ML20207S435
| ML20207S435 | |
| Person / Time | |
|---|---|
| Site: | Hope Creek  |
| Issue date: | 03/31/1987 |
| From: | Farschon M Public Service Enterprise Group |
| To: | |
| Shared Package | |
| ML20207S426 | List: |
| References | |
| NUDOCS 8703190446 | |
| Download: ML20207S435 (202) | |
Text
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l ATTAC HHE NT I Attachment to the PSEs.G to NRC Letter dated March 16 . 1987 O ,
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0703190446 070316 ,
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- PDR ADOCK 05000354 J
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PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK GENERATING STATION POWER ASCENSION TEST PROGRAM STARTUP REPORT HARCH, 1987 l
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Approved By:
Power I N.Ascension -- ----------_---
Department Manager t
i' Power Ascension Technical Director l ----- .........--
HCGS General Manager 1
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TABLE OF CONTENTS O PAGE LIST OF TABLES i
. LIST OF FIGURES iv ABSTRACT v
- 1. 0 INTRODUCTION 1-1
- 2. 0 PLANT DESCRIPTION 2-1
- 3. 0 POWER ASCENSION TEST PROGRAM DESCRIPTION 3-1
- 4. 0
SUMMARY
OF POWER ASCENSION TEST PROGRAM 4-1
- 5. 0
SUMMARY
OF TEST RESULTS 5-1 5.1 Test Index 5-2
- 5. 2 Results 5-4
- 6. 0 ACCELERATED TEST PROGRAM 6-1 O
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l LIST OF TABLES 2.0-1 Itope Creek Plant Parameters 2-2 3.3-1 Test Condition ( TC) Region Definitions 3-8 4.2-1 Test Performance Matrix 4-5 l 4.3 Power Ascension Testing Scram Listing 4-7 l 4.4-1 Milestone Summary -
4-8 I 4.4-2 Test Program Chronology 4-9 5,2.1-1 WateF Chemistry Test Results 5-7 5.2.1-2 Resolution of Chemical and Radiochemical Test Deficiencies 5-9 5.2.1-3 Gaseous and Liquid Errluent Test Results at TC-6 5-11 5.2.1-4 Resolution of Process Radiation Monitoring System Problems 5-11
. 5.2.1-5 Integrated Reactor Chemistry Systems l Performance Data 5-12 5.2.5-1 Scram Times of Four Selected CRDs During Planned Scrams 5-26 5.2.10-1 Thermal Limit Comparisons in TC-3 5-40 t
5.2.10-2 Thermal Limit Comparisons in TC-6 5-40 l
5.2.11-1 Summary of RCIC System Testing 5-44 5.2.12-1 Summary of HPCI System Testing 5-47 5.2.14.1 NSSS Piping Thermal Expansion Acceptance Criteria /Results in TC-6 5-56 5.2.14.2 BOP Piping Thermal Expanston Test Conditions 5-58 5.2.16-1 Steam Production Test Results 5-64 i
5.2.17-1 Pressure Regulator Test Results 5-68 5.2.17-2 Pressure Regulator Adjustment Settings 5-69 0 .
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LIST OF T ABLES ( Cont' d)
PAGE 5.2.21-1 Haximum FW Runout Capability Results 5-78 5.2.22-1 Turbine Valve Surveillance Test Results 5-82 5.2.25-1 Full Power Generator Load Rejection Test at TC-6 5-94 5.2.30-1 Summary of Recirculation System Flow Calibration Results 5-106 5.2.30-2 Summary of Recirculation MG Set Electrical and Mechanical Stop Results 5-106 5.2.32-1 NSSS Steady-State Operational Vibration Limits 5-116 5.2.32-2 NSSS Transient Vibration Limits ( TSVC) 5-118 5.2.32.3 NSSS Transient Vibration Limits at Main Steam Safety Relier Valve Blow ( RV1) 5-119 5.2.32-4 NSSS Transient Vibration Limits -
Preop Startup and Pump Trip 5-120 5.2.32-5 BOP Dynamic Response Limits for Hain Steam Piping, outside the Drywell, During Main Steam Stop/. Control Valves Closures at Rated Power 5-121 5.2.32-6 BOP Dynamic Response Li mi t s 5-122 5,2.32-7 BOP Dynamic Response Limits for Saf ety/ Relier Valve Actuation at Normal Operating Condition 5-123 5.2.32-8 80P Dynamic Response Limits for HPCI Turbine Steam Supply During HPCI Turbine Trip at Normal Steam Supply Flow 5-123 5.2.32-9 BOP Operating Vibration Criterion C and D 5-124 5.2.J2-10 NSSS Hann Steam Steady State Vibration Data at 1001 Steam Flow 5-125 5.2.32-11 NSSS Rectreulation System Steady State V1bratton Data at 1001 Power 5-126 9
5.2.33-1 RWCU Normal Mode Performance Data 5-129 5.2.33-2 RWCU Blowdown Mode Performance Data 5-129 5.2.34-1 Heat Exchanger Capaci ty ( MBtu/ hr)
Suppression Pool Cooling Mode 5-131 5.2.34-2 Heat Exchanger Capacity ( MBtu/ hr)
Shutdown Cooling Mode 5-132 5.2.36-1 Gaseous Radweste System Results at Rated Power 5-137 5.2.32-12 NSSS Recirculation System and Main Steam Piping Dynamic Response During Full Power Generator Load Rejection Test 5-127 5.2.37-1 SACS Heat Removal Capacity ( MBtu/HR) 5-140 5.2.38-1 Preliminary Results From December 20 1986 Test - Comparison of Measured vs Predicted -
St rains ( micro i n. / in. ) 5-144 5.2.38-2 Preliminary Results From December 20, 1986 Test -
Maximum Measured Accelerations ( g) 5-145 5.2.46-1 Accoustic Monitor Response to Manual SRV Openings 5-160 b
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6.9-1 Accelerated Test Program Results 6-7 i
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v LIST OF FIGURES
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PAGE 3.3-1 Operational Power / Flow Hap 3-7 4.1-1 Hope Creek Power Ascension Performance 4-2 Schedule 4.1-2 Hope Creek Fuel Load Performance Schedule 4-3 '
4.2-1 Power Ascansion Test Program Power / Pressure Histogram 4-4 5,2.3-1 Fuel Loading Diagram 5-17 6.1-1 Power Ascension Department 6-8 6.2-1 Shift Support Organization 6-9 0
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ABSTRACT O The Hope Creek Generating Station power Ascension Test Program began on April 15, 1986 with commencement of fuel loading, and concluded on December 16, 1986 with the completion of the 100 Hour Warranty Demonstration Run. The test program included static and dynamic performance tests of the reactor, turbine-generator,. related auxiliary systems systems.
and balance of plant Test results were compared where deviations to acceptance criteria, and were identified, resolution or corrective actions were implemented. An a c c e l.o ra t e d test program facilitated completion of a high quality Power Program in 245 days, Ascension Test Reactor which set a record for a Boiling Water era.
( BWR) plant startup in the post-Three Mile Island ( TMI)
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- 1. 0 INTRODUCTION l
This report summarizes the Power Ascension Test Program l performed at the Hope Creek Generating Station ( HCGS) . The report satisfies requirements of the plant Technical Specifications, paragraphs 6.9.1.1 through 6.9.1.3, and i Regulatory Guide 1.16 Revision 4 Section C.1.a.
l The HCGS Power Ascension Test Program included pre-fuel load ac t i vi t i e s, fuel loading, heatup and power ascension testing, and the warranty demonstration. 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 14.2.12.3 in the HCGS Final Safety Analysis Report
( FS AR) , and Regulatory Guides 1.68, 1.68.1 and 1.68.2.
Section 5. 0,
SUMMARY
OF TEST RESULTS, presents a summary description of each test, including the measured values of the operating parameters obtained during the test, and a comparison of these values with specific test acceptance criteria. Corrective actions that were required to obtain satisfactory operation are also described.
Other sections of the report provide descriptions of the Hope Creek Generating Station and the Power Ascension Test Program, and a summary of the conduct of the Program. The last section describes the accelerated test program, and the steps taken to obtain a high quality test program with a reduced schedule duration.
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I 2. 0 PLANT DESCRIPTION f-s The Hope Creek Generating Station,
( )g Electric and Gas Company and Atlanticowned by Publi: Service Electric Company, ts a one-unit nuclear power plant.
southern part of Artificial Island on The theunit is bank east located of on the Delaware River in Lower Alloways Creek the Township, Salem County, New Jersey.
is shared with the The station is on a 700 acre site that two-unit nuclear Salem Generating Station.
The HCGS nuclear steam supply system is a General BWR/4 Electric designed product line direct-cycle boiling water reactor ( BWR) to operate at a rated core thermal power of 3293 MW t. The turbine-generator, also supplied by General l Electric Company, pro vi d e s a gross electrical i output or approximately 1123 MWo. Other principal plant parameters are presented in Table 2.0-1.
Tne primary containment is a drywell/ pressure type designated as suppression Mark I. It is comprised of a steel shell, enclosed in reinforced concrete, to a torus-type steel suppression chamber. and interconnected The architect / engineer l
, Corporation. and constructor was Bechtel Power 1
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TABLE 2.0-1 HOPE CREEK PLANT PARAMETERS lf PARAMETER VALUE Rated Power ( MWt) 3293 Rated Core Flow ( Hlb / hr) 100 Reactor Dome Pressure ( psia) 1020 Rated Feedwater Temperature ( Deq. F) 420 Total Steam Flow ( Hlb /hr) 14.159 Vessel Diameter'(in) 251 Total Number or Jet Pumps 20 Core Operating Strategy Control Cell Core i
Number of Control Rods 185 Number of Fuel Bundles 764 Fuel Type 8 x8 ( Barrier)
Core Active Fuel Length ( in) 150 Cladding Thickness (in) 0.032 Channel Tht ekness ( in) 0.080 HCPR Operating Limit 1.20 Maximum L HG R ( K W / t' t ) 13.4 Turbine Control Valve Mode Full Arc Turbine Bypass Valve Capacity ( % NBR) 25 Reiter Valve Capacity ( % NBR) 88.3 Number of Reiter Valves 14 Rectreulation Flow Control Hode Variable Speed N/G Sets 9
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- 3. 0 POWER ASCENSION TEST PROGRAM DESCRIPTION 3.1 Overview The Hope Creek Generating Station Power Ascension Test Program was established to administrative 1y and operationally control all testing activities commencing with fuel loading, and ending with the rated power warranty run. The test program applied to all structures, systems and components required to conduct normal commercial operation, and was in compliance with all commitments made in the Final Safety Analysis Report.
To facilitate conduct of the test program, a unique station department was established. Under the direction of this department ( the Power Ascension Department ),
programs were implemented to identify and correct potential startup problems, reduce and simplify test procedures, and staff this unique organization to implement this program ( see section 6.0 ).
- 3. 2 Inst _Procram Scope
,6 The Power Ascension Test Program was designed to be in compliance with commitments made in the Final Safety Analysis Report. Specifically, the program performed the startup testing identified in Section 14.2.12.2 of
() the FSAR, and additional testing required to commitments and exceptions made to Regulatory Guide address 1.68 Revision 2 Initial Test Programs for Water-Cooled Nuclear Power Plants. The test program also addressed FSAR Chapter 1 commitments and exceptions to Reg. Guide 1.68.1, Revision 1, Preoperational and Initial Startup Testing of Feedwater and Condensate Systems for Boiling Water Reactor Power Plants and Reg.
Guide 1,68.2, Revision 1 Initial Startup Test Program to Demonstrate Remote Shutdown Capability for Water-Cooled Nuclear Power Plants. The relationship between these regulatory requirements.and power ascension testing to be performed, were documented in a power ascension test matrix.
All changes to the test program as described in the FSAR were reviewed, approved and reported in accordance with the provisions of License Condition 2. C (10).
The remaining FSAR commitments were incorporated in the test program, and were identified in the reference section of each test procedure. Closing Document commitments assigned to the Power Ascension Test Program by the HCGS Technical Department were also incorporated and identified in the test procedures.
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The acceptance criteria for Nuclear Steam Supply System
( HSSS) testing were given in FS AR Section 14.2.12.3, h the General Electric supplied Startup Test Specification ( MPL #23 A4137, TDR #10 8 5 5 - NO- A 41 - 3 610 -
45( 1) -2) , Field Doviation Disposition Requests ( FDDRs) written on the Startup Test Specifications, and the Transient Safety Analysis Design Report ( TS ADR) (MPL
- A41-5010).
The acceptance criteria for Balance of Plant ( BOP)
Systems testing, including thermal expansion and vibration measurements of ASME Section III Nuclear Class 1,2,3 and ANSI B31.1 piping, were given in FSAR Section 14.2.12.3 and Bechtel Power Corporation specifications 10855-P-421(Q) Rev. 5, 108 5 5-P-423( Q)
Rev. 4, 10 8 5 5-1 -P-410( Q) Rev. 17, and 10855-1-P-411 i' Rev. 15. For some BOP tests, the acceptance criteria were obtained from PSE&G Engineering Instructions.
- 3. 3 Test P1_a.teau The Power Ascension Test Program was divided into six #
test plateaus, with each plateau characterized by the type of testing, and plant operating conditions.
3.3.1 Open-Vessel Plateau This phase included all pre-fuel load, fuel load,and pre-heatup tests.
3.3.2 Heatup Plateau This phase included initial criticality and related tests, initial reactor heatup to rated temperature and pressure, and testing up to and including 5 percent rated reactor thermal power. Turbine-generator testing, including synchronization to the electrical grid, was performed at (10% power in this test plateau.
The following test plateaus are more specifically defined by test conditions, which are regions on the Operational Power / Flow Hap, where most power ascension testing was performed. Figure 3.3-1 and Table 3.3-1 identify each of the six test conditions.
3.3.3 Test Condition 1 Plateau Plant conditions could not exceed those defined as Test Condition 1.
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/'" 3.3.4 Test Condition 2 Plateau '
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Plant conditions could not- exceed those defined as Test Condition 2.
3.3.5 Test Condition 3 Plateau Plant conditions could not exceed those defined as Test Condition 3.
3.3.6 100% Rod Line Plateau Testing at plant conditions up to and including 100 percent rated power ( Test Conditions 4, 5 and 6). The warranty demonstration was included as a part of Test Condition 6 testing.
3.3.7 Test Plateau Review A test plateau review was conducted after the completion of testing in each test plateau prior to receiving authorization to commence ',
power ascension testing in the next plateau.
The review included all test results, deficiency reports, on-the-spot procedure
() changes, review and occurrence was performed by the list Power items.
Ascension The Manager, the Station Operations Review Committee ( SORC) and the HCGS General Manager. The General Manager authorized proceeding to the next test plateau.
- 3. 4 Test Acceptance Criteria t Test procedure acceptance criteria were provided by the I
FSAR, General Electric Startup Test Specifications, TSADR, Bechtel Specifications and PSE&G Engineering Instructions ( see Section 3.2). These criteria result from several considerations such as safety analysis assumptions, engineering expectations and contractual commitments. There were three levels of criteria l identified for the testing, as discussed in the following paragraphs. Not all levels of criteria were applicable to all tests.
3.4.1 Level i Level 1 criteria include the values of process variables assigned in the design of the plant and equipment. If a Level 1 acceptance criterion was not s a t i s f i e'd , the j
plant was placed in a hold condition that was
! judged to be satisfactory and safe, based on
! prior testing. Plant operation was also 3-3
limited such that dependence was not placed h on any safety feature or other limiting feature which was proven unsatisfactory in the test. Testing consistent with the hold condition could be continued or initiated.
Following resolution of the Level 1 acceptance criterion-failure, the applicable test portion was repeated to verify that the criterion was satisfied.
3.4.2 Level 2 The limits stated in this category were usually associated with expectations , of system transient performance, and whose characteristics could be improved by equipment adjustments. If a Level 2 acceptance criterion was not satisfied, a determination was made concerning the continuation of testing at the current test plateau.
Following resolution of the failure, the ,
applicable test portion was repeated to verify that all Level 2 requirements were satisfied. If these criteria could not be satisfied, an engineering evaluation to
" accept as is" was processed ( see section 3.5.3 ).
3.4.3 Level 3 The numerical limits stated in this category were associated with expectations of individual component or inner control loop transient performance. Level 3 performance was viewed as highly desirable rather than required to be satisfied. If Level 3 performance was not satisfied, plant operating or startup test plans were not necessarily altered. If all Level 1 and Level 2 criteria were satisfied, then it was not required to repeat the test to satisfy Level 3 criteria.
- 3. 5 Conduct of Testino The conduct of the Power Ascension Test Program was governed by all HCGS Station Administrative Procedures, and was specifically described in S A- AP. Z Z -0 36( Q) ,
Power Ascension Test Program.
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3.5.1 Review and Approval
( The Station Operations Re vi e w Committee
( ( SORC) , a permanent plant committee, was responsible for reviewing test procedures, :
changes, results, deficiencies, plant holds, '
and test plateau escalation, and recommending approval of these items as appropriate during the Power Ascension Test Program. The Power Ascension Manager approved test results, and resolutions and subsequent actions of all result deficiencies. The HCGS General Manager approved initiation of the test program, escalation in power to the next test plateau, and plant test hold conditions.
A Technical Review Board ( TRB) was developed to review test procedures and test results prior to the SORC reviews. Prior to the TRB review, each results package was reviewed by an Independent Reviewer ( I R) , QA re pre s e n t a t i ve and other personnel as appropriate.
3.5.2 Test Procedures i
Power ascension test procedures were devoloped to meet the requirements of the FSAR, 1
O- regulatory guides and vendor technical documents and topical reports as noted in 1
Section 3.2 of this report.
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' There were three types of procedures:
~ Master Sequencer. Test Plateau Sequencer, and Startup Test. The Master Sequencer tracked the progression of the Test Plateau Sequencers which in turn controlled the testing at each test plateau.
A change to a power ascension procedure was ,
accomplished as an obvious typographical error correction, on-the-spot change, or procedure r e vi s i on. A problem or irregularity encountered during a test was documented by an Occurrence List ( OL) entry which also required a proposed d.isposition to be identified and implemented as appropriate.
3.5.3 Result Deficiency A test result which did not satisfy an acceptance criterion was identified as a result deficiency, and was documented on a i
[~' Result Deficiency Form ( RDF) . Also, resolution of the deficiency was documented 3 .5
on the RDF and i mpl e me n t e d after r e vi e w by SORC and approval by the Power Ascension Manager. Following resolution, the applicable test section( s) were re-performed to verify that the acceptance criterion was satisfied, or accepted as-is, as appropriate.
At the end of the test program, all RDFs were closed and all future test responsibilities were transferred to the HCGS Technical Department.
3.5.4 Test Data Test procedure data were obtained primarily from plant instrumentation ( recorders, meters, Control Room Information Display Sys t em) , the plant process computer, and the General Electric Transient Analysis Recording System-1 ( GET ARS-1 ) . Steady-state data were obtained from all sources, whereas GETARS-1 usually pr ovi d e d transient data.
The GETARS-1 high speed digital data acquisition system can directly digitize measurements every millisecond, allowing data to be sampled and recorded in real time at 1000 samples per second per channel.
Approximately 570 channels of a possible 4096 channels were used to monitor analog and i digital plant input signals. In addition to the GETARS used for data recording, a second GETARS was used on-site to perform data r eA uc t i o n, statistical analysis, and scram time analysis.
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CAVITATION
/ e i e r , e R EG6CN 0 to 20 30 4C SO 80 70 80 90 100 tto j PGRCENf CCRE PLOW l
i Figure 3.3-1. Operational Power / Flow Map 3-7
Table 3.3-1 TEST CONDITION ( TC) REGION DEFINITIONS Test Condition No. Power-Flow Hao Recion and Notes 1
Before or after main generator synchronization between 5% and 20%
thermal power and wi t hi n -0, +10% of M-G Set minimum operating speed line in Local Manual mode.
2 After main generator synchronization between the 45% and 75% power rod lines, between M-G Set minimum speeds for Local Manual and Master Manual modes, the lower power corner must be less than bypass valve capacity.
3 Between the 45% and 75% power rod lines, core flow between 80% and 100% of its rated value.
4 On the natural circulation core flow line wi t hi n +0, -20% of the intersection with the 100% power rod line.
5 Within +0, -5% of the 100% power rod line, wi t hi n +0, -5% of the minimum M-G Set speed for Master Manual mode, l
Recirculation System engaged in Master Manual mode only.
6 Within l
+0, -5% of rated 100% power.
within +0, -5% of rated 100% core flow rate.
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- 4. 0 SUMMARI 0F POWER ASCENSION TEST PROGRAM
(s 4.1 Schedule Summary The Hope Creek Generating Station Power Ascension Test Program began on April 15, 1986 with the commencement of fuel loading, and concluded on December 16, 1986 with the {
completion of the 100 Hour Demonstration Run.
The Power Ascension Test Program was completed in 245 days (35 weeks). The performance schedule consisted of 142 days of plant operation, and 103 days of outage time. This schedule was 26 days less than for any other domestic BWR startup in the past 12 years.
The overall power ascension performance schedule'and the fuel load performance schedule, are shown in Figures 4.1-1 and 4.1-2, re s pe c t i ve l y.
- 4. 2 Startuo Test Performance Dates A
histogram of the power generation history during the test program is given in Figure 4.2-1. The completion dates of all tests performed in the various test conditions are gi ve n in Table 4.2-1.
- 4. 3 Startuo Test Procram Scram History O. Sixteen scrams occurred during the test prog r am: 5 planned scrams, and 11 unplanned scrams. This compares well with the industry average of 21 scrams during startup testing.
Table 4.3-1 provides a brief description of each scram
, including the date, cause, and the recovery time.
- 4. 4 Milestone Summary and Startuo Test Procram Chronolocy A Milestone Summary and a Power Ascension Test Program chronology are given in Tables 4.4-1 and 4.4-2, respectively.
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Figure 84.1-1
! HOPE CREEK POWER ASCENSION PERFORMANCE SCHEDULE s '.
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Figure 4. J - 1 i
l POWER ASCENSION TEST PROGRAM POWER / PRESSURE HISTOGRAM r.. . o
- 1 ..c,aa i it .ma.im.i ti. .seoi.e en. .r un. pro.ies
- Screa 92 (BaICS15-093 IItate Generator Fieldt escrea O1 I&PRIB *E" Upecele spikell2. Scras 810 (Ope changeout of egg a IChamael "S*g RFP "B* to "C" caused RFV los esigh Osygen Coacentration la SpV 11. level trip
- 2. Screa S4 IIISIT - SPS Chommell Screa $11 - 2nd pleased screa .r'M7
- 3. esecondary Ceedensate Pumpe INie 14. Unit outage tresolve LOF, IstC/AIT 1 ,
yles Valweel Frebleme . and LLRT action itemel , .". .TM i
se *BCIC Iseperable 15. For 15 heure. problems occused ,.3 l l j',; '
- 4. screa es asas saasteel *e 888 **tectore. Case, ues ..a .h' e
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S. screa 94 Earpose Valve opeseel FSVS veet faae ee g i' ,g. l-A 8" screa em La**1 3 16. Scram 012 - 3rd planned scrar , V)**
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8 6. scram 81 Esec backup power ts11e417. Screa $13 tatt test bos wiring during IC-FT.CE-0818 problem. scram om Level 3D }. ,- *.! fl l 'sm 8.:
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- 7. Drywell cast Outsee 89. Screa 914 - while pertorslag 377-242 , . h )l {[';;j
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Table 4. 2-1 TEST PERFORMANCE MATRII (V}
OPEN VESSEL HEATUP TC-1
---_------.__--._-_-_.---- ---........... ........___________________TC-2 _ ________
FSAR HCCS FIELD FSAR RCGS FIELD FSAR HCGS FIELD NO. NO. COMPL N O.
FSAR RCGS FIELD NO. COMPL NO. NO. COMPL NO. COMPL
_-______.._______________._____.___________________________NO. ______________.
1 011 ( 4 /15) 1 012 (7/26) 1 013 (8/21) 1 017 (9/11) 3 031 ( 3/25) 017 (7/26) 019 (8/23) 5 054 (9/12) 032 (4/27) 018 (6/18) 5 033 (4/28) 054 (8/23) 8 101 ( 9/07) 2 021 ( 7/30) 9 112 (8/21) 103 (8/31) 5 051 ( 4 /11) 4 041 ( 6/29) 10 122 (8/21) 051 ( 4/28) "
10 122 (9/09) 5 052 (7/13) 11 133 (8/18) 14 162 (9/08) 052 (4/28) 052 (7/16) 12 142 (8/12) 17 191 ( 9/09) 053 (4/28) 055 (7/23) 142 (8/14) 20 223 (9/11) 6 061 ( 4/27) 056 (7/23) 144 (8/20) 21 231 (9/11) 11 131 ( 4 /19) 6 062 (6/28) 13 151 ( 8/20) 15 235 (9/11) 172 (4/21) 064 ( 6/28) 151 ( 8 /14 ) 24 261 ( 9 /11) 173 (4/30) 8 101 ( 7 / 01 )
39 15 172 (8/26) 24 262 (9/12) 175 (5/23) 44 102 (7/01) 39 175 (8/05) 25 272 (9/11) 773 (4/26) 9 45 til ( 7/22) 39 176 (8/22) 274 (9/02) 791 ( 5 /14) 10 121 ( 7/08) 17 191 ( 8/22) 28
-- 303 (9/11) 002 (6/06) 12 141 ( 7/10) 20 221 ( 8/22) 30 311 ( 9 /12) 141 ( 7/23) 223 (8/20) 31 331 ( 9 /05) f 141 ( 8 / 01 ) 21 236 (8/15) 332 (9/06) 142 (7/26) 23 251 ( 8/20) 341 ( 9 /11 )
144 (7/30) 24 261 ( 8/22) 341 ( 9/12) 145 (7/26) 262 (8/23) 343 (9/12) 145 (8/01) 26 281 ( 8/23) 34 722 (9/12) 13 151 ( 7/30) 31 341 ( 8/13) 723 (9/12) 14 162 (7/25) 344 (8/22) 721 ( 9/08) 15 172 (7/08) 341 ( 8/23) 35 741 ( 9/08) 172 (7/18) 341 (8/21) 40 761 ( 9/11) 173 (7/17) 32 702 (8/13) 41 774 ( 9/08) 39 175 (7/08) 34 721 ( 8 /15) 43 715 (9/06) 175 (7/11) 723 (8/23) 45 791 ( 9/02) 175 (7/17) 724 (8/15) 791 ( 9 /11) 21 236 (7/10) 35 741 ( 8/24) 791 ( 9/12) 23 251 ( 7/22) 43 715 (8/13) 46 792 (9/11) 31 332 (7/17) 44 771 ( 8 /15) 792 (9/03) 334 (7/23) 46 792 (8/19) 792 (9/09) 32 701 ( 7/26) 47 793 (8/22) 792 (8/28) 34 721 ( 7/09) --
004 ( 8/27) 792 (8/27) 721 ( 7 /16) 47 793 (9/11) 721 ( 7 /17) 793 (9/12) 43 715 (7/17) --
005 (9/16) 44 772 (8/01) 773 (7/21) 45 791 ( 7 /17) 1
[T --
003 (8/05) 3 V s
4-5
Table 4. 2-1 TEST PERFORM ANCE M ATRII ( Cont' d)
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-c. - . . - . .-
l TADLE 4. 3-1 PORER ASCENSION TESTING SCRAM LISTING
[/)
\_- RECOVERY TIME / RECOVERY TIME /
SCRAM # DAY / TIME CAUSE OF SCRAM DAY TO S/U TO CRITICAL 1 6/29/86 1310 IRM ranging error 6/29/86 1850 6/2 /86 2212 Unplanned <5.75 hrs) <3.25 hrs) 2 6/30/86 1652 Manual scram - RMCS inoperable 7/01/86 1547 7/01/86 1842 Unplanned <6.75 hrs) (3 hrs) 3 7/04/86 1328 APRM ' E' upscale spike 7/05/86 2300 7/06/86 0139 Unplanned (15.5 hrs) <2.5 hrs) 4 7/12/86 0228 Manual scram - Main Steam 7/13/86 1935 7/14/86 2228 Unplanned Isolation <0.5 hrs) <3 hrs) 5 7/19/86 0137 IRM ranging error 7/19/86 1430 7/19/86 1751 Unplanned (13 hrs) <3.5 hrs) 6 7/25/86 2016 By pass Valve opened, 7/26/86 0520 7/26/86 0750 Unplanned scram on Level 3 <3 hrs) <2.5 hrs) 7 7/30/86 1729 EHC backup power 7/31/86 0315 7/31/86 1058 Unplanned failed during surveillance (9.5 hrs) (7.5 hrs)
-s 8 8/22/86 1625 STP-281 Shutdown From Outside 8/31/86 0125 8/31/86 0446 g Planned the Control Room (201 hrs) <3.5 hrs) v 9 8/31/86 2144 RFP trip high level-unable 9/01/86 1320 9/01/86 1553 Unplanned to restart (16.25 hrs) < 2. 5 hrs) 10 9/06/86 0617 Changeout of RFP "B to C" 9/06/86 1400 9/06/86 1845 Unplanned caused RPV low level trip <07.75 hrs) <04.75 hrs) 11 9/11/86 2005
- STP-311 Loss of Offsite Power 10/09/86 1425 10/09/86 1804 Planned (666.5 hrs) <3.75 hrs) 12 10/11/86 0905 STP-311 ( Retest) 10/12/86 0545 10/12/86 0924 Planned Loss of Offsite Power (20.75 hrs) <3.75 hrs) 13 10/18/86 1556 RFP test box wiring problem, 10/19/86 0520 10/19/86 1043 Unplanned scram on Level 3 (13.5 hrs) (5.5 hrs) 14 11/14/86 0912 Scram on Rx Hi-Press during 11/28/86.1410 11/28/86 1819 Unplanned turbine control valve test (341.0 hrs) <4.00 hrs) 15 12/03/86 1025 STP-252 MSIV Full isolation 12/04/86 1155 12/04/86 1556 Planned (25.50 hrs) ( 4. 0 hrs) 16 12/06/86 1111 STP-273 Full Power Load 12/10/86 1715 12/10/86 2130 Planned Re3ection (102.25 hrs) <4.25 hrs) 4-7
Table 4. 4-1 MILESTONE
SUMMARY
April 11, 1986 Received Low Power License April 15, 1986 Started Fuel Load April 27, 1986 Completed Fuel Load May 4, 1986 Completed Ops Hydro and Install Drynell Head June 28, 1986 Initial Criticality July 17, 1986 Reached Rated Pressure First Time July 25, 1986 Received Full Power License July 28, 1986 Initial Main Turbine Roll to Rated Speed 1800 RPM August 1, 1986 Initial Main Generator Synchronization to Grid August 22, 1986 Reactor Shutdown From Outside Control Room ( Reactor Scram)
September 11. 1986 Turbine Stop Valve Trip Test September 11, 1986 Loss of Offsite Power Test
( Reactor Scram)
October 15, 1986 Achieved 50% Power For First Time November 1, 1986 Recirc Pump Tests November 10, 1986 Achieved 100% Power First Time December 2, 1986 Feedsater Pump Tests December 2. 1986 Recirc Pump Tests l
December 3, 1986 MSIV Full Isolation Test l ( Reactor Scram)
December 6, 1986 Full Power Generator Load Rejection Test
( Reactor Scram)
December 12, 1986 Started 100 Hr Demo Run December 16, 1986 Completed 100 Hr Demo Run December 16. 1986 Test Program Completed i 4-8 l
l
v Table 4.4-2
(N TEST PROGRAM CHRONOLOGY Feb 17, 1986 Commenced first startup test, CRD Insert-Rithrawal Checks ( STP-051) .
Mar 05. 1986 Loaded first neutron source into core.
Apr 11, 1986 Received Low Power Operating License from NRC.
Apr 15, 1986 Commenced f uel loading at 6: 40 p. m.
Apr 16, 1986 Experienced first Teen Spec problem at 12: 25 pm. ,
FRVS rans - less than 5 operable.
Apr 20, 1986 Experienced first major problem on refueling bridge.
( Damaged main power supply cable) 2 days impact.
Apr 27, 1986 Ccepleted fuel load - last fuel bundle loaded at 3: 04 pm.
