' repositioned to the 45 . degrees open , position and .results
. accepted. Diecel Generator EG3' unit cooler f azied the . Level : 2 acceptance criteria. The cooler was retested with the service water ' discharge . ; valve '45 ' degrees open . and . the results '
accepted. Standby Gas Treatment' Building Unit Coolers and south MCC area unit coolers failed the Level 2 acceptance criteria. The coolers were retested and the results accepted. High' Pressure Core Spray (HPCS) Pump Room unit cooler 2HVR*UC403A failed the Level 2 acceptance criteria. The cooler was.ratested and _the .results accepted.. HPCS- Puerp -Room unit cooler 2HVR*UC403B also failed the Level 2 acceptance criteria. The cooler was flushed and the ' retest also failed. The service water dischstge valve was then repositioned to the 50 degrees open position. A retest was performed and the results accepted. Test Condition 6 testing'also included RER 'A' and 'B' Pump Room unit coolers (shutdown cooling mode) and the coolers passed the Level 2 acceptance criteria. All ESFE room temperatures were well below Level 1 acceptance criteria of 120 degrees Fahrenheit with the maximum room temperature being 89 degrees Fahrenheit for the RER 'B' Pump Room. Test Exceptions and their resolutions are sinanarized in Table j 3.33-1. l
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as:
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_n_______ . . . _ . _ ._ _
c TABLE 3.33-1 ESF AREA COOLING SYSTEM N2-SUT-76 TEST EXCEPTION SIBMARY Test Test Exception ~ Condition Description 1 1 Capability of ESF coolers for the RCIC Pump Room to remove design heat load could not be demonstrated by the calculations. The cooling water coils were flushed and the coolers retested satisfactorily. 2 1 Unit Cooler for the 'A' RHR. Heat Exchanger Room relative humidity was beyond the range specified in FSAR.- Accepted as is. 3 1 Capability of the Unit Cooler for the 'B' RHR Heat Exchanger Room to remove design heat load ' cannot be demonstrated by the calculations. The cooling water coils were flushed and the coolers retested satisfactorily. 4 1 Various Unit Coolers were retested and failed - Level 2 Criteria. Accept as is per Engineering evaluation. 5 3 Room temperatures in Standby Gas Treatment Building decreased below the design minimum value of 65'F. Accept as is per Engineering analysis. , 6 3 Room temperature for the Diesel Generator EG3 Room decreased below design minimum temperature of 65'F due to fact that the unit cooler was in the manual mode for test. Accept as is since the temperature is within design limits. t
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( TABLE 3.33-1 (Cont'd) ESF AREA COOLING SYSTEM N2-SUT-76 TEST EECEPTI(El SIEWi&RY l l Test Test-Exception Condition Description l-7 3 Unit coolers in the South MCC Area, HPCS Pump ' Room, . Diesel Generator EG3 Room, Diesel Generator EG2 Room, - standby Gas Treatment Bldg.' and Service Water . Bays did not meet Level 2 acceptance criteria per Engineering's " Unit Cooler Performance Evaluation". Retest performed and satisfactory. .
~
8 3 Unit coolers in the Service Water Bays did not meet Level '2 acceptance criteria " Unit' Cooler Performance Evaluation *. Retest complete and satisfactory. 9 3 Unit cooler 2HVR*UC403B in HPCS Pump Room did not meet Level 2 acceptance criteria per " Unit Cooler Performance Evaluation". Retest performed and satisfactory. 10 3 Retest #1 of Diesel Generator EG3 and Retest #2 of HPCS Pump Room cooler UC403B did not meet Level 2-acceptance criteria per " Unit Cooler Performance Evaluation". Retest performed and satisfactory. 11 3 Diesel Generator EG1 unit cooler did not meet Level 2 acceptance criteria per " Unit Cooler Performance , Evaluation" with Service Water discharge valve throttled to 75 degrees closed. Data taken with the valve 45 degrees open and data accepted. No action required. 12 3 Retest of Diesel Generator EG2. did not meet level 2 acceptance criteria per " Unit Cooler . Performance Evaluation". Retest performed and satisfactory. 13 3 There was no " Initial Conditions" section for testing of HPCS Pump Room unit coolers on 11/18/87. No action required. 14 3 There was no " Prerequisite" or " Initial Condition" signed for testing of Diesel Generator EG2 unit cooler on 11/20/87. There is no " Initial . Conditions" signed off for testing standby Gas Treatment unit coolers on 1/5/88 or 1/6/88. No e action required.
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BOF FIFING VIBRATIGE N2-SUT : l 3.34 'N2-SUT-77 BOP PIPING. VIBRATION A. OBJECTIVE
- 1. To . verify that steady-state and/or : transient piping-vibration for the main, steam. (including relief valve discharge)', residual heat " removal, 'feedwater - reactor core isolation- cooling, and . condensate' systems are within; '
t acceptable limits.-
- 2. To. verify that steady-state vibrations for small bore-piping - and essential instrumentation- lines ~ on main ateam, nuclear . steam supply, feedwater, reactor ~ plant sampling, residual heat ' removal and reactor . core isolation cooling are within acceptable limits.
B .~ . ACCEPTANCE CRITERIA l' Level 1
- 1. - Transient: .. The acceptance limits for . Level 1 are based upon ASME B&PVC, Section III, Equation 9 for Class 1,. 2 and- - ,-
3 systems or: ANSI B31.1, Fquation 12 for. Class 4 - systems. These acceptance limits restrict the bending stress due .to deflection plus deadweight and pressure to a .value less than the- normal / upset allowable stress for occasional loads. Vibration displacements greater - than the Level 1 Criteria listed on the -individual system. test' matrix data-sheets-are considered unacceptable.
- 2. Steady State: None Laval 2
- 1. Transient: The acceptance limits for Level 2 arm based on pipe stress and support loads that do not ' exceed design basis predictions. Vibration displacements greater than the Level 2 Criteria listed on the individual system test matrix data sheets are considered unacceptable.
- 2. Steady State:
- Acceptance criteria limits are based upon deflection equations given in ANSI /ASME OM-3 with limiting allowable stress of (0.8/1.3) Set for carbon steel L piping and an allowable stress of S a at 1011 cycles using curve e for stainless steel piping.
-244 am LL_ L_- JL _--.- - - - - - - - - . _ . - _ - . - . . _ - -
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BOF PIPING'VIBRATIGf 4
'N2-SUT-77 g'4 "
a B. Level 2 (Cont'd) 1 Remote steady. . state measurements: Vibration displacements: greateri .than the' steady ~ state displacement acceptance limit'on the individual system.
. test matrix data sheets are considered unacceptable. .;
- Visual. observation . screening / hand held ' ' vibration.. 1
- i. monitor steady state , measurements: Visually : observed - ;'
vibration in the. nitrogen 1(GSN) system while utilizing
. the ' " standing distance ' given in the applicable testa sketch (VSK) and which exceeds .0.5 ' in/sec . velocity measured with a hand held vibration monitor . zis-considered unacceptable.
C. DISCUSSION
~ Remote testing was performed using Lanyard Potentiometers. The -
signals generated were . input _ to the General . Electric Transient-.
. Analysis Recorder (GETARs).
- The . Piping Transient . Response (Displacement) was measured at selected locations .during applicable ~ transient ' events.
The. transient data was. inspected to obtain the piping dynamic response and the displacement values were analyzed to the_ pertinent' acceptance criteria.
- Piping Steady State Displacements were measured at-selected locations and at - appropriate system / station steady state conditions. The steady state data was analyzed to the pertinent acceptance criteria.
- Strain measurements were taken per Engineering's' request of the Main Steam #2 Bypass Valve discharge piping during steady state operation with the #2 Bypass Valve. discharging at various open positions and the data was analyzed to the pertinent acceptance criteria.
- Table 3.34-1 tabulates the Tests, modes of operation and test conditions at which piping vibration was tested.
- Table 3.34-2 tabulates the Test Exceptions and provides a brief description of each, including the applicable test points.