Apr 28, 1986 Completed all CAD testing that was related to fuel load. (Industry record of 12. 2 days)
Apr 29, 1986 Completed draining the Spent Fuel Pool and Reactor Cavity below M.S. Line plugs and started "RPV Stack-up" activities.
O
%_s/ May 01, 1986 Completed setting of RPV Head.
May 03, 1986 Final head tensioning pass completed. Entered Operational Condition 4.
May 04, 1986 Commenced OPS RPV hydrostatic testing. Test was aborted due to the following problems.
a) Thermocouple 6 point 9 & 11 were in-op.
b) Head Spray Flange stud bolts, nuts & gasket changeout and documentation problems, c) Installation of T-Mod for the 2" and 1" Road Spray Lines per DCP # 4-EMJ-86399.
d) Resolution of DR-HTE-86-237 for the Drywell Head Linear indication.
May 08. 1986 Completed OPS hydrostatic testing.
May 10, 1986 Completed Drywell Head Seal LLRT.
May 31, 1986 Commenced SECOND OPS RPV HYDRO.
( NOTE: Management decided to perform second RPV Hydro due to CRD Leakage experienced during the early OPS Hydro. )
Jun 01, 1986 Completed Second Cps RPV Hydro.
(
4-9
Table 4. 4 -2 ( Cont' d)
TEST PROGRAM CHRONOLOGY Jun 02, 1986 Recirc tuneups are completed. ( Run Recire pumps at rated speed and performed scoop tube positioner can sha ping. )
Jun 05, 1986 Started preliminary runs on RCIC/HPCI systems to identify and correct probleas that would impact future tests.
Jun 06, 1986 Completed Open Vessel Plateau Review.
( NOTE: Power Ascension ready for Mode 2 and Heatup. )
Jun 19, 1986 Completed Main Turbine Lube Oil Flush.
Jun 27, 1986 Completed all Mode 2 surveillances.
Jun 28, '9A6 Entered Test condition Heatup and Operational Condition 2 for the 1st time.
Jun 28, 1986 Achieved initial criticality the first time.
Jun 29, 1986 ist Reactor Scram ( Unplanned) - Ranged down IRM D instead of B.
Jun 30, 1986 2nd Reactor Scram ( Unplanned) - Operator initiated manual scram. Tech Spec limit run out due to RMCS inoperability.
Jul 01, 1986 Restarted reactor.
Jul 02, 1986 Reactor at 220 o F. Experienced high oxygen concentration in the RPV which restrained heatup, t
Jul 03, 1986 Heated reactor to 250 oF. Completed NSSS Piping Expansion Naikdown.
l Jul 04, 1986 3rd Reactor Scram ( Unplanned) - APRM "E" upscale
- noise spike reached 151 scram setpoint causing a 1/2 l scram while "B" side already in 1/2 scram due to surveillance testing.
l Jul 07, 1986 Restarted reactor.
Jul 09, 1986 Reactor at 150 psig, RCIC declared operable.
Jul 10, 1986 Reactor at 200 psig. HPCI declared operable.
Jul 12, 1986 4 th Reactor Scram ( Unplanned). Manually initiated by operator due to MSIV Isolation.
Jul 13, 1986 Restarted reactor.
4-10
Table 4. 4-2 ( Cont' d)
[g TEST PROGRAM CHRONOLOGY U Jul 16, 1986 Placed first RFP in service at 560 psig.
Jul 17, 1986 Achieved rated reactor pressure and temperature conditions ( 920 psig/540oF) for the first time.
time.
Jul 19, 1986 Sth Reactor Scram ( Unplanned) - ranged IRM "B" and "G" down instead of up.
Jul 20, 1986 Restarted Reactor. Placed 2 RFPT in service.
Jul 21, 1986 Completed RCIC turbine & flow controller tuneup.
Jul 22, 1986 Scram testing of all 185 rods is completed.
Jul 23, 1986 Increased reactor power to 51 rated.
Jul 24, 1986 Completed HPCI Turbine Tuneup.
Completed main turbine shell & chest warming and initial turbine roll to 100 RPM.
Jul 25, 1986 Received Full Power License from NRC.
g 6th Reactor Scram ( Unplanned) - bypass valve opened.
( } 1evel 3 scram.
Jul 26, 1986 Restarted reactor.
Jul 28, 1986 Completed initial main turbine roll to 1800 RPM.
Jul 30, 1986 7th Reactor Scram ( Unplanned) - error during EHC surveillance. All bypass valves opened, main turbine tripped, level 8 tripped FR pump turbine, RCIC initiated, after 3 minutes reactor scrammed on low water level.
Jul 31, 1986 Restarted reactor.
Aug 01, 1986 Main generator initially synchronized to electrical grid. Manually shutdown reactor in preparation for the drywell unit outage.
Aug 05, 1986 Completed Plateau Review for Test Condition Beatup.
Aug 07, 1986 Restarted reactor.
Aug 08, 1986 Commenced Hot Shutdown due mainly to the Reactor Building to Torus Vacuum breakers being inoperable.
Aug 11, 1986 Restarted reactor and entered Test Condition 1.
4-11
v Table 4. 4-2 ( Cont' d)
TEST PROGRAM CHRONOLOGY Aug 13, 1986 Entered Operational Condition 1 - 1st time.
Increased reactor power to 20% rated - 1 st time.
Completed main turbine roll to rated speed, main generator er1tation and synchronized generator to the grid.
Aug 14, 1986 Continued testing at 20% rated power and completed Startup Level Controller tuneup.
Aug 20, 1986 Completed the MSIV functional test, Pressurs Regulator Bypass Valves test and Pressure Regulator
, Control Valves test.
Aug 22, 1986 8th Reactor Scram ( Planned) - Shutdown from outside the control room to demonstrate the ability to shutdown the plant and achieve cold shutdown conditions.
Commenced scheduled unit outage to perform work on the Bailey Logic Cards and Drywell Insulation Maintenance.
Aug 27, 1986 Completed Plateau Review for Test Condition 1 Aug 30, 1986 Completed Unit Outage - Bailey Logic Cards and various maintenance items.
Aug 31, 1986 Restarted reactor and entered Test Condition 2.
9th Reactor Scram ( Unplanned) - Due to low vessel level caused by RFP inability to restart after vessel high level RFP trip.
Se p 01, 1986 Restarted reactor.
Sep 06, 1986 Increased reactor- power to 40% rated - 1st time.
( Progress was hampered by a field ground which j developed on the generator and the ensuing
! Investigation and evaluation lasted for 3 days.)
l l 10th Reactor Scram ( Unplanned) - Due to low vessel level encountered during swap over from RFPT "A" to RFPT "C". RFPT "C" would not startup and RFPT "A" would not restart.
Sep 07, 1986 Restarted reactor.
Sep 08, 1986 Resumed testing at 40% rated power.
Sep 11, 1986 Performed the Turbine Stop Valve Trip tests.
1 I
t 4-12
Table 4. 4-2 ( Cont' d)
TEST PROGRAN CHRONOLOGY Sep 11, 1986 lith Reactor Scram ( Planned) - Performed Loss of Offsite Power test to demonstrate the ability of the onsite power source to supply poner to systems and components important to safety and to demonstrate safe reactor response.
Commenced Unit Outage to perform work on the Loss of Offsite Power Action items, NRC - AIT (Augmented Inspection Team) Action items and LLRT Leak Repairs. i Sep 16, 1986 Completed Plateau Review for Test Condition 2.
Oct 08,-1986 Completed Unit Outage - ( LOP, NRC/AIT items and LLRT repairs) .
Oct 09, 1986 Restarted reactor and entered Test condition 3.
Oct 11, 1986 12th Reactor Scram ( Planned) - Successful retest of Loss of Offsite Power test.
Oct 12, 1986 Restarted reactor.
Oct 15, 1986 Initially reached 50% rated power and continued Test Condition 3.
Oct 18, 1986 13th Reactor Scram ( Unplanned) - Due to RFP Test Box wiring problem, scrammed reactor on level 3.
- Oct 19, 1986 Restarted reactor and resumed TC-3 testing.
Nov 01, 1986 Completed Recire Pump Trips tests.
Nov 06, 1986 Completed Plateau Revies for Test Condition 3.
Entered Test Condition 5 & 4.
Nov 07, 1986 Performed Natural Circulation testing (Test Condition 4).
. Nov 08, 1986 Completed Test Condition 5 & 4 and entered Test I Condition 6.
Nov 10, 1986 Initially reached 100% rated power and continued TC-6 testing.
Nov 14, 1986 14th Reactor Scram ( Unplanned) - Rhile performing l Turbine Control Valve Surveillance tests. Scrammed on Reactor Hi-Pressure.
f t 4-13 4
,r--, -,,,..c ,,e-, - , . . , , _ , , - - , - - , - - , ,
,-c-- , . - - - ~
U Table 4. 4-2 ( Cont' d)
TEST PROGRAM CHRONOLOGY Nov 14, 1986 Commenced Unit Outage to perform work on the "B" RER pump and motor, pressure transducers replacement and repair RRCU hest exchanger diaphram seal weld.
Nov 27, 1986 Completed Unit Outage.
Nov 28, 1986 Restarted reactor and resumed TC-6 Testing.
Dec 02, 1986 Performed and completed Feedwater and Recire Pump Tests at 100% rated power.
Dec 03, 1986 .. 15th Reactor Scram ( Planned) - Perfermed MSIV Full Isolation at 100% rated power.
Dec 04, 1986 Restarted reactor and resumed TC-6 testing.
Dec 06, 1986 16th Reactor Scram ( Planned) - Performed Full Power Load Rejection tests at 100% rated power.
Commenced Cold Shutdown to complete rework on the RRCU heat exchanger leak repair, troubleshoot and repair "B" Diesel Gen. , repair IRM "D", repair torus to drywell vacuum breakers ( f ailed LLRT) and calibration of the torus pressure tranducers.
Dec 10, 1986 Restarted reactor, achieved criticality and ascended to 100% power, 100% rod line.
Dec 12, 1986 Began 100 Hour Demo Run.
Dec 14, 1986 Completed 8 Hour Rarranty Run.
Dec 16, 1986 Completed 100 Hour Demo Run.
I Dec 16, 1986 Complete Plateau and end of Power Ascension Test Program.
1 i
9 4-14
I
- 5. 0
SUMMARY
OF TEST RESULTS A summary of the results of each power ascension test
, performed during this program is presented in this section.
An index showing the section number, title, FSAR test i
number, startup test procedure ( STP) number, and page number 4
for each test is given in section 5.1.
a i
i I
i l 4
i 1
i.
i
}.
i t
t i
I i
)
t e
i i
I i ,
i f
I 4 5-1 1
I...__-..
5.1 Test Index l l l FSAR l l PAGE :
l SECTION l TI TL E l NO. l STP NO. l NO. l
- .........l..........-------------------;------l.....-....--l...---.;
l 5.2.1 l Chemical and Radiological l 01 l 11 - 19 l 5-4 l l----.....: ...........................--l......: --------..--: .....--;
! 5.2.2 l Radiation Measurements ! 02 l 21 l 5-13 l
- 5.2.3 l Fuel Loading ; 03 l 31 -
33 l 5-15 l
- .......--l---.......--............----l.....-l---......---
- ----...;
l 5. 2. 4 l Full Core Shutdown Margin l 04 l 41 l 5-18 l l 5. 2. 5 : Control Rod Drive System l 05 l 51 -
56 l 5-21 :
l..--..--: -------..--......--...---....l......l........--..l.....--l l 5.2.6 l SRM Performance Test l 06 l 61,62 & 64 l 5-27 :
- --......l----..-.......--..----.......;.....l............;-------;
I 5. 2. 7 l IRM Performance Test l 08 l 101 -
103 l 5-29 :
- .........l......-....--......-----....-l--...-l------------l......-l l 5.2.8 l LPRM Calibration l 09 l 111 & 112 l 5-31 l
- ----...--: -------.....--...-----.....l------l......--....l----..l l 5.2.9 l APRM Calibration l 10 l 121 & 122 l 5-33 l l....--...l .--.............--.....---- : ---...l............l--.....l l 5.2.10 l Process Computer l 11 l 131 -
138 l 5-35 l l........-l....................-.....--l l.....-----..l---..--l l 5.2.11 l RCIC System l 12 l 141 - 145 l 5-41 l
- ....--..;........-.................--;.....-;.....--....-l..--...;
l 5. 2.12 l HPCI System l 13 l 151 - 154 l 5-45 '
l.....--.;..........--....-------......;......l--...--_--;.......;
- 14 5.2.13 l Selected Process & Water l l 161 - 164 l 5-48 l l l Level Reference Leg Temp l l l l l......-----------..--...----- ...---l l....---;
l S.2.14 System Expansion l 15&39 l 170 - 179 l 5-52 l
- --.......;-..--...........--..--.....l......l.......-----l...----;
l 5.2.15 l Core Performance l 17 l 191 ; 5-60 l
- ......... ...............--.........-..;---...l........--..l.......l l 5.2.1f l Steam Production l 18 l 201 & 202 l 5-62 l
- ......-_.;........--.............----;.....l--.-...-----l.......;
l 5.2.17 l Pressure Regulator l 20 l 221 - 224 l 5-65 l
.........;.......-----.......---....---l......l......--....;.....--;
- 5.2.18 Feedwater System - Setpoint l 21-1 l 231, 235 & l 5-70 l l l Changes l l 236 l .
l 5.2.19 l Feed System - Loss FW l 21-2 l 232 l 5-75 l l l Heating l l l l
,.....--..a ...--.........--........--.;....--l--...--.....;-------;
l 5. 2. 20 : Feedwater Pump Trip l 21-3 l 233 l 5-76
- ........-; ---...........--....--.......l .--...; ......---...; ......;
l 5. 2. 21 l Max FW Runout Capability l 21-4 l 234 l 5-77 .
- ....--..;--................--.------_-;......l..--.----...;.......,
l 5.2,22 : Turbine Valve Surveillance 22 l 241 - 243 ! 5-79
- 5.2.23 l MSIV Functional Test
- 23-1 l 251 l 5-83 .
i .--__-_-_______________-______________i_-____i____________i______.
5-2
E
(--)
( ,j
. SECTION l TI TLE l NO. l STP NO. l NO. l
- --.......;----.--..--_..-..........---l.------------..--:---.--:
l 5. 2.24 ! MSIV Full Isolation l 23-2 l 252 l 5-84 '
l 5.2.25 l Relier Valves
......-.-- ...----- .....---- ......: l 24 l 261 & 262 ! 5-87 !
....l.....--.................--_-:---...:....--.---..:----...:
l 5. 2. 26 l Turb Trip & Gen Load Reject l 25 l 272 274 ! 5-90 l 5. 2. 2 7 l Shutdown Outside Control Rm l 281 l 5-95 !
l . . . . . . . . . l . . . . . . . . . . - - - . . . . - - - - - --..l.--- . - - . . . ll .----...:---..
26 .:
l 5. 2. 2 8 l Recirculation Flow Control 27 l 291 & 292 l 5-97 l
---.........................:---..j.-..........;---...:
l 5. 2. 2 9 l Recirculation System l 28 l 301 -
305 l 5-100 t
- ...--...: . ..--.................-----..l......:..........--:.......:
l 5. 2. 3 0 l Recire Flow Calibration 29 351 & 352 l 5-104 l
' : . . . . . . . . . : . . . . - - - - - . . . . - - . . . . - l - . . . . . -----.......: - - - l - - - . . . l:..--..: .
! 5.2.31 l Loss or offsite Power ! 30 & 313 l 5-107 !
- - - - - . . . - - l . . . . . . . . . . . . . . . . . - - - . - - - - - - . . l - - - - - - ll --...------l... 211 ...
l S. 2. 3 2 l Pipe Vibration l 31 l 331 -
335 l 5-110 ?
l l l l 341 -
346 l !
- : l l--..........: .:
l 5. 2. 3 3 l RWCU System l 32 l 701 & 702 l 5-128 !
' --...--..:--......--.......--..------l...---:.-----------l------.:
l- 5.2.34 l RHR System l 33 713 & 714 5-130 l l
l...---.--l.........--..........--..----l--...-ll----.......!
- 5. 2. 3 5 l Dw & Steam Tunnel Cooling 34 l 721 724 s l -
l 5-133 l
} : .........: -
5.2.36 l Gaseous Radwaste System
- ........:.................--..........;.-----l....-------l5-136
! l 35 l 741 l
l 5. 2. 37 l SACS Performance Test l 38 l 751
- .....---.:------......---............l......:--......----l5-139!
l S. 2.38 l Confirmatory In-Plant Test 40 l 761 & 762 l l 5-141 l
- ........-l.......................---..l......l.....----...:....---:
l 5. 2. 39 l Turb. First Stage Pressure ! --
l 774 l 5-146 !
l l Scram Bypass Setpoint l l l l
- .....--..: ......----...------....--...:------l l 5. 2. 4 0 l Ventilation System ! --
l 781 -
783 l 5-147 l l l Performance Test l l l l
........-----....--......l-----.! ; -!
l 5. 2. 41 l LPCI & Core Spray Line l --
l 715 l 5-151 !
! ! Break l l l l
............-----l......: : . ..--..:
l 5.2.42 l Main Turbine & Generator l --
l 771 & 772 l 5-152 ' '
l l Initial Startup l l l l l......--....--.-------..--..l......l l--......
l 5. 2. 4 3 l Steam Seal Evap Initial Test! - -
l 773 l 5-154 '
l 5.2.44 l Setsmic Monitor l - -
l 791 l 5-156 '
- .......-- . .........--.........--.....l....--l........--..: . ......: :
l 5. 2. 4 5 l Loose Parts Monitoring l - -
l 792 ! 5-157
- ....--..: .........--....--.....--..l.-....l...........-: . . . . . . -
l i
- 5. 2. 4 6 l SRV Acoustic Monitoring l --
l 793 l 5-159 '
.-------- .---------------------------- .----- e ----------- ....----
5-3
.l .
= , , m- _ . - - r y,. -- e-e-. .g-- 7 ---v_
+.m & ---r-. -,.w-,%_. -->-my -g ,.p- - - - - - - . - - i-r.-- y
O
- 5. 2 RESULTS
- 5. 2. i Test No. 1 CHEMICAL AND RADIOCHEMICAL A. OBJECTIVES 1 Obtain information on the chemistry and radiochemistry of the reactor system.
- 2. Datermine that the sampling equipment, procedures, and analytical techniques are adequate to supply data required to demonstrate that the chemistry of the reactor system meets quality specifications and process requirements.
- 3. Use the data obtained to monitor fuel integrity, operation of filters and domineralizers, condenser integrity, operation of the offgas system, steam separator-dryer operation (by measuring steam exit q u ali t y) , and process monitor operation.
- 4. Assure releases of gaseous and liquid effluents are within license limitations.
B. ACCEPTANCE CRITERLA Level 1 1 Chemical factors defined in the Technical Spectrications must be maintained within the limits specified.
- 2. Water quality of the following parameters must be known at all times and must remain within the guidelines of the GE Water Quality Specifications and Fuel Warranty.
Reactor Water Conductivity Chloride l pH Feedwater Conductivity Metallic Impurity Oxygen Control Rod Drive Conductivity Hydraulic Water Oxygen Stored Hakeup Water Conductivity
( Condensate Storage Chloride Tank and Demineralized Water Storage Tank)
- 3. The a c ti vi t y of gaseous and liquid effluents must conform to license limitations.
5-4
l Level 2
,/~N Watcr quality parameters other than those given in the Level i.
s ) 1 criteria must remain within the guidelines of the GE Water Quality Spectrications.
C. DISCUSSION Reactor and plant systems water chemistry data were taken prior to fuel loading in Test Condition Open Vessel, at rated reactor pressure in Test Condition Heatup, and at nominal power levels of 25%, 50%, 7 5 %, and 100% of rated reactor power in Test Conditions 1, 3 ( twice) and 6. The major test results are summarized in Table 5.2.1-1; in all test conditions, reactor water chemistry results satisfied the acceptance criteria, except as described in Table 5.2.1-2.
Gaseous and liquid effluent monitoring testing was performed in Test Condition Heatup ( L5% powe r) , and at nominal power levels of 25%, 50%, 75 %, and 100% of rated reactor power.
The testing verified that the activity of gaseous and liquid effluents conformed to license limitations. Problems were encountered with the computer generation of liquid effluent pre- and post release permits during testing at 50% and 75%
power. These problems were resolved by reinttializing the computer and reprocessing the discharge permits, or manually generating the permits. No acceptance criteria violations
/
were found during the testing. Gaseous and liquid effluent k-)/
m test results obtained in TC-6 are given in Table 5.2.1-3.
The performance of the gaseous radwaste ( of f gas) system was monitored and evaluated in Test No. 35.
Process radiation monitoring system operation was verified, and baseline data were recorded, in Test Condition Heatup and at nominal power levels of 25%, 50% 60%, 75% and 100%
rated power. Problems encountered during testing are summarized in Table 5.2.1-4. These problems were successfully resolved.
During steady state operation at near rated power in Test Condition 6 the Reactor Water No-Cleanup test was performed to obtain data on the integrated performance of installed reactor chemistry control systems during reactor operation, and to determine moisture carryover in the steam from the reactor. Prior to the injection of sodium hydroxide, the reactor power was reduced to 73% due to a recirculation pump runback when a secondary condensate pump tripped. After the reactor power was returned to 951, the sodium hydroxide was injected. The reactor water conductivity was allowed to increase to 1.1 uS/cm, at which time the RWCU System was returned to service. Approximately 6 1/2 hours after the RWCU System was restored to service, a reactor scram
[ \
occurred. Although the scram terminated the test prior to 5-5
its expected completion, sufficient data were obtained to satisfy the objectives of the test. Integrated reactor chemistry systems performance data are presented in Table 5.2.1-5. The steam exit quality calculated from the test was 99.99745, which was well within the value of 99.7%
required for the Steam Production Warranty Test (Test No.
18). The Na-23 concentration was not determined because the chemistry laboratory was not equipped to analyze elemental sodium in radioactive samples. The neutron flux could therefore not be calculated. There was also no detectable Cl-38 carryover to the hotwell because of the very low reactor water chloride level.
O O
5-6
.-~ - - . . _ . . --. .. - _.
l
. I Table 5.2.1-1 ;
p WATER CHEMISTRY TEST RESULTS V '
...............e.......................e.................................................................................
.ACu?IA%W yr:N . i . . i .
- :DA'ETE4 lCFliER!A : VESSEL :
i EAii.'? l 7C-1 l 70-3 : IC-3 l. I: :
-......................................,'..........i.......................,i...........
- ,3 s. g , ; t. , ..t.,
. r,- i (s,
c . .
- ,< .c .n.
. :.w
.. .m.
. ,. i o i r
. ..o c..a.. r. . .
4 . .
?
i e t 5 L
Sein c* nte' . I ; ; ; i ;
Cu ia:th:tr h5/:s 325:C) : Nste (t) : 0!6 ! 0.!! : 0.41 l 0.18 : 0.20 O.10 .
hietitestus) l Nste (1) 1 (5 : (5 12 l 5.5 : (5 : (5 '
H(S.U.3250) : Note (1): 7.3 : 7.1 l 7.5 : 7.8 : 7.5 t 7.: :
i DaleEn!v.1-131(VCili)(Note 21 l(0.2 : N/A ! (LLD ! (LLD ! (LLD : ('. ;! ;
(LL:-
j . l . . I f 6 e t t 1 b a
COMeetit!Oestr.eral::erInfhe'it : l l l ! l !
Centuctivity MS/ca 12:001 i{0.5 : N/A l 0.!! : 0.10 l 0.13 0.09 : 0.ti Ohrties in:) (N3te 3) lf!0 l m/A : (5 : (5 : (5 : (5 : (!
- n(3.0.12500) : e.0 5.0 : N/A i 6.7 7.5 : 7.7 1 7.0 l .?
ishale Iton ' :H :{40 : ila ;
(10 : 105 : 3.2 l 1.17 ! 1.07 huh 31eIron(nn) :{t000 u ! !60 : (30 22 : ?.33 : 5.R
! 3::e inal i(50 : U4 : (10 0.36 l 1.20 l 1.41 l 1.17 1
i lthe' 'etals ::3) l{40 U4 : !!! l 52 i 1.0 : !.23 i 1.!3 i , . ,
- i. . i r e
- "*! sit!Dett*!*i::!*E33hent l , ;
! ! l l Ush:::nu bil:n i;5cC! : (0.! ila 0.h ; 0.0! (0.0ci
! i 0.06 ! 0.h -
?'ar::ei i:::: tute3) (2 U : (5 : (! l (5
(! !
(!
I' .
i :. . n.
.~. .; , 6... .i.:. .
0..- , ,. .
7..s . . .
i
, r., . . t. 5 . s.: .
Sta' 'etaisiu::er inD 'f10/f2 : N/A : 1.34/(2 i 5.5/0.024 1 0.193/0.C8: 0.39/0.02 ..: ice.;I i:'::a +::o :tte 4; : f5 : '< /a : (to (10 :
(10 :
i i (10 ;
- )
, ,i , .
~
, .e , ,
i ie:.ite* E%e*** l*Ct : l l l
- *ei* e'l
- ;. ??. ' l l t i : !
% 5 t i:*.b :S i;i/Ca i.500 {0.1 UA 0.06 0.08 :
l 0.21 : 0.!6
- O.0! i I
. *:t:tel in3i 'Mte3) i {2 ; U4 : (5 l (5 l ($ l ($ l (!
i 3- 3..'. i !a *! 3.!-7.5 04 ; 6.9 i 7.5 l 7.2 ; 7.0 ; 3.5 I
'::1 ?sta's/(s:es ;;;O S:te l; ; {!!/{2 , 0; 0.6/0.013l19.!/0.08l0.!:/0.05:0.!!/0.04: 0.!/0.2 i
his:Det C2 f:::t : 20-200 Ua : 150 : 50 l 100 l 30 D 4 f I l $ f I l !'i": . :ot : :nt :' : : i i i 4 i e'ti::f ate (.tt utet!) ,
- 3.:: l !I.27 l 13.4 13.2 : !3.2 : 13.".
l 33'at;D Vahte (gall
- ute!!; :!!: . 4?!3 l 4!60 5027 : 50!2 : 10!2
- ..,.i u., p:. n3ij
- :-- utf -
.u.4g .' in. 3
- st n.
. l:.1 a n e
. +
e e . .
.co............e....e...........e.....'..eee....e ........eee ..ee...eee.Io..........Io..........'........... ...........
t 5-7
1 l
l Table 5.2.1-1 ( Cont' d)
' WATER CHEMISTRY TEST RESULTS
................................................p....gN
. Av.t. IAL J, i
- Ast"E'ER lCHIEUA VE53EL l HEAIL8 : IC-1 l IC-3 IC-3 l 9-:
...........s...........'...........*...........
I v i # 1 I i % 4 lN!"11t! itri ! *i9s l l l ; i l ,
U C Ct1/ity h3!Clil53C) '{!.) l 0.97 0.65 l 0.60 l 0.!5 l 0.74 . 0.:3 i'i (3.J.i25aC) : 6.0-3.0 l 6.9 : 7.5 l 7.2 l 7.9 l 6.! l s.5
"?.!:f1:e
. : {0.05 : (0.05 : (0.005 (0.005 l 0.005 : (0.X5 , G.Mi inan l{0.1 l 0.020 l 0.020 l (0.020 '
(0.020 l 0.020 C.:D ,
3111Ci l 3.0.II. l (10 l .... ! .... .
i ....
ee: Sera!::t1Wate*5tPI:! *n a l l i l l 1 Ot.n Ctivity hii:si !aCl : {t.0 O.4! l 0.66 l 0.71 : 0.57 l 0.57 l 2.!!
., j ai s . ..i . aan 3 6, g e
.1 i 6. g .a. . av , 5. .:
's . ! . 7.2 .' 7. .s* i '4 . ',
31I1CI IPDO 0.0.0. l (!0 l ....
I .... .... .... ....
O1or1:etael '{}.05 ....
(0.005 l (0.005 l (0.005 l 0.005 : 0.X71 3r n boel '!.0.3. : .... l 0.020 ; O.320 O .020 : (0.020 l 0.:D
...................................... ..........i...........'...........'...........'...........'...........'...........
N/A = Acceptance Criteria Not Applicable B. O. D. = Baseline Operating Data Notes:
- 1. The following limits were applicable per the Technical Specifications:
Operational Conductivity Chlorides pH Condition (uS/cm @25oC) ( opb) ( S. U. 625oC) 1-Power Operation (1. 0 (200 5. 6 - 8.6 2-Startup, t2. 0 (100 5. 6 - 8. 6 3-Hot Shutdown 4-Cold Shutdown, (10.0 L500 5. 3 -
- 8. 6 5-Refuel
- 4. LLD = 10 ppb Silica
- 5. Limits are given in Technical Specification Figure 3.1. 5 - 1.
9' 5-8 i
I 1
I l
- 5. During initial plant testing and startup, the normal limit ,!
of metallic impurities may be exceeded for the first 500 l hours of effective full power operation. During such O' periods, the daily average concentration of metallic impurities shall not exceed 100 ppb at (50 percent power and 50 ppb at >50 percent power. Short duration spikes exceeding 100 ppb may occur during startup or when operational changes are made. If the spike concentration does not decrease to less than 100 ppb within 30 minutes, corrective action shall be taken to reduce the concentration to less than 100 ppb.
Table 5.2.1-2 RESOLUTION- OF CHEMIC AL AND RADI0 CHEMICAL TEST DEFICIENCIES Test Condition Descriotion
- 1. OV Torus water filter /demineralizer influent c ond uc t i vi t y slightly exceeded the initial acceptance criterion. An evaluation by the NSSS vendor concluded that the water quality
- was in the proper range and acceptable, and that the criterion being utilized was not applicable to this measurement. This
()
measurement was changed to baseline operating da t a ( B. O. D. ) .
- 2. OV Reactor Auxiliaries Cooling System ( RACS) and Safety Auxiliaries Cooling System ( SACS) pH exceeded the acceptance criterion. The systems were fed and bled to bring the pH within limits.
- 3. O V, HU,1, 3, 6 Engineering decided that the corrosion inhibitor should be removed from RACS and SACS, and the acceptance criteria limits changed to those for domineralized water.
The corrosion inhibitor was removed by feeding and bleeding. However, through most of the power ascension test program the RACS and SACS c o nd uc t i vi t y exceeded criterion limits due to residual traces of corrosion inhibitor. The conductivity was brought into limits by utilization of portable domineralizers in both systems.
e
/
' ' s.9 I
cr
\
~
- 4. HU,1, 3, 6 The lower limit of detection ( LLD) of the installed instrumentation for the Condensate Demi ne rali z e r Effluent'and Feedwater Heaters 6 A, 6B and 6C Effluent was 5 ppb, which exceeded the acceptance criterion of L2 ppb.
, The NSSS vendor evaluation concluded that meeting the LLD value was acceptable as long as reactor water chlorides were maintained i
within limits, since these conditions ensure satisfaction of the (2 ppb criterion.
- 5. HU Nickel concentration in the Condensate Demineralizer . Influent exceeded the metals Receptance criterion. The high concentration was due to impurities in the main condenser hotwell and secondary system piping and equipment, and often occurs during plant startup until stable metal films have formed on the system surfaces. The hotwell was cleaned during an outage, and the metals concentration gradually decreased to an equilibrium level, within the acceptance criterion, as the metals were progressively removed by the condensate demineralizers during normal plant operation.
- 6. HU,1, 3, 6 The LLO of silica in the Condensate Demineralizer Effluent was 10 ppb, which
[ exceeded the acceptance criterion of L5 ppb.
l Similar to item 4, the NSSS vendor evaluation f concluded that this level satisfied the l '
criterion provided the rehetor water chloride level was within limits.
l 7. 1 Similar to item 5, soluble iron concentration in the Condensate Demineralizer Influent l exceeded the acceptance criterion.
l Disposition was to accept as-is since the metals concentration in the feedwater to the reactor was within acceptable limits. The final equilibrium levels were well within the l criterton.
l l
- 8. 3, 6 The conducti vi ty of Feedwater Heaters 6 A, 6B l
, and 6C Effluent exceeded the acceptance criterton limit. Some corrosion from the sample line was considered to contribute to the excessive conductivity level. In TC-6, following an initial sampling of 0.16 uS/cm, the sample line was placed on constant purge which yielded a second sampling of 0.08 uS/cm which was well within the criterion.
l.
5-10
. ~ .- - -- ..
,- .= - .
Table 5.2.1-3
~
GASEOUS AND LIQUID EFFLUENT TEST RESULTS AT TC-6
.. a Maximum Release Dose ( GI-LII)
(5 of Technical Soecifications Li mi t)
Errluent 31-Day Quarterly Annual Gaseous 7.66 0. 6 0. 3 Liquid 22.9 2.71 1.64 i
Table 5.2.1-4 RESOLUTION OF PROCESS RADIATION MONITORING SYSTEM PROBLEMS Test Condition Description 1 . 1,2,3 Offgas pretreatment monitors were downscale at L50% power. A button source was installed on the monitors to provide continuous on-scale indications.
- 2. 1 The- RM-11 computer was out-of-service. It
) was later repaired and returned to service.
- 3. 1 Heating steam condensate waste monitor and L
north plant vent monitor process flows were incorrect, resulting in incorrect monitor i- C readings. Flow measurements were corrected and data later retaken.
! 4. 3 Turbine building exhaust monitor RE4827, 7 technical support center ventilation monitor RE-4868, and SACS monitor RE4859 A1 were sometimes inoperable. Problems were corrected and data later retaken.
, 5. 3 The main steamline C&D monitors were replaced with GE NUMAC monitors, and readings retaken at approx. 20%, 355, 505 655, 80% and 100%
power. NUMAC monitors were installed on MSL j A&B throughout the test program.
- 6. 6 Turbine building exhaust compartment monitor reading was high 'due to turbine shine.
System Engineering is reviewing the problem to determine what corrective action will be taken.
5-11 i
. , . . - , . , , - - , , ,,---,.--.-,.,nn, .n.. .~..,,---,,-,,-.-..---,n-,- -.n_,---.--,- ,-- .
m Table 5.2.1-5 INTEGRATED REACTOR CHEMISTRY SYSTEMS PERFORMANCE DATA h Moisture Carryover 0.0026%
Equilibrium Conductivity 0.27 uS/cm Average Conductivity Input Rate 0.021 uS/cm/hr RWCU System Half-Time 8. 3 hrs Purification Constant 0.084/ hour l
l l
1 i
l l l l l l 1
i 1
i 1
l I
I
)
5-12
v 1
1
- 5. 2. 2 Test No. 2 RADIATION MEASUREMENTS ;
/"'N A. OBJECTIVES 1
Monitor radiation at selected power levels during plant operation to ensure the adequhey of shielding for personnel protection and to verify compliance with 10CFR20.
- 2. Determine background radiation levels in the plant anvirons for baseline operating data to monitor plant activity buildup.
B. ACCEPTANCE CRITERIA Level 1 The radiation doses of plant origin and the occupancy times of personnel in radiation zones shall be controlled consistent with the guidelines in 10CFR20, Standards for Protection Against Radiation, and as explicitly defined in S A- AP. Z Z -046( Q) , Radiological Access Control Program.
Level 2 The radiation doses of plant origin shall meet the following limits depending upon in which radiation zone the radiation base point is located:
Radiation Tone Limit I less than or equal to 0.5 mrem /hr II less than or equal to 2.5 mrem /hr III less than or equal to 15 mrem /hr IV less than 100 mrem / hr V less than or equal to 1 Rem /hr VI less than or equal to 10 Rem /hr VII less than or equal to 100 Rem /hr VIII greater than 100 Rem /hr C. DISCUSSION This test was performed in Test Conditions - Heatup, 3 and
- 6. Gamma dose rates, and where appropriate, neutron dose l rate measurements were made at specific locations around the plant including all potential high radiation areas.
Radiation dose rates were acceptable in all areas except in the reactor building where a reactor water sample panel drain created a crud trap.
l l
lO 5-13
Two types of radiation monitoring were performed - shielding surveys and area surveys. Shielding surveys were performed to verify adequacy of shielding design and construction.
These surveys were performed using hand held instruments to measure gamma and neutron dose rates.
Area surveys were performed to verify that radiation levels do not exceed the specified Radiation Zone limits. These surveys were performed using hand held meters in locations where it was suitable for personnel entry. For those areas
, where radiation levels were too high for personnel access, Thermo-Luminescent Dosimeter ( TLD) surveys were used. This method called for placing TLD's in specified locations for a period of time (about one day) . The coded detectors were then retrieved, analyzed, and the average dose rate calculated.
In Test Condition 3, the majority of the measured dose rates were <.2 mrem / hr ( gamma) and <.5 mrem / hr ( neutron) . Higher dose rates were wi t hi n the Radiation Zone limit values except for five areas in which dose rates exceeded the Radiation Zone limit values. Radiation Protection controlled these areas in accordance with 10CFR20 while the Technical Department resolved the differences between the dose rates and the limit values.
In one of these areas, the reactor water sample panel drain line was identified as the source of the high radiation due to crud buildup at an elbow. Presently, this equipment is identified with a " Hot Spot" sticker. The Technical Department is working on a resolution to this problem.
There were also three locations that had higher than expected readings attributable to temporary transfer and storage of radwaste material. These areas will continue to be controlled by Radiation Protection in accordance with 10CFR20 until the permanent transfer and storage facilities are in place. In the last area a Radiation Base Point ( RBP) sticker was located in the wrong end of a labyrinth which resulted in a higher than expected radiation level. After relocation, the RBP reading was within the required level.
In Test Condition 6, the majority of the measured dose rates were agai n ( 0. 2 mrem / hr ( gamma) and < 0. 5 mrem / hr ( neutron) .
Higher dose rates were also within the Radiation Zone Limits except that there were three violations of Level 2 acceptance criteria. Two of the violations were the same as those found during TC-3 and are discussed in tne previous paragraph. The third violation was attributed to use of an inappropriate radiation monitor. Subsequent measurement with the correct monitor showed the radiation levels all were within the Radiation Zone limits.
9 5-14
- m. __ . _ .. . _ _ . . _ _ _ __
I 5; 2. 3 j Test No. 3 FUEL LOADING A. OBJECTIVE f
O Load fuel safely and efficiently to the full core size.
E r
B. ACCEPTANCE CRITERIA Level 1 A
The partially loaded core must be suberitical by at least 0.385 delta k/k with the analytically determined strongest
- rod fully withdrawn or by at least .0. 385 delta k/ k with the i reactivity equivalent of the strongest rod added by the withdrawal of other control rods.
A C. DISCUSSION Initial core loading ( 764 f uel assemblies) and control rod testing began on April 15, 1986 and were completed 12 days later. A partial core shutdown margin demonstration was i
successfully performed with 144 fuel assembilies loaded.
I Following the completion of fuel loading, full core !
verification was conducted which. verified that all fuel assemblies-were properly located, oriented and seated in the I
- core. Control rod functional, friction and scram tests were performed in parallel with fuel loading for the completed
- control cells. Figure 4.2 in section 4 presents the Hope Creek fuel load performance schedule.
t Prior to loading fuel, the fuel support castings e.nd control !
rod blades were inspected to verify proper installation. i j _ Also, the Sb-Be operational sources were installed and the
] SRM discriminator curves were established using a portable 1
source. The SRM channels were calitrated to initiate a rod block and scram at 10,000 cps and 20,000 cps, r e s pe c t i ve l y.
Just prior to commencing fuel loading, the RPS shorting l l links were removed to provide non-coincident scram j protection during core alterations.
I
- Initial core loading during previous BWR startups began by
!_ loading fuel around a central startup source and proceeding b in a spiral, outward to full core size. Also, movable Fuel Loading Chambers ( FLCs) were utilized to monitor ' neutron count rate. At Hope Creek, the SRMs were utilized to ,
4 monitor the core neutron flux which required a unique fuel loading sequence and related instrumentation requirements I
which had been reviewed and accepted by the Nuclear l' Regulatory Commission. Fuel loading began by locating the i bundles next to the operational source in the northeast
, quadrant which was placed in its alternate location, and
! proceeded in the sequence shown in Figure 5.2.3-1. The
{ minimum count rate specified in the Technical Specifications !
( 0. 7 c ps) was not required to be met until the first 16 fuel assemblies were installed, however, the count rates for SRM 5-15
- , , _ , _ , _ _ _ . _ , .,., _ - _ ,_ .~.___ _
V A were 0. 8, 2.1 and 4. 2 after each of the first three assemblies were loaded, respectively. Operability of the remaining downscale SRMs was periodically verified by a portable neutron source.
Beginning with the 16 assembly array, 1/M plots were maintained to ensure suberiticality throughout the remainder of the fuel loading process. In addition, a subcriticality check was performed for the next control cell to be loaded by fully wi t hd ra wi ng the control rod in a loaded adjacent control cell.
After 144 fuel assemblies had been loaded, a partial core shutdown margin demonstration was performed by withdrawing control rods 38-43, 22-43, 30-35, 30-51, 22-35, 38-51, 38-35, 22-51, and 30-43, and observing the core to be suberitical. Withdrawing these control rods was the reactivity equivalent of withdrawing the strongest rod (26-
- 55) and adding 0.38% delta k/k to the core.
At various timen during the fuel loading, intermittent system problems ( primarily connectors) were encountered with SRM channels B and C which rendered them temporarily inoperable. During these intervals an PLC was installed to assure adequate core monitoring while performing core alterations in these quadrants. Upon completion of fuel loading, a camera and video recorder were used to verify proper fuel assembly location and orientation. The camera was then turned at a right angle to the fuel and the core was again scanned to verify proper fuel assembly seating.
There were no discrepancies found during the full core verification.
arr Other significant problems were:
- 1. Setting a fuel assembly on the bail handle of a leaded assembly. The loaded assembly was subjected to about 100 lbs. force ( based on load cell i ndi c ation) . Both assemblies were removed, inspect d and reloaded when found undamaged.
- 2. Several refueling bridge outages occurred, primarily for replacement of the main power supply cable and blown fuses. Replacement of STATATROL cards corrected the fuse problem.
O 5-16
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Figure 5.2.3-1, Fuel Loading Diagram 5-17
l 5.2.4 Test No. 4 FULL CORE SHUTDOWN MARGIN A. OBTECTIVE l
Demonstrate that the reactor will be suberitical :
throughout the first fuel cycle with any single control rod !
f ully withdrawn.
B. ACCEPTANCE CRITERIA Level 1 The shutdown margin of the fully loaded, cold ( 68oF) xenon-free core occurring at the most reactive time during the cycle must be at least 0.38% delta K/K with the analytically strongest rod ( or its re ac ti vi t y equivalent) wi t hd r a wn. If the shutdown margin is measured at sometime during the cycle other than the most reactive time, compliance with the above criterion is shown by demonstrating that the shutdown margin is 0.38% delta k/k plus an exposure dependent correction factor ( R) which corrects the shutdown margin at that time to the minimum shutdown margin.
Level 2 Criticality should occur within t1. 0% delta K/K of the analytically predicted critical ( reactivity anomoly) .
C. DISCUSSION Initial criticality was achieved at 2318 hours0.0268 days <br />0.644 hours <br />0.00383 weeks <br />8.81999e-4 months <br /> on June 28, 1986 in TC-Heatup. During a subsequent criticality, the full core shutdown margin ( SDM) and reactivity anomoly were verified to be within the test criteria limits.
The numerous activities associated with initial criticality require considerable coordination to assure that testing proceeds in a safe, efficient and orderly manner. The full core SDM procedure served as the coordinating document for all tests with the initial criticality process. The results of these conjunctive tests are summarized in sections 5.2.6 and 5. 2. 7, SRM Performance and IRM performance, r e s p e c t i ve l y.
Just prior to beginning the in-sequence control rod wi t hd ra wals, the predicted critical rod position was calculated (based on analytical data and the initial
! moderator temperature of 130oF) , and the minimum and maximum allowable critical rod positions corresponding to t1% delta K/K (the allowable reacti vi t y anomoly) were determined. At the end of specified rod withdrawal intervals, 1/M data were plotted as a function of number of notches withdrawn ( Tes t No. 6).
5-18
During the approach to criticality, the moderator temperature was observed to be decreasing such that the critical rod position predictions would be significantly affected. In order to assure the availability of up-to-date critical rod position predictions at the time criticality was achieved, shift test personnel calculated predicted minimum and maximum critical rod positions for several moderator temperatures.
, Initial criticality was achieved in withdrawal sequence A-2 with Rod Sequence Control System group 3 control rod 46-27 at position 08 ( step 84 of the withdrawal procedure) . The period was 500 seconds and the moderator temperature was 123oF. This was within the limits of the critical rod position predictions for a moderator temperature of 123oF as shown below:
Minumum Maximum Allowable Allowable Critical Predicted Actual Critical Position Critical Critical Position l -15 dK/K) position Position ( +15 dK / K)
Step No. 31 50 84 107 Rod Location 10-39 54-19 46-27 14-35 Notch Position 36 04 08 12
() Following criticality, to neutron flux was increased in order perform the SRM/IRM overlap test ( Test No. 8) and then l the reactor was returned to a suberitical condition.
3 A second criticality was achieved to determine the full core 7 shutdown margin. The value of the demonstrated full core shutdown margin was determined to be 2.4% dR/K which is well in excess of the minimum required value of 0.38% dR/ K. A third criticality was conducted to verify the non-saturation of the SRMs, discussed in section 5.2.6. The RPS shorting links were re-installed following these demonstrations.
There were three violations issued by the Nuclear Regulatory Commission involving this test. The first violation noted that revision 0 of the test procedure did not t adequately address all of the requirements of Regulatory l
Guide 1.68. The procedure was subsequently revised, prior to fuel loading, and was in full compliance with the requirements of Regulatory Guide 1.68 when the test was performed. A review of all test procedures was conducted to assure that the requirements of Regulatory Guide 1. 68 were adequately addressed.
The second violation involved the failure to obtain and plot 1/M data at the end of one of the required intervals. The O omission occurred following trouble shooting efforts to correct the failure to receive full out indication of a control rod that had just been withdrawn. The test 5-19
engineers were counseled regarding adherence to procedures and assuring proper communications with personnel involved in testing. The third violation identified a failure in the results review process. The calculations of the predicted minimum and maximum critical rod positions that were performed for the initial temperature of 130oF contained an arithmetical error which would have resulted in a non-conservative minimum critical rod position prediction. As noted earlier however, the moderator temperature was decreasing throughout the test which required new predictions to be calculated. The additional calculations were correct and the initial prediction was never used. The error was corrected in the test results package and reviewers and test engineers were counseled on the need to independently verify all test results. All of these violations were resolved to the satisfaction of the Nuclear Regulatory Commission and none involved a reduction in plant safety.
O l
l O
5-20
5.2.5 Test No. 5 CONTROL ROD DRIVE SYSTEM
( A. OBJECTIVES l 1 Demonstrate that the Control Rod Drive ( CRD) system l operates properly over the full range of primary coolant temperatures and pressures from ambient to
, operating.
I 2. Determine the initial operating characteristics of the CRD system.
B. ACCEPTANCE CRITERIA Level 1 1 1. Each CRD must have a normal withdraw speed less than or equal to 3.6 inches per second ( 9.14 cm/ s e c) , indicated by a full 12-foot 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-e ne rgi zed) .
Position Inserted from Fully Withdrawn Scram Time ( Seconds) 45 0.43 39 0.86 j 25 1.93 05 3.49 l
i 3. The mean scram time of the three fastest CRDs in a two by two array must not exceed the following times:
(Scram time is measured from the time the pilot scram valve solenoids are de-energized).
Position Inserted from Fully Withdrawn Scram Time ( Seconds) 45 0.45 39 0.92 25 2.05 05 3.70' Level 2
- 1. Each CRD must have a normal insert or withdraw speed of
- 3. 0 10. 6 inches per second ( 7. 62 t 1.52 cm/sec).
Indicated by a full 12-foot stroke in 40 to 60 seconds.
5-21 l - - - - . -
a
- 2. With respect to the control rod drive friction tests, if the differential pressure variation exceeds 15 psid (1.1 kg/cm2) for a continuous drive i n. a settling test must be performed, in which case, the differential settling pressure should not be less than 30 paid ( 2.1 kg/cm2) nor should it vary by more than 10 psid (0.7 kg/cm2) over a full stroke.
Level 3
- 1. Upon receipt of a simulated or actual scram signal
( maximum error), the FCV must close to its minimum position within 10 to 30 seconds.
- 2. The CRD system flow should not change by more than 13. 0 gpm- as reactor pressure varies from 0 to rated pressure.
- 3. The decay ratio of any oscillatory controlled variable must be (0.25 for any flow set point changes or for system disturbances caused by the CRD' s being stroked.
C. DISCUSSION Control rod testing was conducted throughout the Power Ascension Test Program. The bulk of the testing was performed prior to fuel loading, concurrent with fuel loading, and in Test Condition Open Vessel. The testing performed on all 185 control rod drives consisted of functional testing, friction testing, and scram time testing. The four slowest control rods encountered during scram time testing with fuel loaded during the open vessel testing were scram time tested three additional times (at Reactor Pressure Vessel pressures of 0 psig, 600 psig, and 800 psig) for trend analysis. At rated reactor pressure.
all 185 control rod drives were again functionally tested and scram time tested, and the four control rods with the slowest scram times encountered in the open vessel testing were friction tested. The four slowest control rods encountered during scram time testing with the reactor at normal operating pressure were then monitored for scram t i mi ng during the planned reactor scrams associated with other power ascension tests. Additionally, during tuneup testing, the control rod drive system flow control valves were verified to properly control flow during normal reactor and system transients. The testing described above demonstrated that the CRD system performance was within all acceptance criteria limits.
O 5-22
All control rods were first functionally tested prior to fuel load with only the control rod blade guides loaded into the core. This was done to identify and correct any problems, and verify proper CRD system operation prior to the actual power ascension testing. The functional checks for each control rod consisted of measuring full 12 foot continuous stroke time in both directions, drive water flow rate verifications at mid stroke, Rod Position Indication System ( RPIS) verifications, and a coupling check. Three control rods required minor speed control valve adjustments at their respective Hydraulic Control Units ( HCU's) to meet the full stroke speed requirements. Nine control rods were noted to have one or more position indication switches which did not properly function during the continuous insert and withdrawals for full length stroke times. However, the conditions were not repeatable. Subsequent strokes of the affected control rods demonstrated proper function for all position switches. This phenomenon occurred with decreasing frequency throughout control rod testing, and it appeared that the position switches had become " frozen" with i na c t i vi t y and required exercising by stroking the associated control rod to restore free switch action. One control rod position indication probe required replacement, but this did not impact the test program.
During fuel load all control rods were again functionally tested in the same manner as before, only this time each rod was tested after the four adjacent fuel bundles were loaded
~' around the control rod. Three additional control rods required minor speed control valve adjustments to meet the full stroke speed and stroke time acceptance criteria.
Friction tests and scram time tests wei e a l t: cs performed i '
for all control rods. The friction test was conducted by measuring the differential pressure between th6 insert and withdraw lines for a given control rod at its HCU during a continuous insert of that control rod. Scram time testing was performed by measuring the elapsed time for a fully withdrawn control rod to reach notch positions "45", "39",
"25", and "05" following a scram initiated locally at the
, HCU for that rod. All the control rods '
satisfactorily I passed the friction test with a ma'ximum differential pressure variation during continuous insert of 13.15 paid.
Because this value was less than the acceptance criteria value of 15.0 paid, settling friction tests were not required. The mean scram times for all 185 control rods were satisfactory and were as follows:
Notch Position Elapsed Time Reauired Time l 45 0.21 see t 0.43 sec
- 39 0.38 sec L 0.86 see 25 0.82 see t 1.93 sec 05 1.52 see t 3.49 sec j 5-23 i
The greatest mean scram times of the three fastest CRD's in a two by two array were also satisfactory and were as follows:
Notch Position Elapsed Time Reauired Time 45 0. 28 see t 0.45 sec 39 0.49 see t 0. 9 2 sec 25 0.90 see L 2.05 sec 05 1.60 sec ( 3.70 see The four slowest control rods, as determined by the scram time testing, were then additionally scram time tested in Test Condition Open Vessel (0 psig RPV pressure) and in Test Conditton Heatup (600 psig and 800 psig RPV pressure). At 0 psig RPV pressure, the scram timing tests were performed with HCU accumulator pressures just above the low pressure atarm setpoint. Scram timing tests at 600 psig and 800 pas J RPV pressure were performed with HCU accumulator pressures in the normal operating band. The greatest scram time to notch position "05" for the four selected rods was 2.581 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.
At normal operating reactor pressure all 185 control rods were again functionally tested and scram time tested with HCU accumulator pressures at normal operating pressure, in a ma r.n e r identical to the previous tests. No control rod speed control adjustments were required, nor were any other problems encountered except for an occasional control rod pos1*1or indication switch not indicating. The
" sticking" switcher would function properly on subsequent strokes of the associated control rod. The mean scrim times for all 185 control rods were satisfactory and were as f ollows:
Notch Position Ela.*.ed Time Reauired Time 45 O.26 see t 0.43 sec 39 0.54 see t 0.86 sec 25 1.24 see L 1.93 sec 05 2.27 see t 3.49 see The greatest mean scram times of the three f astest CRD's in a two by two array were also satisfactory and were as f ollows:
Notch Position Elapsed Time Reauired Time 45 0.32 see t 0.45 see
. 39 0.61 see t 0.92 soc 25 1.32 see L 2.05 sec 05 2.45 see t 3.70 sec 5-24
Additionally, the four control rods with the slowest scram O times encountered satisfactorily during open friction tested again, vessel observed differential pressure variation of 12.50 paid.
testing were with a maximum Because this value was less than the acceptance criterion valve of 15.0 paid, settling friction tests were not required.
The four slowest control rods encountered during scram time testing with the RPV at normal operating pressure were monitored for scram times during the planned reactor scrams associated with power ascension tests " Shutdown From Outside the Control Room", "
Loss of Offsite Power", "MSIV Full Isolation", and Full Power Generator Load Rejection". All scram times observed for the four selected control rods were less than 2.70 seconds for insertion to position 05, and no unusual or abnormal trends in the scram times were noted.
During system tuning the CRD flow controller response was verified to meet all acceptance criteria in Test Condition Heatup. The "A" CRD flow control valve ( C11 -F002 A) was discovered to have binding occurring in its pneumatic positioner which resulted in erratic valve motion and poor flow control characteristics. The entire pneumatic operator was replaced, and the "A" flow control valve then functioned properly. Both the "A" and the "B" CRD flow control valves were monitored during pressurizations of the RPY from 0 psig to rated pressure to ensure that the CRD system flow was O.-
controlled within a t3.0 gpm band around the 69 gym flow controller setpoint. Flow control valve closure times in response to a scram condition were also verified to be within the 10 second minimum and 30 second maximum allowable
=. values. System oscillatory response to the stroking of a CRD was verified to demonstrate a decay ratio of equal to or less than 0.25. A summary of the flow controller test results follows:
"A" / Flow "B" Flow Parameter Control Valve Control Valve Reauired Flow Deviation Over (2.0 gym (1. 0 gym (3.0 gpm the RPY Pressure Range closure Time From 19.8 see 16.0 (10-30) see Scram Initiation Decay Ratio Response 0. 0 0. 0 10.25 for Control Rod Motion Final CR0 system flow controller ( C11-R600) settings were ss follows:
Gain 0.06 Reset 40.0 O The CRD system testing was completed with all d ri ve s and the flow control system meeting all acceptance criteria.
control rod 5-25
l Table 5.2.5-1 SCRAM TIMES OF FOUR SELECTED CRDS DURING PLANNED SCRAMS Hr! TC-3 Sele: n F sitica Ninhai TC-1 70-2 Lassaf TC-6 TC-6 4:a Irsettea D 3:raa Lass of T/s Shtdawn Offsite M51V Full (.3ad L3cattan to Tiun; & Offsite PWR Fras 0/3 CR Pcwer Isolation 4ejectica 26-23 45 0.482 0.244 0.252 0.244 0.280 0.252 39 0.800 0.544 0.555 0.!!! 0.571 0.524 25 1.!63 1.227 1.247 1.247 1.271 1.t63
- 9 4 n t. . . .ee 9.
. .s.t 7 6.536 . . e.8 < ?
. . u. . .t 3. t .a.t 42-15 45 0.272 0.248 0.243 0.256 0.292 0.260
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- 5. 2. 6 Test No. 6 SOURCE RANGE MONITOR PERFORMANCE O
(j A. OBJECTIVES
- 1. Demonstrate that the neutron sources, SRM instrumentation, and control rod withdrawal sequences provide adequate information to achieve criticality and increase power in a safe and efficient manner.
- 2. Demonstrate that the SRM detectors do not saturate below 300,000 c ps.
B. ACCEPTANCE CRITERIA Level 1
- 1. There must be a neutron signal count-to-noise count ratio of at least 2: 1 on the required operable SRM channels.
- 2. There must be a minimum count rate of either 3. 0 counts /second or 0.7 counts /second ( with a signal-to-noise rati ot2. 0) on the required operable SRM channels.
Level 2 None C. DISCUSSION Prior to initial criticality, the signal-to-noise ratio and minimum count rato of cach SRM channel were determined to be within test criteria limits. In TC-Heatup, the adequacy of the SRM response to control rod wi t hd ra wal was verified during the approach to initial criticality.
Following initial criticality, the SRMs were demonstrated to meet the system non-saturation design requirements.
To assure that the SRMs were functioning properly prior to withdrawing control rods to achieve initial criticality, the minimum count rate and signal-to-noise ratio of each SRM channel were measured. The signal-to-noise ratio ( S/ N) was determined by recording the channel readings with the SRM detector fully inserted into the core and in its fully withdrawn position. The results are summarized b elow:
Minimum Count
.S_Rji Rate ( cos) 3/_F_
A 69 689:1 B 55 549:1 C 71 472: 1 l 23 D 229:1 I
l 5-27
- v As control rods were wi thdra sn to achieve criticality, SRM count rate data were plotted against the total number of notches of all withdrawn rods. The results demonstrated that the SRMs adequately monitor core reactivity changes to achieve criticality in a safe, efficient manner. Inverse multiplication data were also plotted to further assure that criticality would be achieved in a controlled manner.
Following ini tial criticality, reactor power was increased, with the SRMs partially wi thdrawn, such that the fully inserted SRM neutron flux reading would be greater than 300,000 cps. Each SRM channel was bypassed and its detector inserted i ndi vi d ua ll y, until a reading of at least 500,000 cps was indicated and then the detector was withdrawn to its original position. All SRM channels were demonstrated not to saturate ut up to 500,000 cps. Upon completion of the non-saturation demonstration, the SRM rod block and scram set points were raised one decade to the normal Technical Specification values of 100,000 cps and 200,000 c ps, r e s pe c t i ve l y. 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.
O a
O 5-28
j 5.2.7 Test No. 8 INTERMEDIATE RANGE MONITOR PERFORMANCE j A. OBJECTIVES
- 1. Assure that adequate overlap exists between the SRMs
! 2. Verify the range correlation between the low and high j frequency IRM channels ( ranges 1 through 6 and 7 through 10).
{
B. ACCEPTANCE CRITERIA j Level 1 i
{ 1. Ea'ch IRM channel must be on scale ( L1. 6 on Range 1) i before the SRMs exceed their upscale rod block ( slarm)
} setpoint ( ti x10 5 cys).
4
- 2. Each APRM must be on scale ( L45) before the IRMs exceed i their upscale rod block setpoint on the highest range l (108/125 on Range 10).
]
i Level 2 l 1. Each IRN channel should be adjusted so that at least a l
! half decade overlap with the SRMs is assured (IRM !
( ti.6 on Range 1, SRM <3.16 x 10 4 cys).
l j 2. Each IRN channel should be adjusted so that at least i one decade overlap with the APRMs is assured ( APRM L45,
! IRH (108/125 on Range 8).
l l C. DISCUSSION This test was performed several times during the Power i Ascension Test Program, initially in TC-Heatup and the final.
performance in TC-6 during a scram recovery. Except for IRM D, all IRMs were successfully adjusted to meet the test j criteria. IRN D was inoperable at the time the final )
IRM/APRM overlap verification was performed and will be checked, using station procedures, when it becamos operational.
l In TC-Heatup, the IRM voltage preamplifiers were successfully adjusted to obtain the desired continuity between the low frequency ranges ( ranges 1 through 6) and the high frequency ranges ( ranges 7 through 10). The desired correlation between ranges 6 and 7 is that the range 7 reading be within t55 of the range 6 reading divided by
- 10. When the range correlation is properly adjusted, the reactor operator should see, at most, only slight changes in O the IRM readings when moving the IRM range switches between ranges 6 and 7 5-29
The SRH/IRM overlap and IRM/ApRM overlap are interrelated because an IRM gain change made to improve one overlap will alter the other overlap correlation. Therefore, whenever an IRN gain change was made to achieve the desired overlap at one end of the IRM operating range, the overlap at the other end of the operating range was rechecked to assure its adequacy. Several iterations were required before obtaining the final IRM gain adjustments which provided overlaps that satisfied the Level 2 criteria for both ends of the IRM operating range. Satisf action of the Level 1 criteria and Technical Specifications requirements was always achieved on the required operable channels.
During the final performance of this test, in TC-6, the S R M/ I R M, , overlap for all channels was successfully demonstrated to satisfy the Level 2 criteria. In order to demonstrate this overlap, the SRM detectors had to be partially withdrawn, with the concurrence of General Electric, due to the high sensitivity of these detectors.
The IRM/ApRM overlap was also found to satisfy the Level 2 criteria requirements for all channels except IRH D. IRM D was inoperable at the time the final IRM/APRM overlap verification was performed and will be checked using station procedures when it becomes operable. A final set of mean square analog circuit voltage measurements was taken and the results were incorporated into the station IRH channel calibration procedures for subsequent verification of the IRM gain settings.
The primary problems encountered during the performance of this test were associated with inoperable IRM channels due to connector problems and failed detectors. Testing was repeated several times in an attempt to simultaneously demonstrate proper overlap among all the channels. Each time the overlap demonstration was performed there was at least one inoperable channel which required preparing a deficiency report and re-performing the test, as noted above for IRN D.
O 5-30
(
L
s
-s 5.2.8 Test No. 9 LPRM CALIBRATION
-- A. OBJECTIVES 1 Calibrate the Local Power Range Monitoring ( LPRM)
System.
- 2. Verify proper connection of the LPRM chambers and functional operation of the associated electronics.
B. ACCEPTANCE CRITERIA Level 1 None Level 2 Each LPRM reading will be within 10% of its calculated value.
C. DISCUSSION The LPRM system was successfully checked for proper electrical connection and operation, and calibrated in Test Conditions - Heatup, 1, 3 and 6. Various system problems, including a failed detector, prevented the final calibration
(~N
() in Test Condition 6 of five LPRM channels.
In TC-Heatup, the verification of proper connection of the LPRM detectors, and functional operation of the associated a electronics, was performed in conjunction with control rod
~
scram testing. As an adjacent control rod was withdrawn, the LPRM channels were monitored for a response to the change in neutron flux. No response could be discerned for LPRM channels40-098, 16-33B, 16-49A, and 24-57C.LPRM 40-098 has a bad detector and the other channels had problems with their power supplies and amplifier cards. All channels except 40-098 were corrected and latcr sucessfully checked for proper response.
In TC-1, the LPRM channels were calibrated in accordance I with the Reactor Engineering surveillance procedure, using l the process computer and TIP System to obtain Gain l Adjustment Factors ( G AF) . The amplifier gain for each LPRM detector was adjusted to provide an output voltage of eight times the GAF for an as-found amplifier input calibration current. The final GAF values were used to determine how well the acceptance criterion was satisfied ( 0. 90 G aft 1.1)
O 5-31
During the performance of this test in TC-1, 17 out of 172 LPRMs did not meet the Level 2 acceptance criterion. Their final GAF values did not fall within 10% of their expected value of 1. The reasons for failing to meet the cratorion for most of the channels in this group of LPRMs include:
- 1. Feedwater flow oscillations during the performance of the test which resulted in a less accurate thermal power calculation.
- 2. The LPRM calibration was performed at very low power (approx. 17.5% of rated) thus affecting the accuracy with which the LPRH meters could be read ( primarily A&D levels).