In all cases, the Acceptance Criteria were satisfied or resolved , in accordance with existing plant procedures. ~j
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J,) .- p TABLE 3.34-1 BOP. PIPING VIBRATION N2-SUT-77 VIBRATION TEST DESCRIPTION TEST- SYSTEM CONDITION SYSTEM DESCRIPTION TYPE OF TEST MODE OF SYST1!N OPRRATION Reactor Core HU4 ICS Isolation Coolina Transient- Pin =n Start - CST to' CST Reactor Core HU' ICS Isolation Coolina Transient Pimen Ston - CST to CST'
.c- Reactor Core- Steady. Rated Flow Rate -
HU ICS Isolation Coo 14na -State CST to CST Control Rod Drive Single' Rod Scram'at less HU' RDS Hydraulle mSvatem Tran= lent than 50 PSIG n.=etor Pressure? Control Rod Drive Single Rod Scram atl rated. HU RDS Hydraulic-Svaten Transient' n==etor' Pressure Reactor Water. Level.Setpoint 1 CNM- Condan==te Svatem Translant' chen-(Incr==me-Decr===e)- Reactor Water Level Setpoint 1- FWS Feedwater Svatem Tran sient ches'(Incr===e-Decr===e) Main Steam Safaty Relief Main Steam Valve Discharges 2 MSS *PSV-- 1 MSS System- Transient 120,121.122,123,129,130 . ! 131;132 & 133' Main Steam Safety Main Steam. Safety Relief 1 SVV Relief Valve Transient Valve 2 MSS *PSV-133 Dischmene Residual Heat Steady Loop 'A' During Steam 1 RHS Removal System State Condensing Mode Operation at 1001 Flow Rate Reactor Core Pump Start - Reactor _ Pressure 1 ICS Isolation Coo 14nn .Tran sient vessel'(RPV)-Inlaction Reactor Core 1 ICS Isolatfon Coo 14ne Tran sient ' Pin =n Ston - RPV Iniec_ tion Reactor Core Steady Rated Flow Rate - . 1 ICS Isolation Coo 14na State RPV Iniection Main Steam System Steady #2 Main Steam Bypass Valve 1 MSS (Bypass Line #2) State Operation at'20%,40%,60%, , 801 and 1001 onen'oomitions Condensate Turbine Trip within Bypass 2 CNM Svatem Transient canacity Condensate Feedwater System, Line 'A' 2 CNM System Transient 5% Flow Step Changes (Ineramme - Decr===e) Condensate Steady System Steady State Oper-2 CNM System State ation at 25% of rated , n.neter Core Thermal Power - Feedwater Turbine Trip within Bypass , 2 FWS Svatem Transient caoacity
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l TARI.E 3. 34-1 (Cont'd) BOP PIPING VIBRATION
'N2-SUT-77 VIBRATION TEST DESCRIPTION TEST SYSTEM
' CONDITION SYSTEM DESCRIPTION TYPE OF TEST MODE OF SYSTEM OPRRATION Feedwater Line 'A':Feedwater System 2- PWS System Transient 5% Flow Step Changes (Increase - Decrease)
Feedwater Steady. System Steady State oper-2 FWS . System State ation 25% of rated Reactor-Core Thermal Power Main Steam Turbine Trip within Bypass-2 MSS System Tran sien t canseity Main Steam 2 M3S System Transient Pressure Reenlator Failure Main Steam Pressure Controller Set-2 MSS System Tran sient noint channes Main Steam Steady System Steady State Oper- . 2 MSS' System State ~ at1on at 25% of Rated Rameter Core Thermal Power Reactor Recire Steady System Steady State Oper-2 RCS System (Small State ation at 25% of Rated' Bore) Rametor Core Thermal Power Nuclear Boiler Steady System Steady State Oper-2 ISC Instrumentation State ation at 25% of Rated Rameter Core Thermal Power _ Condensate Steady System Steady State Oper-3 CNM System State ation at 50% of Rated Remetor Core Thermal Power Feedwater Steady Systes' Steady State Oper-3 FWS System State ation at 50% of Rated Reactor Core Thermal Power Main Steam Individual MSIV Closures, 3 MSS System Transient 2 MSS *HYV-7A.B.CLD Main Steam Steady- System Steady State Oper-3 MSS System State ation at 50% of Rated Reactor Core Thermal Power Reactor Recire Steady System Steady State Oper-3 RCS System (Small State ation at 50% of Rated Bore) Ammeter Core Thermal Power Nuclear Boiler Steady System Steady State Oper-3 ISC Instrumentation State ation at 50% of Rated nameter Core Thermal Power Nitrogen Steady Full Flow Containment 3 GEN System State Inertine Condensate Steady System Steady State Oper-5 CNM System State ation at 65% of Rated . Reactor Core Therinal Power
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au
.. j TABLE 3. 34-l' (Cont 'd)-
r BOP PIPING VIBRATION N2-SUT-77 I VIBRATION TEST DESCRIPTION 3 TEST SYSTEM
. CONDITION SYSTEM DESCRIPTION- TYPE OF TEST MODE OF SYSTEM OPRRATION Condensate Reactor Water. Level Setpoint' 5 CNM S_vstem Tran sient 'Chan (Increase ' Decrease)'
Feedwater Steady System Steady State Oper-5 WS . System State ation.at'65% of Rated Rameter Core Thermal Power Main Steam Steady' System Steady State Oper-5 ' MSS System State ation at 65% of Rated Remetor Core Thermal Power Reactor Recire Steady System Steady State Oper-5 RCS System (Small State ation at 65% of Rated-Bore) Rametor Core Ther==1 Power Nuclear Boiler Steady System Steady State Oper-
- 5. ISC Instrumentation. State- ation at 65% of Rated _
' Ammetor Core Thamm1 Power-.
Feedwater Reactor Water Level Setpoint 5 WS System Transient Cham. (Increase - Decramme) Feedwater 6 WS System' Transient WS Pi=n (A) Trin Feedwater 6 WS System 2 Transient Full MSIV Isolation Feedwater Turbine Trip with Generator 6 WS Svetem Transient tend Reiection Feedwater Steady System Steady State Oper-6 WS System State ation at 75% of Rated Rametor Core Therrmal Power Feedwater Steady System Steady State Oper- - 6 WS System State ation at 100% of Rated Rametor Core Thermal Power 6 CNM Condannate Tran sient WS Pisan (A) Piann 6 CNM Condensate Transient Full MS1V Isolation Turbine Trip with Generator 6 CNM Condannate Transient Load Reiection Steady System Steady State Oper-6 CNM Condensate State ation at 75% of Rated Reactor Core Thermal Power Steady System Steady State Oper-6 CNM Condensate State ation at 100% of Rated Rameter Core Thermal Power Steady System Runout with 2 Con-6 CNM Condensate State densate & 2 Condensate _ Booster Pumps ('B' & either
'A' or 'C ' Boos ter Pinnna ) *
-248 an.
~
0, '- O_ L TARI.E 3.34-1. .(Cont'd). 1., BOF PIPING VIBRATIGt l' N2-SUT-77 VIBRATION TEST DESCRIPTION TEST SYST91-CONDITION SYSTEM DESCRIPTION TYPE OF TEST' MODE OF SYSTEM OPRRATION' r 1 . , . Residual-Heat Steady- RHS Shutdown Cooling
-6 State ~ Loon RNR- 'R==aval Svstem 'A
l Main Steam 6' MSS System- Transient Full MSIV Isolation Main Steam _ Turbine ~ Trip with . . 6 MSS' System Transient Generator f.and Reiectigg___ Main Steam l Steady System Steady State Oper-6- MSSi -System State ation st 75% of' Rated. Ramet.or Core Thermal Power-Main Stem Steady System. Steady State Oper-6 MSS System State ation at 100% of Rated nameter Core Tha mm1 Power . c; Main Steam i 6 SVV Safety Relief Transient Full MSIV Isolation-Valves Main Steam _ Turbine Trip with 6 SVV Safety Relief TransientJ Generator Load Rejection Valves Nuclear Boiler Steady System Steady State Oper-6 ISC Instrumentation State- ation at.75% of Rated Maneter Core Thermal Power Nuclear Boiler Steady System Steady State Oper-6 ISC' Instrumentation State ation at 100% of Rated R==etor Core Thermal Power Reacter Recire Steady System Steady State Oper-6 RCS System (Small State ation at 75% of Rated Bore) Rameter Core Thermal Power Reactor Recire Steady System Steady State Oper-6 RCS System (Small State ation at 100% of Rated Bere) Rameter Core Ther=m1 Power i 1
-b <
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, y7 9...
T i
?. . TART.R 3,34-2 BOP PIPING VIBRATI(El' N2-SUT-77
TEST EXCEPTION SIRWIARY Test- Test
'Excention Condition Damerlation
~
1 HU Test ' Point RDS-110A-X failed Level' 1 Criteria during Single. Rod Scram- with . Reactor Pressure - less than 50 ~ p PSIG. Evaluated by Engineering and found acceptable.' - 2 H'U - Test Point . RDS-130-Y fsiled - Level 2 Criteria. during Single Rod Scram with' Reactor. Pressure less than 50-
, PSIG. Evaluated by Engineering and'found acceptable.
3 HU- Test Point, RDS-110A-Y failed Level . 2. Criteria during Single Rod Scram with; Reactor Pressure less than ' 50 PSIG. Evaluated.by Engineering and found acceptable. .. 4 HU Test Points ICS-50-X,Y & Z failed Steady State -(Level '
- 2) Criteria during Steady State 'ICS Operation in - . the -
CST-CST mode. Evaluated by Engineering and found-acceptable. 5 HU Test Point RDS-130-X & Y . failed Level -2 Criteria. during Scram from Rated Reactor Pressure. - Evaluated. by Engineering & found acceptable.