The LPRH input currents of these seventeen channels to their respective APRM and LPRM groups were bypassed and the APRM gains readjusted. In TC-3, the LPRM detectors were again successfully calibrated. This time, four LPRM detectors were inoperable. Two of these four were also inoperable in TC-1. The LPRM inputs to the respective APRMs of these four LPRH channels were also bypassed or remained bypassed.
In TC-6, all LPRM channels except for five were successfully calibrated. Most channels required minor gain adjustment.
Of the five inoperable channels, three were also inoperable in TC-3 ( 40-09 B,24-498, 08-49D). At the time of this report, LPRM 24-49B is under investigation, and LPRH 40-098 has been determined to have a bad detector. The other three LPRM channels were corrected, and were calibrated during the next scheduled performance of the surveillance procedure.
During performance of the APRH calibration in TC-Heatup ( see Test No. 10), the LPRHs with inputs to APRH channels C and E were found to have gain adjustments based on amplifier input currents of 80 microamps rather than the specified initial value of 400 microamps. Later, during the same APRH calibration test, all of the LPRH gains were re-adjusted with the more appropriate input current value of 700 microamps. These gain adjustments were all completed prior to performance of this LPRH calibration procedure.
O 5-32
,. 5.2.9 Test No. 10 APRM CALIBRATION
/ \
Cl A. OBJECTIVES
- 1. Calibrate the Average Power Range Monitoring System.
- 8. ACCEPTANCE CRITERIA Level 1
, 1. The APRM channels must be calibrated to read equal to I
or greater than the actual core thermal power.
- 2. Technical Specification and fuel warranty limits on APRM scram and rod block shall not be exceeded.
- 3. In .the startup mode, all APRM channels must produce a scram at less than or equal to 155 of rated thermal power.
Level 2 If the above criteria are satisfied, then the APRM channels g- will be considered to be reading accurately if they agree (3
) with the heat balance or the minimum value required based on peaking factor, MLHGR, and fraction of rated power to within
( +7. -01 % of rated power.
C. DISCUSSION
- 4 _
This test was performed in Test Conditions - Heatup, 1, 2, 3, 5, and 6. In TC-Heatup, several manual heat balance calculations were performed duris.g a constant rate heatup, results were compared to the assocAated APRM readings, and the APRM gains were adjusted as required. In Test Conditions 1 through 6, the APRM channels were successfully calibrated using the Reactor Engineering surveillance
- procedure.
During performance of this test in TC-Heatup, the gains of approximately 50% of the LPRM inputs into APRM Channels C and E were found to be improperly set with 80 microamps rather than the specified input current value of 400
, microamps to achieve an 8 VOC output. After correcting I
their LPRM input gains, the gains of APRM channels C and E were adjusted so that the monitors would read the average of i
the other APRM channels.
5-33
Later, it was found that the APRH channels over-indicated even with the APRM gains set at minimum. The LPRH calibration currents were then changed from 400 to 700 microamps which reduced the LPRM gains and allowed the APRH gains to be appropriately adjusted. The plant was shutdown before the APRH adjustments could be made so they were accomplished during the shutdown with a technique which utilized the calibration data and a standard APRH input current.
In TC-2, a scaling f actor of 1. 073 was applied to the APRH gains as per Technical Specification 3.2.2 when Fraction of Rated Thermal Power ( FRTP) was less than Core Maximum Fraction of Limiting Power Density ( CHFLPD) .
While in TC-5, the test had to be repeated because four of the APRH channels indicated less than core thermal power.
Level 1 criteria for the startup test specifies that APRM readings must be greater than or equal to core thermal power, and Level 2 criteria specifies that any difference must be limited to -01, +7% of core thermal power. The Reactor Engineering procedure which calibrates the APRH's specirles that the difference be within 12% (the Technical Speci fication requirement) . It was recognized at the outset of the Power Ascension Test Program that the startup test's criteria were more stringent than the calibration procedure's criteria at the lower end of the allowable band and that the difference in criteria would have to be taken into account during APRH calibration. However, the A P R H' s were inadvertently calibrated only to the Reactor Engineering procedure criterion such that during the first performance of this test in TC-5, four of the APRH channels did not meet the Level 1 and Level 2 Power Ascension Test procedure acceptance criteria. The four APRH channels were subsequently recalibrated to satisfy both criteria.
During each of the APRH calibrations, the APRH scram and rod block trip getpoints were verified to be at their correct values by reviewing the most recent performances of the !&C functional tests.
All acceptance criteria have been met. No outstanding issues remain.
O 5-34
5.2.10 Test No. 11 PROCESS COMPUTER A. OBJECTIVES To verify the performance of the Nuclear Steam Supply System
( NSSS) and Balance of Plant (BOP) process computer programs under plant operating condition.,
B. ACCEPTANCE CRITERIA Level 1 None Level 2
- 1. The MCPR calculated by BUCLE.and the process computer ei t her:
- a. Are in the same fuel assembly and do not differ in value by more than 25, or
- 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 25.
- 2. The maxtmum LHGR calculated by SUCLE and the process computer either:
- a. Are in the same fuel assembly and do not d'ri'or in
, value by more than 25 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 25.
- 3. The MAPLNGR calculated by BUCLE and the process computer either:
l
- a. Are in the same fuel assembly and do not differ in value by more than 25, or i
- b. For the case in which the MAPLHOR calculated by the process computer is in a different assembly than that calculated by BUCLE, for each assembly, j the MAPLHGR and APLHGR calculated by the two j methods shall agree within 25 l
- 4. The LPRM calibration factors calculated by BUCLE and the process computer agree to within 25.
5-35
C. DISCUSSION Introduction This test was performed in Test Conditions Open Vessel. 1, 2, 3 and 6. Test conditions included both steady state.and non-steady state reactor power. The test method wa6 to compare indiv! dual process computer software results to applicable plant parameters and/or hand calculations to verify software and hardware operability. Overall test results were satisfactory.
Test Condition Open Vessel
- In Test Condition Open Vessel, the preliminary process computer test was performed, including the OD-1 Static System Test Case, OD-1 Response to Control Rod Motion during a TIP Traverse, and the OD-1 verification using simulated inputs. This testing verified that the 00-1 program recognizes related errors, and outputs the appropriate error messages, warnings and edits. Several small problems in the program softwarv were encountered and resolved durtr.g the Static System Test Case. The test was put on hold four times during the 00-1 verifiestion using simulated fnput due to TIF machtne problems. The problems included inoperability of stveral of the TIP machines, exceeding the maximum number of pulses in TIP machines A. B, and C, and inoperability of the Veeder Rooter counter. Through repairs and replacement, all of these pro'olems were resoty4d. The test was successfully completed, resulting in a (unctional process computer /TIP machine interface.
Test ConditLon One In TC-1, the interface between the process computet and the TIP System was verified to be functioning properly at low power ( approximately 20% of rated) . During the test. 0D-1 was run while a complete set of TIP tvaverne d a' t a , X-Y plotter TIP traces, and 1 inch TIP data were obtained. A software patch was added to the TIP Scan program to store the i anch TIP data. The 1 inch T!P data was used to verify that the proper number of unscanned TIP nlevations existed for the TAV calculation, and that th6 propor extrapolation was performed. The 1 inch data was also intended to confirm that the TIPS.were axially aligned on the 4th apacer grid.
Due to TIP d69nal depronston not being' large enough to accurately locate the 4th spacer prid at the low power
(<200 at which the test was p e r f o r e1e d , this confirmatton could not be accomplished. Reactor Enginuarings as reperforming the test at near rated pcwor to identify 'the location of the 4th spacer dip and will reftne the axial alignment of the TIP and set the final core bottom, core top, and core scan range constants as necessary. The 00-1 TIP data was ver101ed against the actual X-Y ulotter TIP traces and hand calculations. At the time of the test, 5-36 1
h -
f several L P R M' s read zero due to detector or electronics j -
5;oblems. This did not adversely affect the OD-1 veri fi ca ti on. In addition, the Veeder Rooter counter required replacement to correct an " extra pulse" condition
, on channels 4 and 5 of TIP machine C. In order to complete p '
/ t a sj OD-1, core top was moved down one notch for these affected the thermal limit calculations for strange. This 63 ^
these strings and associated bundles, but was negligible at s less than 505 power.
q The counter was later fixed, and the core top was returned to its correct value. OD-1 was 1 y d +cuccessfully tested and found to be fully operational.
D pamic '3vstem Test Case
/ 'i The , Process Computer Dynamic System Test Case ( DSTC)
['
verifles the performance of the NSSS Computer Programs under
- g*, ~- plant operating conditions by a step-by-step verification of the programs using hand calculations, input variable
, verifications, comparison of the outputs of related programs,, and. comparison with an approved off-line computer
, , program ($UCLE). The testing was performed in TC-1 TC-2,
^
and TC-3,'and included:
- 1. Verification that plant sensor inputs for Core Thermal Power Heat Balance, Control Rod Positions and LPRM r
readings, functioned properly.
2.
( ,
Verification of reactor core thermal limits calculated by P1 ( Periodic Core Evaluation) against BUCLE, with and without core exposure.
i T
- 3. Verification of the heat balance calculation used by
! OD-3 and P1 against a manually calculated heat
,/ '
balance.
i 4. 00-1 verification following an LPRM calibration.
l j 5. Vertricat)on of the exposure updating programs P1
! ( Periodic _ Core Evaluation), P2 ( Daily Core Performance
! j. S umma r y) ,' P3~(Monthly Core Performance S umma r y) , and P4
,/ (10 Minute Corw Energy Increment) .
1 l / 6. Proper functioning of the P1 and P5 ( Drif ting LPRM j
', , 'Diagnostid irterface, t
i 7. Verification of the remaining NSSS programs through p .I ' hand calculations and inputting variables.
l '
The test was intended to be performed at relatively constant
- isteady state plant conditions throughout the duration of the
! , ) tese. This was not possible due to changing plant I
donditions. Also, some computer input associated hardware l e did' not function as' initially designed. These problems l- f,Mffected g the straight forward performance of the test, but did not invalidate the results.
The procedure was segmented f
/
- 5-37 l ,
! , 1 i
to allow testing of the various sections separately when necessary inputs were made operable, and the proper initial conditions existed. With the exception of two items, all test problems were resolved. First, the proper operation of the JCOUNT software, which calculates the energy accumulation in the P4 program, could not be verified because the main generator megawatt pulse counter signal was I inoperable. The energy accumulation was determined by an alternate method using the generator megawatt output. When the pulse counter signal is available, the proper operation of the evergy accumulation sof tware will be verified by Reactor Engineering. Except for the JCOUNT software, the proper operation of P4 was verified. The second item involves plant sensors required for heat balance and OD-3 checks. This check was done when feedwater temperatures ;
, were below 300oF and a gai n when they were greater than 300oF. Enring the latter check, the difference in the heat balance and OD-3 values for feedwater flow, core pressure drop, and recirculation dri ve flow were greater than the required 5% limit. The first two problems have been corrected. Low feedwater temperatures caused the large deviation i n calculated feedwater flows. ' The appropriate sections of the test,were repeated at higher feedwater temperatures, and yielded satisfactory results. The core plate pressure drop signal in the process computer had an incorrectly' scaled range. The software was modi fi ed to change the upper end of the. instrument span f rom 100 psid to 30 psid to agree wi t h the instrument calibration. After the reteq1, the recirculation drive flow indicator "B" was reading 1% low, while "A" was reading 3.5% low. A work order pas written to recalibrate the recirculation flow indicators. Also, new substitute values of drive flow versus core flow were input to the P-1 program to agree with measured test data. All of the tested programs are now considered operational. All acceptance criteria were satisfied.
Test Conditions Three and Six In TC-3 and TC-6, verification of the OD-3 and P-1 programs at higher reactor powers were performed. OD-3 was compared to a manual heat balance calculation. The OD-3 Reactor Power was within 0.04% of the manually calculated power, satisfying the criteria of +2%.
l Symmetric and asymetric P-1 cases were also run, and
.. compared to corresponding calculations using the BUCLE
- program, and the results compared with the acceptance I criteria. Thermal li mi t s results are summarized in Tables
! 5.2.10-1 and 5.2.10-2. The percent difference in bundle powers was required by criteria ,to be LS% RMS. This l criteria was satisfied with Symmetric P1 versus Asymmetric P1 differing by 4.53% RMS, Symmetric P1 versus Symmetric BUCLE differing by 1.05% RMS, and Asymmetric P1 versus Asymmetric BUCLE differing by 0.47% RMS. The GAF ( gain 5-38 l
=.
adjustment f actor) comparison criteria was not met for one
) LPRM (2.065) in TC-3. All other LPRM GAF comparisons were
! d within the 25 criteria. The resolution of the criteria failure was to accept it, as is, since the 0.06% deviation was only on one LPRM, and was not significant to indicate i any problem with the process computer software. The OD-3, P-1 symmetric and asymmetric programs all operated properly at mid and high power levels.
Also, in Test Condition 3 several on-demand programs were tested during changes in reactor power and flow. OD'-4 and OD-5 make power distribution estimates to obtain new estimated values of tharmal limits. Edits of these programs were demanded and compared against P-1 and OD-6 before and after a 25% power change after plant conditions stabilized.
The ODT 4 'MFLPD values were not within 5% of the OD-5, P-1, and OD-6 MFLPD values. There was no acceptance criteria associated with this, but the problem was investigated and resolved by GE computer personnel. The operation of OD-4 was retested and verified to be within the 5% procedural limit for rod moves limited to 2-4 notches. OD-4 should not be used for large power changes.
- OD-18 automatically updates the LPRM Alarm Trip Settings
, after a gross change in core flow or if demanded by OD-19,
- which normally demands a new LPRM scan after a control rod
()
! movement or gross change in pcwcr and only de.iisnde OD-18 if
! the new scan results in an LPRM alarm trip. Both OD-18 and OD-19 were successfully demonstrated by verifying that 4 proper response to core power and flow changes were obtained, and that the new high and low core power / flow
. : setpoints were properly calculated.
a Although not required by the FSAR, the OD-11 program
( Preconditioni ng Interim Operating Management Re c omme nda ti ons) was tested to verify proper operation for i its subsequent use in implementing and monitoring station I
administrative limits on reactor power increase and core operation. In TC-3 at approximately 72% of rated power, the proper data interrogation, envelope updating, predictive overpower, and automatic alarm and initiation functions of the OD-11 program were statically verified.
The dynamic verification of the OD-11 programs ability to provide preconditioning ramp monitoring functions, including automatic envelope updates during a power increase ramp, was performed in TC-6 at 99% of rated power. During the test it was noted that the recommended value for the minimum peak pin power for which pre-conditioning data is stored
( PCIKON( 1) ) was 7.945 when the value could actually be increased to 8.445 since the Hope Creek core contains all pre-pressurized fuel. The value was increased to 8.445 in
' () the preconditioning process computer data bank.
successfully demonstrated.
ramp monitoring functions Proper operation of of OD-11 the were 5-39
Table 5.2.10-1 THERMAL LIMIT COMPARISONS IN TC-3 Acceptance l l l P-1 l Symmetric l BUCLE l Symmetric l l
Criteria l%
Difference!. Location l P-1 l. Location l BUCLE l
. _ _ _ _ _ _ _ _ _ _ _ _ _ _ , _ _ _ _ _ _ _ _ _ _ _ _ , _ _ _ _ _ _ _ _ _ .,__________i_________ _ _ _ _ _ _ _ _ _ _ , .
l MCPR L 2% l 0.70 l 29-10 l 2.153 l 29-10 l 2.138 l l LHGR L 25 l -0.60 l 20-10-5 l 8.18 l 29-10-5 l 8.23 l
- l. HAPLHGR L 2% l. -0.70 7.08 l 29-10-5 l 7.13
. _ _ _ _ _ _ _ _ _ _ _ _ _ _ , _ _ _ _ _ _ _! _29-10-5 !. l
_ _ _ _ .._________i_____________________________. .
l Acceptance l l P-1 l Asymmetric l BUCLE l Asymmetric l l Criteria l% Difference! Location l P-1 l Location i BUCLE l
______________,____________.____________________________i__________.
l MCPR L 25 i~ 0.00 l 39-44 l 2.069 l 39-44 l 2.069 l l LHGR L 2% l -0.11 l 31-52-4 l 8.97 l 31-52-4 l 8.98 l l MAPLHGR L 2% l. -0.13 l 31 4 l . 7.75 l 31-52-4 l 7.76 l
.i ______________i____________
Table 5.2.10-2 THERMAL LIMIT COMPARISONS IN TC-6 l Acceptance l l P-1 l Symmetric ! BUCLE l Symmetric l l Criteria l% Difference l Location l P-1 l Location l BUCLE l
______________,____________i_________i__.._______ _________i__________
l MCPR L 2% l -0.48 l 21-18 l 1.465 l 21-18 l 1.472 l l LHGR L 2% l 0.35 l 21-18-10l 11.53 l 21 10l 11. 4 9 l l MAPLHGR L 2% l .
- c. 4 3 l 39-46-9 l 9.27 l 21-16-9 l 9.23 l l Acceptance l l P-1 l Asymmetric l BUCLE l Asymmetric l l Criteria l% Di f f erenceli Loc a ti onl P-1 l Location l BUCLE l
.______________,_____________________.__________e
. . i i i_________i__________i l MCPR L 2% l 0.22 l 15-36 l 1.384 l 15-36 l 1.381 l l LHGR L 2% l -0.41 l 37-16-8 l 12.20 l 37-16-8 l12.25 l
- l. MAPLHGR L 2% l. -0.20 l 45-40-8 l 9.84 l 45-40-8 l 9.86 l
. _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . _ _ _ _ _ _ _ _ _ _ _ _ _ _ _.___________________i e
5-40
s 5.2.11 Test No. 12 REACTOR CORE ISOLATION COOLING b
A. OBJECTIVES
- 1. Demonstrate the proper operation of the Reactor Core Isolation Cooling ( RCIC) system over its expected operating pressure and flow ranges.
- 2. Demonstrate RCIC system reliability in automatic starting from cold standby when the reactor is at power conditions.
B. ACCEPTANCE CRITERIA Level 1
- 1. The average pump discharge flow must be equal to or greater than the 100% rated value (600 GPM) prior to exceeding 30 seconds from automatic initiation at any reactor pressure between 150 psig ( 10. 5 kg/ cm2) and rated.
- 2. The RCIC turbine shall nct trip or isolate during auto or manual start tests.
Level 2 1 In order to provide an overspeed and isolation trip avoidance margin, the transient start first and subsequent speed peaks shall not exceed 5% above the rated RCIC turbine speed.
--. 2. The speed and flow control loops shall be adjusted so that the decay ratio of any RCIC system related variable is not greater than 0.25.
l l 3. The turbine gland seal condenser system shall be l capable of preventing steam leakage to the atmosphere.
i
- 4. The delta P switches for the RCIC steam supply line high flow isolation trip shall ,lus calibrated to actuate between 272% and 300% steam flow, and the value entered in the plant Technical Specifications.
C. DISCUSSION The RCIC system testing consisted of a series of tests to demonstrate overall system dynamic performance. Automatic system " quick-starts" and 10% flow controller step changes with the system in operation were utilized to insure that the RCIC control system was tuned for optimum system i response throughout both the normal pump flow range and the l normal turbine steam supply pressure range. At the l completion of the preliminary tests, automatic starts of the RCIC system from cold conditions ( system secured for greater 5-41 1
l than 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />) with reactor steam dome pressure at 150 psig, !
and again with dome pressure at rated conditions, were performed to demonstrate the s ys t em' s reliability. At rated reactor pressure, the RCIC pump was to be run at rated flow !
until either the turbine and pump temperatures stabilized or '
until two hours of continuous operation had elapsed to demonstrate that all temperatures and vibration levels would remain within operational li mi t s. Additionally, the RCIC steam line flow element delta-P values at rated pump flow, reactor at normal operating pressure, were measured so that the steam line break Technical Specification system isolation setpoint could be determined.
The RCIC system was tuned and tested in Test Condition Heatup and Test Condition 1 in four basic configurations.
Those ccnfigurations were as f ollo ws:
- 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.
In all, a total of 10 separate tests were conducted to demonstrate RCIC system performance so that all acceptance criteria could be properly evaluated. Table 5.2.11-1 summarizes the results of those tests and Section 6. 7 describes the control systems tuneup program.
j Overall RCIC system performance was excellent. Rated flow l (600 g pm) was always obtained wi thin the specified time l
limit ( L3 0 seconds), and oscillatory behavior in the controlled process variables was essentially nonexistent.
Turbine exhaust check valve chatter was not observed at any turbine speed. The turbine gland seal system properly prevented steam leakage from the seals. RCIC turbine and l pump bearing temperatures stabilized af ter apt oximately 1. 5 i hours of continuous operation at rated pump fr9w (reactor l steam dome pressure at rated), and all turbine and pump i bearing temperatures and vibration levels did stabilize I within operational limits for those parameters. All l acceptance criteria were satisfied in all the system
! configurations with the exception of the maximum allowable
( RCIC pump turbine speed. On automatic starts with injection to the CST and the full flow test valve pre-positioned to throttle pump discharge to achieve a head approximately 100 psig greater than reactor pressure with the RPV at rated i
pressure, peak turbine speeds of 4800 RPM and 4750 RPM were l
l 5-42
obtained. -These speeds exceeded the Level 2 criterion of 4725 RPM. Control system and overall system behavior in all O other aspects met the acceptance. criteria.
data associated with the excessive turbine speeds The transient was determined by the vendor to be acceptable because a liberal margin. to the RCIC turbine trip setpoint of 5625 RPM still existed and also because_the peak turbine speed observed when injecting to the RPV was 4500 RPM, a value well wi t hi n
, the acceptance criteria. The criteria deficiency issue was closed, based upon this evaluation.
As previously mentioned, the RCIC, system steam supply flow element delta-P values were measured ~following an automatic
" cold quick-start" of the system with injection to the RPV at rated steam dome pressure. Based upon that data, RCIC system steam line flow element delta-P values corresponding to 272% and 300% rated RCIC steam line flow were extrapolated. The test data are being reviewed by Site Engineering for determination of the Technical Specification setpoint for the RCIC system high steamline flow (line break) isolation.
The final RCIC system controller settings were as f ollows:
1 RCIC Flow Controller Proportional Gain 0.11 (0.15 indicated) j Integral Gain 40 (30 i ndi c a t e d)
Ramp Time 10.5 seconds
- 2. RCIC Woodward EGM Turbine Controller Gain 0.70 Stability 7. 2
- u. EGR Needle Valve 1/2 turn open from full closed I
O 5-43
U Table 5.2.11-1
SUMMARY
OF RCIC SYSTEM TESTING
..................................................... -- - -- ...............===- =................
- RPV :iCICPCMPl l!YFECF .-----__-
RCIC l IIME ID : FEAK
. .-T.: . .o, . , r. . . . , , g :, ,,nun
, .:::v. . . . . .m , , .... , I N, tu1J. .. . eJ ,' U1 ICh- ,i In.n.rN ti- u i To..c: Jr : , G- n.tLu'i LrNae. < a- - -
ttun , ,
-- L , L u e> r x-c 'o. . .i;;::g".;,
a '
e.1 c.i41i .i 1, [ p '. . p '.'" p.:n
.a - e. .m.. . .
+
. .e 1. . .. , in. .
..a ' ' '
. L:. Ap s :: '. : . .v. J
,. p r. .
i i
' , ;:q, s 9 I I I t i . 8
.........+....i..........~ - - = . . .
.........n.........n- __ =.. ........... --- _ s-- .
a 7/9/!6 W .
152 l 275 CSI l h0T l N0 l !!.2 l 2500 l OE l GE N/A -
i e . . . . i > i e .
c60 5 i l HOT 4s?0 sdNE 5555 ~57-
...........'...........'.........i.........'...........'..........'..............'.........'......,....
'......... ....*. =ve0
, 7 / a,,/ e.s,n
. . . .,) .,
.i Ln .w ,.
nv ,. H0# No.
3 t0.vn ,. 4416 h..N,-
u:
e h,uh.c .
i 4,-
, . . . . i i . e lI5575E 95s c60 CSI HUT h~56~!~ii I ~Ii56-i' GE ! " U55 ~ ~ 5IA
'.n.d.t4..'....'..........i...........+ -- n a
'..-- --- o .......... '....- -- -
s.........'..........-
7/30l!6 nV l 040 ; CG) l --R?V ! COLD ; NO l 20.0 l 4360 l OE l OE : EAT ,
7, a. ' a, .
'.... ..........'...........n tca : i
.....n--
--.o i
o ...........i.- --- =' .- - - -
i '
i n...
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G 5-44 1
5.2.12 Test No. 13 HIGH PRESSURE COOLANT INJECTION SYSTEM r
A. OBJECTIVES
- 1. Demonstrate the proper operation of the High Pressure Coolant Injection ( HPCI) System over its expected operating pressure and flow ranges.
- 2. Demonstrate HPCI system reliability in automatic starting from cold standby when the reactor is at rated pressure conditions.
B. ACCEPTANCE CRITERIA Level 1
- 1. The average pump discharge flow must be equal to or greater than the 100% rated value prior to exceeding 27 seconds from automatic initiation at any reactor pressure between 200 psig (14.1 Kg/cm2) and rated.
- 2. The HPCI turbine shall not trip or isolate during auto or manual start tests.
Level 2
~ 1. In order to provide an overspeed and isolation t ri p avoidance margin, the transient start first peak shall not come closer than 15% (of rated speed) to the 3
overspeed trip, and subsequent speed peaks shall not be greater than 5% abovo the rated turbine speed.
- 2. The speed and flow control loops shall be adjusted so that the decay ratio of any HPCI system related variable is not greater than 0.25.
- 3. The turbine gland seal condenser system shall be capable of preventing steam leakage to the atmosphere.
- 4. The delta-P switch for the HPCI steam supply line high flow isolation trip shall be calibrated to actuate at between 272% and 3005 steam flow, and the value entered in the Plant Technical Specifications.
C. DISCUSSION Testing of the HPCI system was similar to the testing performed on the RCIC system. Flow setpoint step changes as well as hot and cold automatic " quick starts" were performed to demonstrate proper system dynamic performance. In TC-Heatup all testing was performed via the full flow test line O to the Condensate Storage Tank ( CST) ,
tuning was limited primarily to the turbine TC-3 the HPCI system controls were tuned and control system controls. In to their final 5-45 l
V settings while injecting to the reactor pressure vessel prior to performing the final demonstration tests summarized in this section. Upon completion of the final demonstration j
tests in TC-6, all HPCI system acceptance criteria were satisfied. Table 5.2.12-1 summarizes the principal results of the HPCI testing and Section 6. 7 provi d e s additional discussion of the control systems tuneup program.
The results of the HPCI automatic quick start to the CST in Test Condition Heatup satisfactorily met all acceptance criteria. The time to rated flow at rated pressure was 26.6 seconds with a Level 1 criteria limit of 27 seconds. The HPCI step change testing to the CST did not pass the acceptance criteria of a maximum decay ratio of 0.25. Due to this criteria failure and the small margin to the time to rated flow criteria, ramp generator adjustments were made which improved subsequent performances. This test was again performed in TC-1 at both 200 psig reactor pressure and rated reactor pressure. Times to rated flow were 14.25 seconds and 17.7 seconds, respectively. The maximum aecay ratios were 0. 0 and 0.13, respectively.
l In TC-3, automatic quick starts and step changes with flow to the RPV were performed. Initial test runs resulted in time to rated flow in excess of 27 seconds. Adjustments to the system were made including the ramp time of the ramp generator, readjusting the balance chamber and changing the proportional gain of the HPCI controller from 0.15 to 0.10.
These adjustments resulted in satisfactory results during all further testing.
The HPCI Cold Quick Start to the RPV test was performed in TC-3 and TC-6 and satisfactorily met all acceptance criteria. The performance in TC-6 was conducted under TC-3 plant conditions. High steam flow isolation data were obtained concurrently with the cold quick start test. Based upon that data. HPCI system steam line flow element delta-P values corresponding to 272% and 300% rated RCIC steam line flow were extrapolated. The test data are being re vi e we d by Site Engineering for determination of the Technical Specification setpoint for the HPCI system high steam line flow (line b r e a k) isolation.
The HPCI Surveillance Test Demonstration with quick starts to the CST were performed in TC-6 at 200 psig and rated reactor pressure to provide baseline performance data for future surveillance testing. An additional performance at rated pressure was conducted to complete the HPCI system extended operation demonstration (" endurance run") which required the system to be operated for up to two hours, or until system parameters stabilize, or a plant limit is reached. The test was successfully completed after 78 minutes of operation when i t was determined that turbine 5-46
bearing . lube oil temperatures had stabilized at 138oF and
) /
that .the Technical Specification supression pool temperature had been reached.
limits of 105oF for The final HPCI system controller settings were as follows:
- 1. HPCI Flow Control Proportional Gain 0.1 5/5 (indicated)
Reset 25 resets / minute (indicated)
- 2. HPCI Turbine Control Gain 6. 3 5/%
Stability 9. 0 EGR Needle Valve 1/4 turn EGR Null Voltsge 1.0t0.2 VDC ( cold)
Ramp Time 5. 5 seconds Table 5.2.12-1 i
SUMMARY
OF HPCI SYSTEM TESTING
- : l l l l
\ , , , ,- ------- ; , , , ,
. . Peak . Maxinun , , , .
l Cold / Hat l ! ! Reactor l Injection l TimetoRated ; Turbine Decar iSeal DeltaP! '
liJickstartl ,
Date ! T.C.! Pressure l To l Flow (sec.) : Trip l Speed (RPM) : Ratio l Leakage l Set;ointl
.....................................................'._ ..........'....... .. '..........>.........i.. s l : ! ! l ! ! ! l l l Hot ; 7-29-!6! HVl Rated l CST l 26.6 l No 4100 l 0.93 : No ! N/A !
l l Wat : !-!2-!6l !200psig CST ! 14.25 l No 3217 l 0.0 No N/A
- Hst l !-22-!e l Rated l CST l 17.7 ! No l 4070 0.13 l No ! N/A l tt : 10-25-!6 i 3 l Rated l RPV l 26.5 No l 4150 0.0 i 40 l N/A :
Hot : 1:-02-!6: 3 Fated : RPV : 18.72 : No 4125 0.0 l No ; N/A i Colf : 11-06-!6l 3: Sated : RPV l 23.75 : No : 4232 0.0 l No l SAT l l i ot : !!-06-!6: 3i Rated l CST : !!.56 l No 4333 l 0.0 l No l N/A ;
- Hot
- !!-20-!6 ; 6 l 200 psig l CST l' it.65 : No ; 3284 l 0.0 : No l N/A !
NIH ;!!-29-!6l 6: Rated l CST l N/A No l N/A l N/A l No l N!A
- Csid 12-02-!6l 6
Rated l RPV : 24.96 l No : 4125 : 0.0 l No ! SAT :
- *E W rance r # lata oniv.
s 5-47
5.2.13 Test No. 14 SELECTED PROCESS AND WATER LEVEL REFERENCE LEG TEMPERATURES A. OBJECTIVES 1 Assure that the measured bottom head drain temperature correnponds to bottom head coolant temperature (indicated by recirculation loop temperatures) during normal operation.
- 2. I d e n t:t ry any reactor operating modes that cause temperature stratification, and familiarize the plant personrel with the temperature differential limitations of tp:e reactor system.
- 3. Me a s u:. e the reactor water level instrument reference leg temperature and recalibrate the affected indicators if the measured temperature is different than expected.
B. ACCEPTANCE CRITERIA Level 1' 1 The reactor recirculation pumps shall not be started, flow increased, nor power increased unless the coolant temperatures between the steam dome and bottom head drain are wi t hi n 14 5 oF ( 81 oC) .
- 2. The started, recirculation pump in an idle loop must active loop flow must not be raised and power not be O must not be increased unless the idle loop suction temperature is wi t hi n 50oF of the active loop suction temperature and the active loop flow rate is less than or equal to 50% of rated loop flow. If two pumps are idle, the loop suction temperature must be within 50oF of the steam dome temperature before pump startup.
Level 2
- 1. During two pump operation at rated core flow, the bottom head temperature, as measured by the bottom head drain line thermocouple, should be within 30oF ( 17 oC) of the recirculation loop temperatures.
I
- 2. The difference between the actual reference leg tempe rat ure( s) and the value( s) assumed during initial calibration shall be less than that amount which will result in a scale end point error of 1% of the instrument span for each range.