- 6. 1 Test Point ICS-40-X, ICS-45-Y & Z failed Level'2 Criteria During Pump Start and Test Points- ICS-45-Y &
Z failed Level 2 ' Criteria during Pump Stop . in . RPV injection mode. Evaluated by - Engineering &- found acceptable. 7 1 Test Point ICS-50-X,Y & 2 failed Steady State (Level
- 2) Criteria During Steady State . ICS Operation :in z the RPV injection mode. Evaluated by Engineering L' found acceptable.
8 1 Test Point MSS-135-Z failed Steady State (Level 2) Criteria During Steady State MSS Bypass Operation with
#2 Bypass Valve at 60% Open Position. Evaluated by Engineering & found acceptable.
9 1 Test Point MSS-135-Z failed Steady State (Level 2) Criteria During Steady State MSS Bypass Operation with
#2 Bypass Valve at 80% Open Position. Evaluated by _
Engineering & found acceptable. m
-250
t f:
' TABLE 3.34-2 (Cont'd)
F BOF FIFING VIBRATImi N2-SUT-77 TEST EECEPTIGi SWWIARY
/
Test. Test Excention Condition Description 10 1 Test Point MSS-135-Z f ailed. ' Steady . State - (Level ' 2) ' Criteria During Steady State MSS Bypass Operation with
#2 Bypass. Valve Lat ' 100% .Open Position. Evaluated by Engineering & found acceptable.
11 1 . During . SRV Actuations, , Test' Points as follows failed ,l Level 2 = Criteria: MSS-18-X,Y & . Z,..-MSS-40-Y, MSS-42-X,Y & Z, MSS-7bY&Z, MSS-124-X & . Z, L MSS-209-Z, MSS-7082-Z, SVV-617-X & Y. and SVV-657-Y. Evaluated by. Engineering and found acceptable. ,- 12' 2 -Test Point CNM-060-X & Z failed' Steady State-(Level 2), criteria during Steady State Operation at 25% ' Reactor Core- Thermal Power.- Evaluated by Engineering and accepted. 13 2 Test Points MSS-209-Z - and MSS-521-Y failed Level 1-Criteria during Turbine Trip . within Bypass capacity. The results Wre evaluate'd by Engineering. Based on the review 'of . the resultant displacement- (ie,- Combining the X, Y & ZL displacements) the displacement . was found to be less~ than 'the Level 1. Limit. Engineering ' subsequently determined the violation to be Level 2 failures- in lieu of Level -1. Test Exception 14 subsequently was issued documenting these failures and test exception 13 was accepted by Engineering and closed.
=
14 2 Test Points, as follows, failed Level 2 Criteria during _ Turbine trip within Bypass Capacity. MSS-209-X
& Z, 521-X,Y & Z, 7082-X,Y &-Z, 18-Z, 135-X,Y & Z, 124-Z and FWS-85-X & Z. Evaluated by Engineering ' and accepted.
15 2 Test Points MSS-18-X & 7. were experiencing spurious-noise. Evaluated by Engineering and accepted for previous test - data. Test points were subsequently corrected and made operable.
-251 .
m 3"i
*l
= - - __ _ _ _ _ _ - - - _ _
- I
;. i TARLE 3.34-2 (Cont'd) l
, . .i I BOP PIPING VIBRATIGi N2-SUT-77 TEST EXCEPTION SIRBl&RY .I i Test Test Excention Condition Description 16 3 Test Point CNM-060-Z failed. Steady State (Level 2) Criteria during Steady State Operation at 50% Reactor Core Thermal Power. Evaluated. by Engineering & found
~
acceptable. Test Point CNM-060-X & Z failed Steady-State.(Level 2)
~
17 -5 Criteria during Steady State; Operation at 65% Reactor Core Thennal Power. Evaluated by Engineering and accepted. 18 .6 Test , Point CNM 1 220-Z failed . Steady State (Level 2) ,
. Criteria during Steady State Operation at 75%- Reactor Core Thermal Power; Evaluated by Engineering and found acceptable.
19 6 Test Point. SVV-657-Y failed Level 1 Criteria ~during MSIV Full. Isolation. Evaluated by Engineering and found acceptable. 20 6 Test Points CNM-220-Z and CNM-060-X failed Steady State (Level 2) Criteria during Steady State Operation at Condensate Runout in the 2-2-2 pump alignment. Evaluated by Engineering and Found acceptable. 21 6 Test . Points SVV-617-X,Y,&Z, SVV-657-X & Z, MSS-75-Y, and MSS-124-X failed Level 2 Criteria during MSIV Full Isolation. Evaluated by Engineering and found acceptable. 22 6 Test Point RCS-124-Y failed Steady State (Level 2) Criteria during Steady State Operation at 100% Reactor Core Thermal Power. . Evaluated by Engineering and found acceptable. 23 6 Test Points MSS-209-X & Z, MSS-521-Y & Z, MSS-7082-Y and MSS-657-Y failed Level 1 Criteria during Turbine Trip with Generator Load Rejection. Evaluated: by Engineering and found acceptable. 24 6 Test Points MSS-124-X, MSS-521-X, MSS-75-Y, MSS-135- X _
& Y, SVV-617-X, Y&Z, SVV-657-Z, FWS-190-X, Y, & Z, FWS-1455-X, FWS-85-X, Y, & Z and CNM-060-X failed
- Level 2 Criteria during Turbine Trip with Generator Load Rejection. Evaluated by Engineering and found acceptable. ,
-25 2 l
h.4 4 1
..-]
h J I BOP SYSTEM EXPANSI(Ni - N2-SUT-78 I !s 3.35 -N2-SUT-78 BOP SYSTEM EXPANSION
.1 A .' OBJECTIVES I L The purpose of this test procedure is to verify: -J 1.' That the . amount of thermal expansion is within prescribed - q limits representing both the - expected deflections and the H allowable deflections as limited by design.
- 2. . That - there are no interferences to constrain the piping tj during heatup or cooldown cycles. J
- 3. Preservice Examination Criteria for selected Snubber and' Spring Supports on systems which have a design operating-temperature greater than 250 degrees F.
~
B.- ACCEPTANCE CRITERIA Level 1
- 1. Remote Lanyard Potentiometer Test Points, Local Scriber Test Points, Local Pipe Support . Test Points: Measured Displacements which fall outside the Level 1 limits.
prescribed in the test procedure are unacceptable.
- 2. Snubbers and Spring Supports: There shall be no evidence of damage that indicates non-operability or will cause non-operability. There will be no direct interference.with movement of the pipe support during thermal expansion.. ,
Snubbers and Spring Supports shall remain within the operable range of travel.
- 3. Snubbers (for measurements along travel scale): For those snubbers whose rated condition displacement exceeds 3/4" as given in the applicable Data Sheet, some measured movement shall have occurred when measured at the intermediate temperature plateau. For those snubbers whose rated l 3/8" as given in the condition displacement exceeds applicable Data Sheet, coes measured movement shall have occurred when measured at the rated temperature plateau.
- 4. Piping: There will be no direct interference with thermal movement of the piping.
-253 .
*e An'
y l BOP SYSTEM EXPANSION , 1 N2-SUT-78 B. '(Con t ' d ) - ! 1 Level 2
- 1. Remote Lanyard Potentiometer Test Points, Local Scriber Test ' Pcints, Local Pipe Support Test Points,- Local Pipe Whip Restraint Test Points: Measured displacements which fall outside the Level 2 limits prescribed in. the test procedure are unacceptable.
1 2.. Snubbers and Spring Supports: There shall be no ! obstructions within the Swing Clearance " Cone" (a clearance envelope through which the support is projected . with - the cone base at the component connection using a radius as provided by Engineering). There shall be . no evidence of damage. Position settings shall be within the tolerances prescribed in the test sirocedure. -
- 3. Piping: .There shall be no potential interferences with thermal expansion of the piping.
- 4. Reactor Recirculation Pipe Whip Restraints: No interferences shall exist between the pipe insulation and the whip restraint. The whip restraint shall appear visibly concentric to the piping when at the rated temperature position.
C. RISCUSSION Remote testing was performed using Lanyard Potentiometers at selected locations. The signals generated were input to the General Electric Transient Analysis Recorder (CETARs) and processed. The remote data'was analyzed to be within the Level 1 and 2 High and Low Limits prescribed. Local Testing was performed using the following: Scribers at selected locations: Spring Loaded Points were ! utilized to scratch a permanent mark in painted plates mounted onto the piping. This kept a measurable record of the piping motion through heatup to cooldown. j s Pipe Supports: The travel scales on selected pipe supports were used to measure and analyze piping movement from thermal growth. L'
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aus
~
I. ____ _ l
BOP SYSTEM EXPANSION N2-SUT-78 C. (Cont'd) Pipe Whip Restraint Measurement Rods: Measurement rods-were mounted onto ' the pipe whip restraints normal ' to the axis of the pipe, so that piping displacement . would displace the rod leaving a measurable record of the piping movement in that direction. The' Local Test data was analyzed to be within the Level 1 and 2-High and Low limits prescribed. Where prescribed by the Preservice Inspection Plan, Snubbers and Spring , Supports on Piping _ Systems whose design operating temperature is 250*F or greater are examined to fulfill the ASME 5ection XI preservice Inspection VT-4 examination requirements. This examination is ' performed to assure that the support- will operate 'as- expectt:d, and to record the baseline Hot and Cold position settings. . The specified piping systems were walked down comprehensively to verify that no constraint to thermal movement exists during' heatup or cooldown. In all cases. the acceptance criteria-was satisfied or resolved
- in accordance with existing plant procedures.
Table 3.35-1 lists the . Plant Piping Systems tested in Test Condition Heatup. Table 3.35-2 describes the testing performed in - Test Condition Heatup. Table 3.35-3 describes the testing performed in Test Conditions 1, 2 and 6. Test Exceptions and their resolutions are summarized in Table 3.35-4. 1
-255 .;
'l Jiel t
. . ~ __ _ _ - _ - - . _ - - l
j TABLE 3.35-1 1 BOP SYSTDI EXPANSION
.t.
N2-SUT-78 SYSTEMS TESTED IN TEST CONDITION HEATUP. Reactor Core Isolation Cooling (Steam Supply to Turbine) Reactor Core Isolation Cooling (Reactor Vessel Injection Between Refueling Bulkhead-and Reactor Vessel Head Nozzle) q
- _1 Nuclear Boiler Instrumentation (Connected to the Reactor Vessel inside the .j Primary Containment) ]
Reactor Water Cleanup System (with design operating Temperatures >250'F) Main Steam Safety Relief Valve (SRV) Discharge Piping to the first Anchor Standby Liquid Control (Inside Primary Containment) High Pressure Core Spray (Inside Primary Containment) Low Pressure Core Spray (Inside Primary Containment) Low Pressure-Coolant Injection (Inside Primary Containment) Feedwater (Inside Primary Containment) Main Steam from the Reactor Vessel to Stop and Control Valves, Moisture Separator Reheater.(MSR) Isolation Valves and Main Steam Bypass Chest Reactor Recirculation System and Residual Heat Removal (Shutdown Cooling Inside Primary Containment) Diesel Generator Exhausts (only tested at ambient and when Diesel Generators are' running)
-256 ,
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TABLE 3.35-3
,. BOP SYSTEM EXPANSION-N2-SUT-78 RYPANSION TESTING DURING' TEST CONDITIONS 1. 2 AND 6
.Tsst Condition Svstems Tent Descriptions Test Conditions Ita== - Tes ta'd 1 RHS (Steam Initial Ambient Recirculation Suc- Piping, Snubbers &-Spring Condensing tion temperature was Supports were examined for:
# Mode) 70'F-110*F. position settings'and con' -
straintis to thermal'erowth. Rated Temperature The respective Heat Piping. Snubbers & Spring' Plateau' Exchanger.was in Supports were examined for
-Steam Condensing ' position. settings, damage Mode Operation with and constraints to thermal steam' inlet pressure' growth, at 200 PSIC.
Return.to Ambient Recirculation Suc- Piping, Snubbers & Spring tion temperature Supports were examined for.- was.70*F-110'F. ~ position settings, damage . and constraints.to thermal erowth. 1 Main Steam Initial Ambient . Recirculation Suc- . Piping, Snubbers & Spring. Safety' tion temperature Supports were examined for-Relief was 70*F-110*F. cold' positions & con-Valves Disch~ ~ ~ ~ straints to thermal growth' Piping .(performed'in conjunction-with N2-SUT-78-HU). Rated Temperature Test was performed Remote Lanyard Potentio-Plateau during the respec- meter dispiccoment. measure-tive SRV actuation. ments were analyzed. Return to Ambient Recirculation Suc- Piping, Snubbers & Spring tion temperature was Supports were examined for' 70*F-110*F. cold positions damage & constraints to thermal growth. Remote Lanyard Potentiometer return to ambient measurements were. recorded. 1
-259 _
I as
TABLE 3.35 (Cont'd) BOP SYSTEM EKPANSION N2-SUT-78' N ANSION TESTING DURING TEST CONDITIONS 1. 2 AND 6 Test Condition Systems Test Descriptions Test Conditions Itama Tested 1 Main Steam Initial Ambient Recirculation Suc- Piping, Snubbers & Springs From Stop tion temperature was were examined for position
-and control 70*F-110*F. settings and constraints to Valves to thermal erowth.
Turbine HP " Turbine Operation" Main Turbine / Piping, Snubbers & Spring Stage Pieteau Generator.was in Supports were examined for Operation. position settings, damage and constraints to thermal growth. Return to Ambient Recirculation Suc- Piping, Snubbers & Spring tion temperature was Supports were examined for i 70*F-110*F. position settings, damage and constraints to thermal. rrowth. 2 Main Steam Initial Ambient Recirculation Suc- Piping, Snubbere & Spring. to Moisture tion temperature was Supports were examined for Separator 70*F-110*F. cold positions & con-Reheaters straints to thermal growth (this was performed initially during initial ambient walkdowns during TO HU. Rated Temperature 2 MSS-A0V-92A&B Piping, Snubbers & Spring Plateau were open supplying Supports were examined for steam to the mois- cold positions, damage and ture separator constraints to thermal reheaters. nrowth. Return to Ambient Station was in Piping, Snubbers & Spring-shutdown for (3) Supports were examined for days minimum prior cold positions, damage and to walkdown. constraints to thermal growth. 6 RHS Loop Initial Ambient RHS 'A' Heat Piping, Snubbers & Spring
'A' (Shut- Exchanger Inlet Supports were examined for down Cooling Temperature was cold positions & con-70* - 110*F straints to thermal growth l Mode)
Rated Temperature In conjunction Piping, Snubbers & Spring j Plateau with RHS Sys. per Supports were examined for j N2-SUT-71 with hot positions, damage and l l Loop 'A' in shut- constraints to thermal j down cooling growth. Remote Lanyard I potentiometerdisplacements-( were measured and analyzed. Return to Ambient RHS 'A' Heat Piping, Snubbers & Spring Mu Exchanger Inlet Supports were examined for ' i Temperature was cold positions, damage and l 70' - 110' F constraints to thermal " crowth.
-260-
l , k
-1 l'
TABLE 3.35-3: (Cont'd) 1 BOP SYSTEM EKPANSION N2-SUT-78 .: 1 L EXPANSION TESTING DURING TEST CONDITIONS'1. 2 AND__6 l
' Test Condition Syst=== , Test Descriptions ' Test Conditions Itama Tested' 6 RHS Loop 'B' Initial Ambient RHS 'B' Heat Piping, Snubbers & Spring-(Shutdown Exchanger-Inlet' Supports were examined for I Cooling Mode- Temperature was cold positions _& con-
- Including. 70* - 110*F. straints to' thermal growth Head Spray)
Rated Temperature In conjunction. Piping, Snubbers & Spring Plateau with RHS Sys. per Supports were examined for
.N2-SUT-71 with hot positions, damage and-Loop 'B' in' shut- . constraints-to thermal down cooling growth. Remote Lanyard potentiometer displacements were mammured and annivzed.
Return.to Ambient RHS 'B' Heat Piping, Snubbers & Spring
- Exchanger Inlet Supports were examined for Temperature was cold positions, damage and 70' - 110' F constraints to thermal growth. Scriber points were
-. . measured f or . thermal dis-placements from ambient to rated temperature.
6 WS in any Initial Ambient Feedwater Piping, Snubbers & Spring combination Temperature Supports were examined for of WS Pumps was 70* - 110*F cold positions & con-straints to thermal growth Rated Temperature Feedwater Piping, Snubbers & Spring Plateau Temperature was Supports were examined for 425' F i 25' F hot positions, damage and constraints to thermal growth. Remote Lanyard potentiometer displacements were mammured and analyzed. Return to Ambient Feedwater Piping, Snubbers & Spring Temperature Supports were examined for was 70' - 110' F cold positions settings, damage and constraints to thermal growth. Scriber and pipe whip restraint points were measured for thermal displacement from ambient to rated temperature. .