O 5-48
C. DISCUSSION
' The test was performed in Test Conditions Heatup, 2, 3, 4, 5 and 6:
- 1. The bottom head temperature correspondence check was performed in TC-3.
- 2. The reference leg temperatures for water level instrumentation were examined in TC-HU, 2, 3, 5 and 6.
- 3. Vessel process temperatures were examined for e vi de nc e of water temperature stratification after recirculation pump trips in TC-3, 4 and 6.
In all cases the test results satisfied the acceptance criteria. However, the testing did reveal some instrumentation problems. By tripping one recirculation pump, the flow out the bottom ~ head drain dropped below that detectable by the drain flow instrumentation. Flow indication returned after the second recirculation pump was 7
returned to service. The bottom head drain flow instrument calibration parameters, while correctly implemented, did not allow sufficient span to detect lower flows. A design change j'
% request was implemented to change the calibration parameters in order to allow detection of lower flow.
V -
Another problem identified during this test involved
~
.the calibration of the GETARS signals for recirculation loop r suction temperatures. The GETARS signals are approximately
~
20oF too low because of non-linearities in the signal loop.
This problem will be resolved by the HCGS instrumentation personnel.
The results of this test are presented below.
Bottom Drain Temperature l
l The bottom head drain temperature was within 2oF of the recirculation loop temperatures at 97.8% rated core flow
( le vel 2 criterion is 30oF) . This result p rovi de d assurance l
that the bottom head drain temperature indication corresponds to bottom head coolant temperature.
I I
O 5-49
- . _ , - - .. . . _ . _ - , . ~ . . _ . - ,. _ - ,- - . . . . . . . . - - - . - .
l I
Reference Leo Temperatures The water level reference leg temperatures ( drywell and reactor building) obtained in TC-Heatup were shown to result in scale end point values which were less than 1 % of instrument span different from those calculated using initial calibration data ( maximum dif ference was 0.64%).
Reference leg temperatures measured in the other test conditions were not significantly different from those obtained in TC-Heatup. Their results provided assurance that the water level reference leg temperatures assumed for the initial calibration are adequate and that the instrumentation does not have to be recalibrated.
The reference leg temperatures obtained during the test program are summarized belo w:
Reference Leo Temperatures ( oF)
Test Condition Initial Calibration Hu _1_ _1_ _1. _6_
Drywell 135 93.96 98.55 92.50 92.81 93.84 Reactor Bldg 75 79.5 75.0 70.0 71.25 73.8 Baseline data were also obtained for the water level i ns t r ume n t a t i on:
Averace Reactor Water Level Readinos. ( i n. )
Test Condition Hu _a_ _1_ _1_ _q_
Narrow Range 35.94 35.94 33.4 35.1 35.3 Wide Range 37.74 36.44 29.1 37.8 32.94 i
The effect of increased core flow on the wide range indication is shown by comparing the TC-5 to the TC-6 level
- results or the TC-2 to the TC-3 results. The wide range l indication decreased with increasing core flow because the l lower pressure tap senses coolant pressure near the top of l
the Jet pumps. The effect of increased subcooling on the l wide range indication is shown by comparing the TC-3 and TC-6 results. ,
1 l
l l
I 5-50 1
Post Recirculation Pumo Trio Temperature Stratification Test
{ \
\_/ Following trips of one and two recirculation pumps, all reactor coolant temperature stratification limits were me t:
lit ( oF)
TC-3 TC-3 TC-4 TC-6 Criteria 1 Pumo 2 Pumos 2 Pumos 1 Pumo Steam Dome -
( Bottom Drain) 145 22.7 3.1. 1 29.2 30 Steam Dome -
(Idle Loop) 50 NA 32.8 25.2 NA Active Loop -
(Idle Loop) 50 1. 0 2. 0 NA 2 Pump discharge valves were closed after the trips, reopened, and then closed just prior to pump restarts. The pumps remained shutdown a minimum of 45 minutes before they were restarted.
(
\
5-51
5.2.14 Test No. 15 AND 39 SYSTEM EXPANSION 4
A. OBJECTIVES Verify that Nuclear Steam Supply System ( NSSS) piping
( recirculation and main steamline piping inside the drywell) and Non-NSSS, Balance of Plant ( BOP) piping, as identified in Section 3.9.2 in the FSAR, expands in an acceptable manner during plant heatup and power operation. Specific objectives were to verify that:
1 Piping thermal expansion is as predicted by design calculations.
- 2. Snubbers and spring hangers remain wi t hi n operating t r,a ve l ranges at various piping temperatures.
- 3. Piping is free to expand without ioterferences.
B. ACCEPTANCE CRITERIA Level 1 (NSSS Pi pi ng) 1 There snall be no obstructions which will interfere with the thermal expansion of the Main Steam and Recirculation piping systems.
- 2. The displacements at the established transducer locations shall not exceed the allowable values given in Table 5.2.14-1. The allowable values of displacement shall be based on ASME Section III Code Stress Allowables.
Level 1 (BOP Pi pi ng)
None Level 2 ( NSSS Pi pi ng) 1 The displacements at the established transducer locations shall not exceed the expected values given in Table 5.2.14-1,
- 2. All hangers and snubbers shall be within their normal operating range.
Level 2 (BOP Pi pi ng)
- 1. The piping system is not restrained against thermal expansion except as provided by design.
- 2. Spring hangers and snubbers are not extended or compressed beyond their design or expected working range.
5-52
- 3. Measured piping system deflections, when plotted against the corresponding calculated deflections, shall Os fall within the acceptable region.of the graph provided by engineering.
- 4. Initial piping position change during the return to ambient test is not more than 125 percent of the maximum deflection measured at the same point, or not more than 11/8 inch, whichever is greater.
C. DISCUSSION l NSSS Pinino Thermal expansion data were taken for the NSSS piping systems ( Mai n Steam inside drywell and Reactor Recirculation) in the following test' conditions.
In TC-Open Vessel, vi s ual walkdown inspections of the piping systems took place at ambient temperature. Baseline data were taken for the hangers and snubbers. All accessible piping in the lines to be tested were inspected to ensure no Interference existed to impede thermal expansion. All NSSS remotely monitored instrumentation were inspected to ensure that they were intact and undamaged.
Baseline data were taken from the remote instruments attached to the main steam lines, (6 lanyard potentiometers O~ attached to each line, and 1 RTD attached to lins A and Line C) and those attached to the Reactor Recirculation System (12 lanyard potentiometers on each loop, 2 RTDs on Loop A,
~
and one on Loop B) .
In TC-Heatup, visual inspection walkdowns of the piping systems were performed at reactor water temperatures of 251or, and at 533oF ( rated) . piping thermal expansion data were obtained from the remotely monitored instrumentation in increments of 50oF, starting at 150 o F t10 o F, and ending at rated reactor water temperature.
In TC-1, after.the plant had been through 2 heatup/cooldown cycles, another piping system walkdown was performed with l
reactor water temperature less than 150oF.
1 i In TC-6, during power operation at near rated feedwater temperature ( 417oF) pi pi ng thermal expansion data were again
, taken for the Main Steam lines and the Recirculation System
- pi pi ng.
l Overall, the results of the NSSS piping thermal expansion testing were satisfactory. During the testing, the I
following exceptions were found and resolved.
2 l 1. During the ambient temperature walkdown for NSSS i v piping thermal expansion, there were four snubbers
! within 1/2" of hanger steel which would have imposed 2
i 5-53
_ . _ - _ _ . _ . _ . _ _ _ _ _ _ . _ _ _ _ _ _ _ _ _ , _ - , _ . - ~ - . _ _ _ _ _
thermal interference during heatup. These snubbers
( which were attached to the bioshield and the recirculation pump motor) were rotated to provide an acceptable clearance. Also, one of the constant supports still had its travel stop installed. The stop was removed before heating u p.
- 2. During operation at rated reactor temperature one snubber on Main Steam Lina B was within 3/4" of being topped out. The resolution was to reset the snubber to provide at least 1" of travel.
- 3. After 2 heatup/cooldown cycles, a snubber on Main Steam Line C was wi t hi n 13/16" of bottoming out. It was determined that the remaining travel was acceptable, and that no adjustment was required.
- 4. During the initial heatup to rated reactor temperature, there were two potential Level i failures. One was for sensor RA-SY on Recirculation Loop A suction in the Y-direction, and the other for RB-HY on the Recirculation Loop B header in the Y-Direction. The displacements were evaluated, and r e vi s e d limits were issued for the two sensors. The displacements were within the re vi s e d li mi t s. Also, a vi r, u a l inspection verified that no interferences existed. There were also 17 Level 2 violations which were evaluated and accepted as-is, by the cognizant piping engineer.
- 5. The data taken during rated feedwater temperature operation in TC-6 indicated 13 Level 2 violations, which were evaluated and accepted as-is. Values of the piping displacements are given in Table 5.2.14-1, along with the final Level 1 and Level 2 acceptance criteria.
BOP Ploino Balance-of-plant piping thermal expansion testing was performed on non-NSSS, BOP piping in the following systems:
- 1. Main Steam ( System AB) outside the drywell.
- 2. Gaseous Radwaste ( System HA)
- 4. Feedwater ( System A E)
- 5. Reactor Water Cleanup ( Sys tem BG).
- 6. Reactor Core Isolation Cooling ( Systems BD & FC).
- 7. High Pressure Coolant I nj ection ( Systems BJ & FD).
- 8. Residual Heat Removal ( Sys t em BC) 5-54
c - -
- 9. Core Spray ( System BE) .
t^)
( 10. Diesel Generator Exhaust ( System KJ) .
11 Auxiliary Steam ( System FB) .
Initial piping positions were determined, relative to structural reference points, prior to reactor heatup in order to establish baseline data.
The thermal movements of system piping were measured in Test Condition Open Vessel ( baseli ne) , Test Condition Heatup, and following reactor initial cooldown from normal operating temperature.
Piping movements were measured using both remotely monitored instrumentation and direct ma nual/ vi s ual methods. Spring hangers and snubbers on specified piping segments were inspected to verify that these devices did not become extended or compressed beyond their working range.
System expansion testing for each system was performed at the test conditions and system temperatures given in Table 5.2.14-2.
The results of the testing verified that the piping was free to move without unplanned obstruction or restraint during l heatup and cooldown, that the system piping behaved in a s_) manner consistent with assumptions of the stress analysis,
- and that there was agreement between calculated and measured i
values of displacement, m Problems encountered during the testing were for the most part minor in nature and include the f ollowi ng:
1 Several expansion values and residual displacements fell outside of the stated tolerances. These values were analyzed for their affect on the involved piping, and were found to be acceptable.
- 2. Insulation on various systems needed to be notched to allow free thermal expansion of the piping systems.
- 3. A small number of hangers and snubbers needed to be reset.
- 4. Electrical conduit near the mainsteam bypass line needed relocating to allow free thermal expansion of the pi pi ng s ys tem.
- 5. One drain line had to be rerouted.
)
g,,/
- 6. Hanger steel obstruction.
or grating needed coping to prevent 5-55
Table 5.2.14-1 NSSS PIPING THERMAL EXPANSION ACCEPTANCE CRITERIA /RESULTS IN TC-6 O Main Steam Line Pipino
___________LtYtt L Bange LLuchtaL___________
! _LtYet 1 Bange LLatbetL_ l l l l l V V Measured V V Criteria
- Sensor Level 1 Level 2 Displacements Level 2 Level 1 Evaluation SA-LX -0.969 -0.369 -0.195 -0.163 0.436 Y SA-LY -0.027 0.047 0.308 0.570 0.644 Y SA-LZ 0.028 0.644 0.806 0.875 1.491 Y SA-RX -0.280 -0.055 0.211 0.366 0.591 Y SA-RY 0.329 0.649 0.743 0.963 1.283 Y SA-RZ -0.123 0.120 0.368 0.354 0.598 LII SB-LX -1.890 -0.770 -0.913 -0.567 0.552 LII SB-LY -0.567 -0.075 -0.063 0.472 0.964 Y SB-LZ -1,333 0.780 0.743 1.058 3.171 LII SB-RX -0.315 -0.061 0.004 0.332 0.586 Y SB-RY -0.181 0.721 0.778 1.036 1.939 Y SB-RZ -0.208 0.029 0.205 0.230 0.468 Y SC-LX -1.739 -0.648 -0.712 -0.445 0.646 LII SC-LY -0.539 -0.049 0.258 0.498 0.988 Y SC-LZ -3.208 -1.174 -1. 029 -0.896 1.138 Y SC-RX -0.429 -0.003 0.117 0.390 0.816 Y SC-RY. -0.103 0.748 0.749 1.064 1.915 Y SC-RZ -0.598 -0.247 0.000 -0.046 0.306 LII SD-LX -0.960 -0.384 -0.085 -0.178 0.398 LII SD-LY -0.024 0.050 0.221 0.573 0.646 Y SD-LZ -1.459 -0.867 -0.925 -0.635 -0.043 LII SD-RX -0.271 -0.058 0.160 0.363 0.576 Y SD-RY 0.381 0.663 0.761 0.978 1.260 Y SD-RZ -0.636 -0.356 -0.130 -0.121 0.159 Y 07 =
Satisfied both Level 1 and Level 2 criteria LII =
Violated Level 2 criteria O
5-56
Table 5.2.14-1 ( Cont' d) f-(_,/ NSSS PIPING THERMAL EXPANSION ACCEPTANCE CRITERIA /RESULTS IN TC-6 Reactor Recirculation Pioino
___________LtYtl 1_ Rangt LLuchtaL___________
_Larel 1 Banst LLachtaL_ !
l l l l V V Measured V V Criterla*
Sensor Level 1 Level 2 Displacements Level 2 Level 1 Evaluation RA-SX 0.450 0.856 0.736 1.092 1.498 LII RA-SY -0.267 -0.145 -0.168 0.079 0.201 LII RA-SZ -0.335 0.005 0.067 0.193 0.533 Y RA-PX -1. 605 0.310 0.463 0.508 2.423 Y RA-PY -0.844 -1.585 -1.792 -2.170 -2.911 Y RA-PZ -1. 887 -0.029 0.156 0.283 2.141 Y RA-DX -1.879 -0.349 -0.369 -0.161 1.369 LII RA-DY -1.610 -1.535 -1.209 -1.012 -0.937 Y RA'DZ
-3.136 -0.495 0.182 -0.270 2.371 LII RA-HX -0.741 -0.161 -0.099 0.026 0.606 Y RA-HY -0.532 -0.404 -0.292 -0.072 0.056 Y RA-HZ -1.636 -0.845 -0.616 -0.619 0.172 Y RB-SX -2.095 -1.021 -0.684 -0.783 0.292 LII RB-SY -0.546 -0.436 -0.300 -0.107 0.002 Y RB-SZ -1.055 -0.258 -0.153 -0.071 0.726 Y I ) RB-PX -2.225 -0.423 -0.472 -0.222 1.580 LII
/ RB-PY -2.777 -2.065 -1.785 -1.479 -0.767 Y RB-PZ -1.968 -0.205 -0.011 0.107 1.870 Y RB-DX -1.295 0.255 0.302 0.413 1.933 Y RB-DY -1. 372 -1.299 -1.126 -0.776 -0.702 Y RB-DZ -2.301 0.247 0.320 0.472 3.020 Y RB-HX -0.691 0.030 0.174 0.218 0.939 Y RB-HY -0.639 -0.505 -0.404 -0.167 -0.033 Y RB-HZ -0.618 0.458 0.552 0.684 1.761 Y Y =
Satisfied both Level 1 and Level 2 criteria LII = Violated Level 2 criteria 5-57
o i
I 1
l Table 5.2.14-2 BOP PIPING THERMAL EXPANSION TEST CONDITIONS l l l Expected l l Test l l Test Temperature ;
! Condition l System l ( oF) l
_______________________________i__________________
l l Main Steam l l l First l Main Steam Bypass l l l Reactor l RFP Turbine Steam Supply ( HP) '
l l Plateau l RHR Return and Supply (I/ D) l l l l HPCI Steam Supply (I/ D) l l l Initial ! RCIC Steam Supply ( I/ D) l 250* l l Reactor ! RHR LPCI ( I / D) l l l Heatup l RWCU (I/D) l l l l Core Spray ( I/ D) l l l l Feedwater ( I/ D) l l i______________i___________________________-___.._________________i .
l l Main Steam l l l l Main Steam Bypass l l l l RFP Turbine Steam Supply ( HP) l l l Second l RHR Return and Suoply (I/D) l l l Reactor l HPCI Steam Supply ( 0/ D) l l l Plateau l RCIC Steam Supply ( 0/ D) l l l ; HPCI Steam Supply ( I/D) l l l l RCIC Steam Supply (I/ D) l l l Initial l RHR LPCI ( I / D) l 406* l l Reactor l RHR Head Spray (I/ D) l l l Heatup l RWCU ( I/ D) l l l l Core Spray ( I/ D) l l l ! Feedwater ( I/ D) l l
__-_________- i__-____________-___--_-_____-__e --__--___----_--_ .
l l Main Steam l l l l Main Steam Bypass l l l l RFP Turbine Steam Supply ( HP) l '
l Reactor at l RHR Return and Supply ( I/ D) l l l Rated l HPCI Steam Supply ( 0/ D) l l l Temperature l RCIC Steam Supply ( 0/ D) l l l l HPCI Steam Supply ( I/ D) l l l l RCIC Steam Supply ( I/ D) l l l Initial l RHR LPCI ( I/ D) l 546* l l Reactor l RHR Head Spray ( I/ D) l l l Heatup l RWCU ( I/ D) l l l l Core Spray ( I/ D) l l l l Feedwater ( I/ D) l l
__________________-__________________________i__________________.
Reactor Water Temperature OD = Outside Drywell ID = Inside Drywell HP = High Pressure
~
5-58
- - - - =-- -- -- - - -- - - - 1--
Table 5.2.14-2 ( Cont
- d) v 80P PIPING THERMAL EXPANSION TEST CONDITIONS l l l Expected l l -Test l l Test Temperature l l Condition l System l ( oF) l
.i
________-_____ _______________________-_______i _-________________i l 20% Fower l l l l l Feedwater l 275 l l Test l l l l Condition 1 l l l i_________-____i__________________-____________i-_________________.
l 505 Power --l l l l l RFP Turbine Steam Supply ( LP) l 323 l l Test l l l l Condition 3 l l l e .
e___--_-_____-_ ___________________________-__a_________________,
l 1005 Power l l l l l Feedwater l 420 l l Test l l l l Condition 6 l RFP Turbine Steam Supply ( LP) l 370 l
______________,_______________________________n__________________s l l RHR Shutdown Cooling Mode l 300 l l l Diesel Generator Exhaust l 900
. . .i l Normal l Gaseous Radwaste l 350,365,546 l l Operation l l l l l Auxiliary Steam l 377, 366 l l l l l l l RWCU ( 0/ D) l 437, 534
.______________i_______________________________i__________________i LP = Low Pressure OD = Outside Drywell l
l l
t l
t 5-59 i
5.2.15 Test No. 17 CORE PERFORMANCE A. OBJECTIVE Calculate the principal thermal and hydraulic parameters associated with core behavior at power levels from 25% to 100% of rated.
B. ACCEPTANCE CRITERIA Level 1
- 1. The Maximum Linear Heat Generation Rate ( MLHGR) of any rod during steady state conditions shall not exceed the l i m.i t specified by the Plant Technical Specifications (13.4 kw/ f t) .
- 2. The steady-state Minimum Critical Power Ratio ( MCPR) shall exceed the minimum limit specified by the Plant Technical Specifications ( MCPR operating limit = 1.20).
- 3. The Maximum Average Linear Heat Generation Rate
( MAPLHGR) shall not exceed the limits specified by the Plant Technical Specifications ( li mi t value is a function of fuel type and exposure).
- 4. Steady-state reactor power shall be li mi t e d to the rated core thermal power ( 3293 MWt).
- 5. Core flow shall not exceed its rated value (100 ml b /.hr) .
Level 2 None C. DISCUSSION The test was performed in TC-1, 2, 3, 4, 5, and 6 at or near the highest power possible for the respective test condition. The test procedure specified use of either the process computer or BUCLE ( a GE off-line computer program) to calculate the parameters listed in the acceptance criteria.
O l 5-60
. _ _ _ _ _ . _ . _ - . _ _ _ . _ . . ~ . _ _ _ . .
f d-4 S
In all test conditions, the results successfully satisfied y the acceptance criteria. In.TC-2, 3, 4, and 5, a correction i '
Q of 0. 03 was added as a conservatism to the MCPR limit value to account for the possibility that the feedwater temperature would be less than 400oF when the plant operated
]. at rated conditions in TC-6. Actual feedwater temperature-I was 421.1oF at rated conditions, so this conservatism was removed during .TC-6 testing. Also, as a result of recirculation pump trip testing in TC-3, an a dmi ni s t ra t i ve i correction of 0.02 was added to the MCPR limit value in TC-
- 3, 4, 5 and 6 to account for actual recirculation pump flow '
coastdown time being above acceptance criteria limits (see Test No. 28). This correctior. wa's later superseded by an ,
emengency Technical Specifications change following the '
j evaluation of the recirculation _ pump flow coastdown occurring l l during the generator load' rejection test at the 1 end of TC-6 testing. Tests No. 25 and No. 28 discuss the j- flow coastdown results and additional analyses that are '
being performed regarding end of cycle recirculation pump '
F tri p ( EOC-RPT) .
3 The core performance test results are summarized below:
I :
- l. .- C8FEi9 E E E E E E i Dre h.ir, N7 (3293 533 1077 2465 1335 2027 3212 ;
&# I' n , W t j f!00 43.5 26.!! i!.6 35.4 !!.3 '! '
j "L9, Wt i13.4 3.34 .76 9.37 5.85 7.?? tt.53 t' G Ges:tti ) Crittrw 5.55 )t.39 3.4)1.41 1.9)t.23 2.46)l.45 1.97)!.39 !.6)t.22 WLY MtHits ( bitirls) 2.!4(12.10 4.067(!!.5 7.4(10.75 4.5!(10.75 6.4t(10.77 9.27(10.;
Core performance in TC-6 compared well with predicted l l thermal performance parameters for 1005 power /1005 flow I
( obtained from the HCGS Cycle-1 Cycle Management Report)- 1 Cvele Manaaement Renort TG-1. i l i Exposure, NWD/ST 200 1000 460
! MLHGR 10.68 11.55 11.53 i MCpR 1.49 1.53 1.46 RAPLHGR 0.80 0.86 0.85 j HCGS core average exposure was equal to about 460 MWD /ST l l
when this test was performed in TC-6. Note that the reactor s conditions ( power, flow, control rod pattern, etc), for ,
! which the cycle management report calculations were made, !
l were not normalized to the actual test conditions in TC-6.
t 6
5-61 !
- l. _ - _ - - -
5.2.16 Test No. 18 STEAM PRODUCTION A. OBJECTIVES
- 1. Demonstrate that the nuclear steam supply system is capable of providing steam sufficient to satisfy all appropriate warranties as defined in the contract.
- 2. Demonstrate that the reactor can operate at greater than 85% of rated core thermal power for a period of at least 100 hours0.00116 days <br />0.0278 hours <br />1.653439e-4 weeks <br />3.805e-5 months <br /> without interruption.
B. ACCEPTANCE CRITERIA Level 1 The NSSS parameters as determined by using normal operating procedures shall be within appropriate license restrictions.
Level 2 The NSSS will be capable of supplying 14,159,000 LBM/HR of steam of not less than 99.7% quality at a pressure of 985 psia at the discharge of the second main steam isolation valve, as based upon a final reactor feedwater temperature of 419.9oF and a control rod drive feed flow of 32,000 LBM/HR at 80oF. The reactor feedwater flow must equal the steam flow less the control rod drive feed flow.
C. DISCUSSION The test successfully demonstrated that the reactor could
[ operate at greater than 85% of rated core thermal power for a period of at least 100 hours0.00116 days <br />0.0278 hours <br />1.653439e-4 weeks <br />3.805e-5 months <br /> without interruption.
Eq ui pme nt trips which resulted in a downpower were not interruptions if the plant remained in operation and was recoverable to >855 power within 100 hours0.00116 days <br />0.0278 hours <br />1.653439e-4 weeks <br />3.805e-5 months <br /> of the test start. An 8 hour Steam Production Warranty Test was performed in conjunction with the 100 Hour Demonstration Test. A plant heat rate test was also performed.
100 Hour Demonstration Run The 100 Hour Demonstration Run was begun at 1723 hours0.0199 days <br />0.479 hours <br />0.00285 weeks <br />6.556015e-4 months <br /> on December 12, 1986 when the reactor attained 86% of rated power during a power increase ramp to 100% power. During the 100 Hour Demonstration Run, the power was reduced to less than 85% of rated twice. The first downpower was caused by problems with the condensate filtee domineralizer system and the shaft seals of the "C" secondary condensate pump. The second downpower was caused by the loss of the "B" recirculation pump due to a problem with its M/G Set.
Power was recovered to >85% power in both cases. The test was successfully completed at 2123 hours0.0246 days <br />0.59 hours <br />0.00351 weeks <br />8.078015e-4 months <br /> on December 16, 1986.
5-62
8 Hour Steam Production Warranty Test (O). The 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> Steam Production Warranty Test was performed successfully on December 14, 1986. With the plant operating at near rated thormal power, various plant parameters were recorded both hourly, and every 10 minutes during two test runs of two hours each. Average values of the data collected during each test run were used to calculate the reactor steamflow. The calculated steamflow rate was then adjusted to account for plant operating parameter deviations from rated heat balance values.
Plant operating data were obtained'from normal installed plant instrumentation, plant process computer programs, and special test instrumentation to measure reactor steam dome
- pressure and the pressure at the discharge of the second main steam isolation valve. The hourly data were used to verify that the reactor thermal power and thermal limits did not exceed the appropriate license restrictions.
The test results are summarized in Table 5.2.16-1. The average calculated steam flow at the actual plant operating
- conditions during the test was 14.185 MLB/HR. The steam flow adjusted to the rated heat balance conditions was 14.159 MLB/HR. Differences between actual plant operating conditions and rated heat balance conditions included a higher final feedwater temperature (423.4oF actual versus O' -
419.9oF rated), higher control rod drive water temperature (104.3 actual versus 80oF rated), and lower recirculation pump heat input to the reactor coolant (4.64 MWt versus 10.0 MWt rated). The carryover fraction, previously determined m in the Reactor Water No-Cleanup Tect (cce Test No. 1), was adjusted for actual conditions at the outboard MSIV to determine the steam quality. All acceptance criteria were satisfied.
l O
( 5-63 1
Table 5.2.16-1 STEAM PRODUCTION TEST RESULTS -
l Average Acceptance Parameter ,
1plue Criteria Core Thermal Power 3292.9 L3293.0 Total Steam riow ( MLB/ HR) L14.159 Actual 14.185 Adjusted to Rated Heat Balance Conditions 14.159 Steabline Pressure ( psia) 988.8 L985 Steam Quality ( %) 99.89% L99.7%
Maximum Acceptance I.hermal Li mi t Parameters '
Value_ C r_i_t e gia MFLCPR 0. 861 L1. 0 MAPRAT a 884 L1. 0 MFLPD u.896 L1. 0
)
g 1
0 5
~
h 5-64 1
,, .x. _
4 g - re \ _
V 1 ?
R f,
~
~
l/ "
,y %
f, '
/, /4.\ 5.2.17 Test No. 20 PRESSURE REGULATOR A. OBJECTIVES
.s ,
i "l , ,
- 1. Determine th,e o p t'A mum s e t t i ngs for the pressure control x; S loop .by' analysis of the transients induced in the t re <
, reactor pressure control system by means of the d
pressure r e gel ~a t ors.
. , s 7 1 -
i
/ 2. I f,D'e monstra t e .the backup capability of the pressure
(
/{ >cegul'ators vi e.
pressure r e gul a t or.
simulated failure of the controlling
^
i
- 3. ,. Demonstrate smooth pressure control transition between s ,- the turbine control valves and bypass valves when the I'-
reactor steam generation exceeds _the steam flow used by the turbine.
fr -
/ 4. Demonstrate that other affected parameters are within i c acceptable limits during pressure regulator induced
- ',5 transient maneuvers.
l If ~
B. ACCEPTANCE CRITERIA
- , Level 1 The transient response of any pressure control system
( related variable to any test input must not diverge.
Level 2 i
l 1. Pressure 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 when operating above the
( lower limit of_the nester recirculation flow controller
- fThis criterion does not apply to tests i nvolvi ng
- ' simulated failure of one regulator with the backup
, , regulator taking over) .
l '
l 2. The pressure response time from initiation of pressure
, setpoint change to the turbine inlet pressure peak shall be L10 seconds.
- 3. Pressure control system deadband, delay, etc., shall be small enough that steady state limit cycles (if a ny) 3 shall produce steam flow variations no larger than t0.5 percent of rated steam flow.
- 4. For pressure regulator failure transients the peak neutron flux and/or peak vessel pressure shall remain below the scram settings by 7.5 percent and 10 psi res pobti vely ( maintain a plot of power versus the peak O- .
variable values along the 100 percent rod line).
l
, 5-65 l__--.______..._. _ . - _
v-s 5 '.' The variation in incremental regulation ( ratio of the maximum to the minimum value of the q uant i t y) ,
" incremental change in pressure control signal / incremental change in steam flow", for each flow range) shall meet the f ollowi ng:
%'or Steam Flow Obtained With Valves Wide Open Variation 0 to 85% [4: 1 85% to 97% L2: 1 85% to 99% L5.1 Level _3 s
1 Additional 6ynamics of the control system, outside of the regulator compensation filters, shall be equivalent I to a. time constant no greater than 0.10 second. This ,
also includes any dead time which may exist. I
- 2. The dynami c s 'of both pressure regulators shall be essentially identical.
C. DISCUSSION The dynamic performance of the pressure regulators was demonstrated by inducing setpoint step changes with control of the pressure transient maintained by control valves alone, bypass valves alone, and both control valves and bypass valves ( bypass valve control initially i nci pi e nt) .
The final controller settings were determined in TC-3 and dynamic response for all modes of pressure control was within acceptance criteria li mi t s through the remainder of the test program. Simulated pressure regulator failures demonstrated satisfactory backup regulator performance capability for each regulator.
The pressure regulator tests with the control valves controlling were first performed i n TC-1 during which the system response to setpoint step changes resulted in maximum decay ratios greater than the Level 2 acceptance criterion of 0.25. In TC-1 and TC-2, with the bypass valves controlling, the system response was well within acceptance criteria. Additional tuning was performed and retesting in TC-3 demonstrated acceptable decay ratios wi t h control valves and bypass valves controlling. Steam flow variation in TC-3 testing was t0.53% which exceeded the Level 2 acceptance criterion of t0. 5 %. The basis for the 1.0 5%
limit is to reduce component wear due to steady state li mi t cycling of the turbina control valves. The test results t
were determined to be satisfactory since the turbine control valve position was steady. The TC-3 testing also demonstrated a smooth transition between control valves and i bypass valves during presrure setpoint variations. Pressure l regulator testing in TC-4 l
l 5-66
I I
demonstrated the pressure control loops to be stable and a i smooth response to pressure transients was evident. The s/ testing in TC-4 was performed below the minimum power level described in the FSAR for TC-4. A safety evaluation determined that the test results were acceptable and an FSAR change was issued to modify the TC-4 test condition to include the lower power condition in accordance with the revised General Electric Startup Test Specification. A l summary of the pressure regulator test results is gi ve n in Table 5.2.17-1, Pressure Regulator Test Results.
l Pressure regulator testing in TC-5 and TC-6 demonstrated both regulators to be responsive and stable. The decay ratios in TC-6 were zero and steam flow variation was within criteria limits. In TC-6 pressure response time was 5. 2 l
seconds with controls valves in control and 4.7 seconds with bypass valves in control, both well within the 10 second criteria limit. Final system adjustment settings are shown in Table 5.2.17-2, Pressure Regulator Adjustment Settings.
Pressure regulator linearity was also demonstrated in TC-6.