-261 au
TABLE 3.35-3 (Cont'd) BOP SYSTEM EXPANSION N2-SUT-78 EXPANSION TESTING DURING TEST CONDITIONS 1. 2 AND 6 Test Condition Systems Test Descriptions Test Conditions Itr== Tested 6 FWS with Initial Ambient -Feedwater Piping, Sntbbers & Spring FWS Pump 'A' Temperature Supports were. examined for in operation was 70' - 110*F cold position settings & for constraints to thermal growth ! Rated Temperature Feedwater Piping, Snubbers & Spring Plateau Temperature was Supports were examined for 425' F 25' F hot position settings, damage and constraints to thermal erowth. Return to Ambient Feedwater Piping, Snubbers & Spring Temperature Supports were examined for-was 70* - 110' F cold positions settings, damage and constraints to thermal growth. Scriber and pipe whip restraint points were measured for thermal displacements from ambient to rated temperature. 6 FWS with Initial Ambient Feedwater Piping, Snubbers & Spring FWS Pump 'B' Temperature Supports were examined for in operation was 70' - 110*F cold positions settings & constraints to thermal crowth Rated Temperature Feedwater Piping, Snubbers & Spring
lateau ' Temperature was Supports were examined for 425 ' F i 25 ' F hot position settings, damage and constraints to thermal erowth. j Return to Ambient Feedwater Piping, Snubbers & Spring Temperature Supports were examined for was 70' - 110' F cold positions settings, damage and constraints to ]
thermal growth. Scriber and pipe whip restraint points were measured for thermal displacements from j ambient to rated I temocrature. j l 1
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TABLE 3.35-3 (Cont'd) BOP SYSTEM EKPANSION N2-SUT-78 EXPANSION TESTING DURING TEST CONDITIONS 1. 2 AND 6 Tact-Condition Systems Test Descriptions- Test Conditions Itama Tested 6 WS with - Initial Ambient Feedwater Piping, Snubbers & Spring FWS Pump 'C.' Temperature . Supports were examined for in operation was 70' - 110*F cold positions settings & constraints to thermal rrog!;h_ Rated Temperature Feedwater Piping,' Snubbers & Spring
' Plateau: Temperature was Supports were examined for 425' F i 25' F'. hot position settings, damage.
and constraints to thennal growth. Return to Ambient Feedwater. Piping, Snubbers & Spring Temperature Supports were examined for was 70* - 110' F cold positions settings, - damage and constraints to thermal growth. Scriber and pipe whip restraint points were measured for thermal displacements from ambient to rated - -. temperature. G 4
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l
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i TARIE 3.35-4 ! BOP SYSTEM EXPANSI(N N2-SUT-78 4 TEST EKCEPTION SGetARY j l Test Test: Egggotion Condition Description
.1 HU - (8) Snubbers were found . to have inadequate, travel' and -
' failed Level 2 Criteria when examined at the initial i ambient temperature plateau. - (2) of the snubbers were evaluated by ' Engineering. and found ' acceptable and the1 remaining snubbers were reworked and retested-satisfactorily.
2 ~ HU- (35) - Spring Supports failed Level 2- Criteria when examined at the initial ambient . temperature plateau. The Spring Supports cold positions were out- of tolerance from the specified cold positions. (23) of. , the Spring . Supports were evaluated by Engineering and The remaining (12) Spring Supports were accepted. reworked, (10) of which were retested satisfactorily and (2) of which retested unsatisfactorily. (See Test Exceptions 3 & 5) 3 HU- (43) Supports failed Level 2 Criteria when examined at the initial ambient temperature plateau.- These supports were found to contain potential interferences within the swing clearance " Cone" (one support was - listed also in Test Exception 2). All (43). supports were evaluated by Engineering and found acceptable.- 4 HU (7) Potential piping interferences- were found, failing Level 2 Criteria at the initial . ambient . temperature plateau. (1) Potential interference was evaluated and accepted by Engineering. The (6) remaining potential-interferences were reworked and retested satisfactorily.- 5 HU (1) Spring Support retested at the initial ' ambient plateau f ailed Level 2 Criteria (reworked and retested for Exception 2). The cold position setting was out of tolerance from the specified cold position. Evaluated by Engineering and accepted. L
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i 1 a, TABLE 3.35-4 (Cont'd) j BOP SYSTEM EKPANSI(N j
.N2-SUT-78 TEST EXCEPTION SUfflARY Test ' Test Exceotion Condition Description 1
6 HUl (15)' Piping Snubbers failed Level 1 ' Criteria when .. examined I at the first' Intermediate . Temperature Plateau ' (275'F). .The subject snubbers exhibited no measured movement although
. expected . to move. Engineering". evaluated . the ' exception and
' determined that it' would be . acceptable to proceed ~ to ' the 360*F 1 plateau and ' to . retest '(11)Tof the snubbers.- Of.
these,- (6)'of the snubbers were retested' satisfactorily and (5)- were retested unsatisfactorily, generating. Test Exception 9). The expected ' deflection for another of the snubbers was determined by Engineering- to be ~ inappropriate. and ' when ' re-analyzed was found ~ acceptable. . The remaining- - (3) snubbers were removed from this test ' procedure - as 'the
. subject . systen: (MSRs)' would not be in operation until i a-later test condition.-
7 HU (1) Constant Support failed Level 1 Criteria when measured at the first Intermediate Temperature Plateau (275'F). The support had moved into the last 1/4" of travel available. Reworked and retested satisfactorily. 8 HU (1)' Spring Support failed Level'2 Criteria when examined at the first Intermediate Temperature Plateau (275'F). A potential interference between hanger - rod swing and conduit was reworked and retested satisfactorily. 9 HU (5) Snubbers failed Level 1 Criteria when retested at the .i second Temperature Plateau (360*F) ' (See Test ' Exception 6). These snubbers still exhibited no measured movement. Of the (5) snubbers, (1)' was found to exhibit inadequate _ movement due to insufficient thermal gaps in. adjacent piping restraints. Following the rework of the restraints, this enubber retested satisfactorily. The other (4) snubbers addressed were evaluated by Engineering and accepted. Engineering requested retesting .of (5) additional snubbers which were also found satisfactory. As a result of this Test Exception, SORC mandated examination of similarly designed piping restraints for thermal gaps j
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6... s 4. L. TARLR 3135-4' (Cont ' d' ) - t.' ' .i BOP SYSTEM EEPANSI(Ni-N2-SUT-78 TEST EECEPTION stb W AY' d j i ' Test- Test excention' Condition' -Description
-with an Engineering' review 'of- the : examination l results, as . welli as an Engineering review f of remote : piping.
'50*F
~
. measurements at temperature . increments.
Following : Engineering review b of the piping restraint '
!- thermal - gap measurements, ( 8). ' restraints . were l-subsequently reworked and inspected satisfactorily.;
- 10 'HU . (1); Main - Steam Snubber ( violated- Level : li Criteria at
; the 360*F plateau : as the . snubber v moved out of the.
1 operable range: of its travel.- : Reworked per Engineering evaluation and retested satisfactorily.
- 11. HU. (1) . Div - 1 diesel . exhaust' Snubber violated . Level 2 out-of-tolerance Criteria when ' measured at its Rated-Temperature Plateau. Evaluated . by- Engineering . and.-
accepted.
'12 HU (1) Div 2 diesel exhaust Snubber violated Level. 2-out-of-tolerance Criteria .- when measured at its :.: Rated.
Temperature Plateau. Evaluated' by Engineering and accepted. 3 13' HU (13) Remote Lanyard Potentiometer measurements failed .I Level 1 Criteria and (10) Remote Lanyard i Potentiometers failed Level 2 Criteria when measured at the Rated Temperature Plateau. (Systems: LPCS, HPCS, Feedwater, RCIC, Main Steam, ' RER (m RWCU inside primary Containment). Evaluated by Engineering. and accepted. 14 HU (1) Main Steam Spring Support, when measured at the Rated Temperature Plateau, violated it's Level 2 deflection limit (Local Tect Point). Evaluated by Engineering and accepted. 15 HU (9) Spring Supports, when measured at the Rated l Temperature Plateau, failed Level 2 out-of-tolerance 1 li. Criteria. Evaluated by Engineering and accepted. ) 16 HU (10) Snubbers, when measured at the Rated Temperature . Plateau, failed Level 2 out-of-tolerance Criteria.
- Evaluated by Engineering and accepted.
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i W . . . ll VARY _R 3,35 4 .(Cont'd)' BOP SYSTBI EIPANSIGE V m- . N2-SUT-78~ r-TEST EICEPTIGI SWWi&RY
.I , Test Test
[. Excention ('ondItinn - DascrintInn 17 HU - (1) Potential '.PipingL interference was found at. the 400'T plateau, between Residual Heat Removal vent line and - Containment ' liner,: violating' Level . 2' Criteria.: Reworked and ratested satisfsetorily.t 18 .HU (1) Residua 1L Heat - Removal Spring Support failed Level ~ 1 Criteria by falling outside the operable range at the . Rated-- . Temperature Plateau. " Evaluated - by Engineering and accepted. 19 HU A direct interference was , found between a 'feedwater pipe . support ' clamp and a pipe whip restraint, violating Level 1.' Criteria at the Rated Temperature-Plateau. Reworked in accordance with Engineering's evaluation and retested satisfactorily. 20 HU A direct interference was found ' between the Reactor Recire System 'A' Pump Motor housing and adjacent grating Violating Level 1 Criteria- at the Rated Temperature Plateau. Reworked and retested satisfactorily. 21 HU- (1) Nuclear Boiler Instrumentation Snubber, when measured at the Rated Temperature Plateau, failed' Level 1. Criteria by exhibiting no measured movement. Evaluated-by Engineering and accepted. 22 HU (11) Spring Supports,. when measured at the Rated Temperature Plateau, failed Level 2 out-of-tolerance Criteria. Evaluated by Engineering and accepted. 23 HU (70) Snubbers, when measured at the Rated Temperature Plateau, failed Level 2 out-of-tolerance Criteria. Evaluated by Engineering and accepted. 24 HU (12) General Electric Reactor Recirculation Spring Supports were out-of-tolerance when measured at the Rated Temperature Plateau, ' f ailing Level 2 Criteria. Evaluated by GE Engineering and accepted.