, The Pressure Regulator Linearity Verification Test i determined the linearity of the pressure regulators from l 0-99% reactor power. Results were acceptable and measured as follows:
Reactor Power Ratios of incremental regulation l ,
Measured Max Allowable i
0-85% 1.67:1 L4: 1 85-97% 1.95: 1 L2: 1 2 85-99% 1.95:1 L5: 1 l
t_-
5-67
O Table 5.2.17-1 PRESSURE REGULATOR TEST RESULTS
...............: =...............................- _ _-_- _ _ .-
! ! ! l lPresse e l Stet h State Stean! !
! ! l iest Nn-hvergentl Worst Case !Respcase !Ein.Vitiallia.17diktit.htilliC1.!!tila!
- , Date ;i.C. Situatuntl0scillations lDecar Ratio lIine(sec)! "A" l "S" ! Flux l Pressne:
i.............i........... .........i.........i.................... >
! !-20-!6l 1 ! SVC -! Y : .213 4.7 : ; ; 91.2 l 103 :
8 I I i f
< f f i t I
........i... 1..- . .i ............. ... _ .......................... ._
' =_....
- . 8-21-55l1 ,
l, CVC Y .4311 4.4 .22 l .30 l 93.5 ._ l 100.7 l
_ ...................i ............ ,
i........................i....... ....' ...................,i---
- l. 9-!!-36!, 3 l, BVC l Y l .10 l 4.6 l l l 77.4 ; 93.5 :
i...- - i....i........................i........... . --- _i_ _- -- i........ .......... ............
l10-14-86 3 : CVC
- Y l .203 : 4.3 l .22 l .22 l 94.5 106 !
.........i.... .......... ............. ...... ......... ....................._ i- - . . ,
!!0-23-!s! 3 : BVI 5.0 :
! Y 0 ;
l l l l
.'is..:g.a03
.......,.,..., Ji
_a,...- __.
,........,...,s.3__a,.........i....................,.---
n .. .. (n.,
vt i Y i .l!4 i .96 e .a3 s
i i 4. 9 i i
44.0 , 6i.4 i
........ ............... l ................................... ............................. ............
'11-07-35:4 l CVC V .13 l 4.5 l 49 l .46 l 70.3 : !!.4 :
............ 1..........i.........................i.........i...................... . .
- !!-07-!5
- 4 : BVC l Y ; 0 5.0 : 66.5 l 35.1 l 9 I I f ,
,........- c . ............
. f
........................................n...........I ,
f 5
.,...;,.25,,.....
s er<, ,. y >
. e.1 4,0 ,' ' '
.46 .
.35 ', , , ,
......... ...................i............
lji.n.?.24!C '
. . ... . . 01,1 ' y 5
. . M. !
1.}
e .
. < . i e e' s e i e i ,
e I f
=.'.......... ...,........,*
i s.1 s. e....g . 3 r,n i vse e
o< e 3 i e i e i sc.e r .
'I i r . .*s . .T ,g a #.?.g 4 , i J4 -
9 f 4
I f f
f 6 I
..;p i . .
g /e.
. . Y , 0 . +., . . i 4 4.1 ;2.-
.J
............ 1........................i...........i.........e i
e i
=_. _s........ ..........'...........
- CVC - Control Valves Controlling BVI - Bypass Valves Incipient BVC - Bypass Valve Controlling
^^ Retest was satisfactory after additional tuning was performed.
1 1
I I
l l
O 5-68 l
i I
l Table 5.2.17-2
- PRESSURE REGULATOR ADJUSTMENT SETTINGS l-l Regulator l Component Parameter A _1_
Regulator Gain 3. 0 3. 0 Regulator Lead 7.05 7.05 Regulator Lag 2. 5 2. 5 Resonance Compensator To 6.85 6.85 Resonance Compensator TR2 5. 0 5. 0 Resonance Compensator p1/p2 2. 0 2.32 Resonance Compensator p2 1.65 1.65 i
>M l
[
i i
5-69
5.2.18 Test No. 21-1 FEEDWATER SYSTEM SETPOINT CHANGES A. OBJECTIVES 1
Demonstrate the ability of the feedwater control system to transfer from single element control to three element control and demonstrate acceptable response to reactor water level setpoint changes of 4 to 6 inches.
This procedure also demonstrates core stability to subcooling changes.
- 2. Demonstrate the capabilty of the feedwater system to control reactor water level using the startup level controller at low reactor power.
- 3. Demonstrate that each feedwater pump controller operates properly in response to feedwater flow step changes and to demonstrate core stability to subcooling changes.
B. ACCEPTANCE CRITERIA Level 1 The transient response of any level control system-related variable to the transfer of controller mode or to any test input must not diverge.
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 flux response of each feedwater actuator ( turbine or valve) to small ( < 10%) step disturbances shall be:
- a. Maximum time to 10% of a step disturbance (1.1 Jec
- b. Maximum time from 10% to 90% of a step disturbance (1. 9 sec
- c. Peak overshoot (% of step disturbance) L15%
- d. Settling time, 100% t 5% of a step disturbance L 14 sec l NOTE I l l Feedwater turbine speed can be used to evaluate the !
l small step response in lieu of feedwater flow as l l long as the size of the step disturbance remains !
l less than 10% of rated feedwater pump flow. l l____-_----_------_-----_-_------___-_---__-------___-_l 5-70
O 3.
to The average rate of response of the feedwater - actuator large ( > 10% NBR flow) step disturbances shall be between l 10 percent and 25 percent rated feedwater flow /second. This average response rate will be assessed by determining the time required to pass line'arly through the 10 percent and 90 percent response points.
C. DISCUSSION Startun Level Controller In Test Condition ( TC) heatup and TC-1, the startup level controller exhibited a steady state reactor water level limit cycle of 3" to 4" peak-to-peak. The limit cycle was
- found to be due to the long pneumatic lines between the I/P converters and the control valves which resulted in significant delay time in the control valves response to control signal changes. The I/P converters were replaced with high volume units which reduced the delay time to-acceptable levels and function generators were added to the control loops to linearize the response of the 3" and 12" control valves to the controller output. In TC-6, after tho' startup controller was retuned, this test was repeated successfully. The results of the retest confirmed that the startup level controller was well damped and responsive to j % level setpoint changes. The steady state limit cycle still I , ~)
s exists but has been reduced to 1" to 2" peak-to-peak which is acceptable since it does not restrict the ability to
, , control reactor water level. The limit cycle developes when the 12" control valve is controlling level in the upper 2.
region of its control range and is due to a deadband between
- the K639 controller output and the function generator output.
Prior to performing the retest in TC-6, components in the control valve positioner were found to be wearing e x c e s s i ve l y. The wear was determined to be due to moisture in the pneumatic air lines and excessive exposure to vibration while operating in long path recycle during low power testing. The positioner was refurbished prior to performing the retest.
The transfer from single element control (Startup Level Control) to three element control ( Master Feedwater Control) was demonstrated in TC-6 after all system changes and tuning were completed. The transfer was essentially bumpless, with no oscillatory response and negligible effect on reactor water level.
i 5-71
Manual Feedwater Flow Steo Chances This test was performed in Test Conditions 2, 3, and 6 by introducing manual 10% to 25% flow demand step changes to the master level controller via the i ndi vi d ual feedpump controllers. Initial testing in TC-2 showed sluggish response which was expected to improve following the initial RFP Tuneups in TC-3. Level 2 criteria were not satisfied but Level 1 stability criteria were satisfied. RFP "C" was not available for testing.
In TC-3 all three RFP's were tested. Level 2 criteria failures on decay ratios ( turbine speed and fl o w) , overshoot of turbine speed, and rate of response on B RFP ( step input not large enough to drive the control system into
" limiting") were experienced. An evaluation by engineering determined that the decay ratio criteria failure and turbine speed overshoot problem were acceptable for TC-3 based on overall system response, however a retest in TC-6 for the rate of response on B RFP was requested. All testing in TC-3 was preceeded by the feedwater turbine controller and master feedwater controller tuneups. Overall the open loop response of the feedpumps was judged to be satisfactory.
In TC-6 this test was repeated and all acceptance criteria were satisfied except the RFP B speed speed undershoot was 21.9% (16 r pm) vs (15% (level 2 criteria). The undershoot was found acceptable based on all other dynamic characteristics being satisfactory and the small amount of undershoot involved. The table below summarizes the results of TC-6 testing.
Parameter Results Criterion Delay Time 0.36 see L1.1 see Rise Time 1.05 see L1. 9 see Settling Time 7.49 see L14 see Actuation response rate ranged f rom 14.1 % to 25%/sec vs criteria limit range of 10% to 25% rated FW flow /sec.
Further optimization of RFPT "B" can be achieved by increasing the reset function which is presently lower than A&C RFPTs. A problem noted during testing was a slight limit cycle induced due to a mechanical binding problem in the C RFPT which causes C RFP discharge flow to cycle which, in turn, causes the A and B RFPs to cycle to compensate.
The net result is stable water level. This problem is being monitored for signs of degradation but does not currently affect system capability to control water level.
9 5-72
Feedwater System Level Setcoint C h a r.L9.t.E.
%)
This test was performed in Test Conditions 2 through 6.
Below is a Table summarizing the pertinent results of that testing.
Level FW Flow IE REE Decay Ratio Decay Ratio 2 A 0.27 0.32 2 B 0.19 0.29 '
2 A&B 0.22 0.20 3 A&B 0.04 0.10 3 A&C 0.00 0.15 3 " B&C 0.06 0.14 3 A/B/C 0.25 0.33 4 B&C 0.06 0.05 5 A/B/C 0.25 0.17 6 A/B/C 0.25 0.17 Tuning of the Master FW Control System did not start until TC-3 due to the program reduction efforts discussed in Section 6. 0. Therefore, early performance was somewhat sluggish but stable. Following tuneup of the turbine controllers, the master controller and the minimum flow recire valve controller in TC-3, the performance was greatly C) improved.
all The level 2 decay ratio criteria was not met when three RFPs were in service because all three pumps are low in their operating band when the reactor is in the 50%
to 75% power range. Later testing in TC-4, 5, and 6 showed improvement in feedwater flow decay ratio but not in the level decay ratio. This was caused by the mechanical binding problem in the actuator of the C RFPT, mentioned earlier, which induced a limit cycle of 11.7% at steady state. With this li mi t cycle taken into account, the actual decay ratios are closer to 0.15. Without adjusting the data for the limit cycle behavior, the decay ratio criteria are still satisfied.
Final Controller Settinas The final setting of the startup and master level controllers, the three element dynamic compensator and RFP flow controllers are presented below:
Startup Level Controller ( C32-K602)
Gai n = 0.13 ( x10)'
Reset = 0. 20 ( x1) resets / minute
-s Master Level Controller ( C32-K656)
Gain = 10 ( x0.1 )
5-73
O Three Element Dynamic Compensator ( C32-K666)
Lead ( T1) = 6. 4 Lag ( T2) = 5. 9 RFP Flow Controllers ( C32-K601 A/ B/ C)
RFP A RPP B RFP C Gain ( dial) 0. 95( x1) 0. 75( x1) 0. 95( x1)
Reset ( dial)
- 2. 0( x10) 3. 0( x10) 2. 5( x10)
Rate min. min. min,
- Actual reset for RFP A&C i
' is about 30/ minute and RFP B is less than 20/ minute.
9 5-74
. . _ . _ . , _ . _ _ _ ~ _ _ . . . _ . .
O 5.2.19 Test No. 21-2 FEEDWATER SYSTEM - LOSS OF FEEDWATER HEATING A. OBJECTIVE The purpose of this test was to demonstrate adequate plant response to a reduction in feedwater temperature caused by the single failure that will result in the largest loss in feedwater heating.
B. ACCEPTANCE CRITERIA Level 1
- 1. The maximum feedwater temperature decrease due to a single failure case must be L 100oF.
I 2. The increase in simulated heat flux cannot exceed the predicted Level 2 value by more than 25. The predicted value will be based on the actual test values of feedwater temperature change and initial power level.
Level 2 i 1. The increase in simulated heat flux cannot exceed the
()
BOL predicted value referenced to the actual feedwater temperature change and initial power level.
- C. DISCUSSION i
On December 3, 1986, the feedwater system loss of feedwater he a t i r. g test was conducted while in Test Condition 6. The
- largest loss in feedwater heating due to a single failure was determined by the system designer to occur when the bypass line around the third, fourth, and fifth stage feedwater heaters was opened during power operation.
The test was initiated by opening the feedwater heaters 3, 4 and 5 bypass valve 1 AD-HV-162 3 while operating at 83.85 power, 96.55 core flow. The predicted drop in feedwater temperature at 1005 reactor power was approximately 40oF.
The actual drop in feedwater temperature was 21oF, with a resultant increase in thermal power to 86.25.
The feedwater temperature decrease was well within predicted, and significantly less than the acceptance criterion of L100oF. The observed 2.7% heat flux increase was 0.23% less than the allowable Level 2 value of 86.68%.
ihermal limit margins were maintained throughout the transient.
O 5-75 L__.____.___
5.2.20 Test No. 21-3 FEEDWATER PUMP TRIP A. OBJECTIVE Demonstrate the capability of the automatic core flow runback feature of the recirculation system to prevent a low water le vel scram following the trip of one feedwater pump at near rated power ( L95%) conditions.
B. ACCEPTANCE CRITERIA Level 1 None Level 2 The reactor shall avoid low water level scram by three Inches margin from an initial water level halfway between the high and low level alarm setpoints.
C. DISCUSSION On December 2, 1986 while in Test Condition 6, Reactor Feedwater Pump "A" was tripped from 97.4% core thermal power. Reactor water level dropped from 34.8 inches to a minimum water level of 29.8 inches, and stabilized at approximately 34.5 inches. The capacity and quick response of the two remaining Reactor Feed Pumps nearly prevented a recirculation runback during this test, as the reactor low water level ( Le vel 4) signal just reached (30 inches).
However, the core flow runback feature of the recirculation system functioned correctly, as total core flow dropped from 98.75% to approximately 45% flow within 22 seconds.
Tripping Reactor Feed Pump "A" resulted in a margin to scram of 16.9 inches. The criteria of margin greater than or equal to three inches from the low water level scram setpoint ( + 12. 5 i n) was therefore satisfied.
l Overall, the test demonstrated excellent integrated response l of the feedwater and rectreulation control systems.
l l
l 5-76
() 5.2.21 A. OBJECTIVE Test No. 21-4 MAXIMUM FEEDWATER RUNOUT CAPABILITY Verify that the flow capability of the Feedwater System is within required limitations for the design runout transient and desired level control capability.
B. ACCEPTANCE CRITERIA Level 1 Maximum speed attained shall not exceed the speeds which will gi ve the following flows with the normal complement of pumps operating:
- 1. 1355 NBR at 1075 paia
- 2. 1465 NBR at 1020 psia Level 2 The maximum speed must be greater than the calculated speeds
- required to supply
Q~
k,) . -
1 With the rated complement 1071 psia dome pressure.
of pumps, 1155 NBR at
- 2. With one feedwater pump tripped, 685 NBR at 1021 psia dome pressure.
C. DISCUSSION This test was performed in Test Condition 6 and demonstrated that the reactor feedwater turbine controller ( high speed limiters) were set such that the maximum runout flow capability of the feedwater system was within all criteria limits. This verified that the worst case runout flow will not exceed the limitations of the FSAR transient safety analysis ( Le vel i cri te ri a) . In addition, the results confirm that the feedwater system flow capability is I adequate to provide satisfactory reactor level control during normal operating and transient conditions.
Data for maximum f eedwater ( FW) runout capability test was taken with the FW system in a normal full power lineup
- ( three FW pumps, three secondary condensate pumps, three
! primary condensate pumps and feedwater heaters and drains in normal service). Various FW system parameters (FW pump speed, flow, controller output and pressure) and reactor
, plant process parameters ( narrow range reactor pressure, I
narrow range reactor level, total FW flow) were re:orded.
5-77
e The procedure was segmented into three sections of data collection.
( - 5, The first set of data was recorded on the 100%
+05) rod line at about 5% reactor power level increments between 65% and 100% of rated power. For the second set of data, individual FW pump maximum flow measurements were obtained while at 95-100% of rated thermal power, on the 100% rod line, by raising each FW pump flow controller setpoint (one at a time) until limited by its high output clamp. A third set of data was obtained at constant power (95 + 1% rated) while va ryi ng the reactor pressure in 5 psig increments between 1005 psig and 975 psig to record FW flow variation with re&ctor pressure.
The feedwater & plant data were used to produce two sets of characteristic curves for each FW pump. The first curve was reactor precsure versus FW turbine speed, and the second curve was FW pump discharge flow versus FW turbine speed.
These curves were used to extrapolate system performance under the conditions specified by the acceptance criteria.
All results were within limits as shown in Table 5.2.21-1.
Table 5.2.21-1 MAXIMUM FW RUNOUT CAPABILITY RESULTS
.i . .
l Acceptance Criteria l Extrapolated Results l i .
.i ___________________________i________-____________________i I f g l 1. FW Flow L 135% NBR at l FW Flow = 127% NBR l l 1075 psia Reactor l (17.92 HLB / hr) at 1075 l l Pressure l psia l l l l l 2. FW Flow L 146% NBR at l FW Flow = 136.5% NBR l l 1020 psia Reactor ! (19.28 MLB/ hr) at 1020 l l Pressure l psia l l l l l 3. FW Flow > 115% NBR at l FW Flow = 128% NBR l l 1071 psia Reactor l (18.04 HLB / hr) at 1071 l l Pressure l psia l l l l l 4. FW Flow > 68% NBR at l FW Flow = 90.5% NBR l l l 1021 psia Reactor l (12.78 HLB / hr) at 1021 l l Pressure with 1 FW l psia l l pump tripped l l l l__--___-___________-_--_____l_________-_____---__________l 1
I 5-78 1
5.2.22 Test No. 22 TURBINE VALVE SURVEILLANCE TEST A. OBJECTIVES
- 1. Demon;trate acceptable procedures and maximum power levels for recommended periodic surveillance testing of the main turbine control val ve s, stop valves, and j bypass valves without producing a reactor scram.
- 2. Establish baseline data to determine the effect of turbine stop valve closure, turbine control valve 4 closur6 and turbine bypass valve closure on neutron 1
flux, heat flux, steam line flow and reactor pressure.
B. ACCEPTANCE CRITERIA Level i None I Level 2 i ?
! 1. Peak neutron flux must be at least 7.5% below the scram trip setting. Peak vessel pressure must remain at least 10 pai below the high pressure scram setting. l 4
Peak heat flux must remain at least 5.05 below its :
l scram trip point.
- 2. Peak steam flow in each main steam line must remain 105 j _
below the high flow isolation trip setting.
f C. DISCUSSION The turbine stop valve surveillance test was performed at
- 655, 805, and 995 reactor power. Main turbine stop valve No. 4 ( TSV-4) was determined to have the most limiting effect on reactor parameters during an earlier run of the l
, Operations Surveillance procedure and was therefore selected to be used for the performance of this test. The test was l initiated by depressing the TSV-4 test push button to close TSV-4, while observing smooth TSV operation between 100% and 105 open, and fast closure from 105 open to fully closed.
When reactor conditions stabilized. TSV-4 was reopened and ,
the results were analyzed. In TC-6, scram avoidance margins i were extrapolated from previous TSV tesking to determine the
( maximum power level for test performance. In all cases, no problems were encountered, and the tests proved that the plant could perform this test at 1005 power without causing a reactor scram. All the margin to scram requirements were satisfied.
O 5-79
The turbine control valve surveillance test was performed at 65%, 80% ,and 93% reactor power. Turbine control valve No.
1 ( TCV-1) was used for this test because of its overall limiting effects on reactor parameters which were determined during initial testing. This test was also performed on turbine control valve No. 2 ( TCV-2) during TC-6 because it was the most limiting valve with respect to steam flow. The test was initiated by depressing the appropriate TCV test push button to close the TCV. The TCV position indicator was observed for smooth TCV operation between its position and 10% open, and fast closure from 10% open to fully closed. After the associated RPS channel trip ( TCV fast closure; reactor power > 30%) , when reactor conditions stabilized, the TCV was opened and observed to return to its pretest postion. In TC-6, scram avoidance margins were extrapolated f rom pre vious TCV testing to determine maximum power le vel for test performance.
During TCV testing at 9d5 power, the plant scrammed on high RpV pressure. Even though the three control valves not being tested opened full > to compensate for the one control valve being closed, less than 93% of rated steam flow was passed by those valves. The main turbine Electro Hydraulic Control ( EHC) system only allowed the turbine bypass valves to pass an additional 5% of rated steam flow because the maximum combined flow limiter was set too low (105%).
Consequently, the reactor precsure increased leading to a reactor pressure vessel high pressure scram. Subsequent to the scram, the following corrective actions were t a ke n:
- 1. The power ascension test procedure was revised to specify a prerequisite MAX COMBINED FLOW LIMITER setting of 125% as opposed to 105% allowed by the operations piocedure.
- 2. The test was reperformed at 83% power for TCV-2 since it was the most limiting valve with respect to steam flow.
- 3. A recommendation was made to the Station Operating R e vi e w Committee ( SORC) that the operations TCV surveillance procedure be run at (92.5% power.
When this test was subsequently performed at 93.1% power, the APRM Neutron Flux scram margin criterion was nearly exceeded (8% scram avoidance vs 7. 5 % allowable) due to a flux spike while opening TCV-1. The spike was determined to be caused by a partial loss of pressure control capability in the configuration necessary for this test at high power levels. When the TCV being tested is reopened there is a time lag between the bypass valves reclosing and the three fully opened TCVs closing down sufficiently to control pressure. This time lag causes a momentary loss of pressure control which results in a small pressure decrease followed by a rapid increase, and corresponding neutron flux spike, 5-80
when pressure ' control is re-established on the TCVs.
O' To avoid this condition Operations was advised- to not perform this test above 92.55 reactor power and to increase the maximum combined flow limit to 1255.
The main turbine bypass valve surveillance test was performed at 90.85 power. Main turbine bypass valve No. 1
( BPV-1) was used because it had the most limiting effect on reactor parameters during previous surveillance testing.
The test was initiated by depressing the test pushbutton for BPV-1 and observing smooth operation from 05 to 100% open.
When reactor conditions stabilized. BPV-1 was closed and the results analyzed. The test showed significant margins to scram, and therefore bypass valve surveillance testing is not a -problem at the upper power level limit of 92.55 power.
Table 5.2.22-1 Turbine Valve Surveillance Scram Avoidance Margins, summarizes the results of the tests described above.
- O e
l I
i i
1 6
O 5-81 L
Table 5.2.22-1 TURBINE VALVE SURVEILLANCE TEST RESULTS Margin to High Steam Reactor Scram Haroins Flow Isolation Power APRM Reactor Heat Trip Setpt.
Date Testa T. C. ( %) Flux Pressure Flux ( MLB/ HR)
________ _____ ____ ______ _L1L__ _LaaLL_ _L1) _ __________
11-08-86 TSYST 5 64.3 52.8 76.2 12.6 2.57 11-08-86 TSVS'T 6 79.8 38.0 59.9 15.5 1.92 11-14-86 TSYST 6 99.2 18.7 34.3 14.4 1.21 11-08-86 TCVST 5 65.0 50.6 67.0 11.9 2.38 11-08-86 TCVST 6 79.8 35.5 55.3 14.6 1.81 12-02-86 TCVST( CV-2) 6 80.1 36.0 49.3 20.4 1.75 12-02-86 TCVST( CV-1 ) 6 93.1 8. 0 29.0 13.1 1.15 12-05-86 TBVST 6 90.8 25.7 43.3 16.9 1.38 h
TSYST - Turbine Stop Valve Surveillance Test TCVST - Turbine Control Valve Surveillance Test TBVST - Turbine Bypass Valve Surveillance Test 9
5-82
/ 5.2.23 Test No. 23-1 MAIN STEAM LINE ISOLATION VALVE b FUNCTIONAL TEST A. OBJECTIVES
- 1. Functionally check the MSIVs at selected power levels.
- 2. Determine MSIV closure times.
B. ACCEPTANCE CRITERIA Level 1
- 1. MSIV stroke time ( ts) shall be ne faster than 3. 0 seconds.
- 2. MSIV closure time ( tsol) shall be no slower than 5. 0 seconds.
Level 2 1
None C. DISCUSSION In Test Condition Heatup at 35 power and in TC-1 at 16%
O. power, i ndi vi d ually each main steam line isolation valve ( MSIV) closed to demonstrate proper operation and to was measure its closure time. Proper operation was demonstrated and stroke and closure times in TC-1 were within limits as shown below. It was noted in TC-1 testing that the stroke times on valves AB-F022A and AB-F028C were close to the minimum limit of 3. 0 seconds ( 3. 09 seconds and 3. 01 seconds, res pe c ti vely) . The stroke times were subsequently adjusted j and later demonstrated to still be acceptable during the full MSIV closure test, 4.01 seconds for AB-F022A and 3.75 seconds for AB-F028C.
Stroke Tirs Closure Time ts ( sec) tsol ( sec)
Valve Criterion > 3. 0 sec _ Criterion (5.0 see AB-F022A 3.09 3.27 AB-F022B 3.57 3.90 AB-F022C 3.57 3.97 AB-F022D 3.55 3.92 AB-F028A 3.59 3.75 AB-F0288 3.34 3.88 AB-F028C 3.01 3.52 AB-F028D 3.33 3.57 5 83
- 5. 2. 24 Test No. 23-2, MAIN STEAM ISOLATION VALVES - FULL ISOLATION A. OBJECTIVE Determine the reactor transient behavior resulting from the simultaneous full closure of all Main Steam Isolation Valves
( MSI V' s) .
B. ACCEPTANCE CRITERIA Level 1
- 1. The positive change in vessel dome pressure occurring withia 30 seconds after closure of all MSIV's must not exceed the predicted values (see Level 2 criteria) by more than 25 psi. The positive change in simulated heat flux shall not exceed the predicted values by more than 2% of rated value.
- 2. Feedwater control system settings must prevent flooding of the steam lines.
- 3. MSIV stroke times ( ts) shall not be faster than 3. 0 seconds, and MSIV closure times ( tsol) shall not be slower than 5.0 seconds.
- 4. The reactor must scram to limit the severity of the neutron flux and simulated heat flux transients.
Level 2
- 1. The temperature measured by thermocouples on the discharge side of the safety / relief valves must return to wi t hi n 10oF of the temperature recorded before the valve opened. If pressure sensors are available, they shall return to their initial state upon valve closure.
- 2. The positive change in vessel d o.:.e ptessure and simulated heat flux occuring within the first 30 seconds after the closure of all MSI V' s must not exceed the predicted values. Predicted values will be referenced to actual test conditions of initial power level and dome pressure and will use beginning of life nuclear data.
- 3. If water level reaches the reactor vessel low water level ( Level 2) setpoint, RCIC and HPCI shall automatically initiate and reach rated system flow.
- 4. The reactor recirculation pump trip shall be initiated if water level reaches the reactor vessel low water level ( Le vel 2) setpoint.
5-84
4 C. DISCUSSION
{
The MSIV full closure test was performed in Test Condition 6 with reactor core thermal power at 99.6% of rated and the
- main turbine generator producing 1105 MWE. The initial I
reactor steam dome pressure and reactor water level were 998 l psig and +35 inches, r e s pe c ti ve l y. A full MSIV NSSSS i isolation was initiated by inserting trips in the "A" and "B" channels of the MSIV NSSSS isolation logic. All the Level 1 and Level 2 acceptance criteria for this test were met with one exception: RCIC failed to auto-initiate and
- inject properly to the reactor vessel.
The reactor scrammed on "MSIV's NOT FULL OPEN" 0. 6 seconds
- after the second channel of the MSIV logic was tripped. The i MSI V' s isolated with an average stroke time ( ts) of 3.56 seconds and an average closure time ( tsol) of 3.91 seconds.
. Reactor steam dome pressure peaked at 1049 psig approximately 5 seconds into the t r a'n s i e n t. The pressure increase was terminated by the opening of Low-Low Set Safety
, Relief Valve ( SRV) " H" at its' initial opening setpoint of 4 1047 psig. SRV " H" closed approximately 54 seconds later at
- its Low-Low Set reset setpoint of 905 psig. (SRV " H" demonstrated its Low-Low Set function one more time during the test, opening again approximately three minutes into the t ransi ent) . No other SRV's lifted.
( Reactor water level reached its mi ni mum value of -46.3 inches at approximately five seconds into
( Both the RCIC and HPCI systems received a low reactor water the transient.
level auto-initiation signal, but only the HPCI system properly performed its function, injecting water to the reactor vessel ( The failure of the RCIC system to inject will be addressed at the end of this di s c ussi on) . The Redundant Reactivity Control System ( RRCS) properly tripped both Reactor Recirculation Pumps at approximately fifteen seconds into the transient, demonstrating the ATWS reactor water Level 2 trip. The maximum reactor water level achi e ved during this test was +65.0 inches and was largely caused by the HPCI injection. This maximum level was well below the +118 inch level at which main steam line flooding would occur.
Using data obtained from the Transient Safety Analysis Design Report ( TS ADR) and adjusting that data for actual plant and test conditions, the predicted reactor steam dome pressure rise was 87.7 psi. The actual pressure rise observed was 51.1 psi, a value well within the acceptance criteria for this parameter. Both acceptance criteria for the rise in heat flux were also met with a 0% observed rise as compared to the 0.55 predicted rise. All MSI V' s l satisfied the acceptance criteria for stroke and closure times. The slowest observed closure time ( tsol) was 4.16 l seconds, while the fastest stroke time ( ts) was 3.28 seconds. SRV " H" was the only SRV to open during the 5-85
performance of this test, and it properly resented as indicated by its tailpipe temperature returning to within 10oF of its pre-test value.
A summary of selected parameters discussed in the preceding paragraphs is as follows:
Criteria Measured Heat Flux Increase 0.5% 0.0%
Steam Dome Pressure Increase 97.7 psi 51.1 psi Average MSIV Stroke Time ( ts) 3.56 sec.
Fastest MSIV Stroke Ti me ( ts) L3. 0 sec 3.28 sec.
Average MSIV Closure Time ( tsol) 3.91 sec.
Slowest MSIV Closure Time ( tsol) L5. 0 sec. 4.16 sec.
Maximum RPV Water Level (118 i n. +65.0 i n.
Minimum RPV Water Level -46.3 i n.
As previously stated, the RCIC system failed to inject properly to the reactor vessel although it did receive and respond to en auto initiation command. The RCIC pump did not develop the head necessary to inject into the reactor vessel because the steam admission valve only partially opened as a result of faulty relay contacts. The relay contacts were later cleaned and adjusted, and the system was successfully retested with the reactor at power and pressure.
5-06
5.2.25 Test No.24 RELIEF YALVES
(
A. OBJECTIVES
- 1. Verify that the relief valves function properly and can be manually opened and closed.
- 2. Verify that the relief valves reseat properly after operation.
- 3. Verify that there are no major blockages in the relief valve discharge pi ping.
- 4. Verify the proper operation of the Low-Low Set relier valve actuation logic system.
B. ACCEPTANCE CRITERIA Level 1
- 1. There must be positive indication of steam discharge during the manual actuation of each valve.
- 2. The Low-Low Set pressure relier logic shall function to preclude subsequent simultaneous SRV actuations following the initial SRV actuation due to the original pressurization transient.
Level 1
- 1. Pressure 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.
i 2. The temperature measured by thermocouples on the
- discharge side of the valves shall return to wi t hi n l 100F of the temperature recorded before the valve was opened.
- 3. During the rated pressure test 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%
of rated MWe, or as measured by BPV position shall not
- be less than 90% of the average relief valve steam flow.
C. DISCUSSION The saf ety relief valves ( SRVs) were initially tested in TC-1 with reactor power at 205, steam dome p r e s s u r's at 927 (S psig, and the main turbine secured ( steam was being routed
(_,) to the main condensor via the bypass valves). Each relief valve was manually opened to verify proper operation. The valves were maintained open for approximately ten seconds to 5-87
allow plant variables to stabilize and be recorded for acceptance criteria evaluation.
All fourteen SRVs were individually cycled open and closed with their manual handswitches. Positive indication of relief valve discharge for all SRVs was verified using the Acoustic Honitoring System indications, changes in SRV tailpipe temperatures, changes in turbine bypass valve positions, and changes in main steam line total flow indications. However, failure of the acoustic monitoring system to respond to the opening of three SRVs, and of the tailpipe temperatures for five SRVs. to return to within 10oF of their pre-lift values, resulted in failure to meet a Level 2 criterion for the test. The Acoustic Monitoring System failures are addressed in detail in section 5.2.46 of this report. Engineering evaluated the five SRVs whose tailpipe temperatures did not return to within 10oF of their initial value and considered them to be weeping. This did not preclude continued reactor operation. A "use as-is" disposition was given to the Level 2 criterion failure with the recommendation that the SRV tailpipe temperatures be monitored closely for further degradation of seating integrity. The basis for the "use as-is" disposition was that the seat weepage was not causing measurable suppression pool heating. All of the SRV tailpipe temperatures eventually returned to normal indicating that any weepage had stopped.
All other acceptance criteria for the test were met. The least amount of steam flow through any SRV, as measured by turbine bypass valve position, was 99.8% of the average turbine bypass valve response for all SRVs, easily meeting the required minimum of 90%. The greatest decay ratio for oscillatory b e ha vi o r in pressure control system related variables was seen in turbine bypass valve position and was
- 0. 21, less than the Level 2 maximum allowable value of 0.25.
Low-Low Set pressure relief logic was verified to function properly in conjunction with other Power Ascension Test Program testing where reactor pressure transients adequate to trigger the Low-Low Set logic were anticipated.
Specifically, relier valve response was monitored during performance of " Shutdown From Outside the Control Room",
" Loss of Offsite Power", " Full MSIV Isolation", and " Full Power Generator Load Rejection" tests. The pressure transient for " Shutdown From outside the Control Room" was not sufficient to require Low-Low Set logic actuation, and so no actuation was observed. However, the pressure transients observed in the remaining three major tests did require the Low-Low Set logic to actuate, and in all cases the logic properly functioned per design. The associated Level 1 acceptance criterion was satisfied.
5-88
O One relief valve failure did occur during the Power Ascension Test Program.
scope of formal SRV testing.
This failure occurred outside the During the performance of
" Shutdown From Outside the Control Room", the "H" SRV was opened manually from the Remote Shutdown Panel several times to depressurize the RPV so that the Residual Heat Removal System could be placed into the Shutdown Cooling mode. The relief valve became stuck in the open position following the last opening at 75 psig reactor pressure. The SRV was replaced during the outage after the event occurred with a replacement obtained from Unit #2 spares. After the subsequent reactor startup, the new SRV was cycled at normal operating pressure and retested satisfactorily. The failed SRV was sent to Wyle Laboratories for evaluation where it was determined that the stem of the SRV pilot valve leading to its solenoid operator was bent, causing the stem to bind. It appeared that personnel in the drywell could have been using the solenoid casing of the pilot valve as a toe-hold. Inspection, personnel training, and protective devices were utilized to prevent reoccurance.
It was noted throughout the Power Ascension Test Frogram that some SRY tailpipe temperatures would initially be as high as 210oF after a reactor startup and pressurization.
However, the high temperatures would slowly trend downward over the next several days, often taking several weeks to O stabilize at a temperature consistent with the other Additionally, this phenomenon did not always occur with the SRVs.
same SRVs from startup to startup. SRV weepage during the Power Ascension Test Program was monitored closely x and evaluated by the NSSS vendor. In all cases the weepage condition was considered acceptable based on the combination of ta11 pipe temperature, acoustic monitor and suppression pool temperature data evaluations.
The SRV testing which was performed met the objectives of the Final Safety Analysis Report. The single acceptance criteria deficiency has been resolved, and no outstanding issues remain.
O 5-89
5.2.26 Test No. 25 TURBINE TRIP AND GENERATOR LOAD REJECTION A. OBJECTIVES
- 1. Demonstrate the proper response of the reactor and its control systems f ollowi ng trips of the turbine and generator.
- 2. Demonstrate the capacity of the turbine bypass valves.
B. ACCEPTANCE CRITERIA Level 1
- 1. For Turbine and Generator trips at power levels greater than 50% NBR, 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 lines following these transients.
- 3. The recirculation pump and motor time constant for the RPT two pump drive flow coastdown transient should be L4. 5 seconds from 1/4 to 2 seconds after the pumps are tripped and L3. 0 seconds from 1/4 to 3 seconds after the pumps are Laapped.
- 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.
- 5. The positive change in simulated heat flux shall not exceed the Level 2 criteria by more than 25 of rated value.
- 6. The total time delay from start of turbine stop valve motion or from start of turbine control valve motion to the complete suppression of electrical are between the fully open contacts of the RPT circuit breakers shall be less than or equal to 175 milliseconds.
9 5-90
Level 2
- 1. 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.
( The operator may take action as he desires after the first three minutes, including switching out of run mode. The operator may also switch out of run mode in the first three minutes if he confirms from measured data that this action did not prevent MSIV closure).
- 2. The positive change in vessel dome pressure and in simulated heat flux which occur within the first 30 seconds after the initiation of either generator or turbine trip must not exceed the predicted values.
( Predicted values will be referenced to actual test conditions of initial power level and dome pressure and will use BOL ( Beginning of Life) nuclear data. Worst case design or technical specification values of all hardware performance shall be used in the prediction, with the exception of control rod insertion time and the delay from beginning of turbine control valve or stop valve motion to the generation of the scram signal. The predicted pressure and haat flux will be O corrected for the actual measured values of these two parameters).
- 3. For the turbine trip within the bypass valves capacity, the reactor shall not scram.
- 4. The bypass capability (in percent of rated power) as calculated from startup data, shall be equal or greater than that used for the FSAR analysis.
- 6. Feedwater level control shall avoid loss of feedwater due to high level ( L8) trip during the event.
- 7. The temperature measured by thermocouples on the discharge side ~ of the safety / relief valves must return to within 10oF of the temperature recorded before the valve was opened. If pressure sensors are available, they shall return to their initial state upon valve closure.
O 5-91
d C. DISCUSSION Bypass Valve Capacity De t e rmi n3 Alan On September 2, 1986, in TC-2, with the main turbine-generator synchronized to the grid, the total capacity of the main turbine bypass valves was ' determined. The bypass valve capacity was determined by mstataining a constant ,
generator output of approx. 85 Mye while increasing reactor thermal power f rom 14% to 24.55, and recording feedwater flow as a function of individual bypass valve position. ,
From a plot of the total feedwater flow versus percent total bypass valve opening data, the total bypass valve capacit y was determined to be 25.2% of rated nuclear boiler steam flow. .This natisfied the acceptance criterion that t n r.
total bypass valve capacity be greater than or equal to 3f%
of rated steamflow.
During the test, oscillations in rea ac t or water level occurred with the startup level controller in auto
( discussed i n s ec ti on 5. 2.18) . This resulted in reactor power varying by as much as 40 to 50 MWth. The startuu level controller was placed in manual to obtain steady reactor power levels during the test.
Turbine Trio Within BvDass Valve Cacacity ,
On September 11, 1986, in TC-2, a Main Turbine Trip Within Bypass Valve Capacity was performed. The trip was initiated at 21% reactor power by depreasing the Main Turbine Master Trip pushbutton. The test demonstrated smooth pressure control transition from the turbine control valves to the bypass valves. The reactor Jid not s e r ain during the transient sinco a direct reactor scram from turbine stop valve closure is inhibited below approximately 305 power.
The reactor done pressure increase was only 7 ps i g. All acceptance criteria were satisfied.
Full Power GenttA> Load Rejection On December 6, 1986, in TC-6, a main turbine generator load rejection was initiated by simultaneously opening the main generator output breakers ( BS6-5 .und BS2-$) with the plant operating at 97% rated thermal power.
The EHC power-load unbalance circuit caused a fast closure of the turbine control valves, initiating a turbine trip, reactor scram, and reactor vessel pressurization. The rapid reactor vessel pressurfzation trancient caused the vi de and narrow range reactor water level innet'umentation output signals to oscillate spuriously between the Level 8 and ,
Level 2 trip setpoints in less than 0.6 seconds, causing a trip of the reactor feedwater pumps on Level 8, and initiation of the RCIC and HPCI systems, and trip of the reactor rectreulation pumps, on Level 2. The actual wide 5-92
. .y . .
--..e- e .- - ,
4 s
i >
range water level in the reactor remained at approximately j O 30 inenes during the water level instrumentation oscillation transient. The low-low setpoint safety / relief valves H and p lifted to control reactor pressure during the remainder of
., the transient. The sequerce of events during the transient
- is given in Table 5.2.26-1.
bl wThe spurious Level 8 trip signal at the start of the
- ' transient also tripped the feedwater turbines, therefore the capability of the feedwater control system to control reactdr ' water level during this transient could not be l evalusted as originally planned. Alternatively, an
- engineering evaluation was performed by the vendor and
} ,
System Engineering utilizing data from an earlier unplanned
- scram from high power ( 985) and response characteristics l observed at other BWRs with feedwater control systems similar to Hop 0 Creek. The conclusion of this evaluation was that the Hope Creek feedwater control system is capable i of maintaining reactor level between Level 2 and Level 8,
) '
during transients similar to a full power load rejection, as
- designed. The spurious trips caused by the level instrument l 9
, oscillations are independent of the feedwater control system l
ronponse capabilities. While not a safety concern, an la ipvestigation is in progress by Nuclear System Engineering y ( tb . determine the cause of the spurious level signal osct11ations.
The moximum speed of the main turbine during the transient
- was 1900 rpm ( 105. 65 of rated turbine speed) . This met the l t acceptance criterion that the speed of the main turbine not
, exceed 1967.4 rpm ( 109. 3% rated turbine speed) . The peak
, turbine- speed was unaffected by the turbine stop valve closure due to the spurious Level 8 trip because the control valves closed over one-half second before the stop valves i
closed. The steam flow path to the turbine was therefore closed by the fast closure of the turbine control valves and intercept valves, before the stop valves closed.
Due to slightly greater than expected pump / motor inertia.
l the recirculation pump drive flow coastdown was found to be
- ,sitghtly above the 4.5 second pump inertia time constant coastdown curve between 0.25 and 1.5 seconds following the trip of the pumps. Discussion of this problem, and
^
additional analysis being performed to assess the impact on MCPR limitations, is discussed in Test No. 28.
All other acceptance criteria were satisfied for this test.
. .s, 5-93
o Table 5.2.25-1 FULL POWER GENERATOR LOAD REJECTION TEST IN TC-6 Time ( seconds) Event 0.000 Main Generator MWe Output Begins to Decrease ( first transient event observed on data acquisition system) 0.008 Power / Load Unbalance Relay Trips 0.017 Bypass Valves Begin to Open 0.034 Turbine Control Valves Begin to Close 0.060 Reactor Scran, 0.076 Recirculation Pump Motor RPT Breakers 4A and 4B Trip 0.156 Turbine Control Valves Full Closed 0.185 Recirculation Pump Motor RPT Breakers at Full Arc Suppression (time determined from preoperational test data) 0.197 Bypass Valves 80% Open 0.232 Bypass Valves Full Open 0.792 RCIC Initiation 0.816 HPCI Initiation 0.968 S R V' s " H" and "P" Low-Low Set Logic Valves Open at 1052 psig 0.976 Feedwater Pump "A" Trip 1.088 Feedwater Pump "C" Trip 1.224 Feedwater Pump "B" Trip 2.472 Maximum Rea'ctor Dome Pressure Reached (1074.2 psig) 18.088 SRV "P" Closes at 929 psig 21.688 SRV " H" Closes at 906 psig O
5-94
5.2.27 Test No. 26 SHUTDOWN FROM OUTSIDE THE CONTROL ROOM A. OBJECTIVES Demonstrate the capability of performing a controlled shutdown of the plant from outside the control room. The major elements included within this test are:
- 1. Verify the plant can be safely shutdown from outside the control room.
- 2. Verify the plant can be maintained in a stable hot standby condition for at least 30 minutes from outside the control room.
- 3. Verify the potential exists to safely cool the reactor from hot standby to cold shutdown conditions from l outside the control room. This verification is to include an actual reactor cooldown of at least 50 degrees fahrenheit using the RHR Shutdown Cooling mode.
B. ACCEPTANCE CRITERIA Level 1 None Level 2
- 1. The ability to safely scram the reactor from outside the control room shall be demonstrated.
- 2. The ability to maintain stable hot standby reactor conditions from outside the control room for a mi ni mum period of 30 minutes shall be demonstrated.
- 3. The ability to safely cool the reactor from hot standby to cold shutdown conditions at a rate L 100oP/hr from outside the control room shell be demonstrated.
l 4 The ability to initiate and safely cool the reactor at least 50oF using the RHR Shutdown Cooling Moce controlled from outside of the control room shall be i
t demonstrated.
C. DISCUSSION 1
This test was initially performed in TC-1. The first part of the test demonstrated scramming the reactor and placing the plant in stable conditions (stable reactor level and pressure) and maintaining these conditions for a minimum of 30 minutes. This was successfully accomplished.
l O reactor scram and vessel isolation were physically initiated outside the control room by opening the generator (The output breakers of the "A" and "B" Reactor Protection System ( RPS) 5-95
motor generator sets) .
The second part of the test involved the " Cold Shutdown Demonstration". This demonstration was to cooldown and depressurize the reactor using Safety Relief Valves ( SRVs) for pressure control and the Reactor Core Isolation Cooling
( RCIC) system for RPV level control to a point where the Residual Heat Removal ( RHR) system could be placed in the Shutdown Cooling Mode. All these actions were to be controlled from outside the maia control room utilizing the Remote Shutdown Panel ( RSP) . During the final depressurization of the reactor (initiated at 75 p s i g) using SRVs, one SRV ( F013H) stuck open. At that point the test was aborted.
Subsequent to the test abort it was decided that only the second part of the test (" Cold shutdown Demonstration")
needed to be re-performed and that the Hot Shutdown Demonstration portion was satisfactory.
In TC-6, the second part of the test ( Cold Shutdown Demons t ra ti o n) was successfully performed. The cooldown rate was maintained within Technical Specification limits using the Shutdown Cooling Mode of RHR and was controlled from the Remote Shutdown Panel.
Following TC-6 testing, all acceptance criteria were met, and the procedures and systems involved were found to satisfy all requirements.
Some problems were encountered during the test that were related to the plant but had no effect on the test. They were documented on a " lessons learned" letter and resolved by the plant staff.
O 5-96
I 5.2.28 Test No. 27 RECIRCULATION FLOW CONTROL A. OBJECTIVES
- 1. Determine plant response to changes in recirculation flow.
~
- 2. Optimize the master flow controller settings.
B. ACCEPTANCE CRITERIA Level 1 The transient response of any recirculation system related variable to any test input must not diverge.
Level 2
- 1. A scram shall not occur due to recirculation flow control maneuvers. The APRM neutron flux trip avoidance margin shall be L7. 5 % and the heat flux trip avoidance margin shall be L5 % , when the power maneuvers effects are extrapolated to those that would occur along the 1001 rated rod line.
- 2. The decay ratio of any oscillatory controlled variable must be 10. 25.
(~")s
\_ -
- 3. Steady state limit cycles (if any) shall not produce l
i turbine steam flow variations greater than 10.5% of l , rated steam flow.
~
- 4. In the scoop tube reset function, if the speed demand meter has not been replaced by an error meter, the speed demand meter must agree with'the speed meter within 6% of rated generator speed.
Level 3
- 1. The f ollowi ng criteria are for the closed speed loop ad j us t me nt:
l a. Above 901 rated core flow, the speed delay time
! shall be L2. 0 seconds, and the rise time shall be 15.0 seconds.
- b. Following a 101 speed demand step at the low end of the speed control range, the time f rom the step demand until the generator speed peak occurs, must be L25 seconds.
O 5-97
- 2. The following four criteria are for open speed loop adj us tme nt s:
- a. The speed response to 10% speed step input changes shall have a delay time LO. 9 seconds and a rise time (1. 6 seconds,
- b. The scoop tube actuators or the function generators may be adjusted so that the maximum change in the slope ( of generator speed output versus function generator input change) shall not exceed a factor of 2 to 1 for the maximum slope versus the minimum slope over the operating speed range of 20% to 102.5% rated generator speed.
- c. The variation in the open loop response time (symmetry of positive and negative responses, or variation with generator speed range) shall not exceed a f actor of 3: 1.
C. DISCUSSION The recirculation flow control capability of the plant was successfully demonstrated over the entire pump speed operating range including i ndi vi dual loop manual and combined master manual operation. All electrical compensators and controllers were adjusted as required for desired system performance.
At cold reactor conditions, prior to startup, the speed loop controllers were set to gi ve a smooth well-damped response to plus and minus 10% speed demand steps. The speed loop controller gain values were established using pretest analysis a n.d bench calibration of the controllers. In TC-3, the control loops were tested along a midpower rod line using plus and minus 5% and 10% speed demand steps after the feedwater control and pressure regulator systems had been l tuned. Finally, in TC-6, the controllers were tested on the 100% load line by inserting plus and minus 5% steps to check l speed loop stability. In all cases, the speed demand steps were inserted with a test step generator. The final controller settings are listed below.
Recirculation Speed Controller Settings Gain Resets i Loop A 0. 8 14 Loop B 0.85 14 i
1 5-98
Level 1 and 2 acceptance criteria were satisfied for all the O tests, and the response of both recirculation loops to speed step changes were also demonstrated to be well matched. The worst case decay ratio, 0.18 for pump A speed, occurred f ollowi ng the minus 55 speed demand step in TC-6. The corresponding decay ratio for pump B speed was 0.16. Scram avoidance margins were a factor of two greater than the criteria limits for both positive and negative speed steps.
although steam flow variation was 10.475 which just met the acceptance criterion of 10.55, the turbine control valves were not exhibiting excessive cycling, and therefore premature component wear is not expected.
The level 3 acceptance criteria for closed speed loop testing were not met. These criteria specify requirements for system responsiveness, however when tuning the system using 105 speed steps, the plant response would not meet the level 2 acceptance criteria for neutron and heat flux trip i avoidance margins. The system was therefore tuned to always i meet the level 2 criteria for both 55 and 105 speed steps.
The recirculation system high speed electrical and
- mechanical stops are properly set. For a two recirculation
, pump runout event, the electrical stops will limit total core flow to a maximum of 101. 6% of rated and the mechanical stops will limit flow to 104.2% of rated. These settings j meet the plant Technical Specification values of L102.5% and L105% of rated for electrical and mechanical stops respectively.
. During the TC-3 testing, .oth recirculation motor-generator set scoop tube positioner brake assemblies were found to be dragging due to burned out solenoids. The brake assemblies were replaced and the testing was successfully performed.
The design of the brake system is undergoing engineering review for possible replacement with a brake design less prone to solenoid failure.
I i
- O 5-99
5.2.29 Test No. 28 RECIRCULATION SYSTEM A. OBJECTIVES
- 1. Determine transient responses and steady-state conditions following recirculation pump trips at selected power levels.
- 2. Obtain recirculation system performance data.
- 3. Verify that cavitation in the recirculation system does not occur in the operating region of the power / flow map.
- 4. Verify that the feedwater control system can control water level without causing a turbine trip / scram following a single recirculation pump trip.
- 5. Demonstrate the adequacy of the recirculation pump restart procedure at the highest possible power level.
- 6. Verify acceptable performance of the recirculation two-pump trip circuit.
B. ACCEPTANCE CRITERIA Level 1
- 1. During recovery from a one pump trip, the reactor shall not scram.
- 2. The recirculation pump and motor time ev:stant for the RPT two pump drive flow coastdown transient should be L4. 5 seconds from 1/4 to 2 seconds after the pumps are tripped and L3.0 seconds f rom 1/ 4 to 3 seconds after the pumps are tripped.
l Level 2 l
1 The reactor water level margin to avoid a high level l
trip shall be L3. 0 inches during the one pump trip.
l 1
- 2. The simulated heat flux margin to avoid a scram shall be L5. 0% during the one pump trip and during the pump trip recovery.
- 4. Criteria a through e are evaluated at or near rated power:
- a. The core flow shortfall shall not exceed 5% at rated power.
5-100
O b. The measured core LLP shall not be > 0. 6 psi above prediction.
- c. The calculated jet pump M ratio shall not be < 0. 2 points below prediction.
- d. The drive flow shortfall shall not exceed 5% at rated power.
- e. The measured recirculation pump efficiency shall not be > 8% below the vendor tested efficiency,
- f. The nozzle and riser plugging criteria shall not be exceeded.
- 5. Runback logic shall have settings adequate to prevent operation in areas of potential c a vi t a t i on.
C. DISCUSSION Recirculation System Sincie Pumn Trio Test Reactor recirculation pump "A" was tripped on December 2, 1986 in TC-6 from 99% power and 985 core flow, and pump "B" was tripped on November 1, 1986 in TC-3 from 75% power and-95% core flow. The pumps were tripped by opening the MG set l drive motor breakers from the control room. During both of the pump trips, reactor parameters were analyzed to verify both adequate margin to RPS setpoints and the capability of the feedwater system to prevent a high water level trip.
,3 The capability for restarting a recirculation pump at a high
_. power level without causing a reactor scram was also demonstrated when recirculation pump "A" was restarted from 55% power and pump "B" was restarted from 405 power. The margins to scram measured during the pump trip and pump restart, presented below, satisfied all acceptance criteria.
, l Margin to High l APRM Margin to! Margin to Flow PUMP l Water Level Trip l Scram on Pump l Bias Scram on l Pump Trip ! Restart l Pump Restart l Criteria L3 inches l Criteria L7.5% l Criteria L 5%
e , ,
_______________i__________________e_______________i_______________
'=
RR Pump "A" l 14.3 inches l 545 l 5%
i RR Pump "B" ! 15.3 inches ! 67% ! 32%
l 5 101
_ _ _ . - . . _ _ ~ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
Recirculation System Two Pump Trio Test Both reactor recirculation pumps were tripped simultaneously by tripping the RPT breakers using a temporary test switch.
The pumps were tripped from 72% power and 96% core flow on November 1, 1986 in TC-3. The recirculation pump flow coastdown times did not meet the acceptance criteria. The averaged pump flow coastdown failed to fall within the upper (4.5 second pump inertia time constant) bounding curve between 0.25 seconds and 1.0 seconds. A coastdown that exceeds the upper boundary is too slow and may not satisfy the RPT requirement for a ra pi d power reduction to ensure that thermal hydraulic limits are n'ot exceeded at the end of core life ( EOC) . These coastdown results were similar to those observed during tests at other plants. Plant operati'dn was resumed using an interim adder of 0.02 to the MCPR operating limit value, making it 1.22. The adder was applied until the pump coastdown was evaluated again in TC-6 during the performance of the Full-Power Generator Load Rejection Test (test number 25).
The recirculation loop coastdown again failed to meet the acceptance criteria during the Generator Load Rejection test in TC-6. To resolve this issue for the first fuel cycle, an EOC-RPT out-of-service analysis was performed by General Electric Company, and an emergency Technical Specification change to incorporate an appropriate MCPR penalty was submitted to the NRC and subsequently accepted on December 9, 1986. The Technical Specification change allowed continued operation of the plant at full power with EOC-RPT declared out-of-service. A plant specific analysis is being performed to assess EOC-RPT transient events using actual RPT coastdown data.
Recirculation System Performance Recirculation system operating data were recorded in TC-2, 3, 4, and 6 during steady state operation and during the recirculation pump restarts f ollo wi ng the single pump trips in TC-3 and TC-6. The data were used to obtain a baseline relationship for drive flow versus core flow, and to determine core flow shortfall, core plate differential pressure, calculated jet pump M ratio and drive flow shortfall. Recirculation pump efficiency and jet pump nczzle and riser plugging parameters were also evaluated.
Due to inoperable telewatt meters the recirculation pump efficiencies could not be evaluated using the methodology utilized at other BWRs. However, in TC-6 the pump efficiencies were calculated, using performance correlation data supplied by the vendor, and were found to meet acceptance criterion. In addition, all other acceptance criteria were satisfied. In TC-6, the recirculation system performance was as follows:
5-102
Acceptance
(,. ) Parameter Measured Value Criteria Core Flow Shortfall -9.3%* L 5%
Core plate differential Pressure 13.7 paid L 15.7 psid Jet Pump H-ratio 2.13 L 1. 8 Drive Flow Shortfall -0.21%* L 76%
Recirculation Pump Efficiency 77.4% t 76%
Jet Pump Nozzle Plugging 5. 5 % L 12%
Jet Pump Riser Plugging 2.2% L 10%
- Note: The negative number indicates there was excess flow.
Recirculation Pump Cavitation Test pg This test successfully demonstrated that the recirculation
(_f pump feedwater flow runback circuit is s'et such that no cavitation of the recirculation pumps or jet pumps will occur in the operating region of the power-to-flow map. The test commenced in TC-3 with reactor power at 69% of rated and core flou at 97% of rated. The runback circuit was bypassed so that the actual runback would not occur ( however the runback signal was monitored) and control rods were l inserted to reduce power (and feedwater flow) until feedwater flow was 19% of rated. Cavitation was not observed, and the runback signal occurred at 21 % of rated feedwater flow.
O .
l l
f 5-103
5.2.30 Test No. 29 RECIRCULATION FLOW CALIBRATION A. OBJECTIVES
- 1. Verify the calibration of the recirculation system flow instrumentation, including total core flow and recirculation drive flow signals.
- 2. Verify the position of the maximum electrical and mechanical speed stops on the recirculation pump M-G sets are set such that core flow will .t o t exceed 102.5%
of rated in case of a single failure.
B. ACCEPTANCE CRITERIA Level 1 None Level 2
- 1. Jet pump flow instrumentation shall be adjusted such that the jet pump total flow recorder will p r o vi d e a correct core flow indication at rated conditions.
- 2. The APRM/RBM flow-biased instrumentation shall be adjusted to function properly at rated conditions.
- 3. The flow control system shall be adjusted to li mi t maximum core flow to 102.5% of rated.
C. DISCUSSION During the Recirculation System Flow Calibration, data were taken for various parameters of the recirculation system (i.e. single and double tap jet pump mi lli vol t inputs, APRM/RBH Flow Unit millivolt inputs and outputs) and input as the test data file into the General Electric, Mark III l computer program JRPUMP. This program utilizes a plant l specific data file and the test data file to calculate l actual loop flows and total core flow. These calculations l
were used to adjust APRM flow unit gains, jet pump loop flow
! summer gains, and recirculation flow control system drive flow signal inputs. The total core flow and recirculation dri ve flow inputs to the process computer were also verified to be accurate.
Recirculation System Flow Calibration was performed four I
times in TC-3. Using the JRPUMP output, adjustments were made to the flow instrumentation after each of the first two
, performances. The latter two performances were done to
! confirm satisfactory instrument calibration f ollo wi ng the adjustments. The resultant GAFs for both loops did not meet the Level 2 criteria required by the procedure but were found to be acceptable by since they are conservative with l
5-104
(' conservative with respect to thermal The TC-3 results are summarized in Table 5.2.30-1.
limit calculations.
In TC-6, Recirculation System Flow Calibration was performed three times. Again JRPUMP calculations were used to make adjustments on the recirculation flow instrumentation following the first performance of the test. During the second performance it was concluded that the noise on the uncalibrated and calibrated jet pump square rooter input signals was large enough to impact some of the test results.
The second run was aborted and re-performed using a data logger to obtain an average value from 10 data samples, for the square rooter inputs, thus reducing the effect of the signal noise on the square rooter calibration check test results. All JRPUMP required data were obtained from GETARS. All acceptance criteria were satisfied showing the recirculation system flow instrumentation to be satisfactorily calibrated. The TC-6 results are summarized in Table 5.2.30-1 Also in TC-6 the maximum positions of the electrical and mechanical speed stops on the recirculation pump M-G sets i
were set so that core flow will not exceed Technical Specification limits in the event of a single failure.
During this test, recirculation M-G set speeds were recorded for both loope A and B. These speeds were used to determine
'T the maximum total core flow at both the electrical and s mechanical stops.
All acceptance criteria were satisfied, l and the final results are shown on Table 5.2.30-2.
In addition, process computer core flow and drive flow evaluations were done. The process computer total core flow was compared to the calculated ( J RPUMP) total core flow and found to read slightly lower. The drive flow comparison showed the process computer drive flow to also read slightly lower than the calculated value. There is no acceptance criteria related to this, but these results were reviewed by Reactor Engineering for determination of Process Computer Core / Drive flow accuracy. The process computer value for 100% drive flow was updated, and the APRM/ RBM flow units were recalibrated. Reactor Engi ne e ri ng' s core flow calibration procedure was also performed and gave similar results to the JRPUMP calculations.
l i
P)
L.
5-105 I -.
Table 5.2.30-1
SUMMARY
OF RECIRCULATION SYSTEM FLOW CALIBRATION RESULTS 1
____-_____________________-______________________________________________ 1 l PARAMETER l TC-3 l TC-3 l TC-6 TC-6 l l l RESULTS l CRITERIA l RESULTS l CRITERIA l
________________________________,_____________,___________,i i l Reactor Power l 67.55% l N/A l 99.58% ! N/A l i i i_____________________i___________i_____________i________________________ii i e l Total Core Flow l 95.70% l L90% and l 95.90% l L95% and l l L100%
l l l
l L1005 l
. _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ .___________i_____________,___________i_____________i l Jet Pump Loop A l 1.008 l 0. 9 9 tG A FL1. 00l 1.000 l 1. 00 LG AF L1. 01l l Summer GAF l l ( Note 1) l l ( Note 1) l e i
.i
_____________________i___________._____________e. _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ , .
i l Jet Pump Loop B l 1.003 10.99tGAFL1.00! 1.010 l 1. 00 LG AFL1. 01 l l Summer GAF l l ( Note 1) l l (Note 1) l i i i________________________________e e i
.________________________i_____________i i
i Recirculation Drive l N/ A l N/A l 0.9905 l 0. 9 8 L ratio l l Flow Ratio l l l l L1. 0 0 l
._____________________i________________________i________________________i.
Note 1: GE Startup Test Specification criteria changed after TC-3 to place GAFs on conservative side. PSE&G calibration tolerance is 12. 0 %.
Table 5.2.30-2
SUMMARY
OF RECIRCULATION MG SET ELECTRICAL & MECHANICAL STOP RESULTS 4
l ACCEPTANCE CRITERIA l LOOP A l LOOP B l 1 .i ________________________________i______________,_______-______.
l Extrapolated Total Core Flow l l l l l ( Electrical Stop) (102.5 MLB/ HR l 101.6 MLB/HR l 101.0 MLB/HR l
.i ________________________________,______________i______________.
l Extrapolated Total Core Flow l l l l(Mechanical Stop) L105.0 HLB / HR l 104.0 MLB/HR l 104.2 HLB /HR l i________________________________i______________i______________i i
l l
l 9
l l
(
l 5-106 l
.e _ . _ _ _
5.2.31 Test No. 30 LOSS OF OFFSITE POWER (p) A. OBJECTIVE
- 1. Demonstrate the response of the reactor and electrical systems during a loss of main turbine generator coincident with a loss of offsite power.
- 2. Demonstrate the ability of the onsite power sources
( Emergency Diesel Generators) and electrical distribution systems to supply power to systems and components important to safety.
- 3. Demonstrate that the loads necessary for s safe and orderly shutdown of the reactor during a loss of the main turbine generator coincident with a loss of offsite power event f unction i n accordar.ce with design.
B. ACCEPTANCE CRITERIA Level 1 All safety systems, such as the Reactor Protection System, the diesel-generators, and HPCI must function properly without manual assistance, and HPCI and/or RCIC system action, if necessary, shall keep the reactor water level above the initiation level of Low Pressure Core Spray, LPCI,
('} Automatic Depressurization system, and MSIV closure. Diesel
(_/ -
generators shall start automatically.
I Level 2 l 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.
- 2. If safety / relief valves open, the temperature measured by thermocouples on the discharge side of the safety / relief valves must return to within 10oF of the temperature recorded before the valve was opened. If l pressure sensors are available, they shall return to their initial state upon val ve closure.
O V
1 I
5-107
C. DISCUSSION The Loss of Offsite Power ( LOP) Test was initially performed on September 11, 1986, 9,
in TC-2. During this test, design problems in the control logics of the Reactor Auxillaries Cooling ( Closed Cooling Water) System were encountered that j resulted in a total loss of drywell cooling. Consequently, drywell pressure control could not be assured, and the test ,
was aborted four minutes after it was initiated. Reactor '
performance during the test was as expected, with the scram occuring due to loss of RPS power. Post test debriefings identified the following additional,significant problems:
- a. Reactor building supply and exhaust ran damper positioners were not supplied from a 1 E power source.