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TABLE 3.35-4 (Cont'd) BOP SYSTEM EKPANSIGt N2-SUT-78 TEST EXCEPTION SG91ARY Test Test Excention Condition Description 25 HU (5) General Electric Reactor Recirculation Snubbers were out-of-tolerance when measured at the Rated Temperature Plateau, failing Level 2 Criterna. Evaluated by GE Engineering and accepted. 26 HU (1) Residual Heat Removal Snubber was out-of-tolerance when measured at the Rated Temperature Plateau, failing Level 2 Criteria. Evaluated by Engineering and accepted. 27 HU (1) Main Steam System Constant Support failed Level 1
-Criteria when measured at the " Return to Ambient" temperature plateau. The support entered the last 1/4" of travel remaining. Evaluated by Engineering and accepted.
28 HU A Main Steam Scriber test point failed Level 2 Criteria when measured at the " Return to Ambient" plateau. Evaluated by Engineering and accepted. 29 HU (16) Pipe whip restraints failed Level 2 Criteria when measured at the " Return to Ambient" plateau. Also, (3) pipe whip restraints could not have_ acceptance . I criteria verified as no measurement equipment was installed at required points. Evaluated by 1 Engineering and accepted. 30 HU (40) Pipe Supports failed Level 2 Criteria when measured at the " Return to Ambient" plateau. These supports had potential interferences within the swing clearance " Cone" of the supports. Evaluated by Engineering and accepted. 31 HU Reactor Bottom Head drain temperature rose 5'F above 110*F (upper limit established for the " Return to Ambient" temperature walkdowns) during the walkdowns. Evaluated by Engineering and accept.ed.
~,
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1. !^ J TABLE 3.35-4 (Cont'd) BOP SYSTEM EXPANSICBI N2-SUT-78 TEST EXCEPTION SIWelARY Test Test Exception Condition Description 32 HU (1) Reactor Core. Isolation Cooling Spring Support failed Level 2 Criteria, was out-of-tolerance from the specified cold set for the " Return. to Ambient" plateau. Evaluated by Engineering and accepted. 33 HU (2) Reactor Water Cleanup Supports were found to have failed Level 2 Criteria when at the Rated Temperature Plateau. The support's actual " Hot" position was out-of-tolerance. Evaluated by Engineering and accepted. - 34 HU Due to high ambient temperatures in the Reactor Primary, above elevation 306', some piping and pipe supports above this elevation could not be examined at rated temperature. Engineering evaluated the exception and, using data collected at a 400'F Temperature Plateau for piping and supports above elevation 306' (but below the refueling bulkhead), prorated this data to Rated Temperature for use as baseline data. Engineering evaluated and approved exemption of Rated Temperature walkdowns abov? 306' elevation in the Reactor Primary where high ambient temperatures made them inaccessible (A Relief Request , to the ASME XI preservice inspection plan was i processed to exempt " Hot" setting verification for those supports above the refueling bulkhead in primary containment). 35 HU (1) Reactor Water Cleanup Snubber was found to have failed Level 2 out-of-tolerance Criteria when at the Rated Temperature Plateau. Evaluated by Engineering and accepted. , l 36 1 Test Points on the SRV Discharge Piping failed Level 1 Criteria during opening of SRVs 2 MSS *PSV-129 & 137. Evaluated by Engineering and accepted. 37 1 Test Point on the SRV Discharge failed Level 2 Criteria during its respective SRV actuation. L Evaluated by Engineering and accepted. ,
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TABLE 3.35-4 -(Cont'd) BOP SYSTEM EXPANSIGi N2-SUT-78 TEST EXCEPTION SIN 9tARY Test Test Exceotion- Condition Description 38 1 (13) Piping Snubbers Failed Level 2' Criteria when examined at " Return to Ambient" plateau. Potential. Interferences fell within the Swing Clearance Con e " . Evaluated by Engineering and accepted. 39 1- A 1" diameter Residual Heat Removal Steam Condensing Mode'line failed Level 1 Criteria when it was'found to have " bound" in its restraints during Steam Condensing Mode operation. The piping Supports were modified and the piping retested satisfactorily.
.40 1 (1) Residual Heat Removal Spring Support failed Level 2 out-of-tolerance Criteria when measured at its rated temperature position. Evaluated by Engineering . and -
accepted. 41 1 (2) Residual Heat Removal Snubbers failed Level 2 out-of-tolerance Criteria when measured at their Rated Temperature Positions. Adjacent piping restraints were modified and the resulting retest resulted in Test Exception 44. 42 1 (3) Snubbers failed Level 2 Criteria 'when measured at their Rated Temperature Positions. (1). Snubber used as a local test point failed its Level 2 limit, and (2) Snubbers were found out-of-tolerance. (2) anubbers were accepted after Engineering evaluation and the third snubber had adjacent restraints modified. The resulting retest resulted in Test Exception 44. 43 1 Deleted. Not a Test Exception. 44 1 During the retest for Test Exceptions 41 and 42, a Snubber was found out-of-tolerance again at the " Hot" position. Evaluated by Engineering and accepted. 45 2 (13) Main Steam Snubbers failed Level 2 out-of-tolerance Criteria, when measured at the Rated Temperature Plateau. Evaluated and accepted by f Engineering. g
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,.e l TABLE 3.35-4 (Cont'd) . ; i BOP SYSTDI EXPANSION N2-SUT-78 4 1 TEST EXCEPTION SINEARY ' Test Test Exceotion Condition Description 46 2 (2) Main Steam Spring Supports failed Level 2 out-of-tolerance Criteria when. measured at the Rated
. Temperature Plateau. Evaluated by Engineering and accepted.
/"
47 2 (1) Main Steam Snubber failed Level 1 Criteria. When examined at the " Return to Ambient" condition, it was found to be in contact with a beam. The support was reworked per Engineering's direction and retested satisfactorily. 48 2 (3) Main Steam Snubbers and Spring Supports were found to fail Level 2 Criteria when examined at the " Return to Ambient" condition. Obstructions existed in the Spring Clearance " Cone". Evaluated by Engineering and accepted. 49 6 (3) Feedwater Snubbers and Spring Supports- failed Level 2 Criteria when examined at Initial Ambient condition. Obstructions existed in the Swing Clearance " Cone". Evaluated and accepted by Engineering. 50 6 (1) Feedwater Snubber failed Level 1 Criteria when examined at Initial Ambient condition. Measurement fell outside of the operable range. Evaluated and accepted by Engineering. 51 6 Test Points RHS-E-48-X and RHS-E-203-Z failed Level 1 Criteria during RHS shutdown cooling operation (Loop
'A'). Evaluated and accepted by Engineering.
52 6 (17) Feedwater Spring Hangers failed Level 2 setting violations when measured at the Initial Ambient condition. Evaluated and accepted by Engineering. 53 6 (1) Residual Heat Removal Spring Hanger failed Level 2 Criteria when examined at the Rated Temperature Plateau. Spring was making hard contact with a cable tray. Evaluated and accepted by Engineering. -
]
i 54 6 (5) Residual Heat Removs1 Snubbers and Spring Hangers *' failed Level 2 Criteria when examined at Initial Ambient condition. Obstructions existed in the Swing Clearance " Cone". Evaluated and accepted by . Engineering. ,
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Mj . . TABLE 3.35-4 (Cont'd) BOP SYSTEM EKPANSION N2-SUT-78 TEST EXCEPTION S1991ARY Test Test Exception Condition Description , 55 6 (14) Residual Heat Removal' Spring Hangers failed Level 2 setting violations when measured at Initial Ambient condition. Evaluated and accepted by Engineering. 56 6 (6) Residual Heat Removal Snubbers and Spring Hangers failed Level 2 setting violations when measured at the Rated Temperature Plateau. Evaluated and accepted by Engineering. 57 6 (3) Residual Heat Removal Spring Hangers failed Level 2 sotting violations when measured at the Rated Temperature Plateau. Evaluated and accepted by Engineering. 58 6 Test Points RHS-E-48-Z and RHS-E-203-X f ailed Level 2 Criteria during RHS Shutdown Cooling Operation (Loop
'A'). Evaluated and accepted by Engineering.
59 6 (3) Residual Heat Removal Spring Hangers failed Level 2 Criteria when examined at Return to Ambient condition. Obstructions existed in the Swing Clearance " Cone". Evaluated and accepted by Engineering. 60 6 Test Points WS-E-190-Y, WS-E-440-Y and WS-E-135-Y failed Level 1 Criteria during Rated Temperature Plateau. Evaluated and accepted by Engineering. 61 6 (8) Feedwater Snubbers failed Level 2 setting violations during Rated Temperature Plateau. Evaluated and accepted by Engineering. 62 6 (1) Feedwater Spring Hanger failed Level 2 setting violation during Rated Temperature Plateau. Evaluated and accepted by Engineering. 63 6 Test Points WS-E-190-X T= Z and WS-440-Z f ailed Level 2 Criteria during Rated Temperature Plateau. Evaluated and accepted by Engineering. ,
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K I TABLE 3.35-4 (Cont'd) BOP SYSTEM EXPANSION N2-SUT-78 TEST EKCEPTION SIM1ARY Test Test' i Exception Condition Description 64 6 (1) Feedwater Snubber failed Level 2 ' Criteria when examined at the Rated Temperature Plateau. Snubber was in hard contact with Fire Protection Line. Evaluated and accepted by Engineering. Work Request was' written to move Fire Protection Line for additional clearance. 65 6 (6) Feedwater Spring Hangers failed Level 2 setting violations during Rated Temperature Plateau. Evaluated and accepted by Engineering. 66 6 Test Point ICS-135-Y failed Level 1 Criteria during RHS Sbutdown Cooling Operation (Loop . ' B ' ) . Evaluated and accepted by Engineering. 67 6 (1) Residual Heat Removal Snubber failed Level 1 setting violation during the Rated- Temperature Plateau. Evaluated and accepted by Engineering. 68 6 (8) Residual Heat Removal Snubbers and Spring dangers failed Level 2 setting violations during Rated Temperature Plateau. Evaluated and accepted by Engineering. . 69 6 (3) Residual Heat Removal and (1) Reactor Core Isolation Cooling Snubbers and Spring Hangers (Identified **) failed Level 2 setting violations during Rated Temperature condition. Evaluated and accepted by Engineering. 70 6 Scriber Plate RHS-C-105 Z Axis (RHS 'B' Loop) failed Level 2 Criteria when measured at Return to Ambient condition. Evaluated and accepted by Engineering. 11 6 Scriber Plate WS-C-145 Y Axis failed Level 1 Criteria when measured at Return to Ambient condition. Evaluated and accepted by Engineering. 72 6 (2) Residus.1 Heat Removal Snubbers and Spring Hangers failed Level 2 Criteria when examined at Return to L Ambient condition. Obstructions exist in the swing , clearance " cone". Evaluated and accepted by Engineering.
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--_______. - ______ _ - _ ~.
-l
)
I TABLE 3.35-4' (Cont'd). BOP SYSTIIM EXPANSION N2-SUT-78 f TEST EXCEPTION SINIARY Test Test Exception Condition Description 73 6 Scriber Plates WS-C-461-Y & Z, WS-C-110-X ~ & Y, WS-C-145-Z and CNM-C-124-X (Line 324) failed Level 2 Criteria. when measured' at Return to Ambient condition. Evaluated and accepted by Engineering. 74 6 Scriber plates CNM-C-124-X & Z (Line 324), CNM-C-124-X
& Z (Line 325) and CNM-C-124-X & Z (Line 326) failed Level 1 Criteria when measured at Return to Ambient condition. Evaluated and accepted by Engineering.
75 6 (8) Feedwater Pipe Whip Restraints failed Level 2 Criteria when measured at Return to Ambient condition. Evaluated and accepted by Engineering. 76 6 (6) Feedwater Snubbers and Spring Hangers failed Level 2 Criteria when examined at Return to Ambient condition. Obstructions existed in the swing clearence " cone". Evaluated and accepted by Engineering. 77 6 (1) Feedwater Pipe Whip Restraint failed -Level '2. Criteria when measured at Return to Ambient condition. Evaluated and accepted by Engineering. L
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Am _ _ _ _ _ _ - - - - - - - )
c.-- id REACTOR INTERNALS. VIBRATION MEASUREMENT _N2-SUT-79
.3.36 1 N2-SUT-79J REACTOR INTERNALS' VIBRATION MEASUREMENT.
A. OBJECTIVES To provide the data required l to verify the ; similarity i between . the reactor internals design and . the limited - valid prototype'. with respect to'. flow induced ~vib ration. . Testing is - in? accordance- with Regulatory. Guide 1.20- for the vibration measurement program for a nonprototype Category IV) Plant. 1 B. ACCEPTANCE CRITERIA hval 1 The.. peak ~ stress intensity. may exceed 10,000 psi (single amplitude) when the component is deformed in a manner corresponding to _._ one of its normal or natural modes, but the - fatigue usage factor must not exceed 1.0. Level 2 The _' peak stress intensity shall not exceed '10,000 - psi (single) amplitude) when ~ the ' component is deformed in 'a manner corresponding- to one of its normal or natural modes. This-is the low stress limit which is . suitable for sustained vibration in the reactor environment for the design life 'of the' reactor components. , C. D25CUSSION The reactor vessel intervals are instrumented with four accelerometers on the upper bolt guide ring near the top _of-the separator assembly'and four strain gauges mounted on each of the H riser braces for jet pump pairs 1-2 and 5-6~ (total of 8 strain gauges). The four accelerometers measure the tangential displacement (absolute) of the upper stud guide ring to obtain the shroud head and separator assembly vibration motion. - The strain gauges measure the strain in the riser pipe braces. Two gauges are used on each of two jet pump pairs, one at the center and one on the end of a single jet- pump bank. 'These measurements are'in the radial direction. The individual gauges on each leaf are used to measure horizontal .and vertical bending. The combination of gauges on both leaves is used to measure the in and out-of-phase vibration motion of the jet pump assemblies.
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, 4 s,' -; REACTOR INTERNALS VIBRATION ISASURFMENT
'7 i '
N2-SUT-79 b< 1 C. (Cont'd)' In-Test- Condition 3 reactor vessel intervals vibration data were-collected for three reactor conditions:
- 1. Steady state along the 60% load line at core flows of-39.2%-
(minimum flow control valve position /high speed), ,50%, c 75% - and 103% of rated. 2.- Transient data during Recirculation Pump A' trip to off'from - 73% power, 104% core flow and,. post-trip, steady state with..
. active loop B drive flows of 100%, 80% and 60%'of rated.
3 3.. Transient : data during a transfer of Recirculation Pumps A' and B from-high.to. slow speed at 63% power, 104%Lcore flow. In- Test condition 6 reactor vessel . internals vibration data were . collected for three reactor conditions:
- 1. Stead'y State along .the 100%' load line at- core flows of.
46.8% (miniman flow control' valve ' position / . high. speed),
'52.3%, 77.6% and 105.0% of rated.
- 2. Transient data during' Recirculation Pump B trip to.off; from -
- 99.2% power, 103.6% core flow and post-trip steady state <
with active Loop A drive' flow of 100% of rated.
- 3. Transient data during: a transfer of Recirculation Pumps A and B from high to low. speed (as part of a' Generator Load Rejection).at 99.5% power, 104.2% core flow.
In Test condition 3- the shroud head vibration measurements :were all within the Acceptance' Criteria. The strain gauge measurements of jet pump ' riser brace vibration met- the Acceptance Criteria for jet pump ' pair 1-2 but not for pair 5-6. Strain gauges S5 and S6 exceeded the Level 2 criteria (10,000 psi) during steady state operation at minimum flow control. valve position and at 48% core flow. In Test Condition 6 the shroud head vibration measurements were all within the Acceptance Criteria. The strain. gauge measurements of jet pump riser brace vibration met- the Acceptance Criteria for jet pump pair 1-2 but not for pair 5-6. Strain gauges 5 and 6 exceeded the Level 2 Criteria during steady . state operation at minimum flow control valve position and at B pump off, A pump at maximum flow. S5 also exceeded the .' Level 2 Criteria at steady state conditions at 52% flow. m
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' REACTOR .' INTERNALS ' VIBRATION MEASUREMENT 6 -
.N2-SUT-79 T C. (Cont ' d):
Although ~ the ' S5 ' and S6 : results : exceed the Level 2. ' Acceptance
'Criteriai.it is not , known whother: these two, sensor readings:
. violate tho' Level.1 acceptance criteria because making . this determination ~ requires- extensive analysis which . cannot - be performed on site. Based on past Lexperience from, similar s
programs, these sensors are ' expected - to : meet :the :Leveli i criteria following further . analysis., ' All sensors. are within~ criteria for core : flows greaterf than j 60% ' rated. Preliminary calculations show that' operations at-low flow'can continue for a total . of at least three yearsL without the jet pump riser brace: incurring. unacceptable usage. Therefore, .a log.:'is~ being maintained of the time the reactor recirculation pumps operate at high speed with core flow is.below 50% rated. Since. attempts are still continuing to refine the calculations, .further lengthening of. the operating time is still possible. The final " report is expected by July 15, 1988. . The maximum vibration stress. amplitudes or the : dominant vibration response for the accelerometers and strain ' gauges are shown on Table 3. 36-l '. The maximum allowable peak stress -! Jamplitude is the Level = 2 Criterion . for the reactor' component material.' During the recirculation pump high to . low speed transfer . in' TC . 3, both recirculation pumps inadvertently tripped to off causing core flow to decrease to natural ' circulation. ' An evaluation determined: that the vibration measurements' taken during Lthe-inadvertent trip were ' acceptable. The original intent of the
' Internals Vibration ' Test e was to perform ~ a two pump trip to natural circulation from 100% flow- while on the 60% load line. ~
As a result of similar BWR startup tests, it was decided that an acceptable substitute to this test would be a high to' low pump speed transfer from the same conditions. Therefore, the fact that a - two pump trip to natural circulation was inadvertently performed in lieu of the alternate method (i.e., two pump. transfer) is considered acceptable. Test Exceptions and their resolutions are summarized in Table 3.36-2. I l
~
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.I Ig LE 3.36-1
,. s REACTOR INTERNAL 6' VIBRATIGt MEASUREMENT N2-SUT .I i MAXIMUM VIBRATION STRESS -l l Test No./ l Comp. Condition Sensor Amplitude Freati=nev 1 Criteria Comunents (p-P)' (Hz)- Jet Pump TP1' . .
.Almer Brace (Min Flow) SS 32.9 ue 8-30 HZ. 671 Total =137%
87.8 ue 30-250 H2 701 TC 3 Shroud TP4 Mand (A991 B991) A1 15.2 mila 8.2'H2 191 Total =61%~ 7.4 alla 12.5 HZ' 421 Jet Pump TP1 R4ser' Brace ~'(Min Flow) SS' 31.3 ue B-30 H2 641~ Total =124% 75.2 ue 28-256 HZ 601 TC 6 TP6 50 ye- 8-30 HZ 68% Total =120% (A Maw. B Off) S6 75 um 28-256 H2 521
~
Shroud. TP4 Head (A1001.B 1001) A1 50 mila 0-45 HZ 631 Total = 63%
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TARLE~3.36-2' .l
' REACTOR INTERNALS VIBRATION MEASUREMENT j N2-SUT-79:
TE.T ExcErrioM so mRr.
' Test . Test
~
Excention- ConM tion ' Description-
~1 ~3 Sensor S5 on ' the . riser ~ brace ; for. Jetpumps 5- A 6:
exceeds .the Level 2 Criteria at 50% steady state flow conditions. . An'. analysis has beeni performed. by ' GE ' 'I i Engineering '(GE letter - NMPC-722) that concludes that-no adverse effects on the plant; should; result for.a d total of 500 hours operation at minimum flow with fast
> ' speed 1 recirculation pumps. This time is. adequate to finish the test program and ' cover. the -commercial operating time until the final analysis . is complete.
.In tho' interim pump operating hours at fast' speed and ~
less than 50% core flow are being recorded. 2 3 The Test Procedure was written . to obtain vibration data. during a Recirculation Pump'~ Transfer to slow-speed. . The actual. event monitored'was a Recirculation Pump Trip to natural. circulation. GE Engineering determined that this ' was acceptable' as, the ' Dual ~ Pump : Trip was the more severe transient. 3 6 Sensors SS and S6 exceed the ' Level 2 Criteria at Minimum Flow, 50% flow and A Maximum, B Off on the
'100% load line.' An analysis has' been performed' by GE '
Engineering (GE Letter NMPC-803) that concludes that no adverse effects on the plant should result for at-least 3 years of operation ' at minimum flow with fast speed recirculation pumps. This time is adequate to finish the test program and cover the commercini operating time until the final analysis is complete. i- In the interim, pump operating hours at f ast~ speed and i less than 50% core flow are being recorded. The final report is expected by July 15, 1988. - 1 J
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- REACTOR BUILDING EMERGENCY RECIRCULATIGi VENTIMTION >
SYSTEM PERFORMANCE N2-SUT-80 t 3.37 N2-SUT-80 llMERGENCY RECIRCULATION VENTILATION A. OBJECTIVES . 1
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The purpose of this . test was to verify the capability 'of ' the Reactor Building Emergency Recirculation Ventilation . System to maintain the required Reactor- Building area . temperatures within design limits under postulated accident conditions. B. ACCEPTANCE CRITERIA Level 1
- 1. All critic'al Reactor Building area temperatures measured shall not exceed the design limits specified in Final Safety' Analysis Report (FSAR) Table 9.4-1.
Level 2
- 1. Evaluation of test data shall demonstrate that critical Reactor Building area temperatures will remain below the design limits specified in Final Saf ety ' Analysis " Report '
(FSAR) Table 9.4 -1 under design basis conditions. C. DISCUSSION > At Steady - State conditions during . Test Condition 6, the Standby Gas Treatment System was placed in operation, normal' Reactor Building Heating and Ventilation Systems were shutdown per Operating Procedure, and the Emergency Recirculation Ventilation System Auto-Started. Reactor Building temperatures were allowed to stabilize and area . temperature and Reactor Building l Ventilation System parameter data were collected. A total of twenty-eight (28) area temperatures were found to be below normal design limits; however, evaluation of the areas ! (Ref. SSM No. N063-0326) indicated no adverse affect upon l equipment located in these areas, no violation of. GDC-51 criteria, and thus the ' low temperatures were acceptable. Overall, it is concluded that the Reactor Building Emergency Recirculation System is capable of performing its design function and maintaining required areas within design limits under design basis conditions (Ref. SSM No. N063-0323). , Test Exceptions are summarized on Table 3.37-1. .g,
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M TI 3.37-1: REACTOR BUILDING !!MERGENCY RECIRCULATION VENTILATION SYSTEM PERFORMANCE N2-SUT-80 TEST EXCEPTION SUPMARY Test Test-r.weention r%= die 4an Descrint4a-
. -1 6 Twentywight .(28) area temperatures .were found below the design minimum of 70'F ' specified in FStA . Table 9.4-1 (Level 1 Acceptance- Criteria). . Per Site Services ' Memorandum (SSM)' No. N063-0326, lower than ,
70*F temperatures in the specified-l areas are acceptable. The temperatures were experienced in the Auxiliary Bays . and High Pressure Core Spray (IPCS)' Pump Room and neither violate GDC-51 Criteria -nor adversely impact equipment located in the areas. .
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i DRYWELL PENETRATION COOLING N2-SUT-81 3.38. N2-SUT-81 DRYWELL PENETRATION COOLING- < l A.- OBJECTIVE Demonstrate the capability of the Dryvell " Thermally' Hot-High Energy" Penetrations, to maintain the surrounding concrete below i its design temperature limits. l
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i B. ACCEPTANCE CRITERIA Level 1 The temperature measured four inches from the wall / penetration outer collar on the wall insert sleeve, shall not exceed the values predicted to cause the surrounding concrete temperature to exceed 200*F. , Penetration Predicted Value Main Steam 1 201*F Feedwater 1 206*F Reactor Water Cleanup (RWCU) I 185*F C. DISCUSSION The Penetration Cooling Test, N2-SUT-81, was performed during Test Conditions Heatup, 3 and 6. During Test Condition Heatup, data was collected at the following Reactor Recirculation Pump suction temperatures, as the plant came up to rated conditions: 256*F, 365'F, 465'F, and 520'F. During Test Condition 3, data i was collected at a Reactor Recirculation Pump suction temperature of 540*F (at rated coolant temperature, 533' i i 25'F). During Test Condition 6, data was collected at a Reactor , Recirculation Pump suction temperature of 532'F. ! To perform this test temporary thermocouple were installed on the piping penetrations per the direction of Niagara Mohawk Engineering. The thermocouple were wired up to a temporary data-logger located in an accessible area of the secondary containment allowing temperatures to be monitored at any time. ;
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l , v. l **' L L l- - DRYWELL PENETRATION COOLING N2-SUT-81' 1 C. '(Cont'd)- Temperature data' collected during Test Condition Heatup showed that penetration sleeve temperatures were reading well below the predicted critical . values., Reactor . -Feedwater . Penetration- . Temperatures were considerably. lower- then . the ' other penetration temperatures because of . the absence of Feedwater heating and RWCU return to '.Feedwater Flow.. 'During TC3, similar results were - seen.; _ The temperatures of - the,' penetrations ' were again . well below the predicted - values. (This time - the Feedwater and RWCU ' < systems were operating at normal conditions). Temperature data collected ' during' Test Condition 6 showed that penetration sleeve temperatures were reading ' well below. _the' predicted critical . values. Reactor ' Feedwater, Reactor " Water Cleanup, and the Main Steam Systems were all in full operation with the plant operating at 97.7% power when data was collected. - See Table 3.38-1 for Penetration Cooling Test Results.
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