- b. SRV acoustic monitors were not supplied from a 1E or uninteruptable power source.
- c. Emergency diesel generator C output breaker failed to close as required.
On September 19, 1986 a LOP test was conducted, with the reactor shutdown, for a period of 30 minutes. This test allowed a more complete evaluation of the plant response and identified the following additional s i gni fi c an t anomolies:
- a. SACS loop B head tank indication lost.
- b. Indication for RACS pumps lost.
- c. Unexpected power loss to some control room indicators.
- d. Service Water loop B high preasure alarm due to power loss.
- e. Additional Bailey control logic problems.
On September 24, 1986 the NRC issued a Confirmatory Action Letter and dispatcht;d an Augmented Inspection Team ( AIT) to the plant to assess the anomolies identified during the above tests prior to plant restart. Upon completion of corrective actions, and with the authorization of the AIT, a second LOP test was conducted on October 2, 1986 with the reactor in cold shutdown. This test included verif ying the proper operation of a sample of Bailey 862 logic module functions that were not specifically included in earlier testing. The results of this test were satisfactory and the l NRC authorized a plant restart to perform the LOP test at l power.
The second performance of the Loss of Offsite Power Test was conducted in TC-3 on October 11, 1986. Initially, the reactor was in the run mode at 20% power ( 658 MWT) with the turbine generator on line, producing 135 MWE. Initial reactor water level was +35 inches, and narrow range reactor pressure was 930 psig. A loss of all offsite power was initiated by simultaneously tripping the main turbine and all power to the 13.8 KV ring bus (the power source for all house loads) Prior to the test initiation, all possible 5-108
alternate sources of power for the 13.8 KV ring bus were locked out by breaker alignment. During the first few Os seconds subsequent to the trip, reactor pressure peaked at 937 psig and APRM power peaked at 225. The reactor did not scram until 3. 2 seconds into the transient, the cause of the scram being a loss of RPS power ( RPS power was maintained an additional 3. 2 seconds by the inertial energy of the flywheels of the RPS motor generator sets). With the loss of RPS power, the MSIVs closed. Reactor narrow range water level stabilized at +13 inches once the MSIVs fully closed and the Reactor Recire Pumps completely coasted down.
During the course of the subsequent thirty minute stabilization period required by the test, reactor pressure and water level were maintained without the use of either HPCI or RCIC. Low-Low Set SRY actuation logic functioned as designed. Eleven minutes into the transient, SRV " H" lifted at a reactor pressure of 1047 psig, closing when pressure decreased to 905 psig. SRV " H" opened one more time during the test, twenty six minutes into the transient at a reactor pressure of 1017 psig. SRV " H" closed again when reactor pressure was reduced to 905 psig, and the test was concluded shortly thereafter. At the completion of the test, reactor narrow range water level was still greater than +0 inches, well above the -38 inch auto-actuation setpoint for both the HPCI and RCIC Systems. SRV " H" tailpipe temperature did return to its pre-test value. All four emergency diesel
( '
generators properly started and loaded onto their respective safety buses, and loads sequenced as required by the FSAR to effect a safe and orderly shutdown. The required instrument displays for the reactor operator were verified to be proper. No safety systems required manual operator assistance.
The objectives of the test were met, and all Acceptance Criteria were satisfied.
l l
I l
l O
5-109
5.2.32 Test No. 31 AND 39 PIPE VIBRATION A. OBJECTIVES
- 1. Verify that the Nuclear Steam Supply System ( NSSS) piping ( recirculation and main steam line piping inside the drywell) steady state vi b ra t i o n is within acceptable limits.
- 2. Verify that, during operating transient loads, pipe stresses are within code limits.
- 3. Verify the f ollo wi ng for Non-NSSS, Balance-of-Plant
( BOP) Piping.
- a. Steady state vibration levels of the main steam
( outside the drywell) and feedwater piping are within acceptable limits during normal operation at rated flow,
- b. Stability of the RCIC system piping during steady state conditions.
- c. Stability of the HPCI system piping during rated flow.
- d. Stability of the HPCI turbine steam supply piping during HPCI turbine trip from rated speed (rated reactor pressure, rated turbine load, rated HPCI flow) and the subsequent transient.
- e. Stability of the BOP main steam piping during turbine stop/ control valve closure, and the subsequent transient.
f f. Stability of the feedwater system piping during l turbine feed pump trip. and the subsequent transient condition.
l
- q. Piping associated with main steam system is l
properly designed to withstand the actuation of main steam safety / relief valves.
i l
t t
5-110
- - - - - - - = - - - - - - .
B. ACCEPTANCE CRITERIA Level 1 NSSS Piping
- 1. Operating Transients: Level 1 limits on piping displacements are prescribed in Tables 5.2.32-2 through 5.2.32-4. These limits are based upon keeping the loads on piping and suspension within safe limits. If any one of the transducers indicate that these movements have been exceeded, the test shall be placed on hold.
- 2. Operating Vibration: Level 1 limits on piping displacement are prescribed in Table 5.2.32-1. These limits are based upon keeping piping stresses and pipe mounted equipment accelerations within safe limits. If any one of the transducers indicate that the prescribed limits are exceeded, the test shall be placed on hold.
BOP Piping - Instrumented Lines
- 3. Operating Transients: Piping systems whose dynamic transient loads and/or velocities exceed the acceptance i
values listed in Tables 5.2.32-5 through 5.2.32-8 by more than 155 shall be held in an acceptable operating mode. These systems shall be designated as test exceptions in the test procedures until they' are evaluated and reconciled in accordance with plant admi ni s t ra ti ve procedures.
- 4. Operating Vibration: Piping systems whose steady state vibrations exceed either criterion C or criterion D by 25% or more shall be held in an operating conditon with acceptable vibration until a resolution of the test
- exception is made. See Table 5.2.32-9 for criterion C and criterion D.
BOP Piping - Non-Instrumented Lines
- 5. Operating Transients: None
- 6. Operating Vibrations: Piping systems whose steady state bivration exceed acceptable vibrations by 25% or
{
more shall be held in an operating condition with acceptable vibration until a resolution of the test exception is made.
O 5-111 l
. - . _ _ - - . ,-__----,,,c--
Level 2 NSSS Piping 1 Operating Transients: Transducers have been placed near points of maximum anticipated movement. Where movement values have been predicted, tolerances are prescribed for differences between measuements and predictions. Tolerances are based on instrument accuracy and suspension free play. Where no movements have been predicted, limits on displacement have been prescribed. Table 5.2.32-2 through 5.2.32-4 tabulates allowable movements or movement tolerances for each transducer.
- 2. Opsrating Vibration: Acceptable levels of operating vibration are prescribed in Table 5.2.32-1. The limits have been set based on consideration of analysis, operating experience, and protection of pipe mounted components.
BOP Piping - Instrumented Lines
- 3. Operating Transients: Piping systems whosa dynamic transient roads and/or velocities exceed the acceptance values listed in Table 5.2.32-5 through 5.2.32-8 by less than 15% and/or by visual evaluations shall be dispositioned by the test engineers in accordance with plant admi ni s t ra ti ve procedures.
Additionally, the main steam piping. HPCI piping, feedwater pi pi n g, safety / relief val ve and discharge piping will be visually verified, prior to and after the transient to have no excessive pipe damage (i.e.
distortion of pipe, damaged pi pi ng supports or structural steel, damaged i ns ula ti on) .
- 4. Operating Vibrations: Piping systems whose steady state vi bra ti ons exceed either criterion C or criterion D by less than 25% shall be dispositioned by the test engineer.
BOP Piping - Non-Instrumented Line
- 5. Operating Transients: none
- 6. Operating Vibrations: Piping systems whose steady state vibration exceed acceptable vibration by less than 25% shall be dispositioned by the test engineer.
O 5-112
.e- --- - -- - - -
l C. DISCUSSION NSSS Pinino Steady-State Vibration Remote measurements of piping vibration were taken during
, the following steady state conditions:
- 1. Main Steam flow at 255 rated steam flow.
- 2. Main steam flow at 50% of rated steam flow.
1
- 3. Main steam flow at 75% of rated steam flow.
- 4. Main steam flow and recirculation flow at 100% of rated.
- 5. Recirculation at minimum pump speed and rated reactor i temperature, j- 6. Recirculation at 50% t 55 of rated core flow and operating temperature.
4 7. Recirculation at 75% t 5% of rated core flow and operating temperature.
- 8. Recirculation during RHR Shutdown Cooling operation.
( . During the testing, data from the remotely mounted vibration sensors were recorded on a high speed PCM magnetic tape recorder, and processed and analyzed using the GETARS
, transient test recorder. The results of the testing showed
,, that steady state vibratory rceponse for the reactor recirculation and main steam piping at all tested conditions were within the acceptance criteria limits. Test results at 100 percent steady-state main steam flow and recirculation.
flow are given in Table 5. 2.32-10 and Table 5.2.32-11, I
r e s pe c t i ve l y.
NSSS Picina Dynamic Response
- Remote measurements of piping vibration were taken for the NSSS portion of the main steam lines during the following tests
- 1. Main Turbine Initial Startup
- 2. Individual Safety / Relief Valve Operation
- 3. Loss of Offsite Power
- 4. Turbine Trip Within Bypass Valve Capacity Test 5.
( MSIV Full Isolation Test
- 6. Full Power Generator Load Rejection 5-113
Remote vi b r a ti on measurements were taken for the NSSS Reactor Recirculation Piping during the following tests:
- 1. Recirculation Single Pump Trip
- 2. Recirculation Two Pump Trip
- 3. RHR Shutdown Cooling Mode Operation Demonstration
- 4. Recirculation Pump Restarts at Natural Circulation Conditions.
The results of the testing showed that the transient vi b ra ti on for the reactor recirculation and the main steam piping was within the acceptance criteria limits. The only violation was one Level 2 failure at location SB-LZ on main steam line "B" when SRV "P" was lif ted during safety / relief valve testing. The measured amplitude of 0.066 i n. exceeded the Level 2 criterion limit of 0.060. After a walkdown of the steam line confirmed that no interferences existed, and a comparison with the vibration amplitudes of the other main steam lines was completed, this minor criterion violation was accepted as-is by the cognizant piping engineer.
Transient vibration data obtained during the Full Power Generator Load Rejection Test are given in Table 5.2.32-12.
BOP Pi or no Steady-State Vibration Steady state Non-NSSS, BOP piping vibration data were taken for the following systems:
- 1. Main Steam and Feewater Piping during Rated Power Operation.
- 2. RCIC Piping during Operation at Rated System Flow.
l
- 3. HPCI Piping during Operation at Rated System Flow.
t l No piping steady-state vibratory response problems were i encountered during any of the testing. The only testing l related problem was the failure of two accelerometers on the main steam drains outside the drywell due to a steam leak in the steam tunnel. After replacing the instruments, the system was retested, and criteria were satisfied.
BOP Pipino Dynamic Response Transient Non-NSSS, BOP piping vibration data were taken during the following major transients:
- 1. Main steam piping vibration during the Loss-of-Offsite Power Test, MSIV Full Isolation Test, and Full Power Generator Load Rejection Test.
1 5-114
/*' 2. Safety / relief valve "J" discharge piping during
( ,]) operation of the valve.
- 4. HPCI steamline piping during a trip at rated system flow.
The following problems were encountered during the dynamic response testing of the BOP Piping Systems:
- 1. After the Full Power Generator Load Rejection Test, a i post-test walkdown showed some damaged insulation on the main steam line outside the drywell. The insulation damage associated with the testing was minor and was dispositioned " accept as-is" by Engineering.
- 2. After the MSIV Full Isolation Tast, a pipe clamp on a main steam line was found rotated a pproxi ma t ely 8 degrees around the pipe, resulting in minor insulation damage and a support orientation out-of-tolerance
+
condition. System Engineering concurred that no piping i
or piping support damage had occurred. A work order to adjust the pipe clamp was completed.
All remote instrument data were within acceptable design limits.
lO .
5-115
TABLE 5.2.32-1 NSSS STEADY-STATE OPERATIONAL VIBRATION LIMITS Pipeline Sensor Level 1 Rance ( i nches)
Description Identification l Level 2 Rance l l l (inches) l l V V V V Main Steam Line A TRA1 SA-LX 0.093 0.046 -0.046 -0.093 SA-LY 0.045 0.023 -0.023 -0.045 SA-LZ 0.111 0.055 -0.055 -0.111 TRA2 SA-RX 0.104 0.052 -0.052 -0.104 SA-RY 0.097 0.049 -0.049 -0.097 SA-RZ 0.064 0.042 -0.042 -0.084 Main Steam Line B TRB1 SB-LX 0.147 0.074 -0.074 -0.147 SB-LY 0.106 0.053 -0.053 -0.106 SB-LZ 0.051 0.026 -0.026 -0.051 TRB2 SB-RX 0.084 0.042 -0.042 -0.084 SB-RY 0.192 0.064 -0.064 -0.192 SB-RZ 0.061 0.031 -0.031 -0.061 Main Steam Line C TRC1 SC-LX 0.233 0.116 -0.116 -0.233 SC-LY 0.073 0.036 -0.036 -0.07 SC-LZ 0.051 0.026 -0.026 -0.0 TRC2 SC-RX 0.122 0.061 -0.061 -0.122 SC-RY 0.101 0.034 -0.034 -0.101 SC-RZ 0.098 0.049 -0.049 -0.098 Main Steam Line D TRD1 SD-LX 0.105 0.052 -0.052 -0.105 SD-LY 0.045 0.022 -0.022 -0.045 l SD-LZ 0.136 0.068 -0.068 -0.136 TRD2 SD-RX 0.105 0.052 -0.052 -0.105 SD-RY 0.082 0.041 -0.041 -0.082 SD-RZ 0.117 0.058 -0.058 -0.117 Recire. Loop A T1 RA-SX 0.055 0.028 -0.028 -0.055 RA-SY 0.020 0.010 -0.010 -0.020 RA-SZ 0.640 0.020 -0.020 -0.040 T2 RA-PX 0.025 0.018 -0.012 -0.025 RA-PY 0.020 0.010 -0.010 -0.020 RA-PZ 0.030 0.015 -0.015 -0.030 T3 RA-DX 0.030 0.015 -0.015 -0.030 l RA-DY 0.020 0.015 -0.015 -0.030 RA-DZ 0.100 0.050 -0.050 -0.100 T4 RA-HX 0.055 0.028 -0.028 -0:05 RA-HY 0.025 0.012 -0.012 -0.025 RA-HZ 0.090 0.045 -0.045 -0.090 5-116
a TABLE 5.2.32-1 r\
( ,) NSSS STEADY-STATE OPERATIONAL VIBRATION LIMITS ( Cont' d)
Pipeline Sensor Level 1 Rance ( i nches)
Description Identification ! Level 2 Rance !
l l ( i nc he s) ! !
V V V V Recire. Loop B T1 RB-SX 0.115 0.058 -0.058 -0.155 RB-SY 0.025 0.012 -0.012 -0.025 RB-SZ 0.073 0.036 -0.036 -0.073 T2 RB-PX 0.025 0.012 -0.012 -0.025 RB-PY 0.018 0.009 -0.009 -0.018 RB-PZ 0.032 0.016 -0.016 -0.032 T3 RB-DX 0.029 0.014 -0.014 -0.029 RB-DY 0.029 0.015 -0.015 -0.029 RB-DZ 0.101 0.050 -0.050 -0.101 T4 RB-HX 0.052 0.026 -0.026 -0.052 RB-HY 0.029 0.014 -0.014 -0.029 RB-HZ 0.092 0.046 -0.046 -0.092 i
(~-}i -
l i
l O
5-117 i~_-.
6 TABLE 5.2.32-2 NSSS TRANSIENT VIBRATION LIMITS ( TSVC)
- Pipeline Sensor Level Rance 1 ( i nches)
Description Identification l Level 2 Rance l l l ( i nc hes) l l V V V V Main Steam Line A TRA1 SA-LX 0.093 0.046 -0.046 -0.093 SA-LY 0.062 0.036 -0.036 -0.062 SA-LZ 0.111 0.055 -0.055 -0.111 TRA2 SA-RX 0.104 0.052 -0.052 -0.104 SA-RY 0.097 0.049 -0.049 -0.097 SA-RZ 0.084 0.042 -0.042 -0.084 '
Main Steam Line B TRB1 SB-LX 0.147 0.074 -0.074 -0.147 SB-LY 0.106 0.053 -0.053 -0.106 SB-LZ 0.051 0.030 -0.030 -0.051 TRB2 SB-RX 0.084 0.042 -0.042 -0.084 SB-RY 0.192 0.076 -0.076 -0.192 SB-RZ 0.061 0.031 -0.031 -0.061 Main Steam Line C TRC1 SC-LX 0.233 0.116 -0.116 -0.233 SC-LY 0.073 0.036 -0.036 -0.0 SC-LZ 0.051 0.030 -0.030 -0.0 TRC2 SC-RX 0.122 0.061 -0.061 -0.122 SC-RY 0.101 0.049 -0.049 -0.101 SC-RZ 0.098 0.049 -0.049 -0.098 Main Steam Line D TRD1 SD-LX 0.105 0.052 -0.052 -0.105 SD-LY 0.046 0.036 -0.036 -0.046 l SD-LZ 0.136 0.068 -0.068 -0.136 l
TRD2 SD-RX 0.105 0.052 -0.052 -0.105 SD-RY 0.082 0.041 -0.041 -0.082 SD-RZ 0.117 0.058 -0.058 -0.117 These displacements are based on Turbine Stop Valve Closure at 100 percent flow. If test condition is at less than l
100 percent flow or without Turbine Stop Valve closure, the test results with the test flow parameters at which the data l were taken shall be sent to GE San Jose Engineering for
! evaluation, l
5-118
TABLE 5.2.32-3 NSSS TRANSIENT VIBRATION LIMITS AT MAIN STEAM SAFETY RELIEF VALVE BLOW ( RV1)
Pipeline Sensor Level 1 Rance ( i nc hes)
Description Identification l Level 2 Rance l l l ( i nches) l l V V V V Main Steam Line A TRA1 SA-LX 0.093 0.046 -0.046 -0.093 SA-LY 0.045 0.030 -0.030 -0.045 SA-LZ 0.111 0.055 -0.055 -0.111 TRA2 SA-RX 0.104 0.052 -0.052 -0.104 SA-RY 0.097 0.049 -0.049 -0.097 SA-RZ 0.084 0.042 -0.042 -0.084 Main Steam Line B TRB1 SB-LX 0.147 0.074 -0.074 -0.147 SB-LY 0.106 0.053 -0.053 -0.106 SB-LZ 0.051 0.030 -0.030 -0.051 TRB2 SB-RX 0.084 0.042 -0.042 -0.084 SB-RY 0.192 0.064 -0.064 -0.192 SB-RZ 0.061 0.031 -0.031 -0.061 Main Steam Line C TRC1 SC-LX 0.233 0.116 -0.116 -0.233
/ '\ SC-LY 0.073 0.036
-0.036 -0.073
\m- SC-LZ 0.051 0.030 -0.030 -0.051 TRC2 SC-RX 0.122 0.061 -0.061 -0.122 SC-RY 0.101 0.034 -0.034 -0.101 SC-RZ 0.098 0.049 -0.049 -0.098 Main Steam Line D TRD1 SD-LX 0.105 0.052 -0.052 -0.105 SD-LY 0.045 0.030 -0.030 -0.045 SD-LZ 0.136 0.068 -0.068 -0.136 TRD2 SD-RX 0.105 0.052 -0.052 -0.105 SD-RY 0.082 0.041 -0.041 -0.082 SD-RZ 0.117 0.058 -0.058 -0.117 l
- O 5-119 t.
O * %
)
l \
'N .j l 1 ,
1 TABLE 5.2.32-4 .
NSSS TRANSIENT VIBRATION LIMITS - , PUMP STAR 7UP AND PUMP TRIP Pipeline , Sensor Level 1 Rance ( i nches) .
Description Identification l Level 2 Rance l l l ( i nc hes) l l V V V V Recirc. Loop A T1 RA-SX -
0.134 0.030 -0.030 -0.134 RA-SY 0.047 0.030 -0.030 -0.047 RA-SZ n.083 0.030 -0.030 -0.083 T2 RA-PX 0.211 0.030 -0.030 -0.211 RA-PY 0.047 0.030 -0.030 -0.047
.. RA-PZ 0.117 0.030 -0.030 -0.117 T3 RA-DX 0.191 0.030 -0.030 -0.191 .'
RA-DY 0.034 0.0'30 - O'. 0 3 0 -0.034~ -
RA-DZ 0.213 0.050 -0.050 -0.213 ,
m T4 RA-HX 0.131 0.030 -0.030 -0.131 g RA-HY 0,034 0.030 -0.030 -0.034 ~
RA-HZ 0.063 0.045 -0.045 -0.063 0.058'
~
Rectre. Loop B T1 R.B-SX 0.157 -0.058 -0.157
- RB-SY 0.050 0.030 -0.030 -0.050 RB-SZ 0.133 0.036 -0.036 -0.13 T2 RB-PX 0.057 0.030 '
-0.030 -0.057' RB-PY 0.037 0.030 -0.030 -0.037 -
RB-PZ 0.043 0.030 -0.030 -0.043
~
T3 RB-DX 0.050 0.030 -0.030 -0.050, RB-DY 0.037. 0.030 -0.030 -0.037-RB-DZ 0.107 0.050 -0.050 -0.-107 T4 RB-HX 0.103 0.030 -0.030 -0.103 RB-HY 0.040 0.030 -0.030 -0.040-RB-HZ 0.070 0.046 -0.046 -0.070' s
O 5-120
5- , ,
- t. .
~
[ } ..
TABLE 5.2.32-5 BOP DYHAMIC RESPONSE LIMITS FOR MAIN STEAM PIPING,
, OUTSIDE THE DRYWELL, DURING MAIN STEAM
] STOP/ CONTROL VALVES CLOSURES AT RATED POWER
.,1 Design Maximum Instrument Acceptance Number Value (1bs)
DT-LZ-AB01_ t105100 Total For Pair D T.- L % i- A B 18 Dh-LX-AB02 161900 DT-LI-AP03 19900 DT-L"-AB04 161400 Total For Pair DT-LZ-AB16 DT-LX-AB05j 124200 Total For Pair DT-LX-AB17 DT-LZ-AB06 t48500 O* 1 DT-LZ-AB07 128600 DT-LY-AB08 t12000 Total For Pair DT-LX-AB19 DT-PO-AB01
- DT-PO-AB02 *
, DT-PO-A301
- i DT-PO-AB04
- DT-PO-AB05
- 195 psi maximum dynamic pressure expected; for j information only.
f s '
O l
5-121 i..___.__. -
TABLE 5.2.32-6 BOP DYNAMIC RESPONSE LIMITS A. Feedwater Piping Inside Drywell During Reactor Feed Pump Turbine Trip at Rated Flow Design Maximum Instrument Acceptance Number Value (lbs)
SS-AX-AE01 2.86 ** >
SS-AZ-AE02 2.86 **
SS-AX-AE03 2.86 **
SS-AZ-AE04 2.86 **
DT-PO-AE04 ***
DT-PO-AE05 ***
- DT-PO-AE06 ***
- Transient peak velocity limit ( Not RMS)
- 125 psi maximum dynamic pressure expected; for information B. Feedwater Piping Outside Drywell Reactor Feed Pump Turbine Trip at Rated Flow Design Maximum Instrument Acceptance Number Value (1bs)
SS-AX-AEOS 2.86 **
SS-AZ-AE06 2.86 **
SS-AX-AE07 2.86 **
SS-AZ-AE08 2c f,
- SS-AZ-BD01 2.86 **
SS-AY-DG01 2.86 **
DT-PO-AE01 ***
DT-PO-AE02 ***
DT-PO-AE03 ***
- Transient peak velocity limit ( Not RMS)
- ?oints located on 6th ctage heater FW inlet nozzle; t 25 pst maximum dynamic pressure expected; for information only.
5-122 i
l TABLE 5.2.32-7 BOP DYNAMIC RESPONSE LIMITS FOR SAFETY / RELIEF VALVE ACTUATION AT NORMAL OPERATING MAIN STEAM LINE TEMPERATURE AND PRESSURE, AND WITH NORMAL WATER LEVEL IN SUPPRESSION POOL.
Design Maximum Instrument Acceptance Number Value (1bs)
DT-LZ-AB09 18300 DT-LY-AB10 121300 Total For Pair DT-LY-AB11 DT-LS-AB12 19500 DT-LS-AB13 16000 DT-LS-AB14 117500 DT-LS-AB15 t17900 0 TABLE 5.2.32-8 BOP DYNAMIC RESPONSE LIMITS FOR HPCI TURBINE STEAM SUPPLY DURING HPCI TURBINE TRIP AT NORMAL STEAM SUPPLY FLOW.
DT-LZ-FD01 t1800 DT-LX-FD02 t1800 DT-LY-FD03 1900 DT-LZ-FD04 11100 DT-PO-FD01 *****
- PSI maximum pressure 155 dynamic expected; for l
information only O
5-123
TABLE 5.2.32-9 BOP OPERATING VIBRATION CRITERION C AND D Criterion C: N
[n(a/f)
= 1 n 5. 2 D c/g Criterion D: N
[nNi= n1 ( a / f) n 1. 2 D d/g Where a = steady state vibration peak acceleration, g' s f= frequency, N:.
V = combined peak velocity, in/sec.
g = 386.1 in/sec2.
Values of Vc and Vd were provi d e d in the applicable Test Specification.
l 0
l O
5-124
TABLE 5.2.32-10 O NSSS MAIN STEAM STEADY STATE VIBRATION DATA AT 100% STEAM FLOW PEAK-TO-PEAX PEAK-TO-PEAK SENSOR MEASURED
- SENSOR MEASURED
- NUMBER AMPLITUDE ( IN. ) NUMBER AMPLITUDE ( IN. )
SA-LX 002 SC-LX 007 SA-LY .002 SC-LY .002 SA-LZ .005 SC-LZ .002 SA-RX .000 SC-RX .000 SA-RY .002 SC-RY .002 SA-RZ .002 SC-RZ .002 SB-LX 002 SD-LX .002 SB-LY .000 SD-LY .005 SB-LZ .002 SD-LZ .002 SB-RX .002 SD-RX .002 SB-RY .000 SD-RY .002 SB-RZ 002 SD-RZ .002 Acceptance Criteria are given in Table 5.2.32-1 O
l O
5-125
TABLE 5.2.32-11 NSSS RECIRCULATION SYSTEM STEADY STATE VIBRATION DATA AT 100% l POWER PEAK-TO-PEAK PEAK-TO-PEAK SENSOR MEASURED
- SENSOR MEASURED
- NUMBER AMPLITUDE ( IN. ) NUMBER AMPLITUDE ( IN. )
RA-SX 005 RB-SX .007 RA-SY .002 RB-SY .007 RA-SZ .012 RB-SZ .007 RA-PX .007 RB-PX .007 RA-PY .007 RB-PY 010 RA-PZ 007 RB-PZ .007 RA-DX .010 RB-DX 010 RA-DY 007 RB-DY .002 RA-DZ .007 RB-DZ 002 RA-HX 005 RB-HX .002 RA-HY .012 RB-HY 002 RA-HZ .012 RB-HZ .000 a
Acceptance Criteria are gi ven in Table 5.2.32-1 0
5-126
TABLE 5.2.32-12 NSSS RECIRCULATION SYSTEM AND MAIN STE AM PIPING DYNAMIC RESPONSE DURING FULL POWER GENERATOR LOAD REJECTION TEST PEAK-TO-PEAR PEAK-TO-PEAK
. SENSOR NEASURED* SENSOR MEASURED
- NUMBER AMPLITUDE ( IN. ) NUMBER AMPLITUDE ( IN. )
RA-SX .015 SA-LX 010 RA-SY .005 SA-LY .015 RA-SZ .007 SA-LZ .007 RA-PX .010 SA-RX 005 RA-PY .007 SA-RY .005 RA-PZ .007 SA-RZ .002 RA-DX 012 SB-LX .034 RA-DY .010 SB-LY .015 RA-DZ .019 SB-LZ 029 RA-HX .007 SB-RX .012 RA-HY .005 SB-RY .007 RA-HZ .010 SB-RZ .002 RB-SX .005 SC-LX .022 RB-SY .007 SC-LY O _ RB-SZ 007 SC-LZ
.012
.015 RB-PX 007 SC-RX .007 RB-PY .007 SC-RY .007 RB-PZ .007 SC-RZ 010 RB-DX .015 SD-LX .012 RB-0Y .005 SD-LY .015 RB-DZ .017 SD-LZ .022 RB-HX .002 SD-RX .007 RB-HY .000 SD-RY 010 RB-HZ .005 SD-RZ .007
- Acceptance Criteria are given in Table 5.2.32-2 O
5-127
I 5.2.33 TEST NO. 32 REACTOR W ATER CLE ANUP SYSTEM ( RWCU)
A. OBJECTIVE Demonstrate the operability of the reactor water cleanup system ( RWCU) in the normal and blowdown modes.
- B. ACCEPTANCE CRITERIA Level i None Level 2
- 1. The temperature at the tube side outlet of the non-regenerative heat exchangers ( NRHX) shall not exceed 130oF ( 54oC) in the blowdown mode and shall not exceed 120oF in the normal mode.
- 2. The Reactor Auxiliaries Cooling System ( R ACS) cooling water supplied to the non-regenerative heat exchangers shall be less than 6% above the flow corresponding to the heat exchanger capacity ( as determined from the process diagram or the design specification) and the existing temperature differential across the heat exchangers. The outlet temperature shall not exceed 180oF.
- 3. Pump vibration shall be less than or equal to 2 mils peak-to-peak ( in any direction) as measured on the pump bearing housing, and 2 mils peak-to-peak motor vibration as measured on the motor housing.
C. DISCUSSION Normal Mode Performance Test The Reactor Water Cleanup Normal Mode Performance Test was performed during Test Condition Heatup at rated conditions with two RWCU pumps and two filter demineralizers in operation. With an RWCU NRHX cooling water ( R ACS) inlet temperature of 90oF and flow at 490 G P M, RWCU flow was increased to 350 gpm before operating li mi t s were reached.
The NRHX cooling water ( R ACS) outlet temperature was 147of
( li mi t 150oF) and the RWCU suction flow was 350 GPM ( li mi t 352 + 5 GP M)
Maximum RWCU pump vibration was 0.42 mils, and maximum motor vibration was 0.88 mils ( li mi t L2. 0 mils). No problems ocurred, and all parameters met the acceptance criteria, Normal mode performance data are given in Table 5.2.33-1.
O 5-128
O Q Table 5.2.33-1 RWCU NORMAL MODE PERFORMANCE DATA Parameter Measured Value Limit NRHX Outlet Temp. 109 oF L120 of NRHX Inlet Temp. 209 oF 233 oF RACS Flow ( NRHX) 490 GPM 468-678 GPM RACS Outlet Temp ( NRHX) 147 oF L150 oF*
RACS Inlet Temp. ( NRHX) 90 oF 85-105 oF RWCU Suction Flow 350 GPM 352 GPM RWCU Suction Temp. 533 oF L534 oF
^ Process diagram value. Level 2 criterion value is L180oF.
Blowdown Mode Performance Test The Reactor Water Cleanup Blowdown Mode Performance Test was performed in both TC-Heatup and TC-1. Initial efforts to perform the test in TC-Heatup were hampered by procedural problems involving 2 pump operation versus single pump operation. The initial test in TC-Heatup utilized two pump operation. When 74 GPM of blowdown flow was reached, the Level 2 criterion limit of 180oF RACS outlet temperature from NRHX was also reached. Subsequently the procedure was modified to use single pump operation with an RWCU system
\ flow rate 'of 124 ( tS) GPM and a maximum RACS flow to the NRHX, enabling the test to pass a blowdown flow rate of 92.2 GPM.
The limiting parameter for this test was the Level 2 criterion of 180oF for RACS outlet temperature. The test was stopped at 176.2oF, which occurred when system flow was wi t hi n 124t5 GPM given in the system design specification.
Maximum RWCU pump vibration was 0.47 mils, and maximum motor vi bra ti on was 1.08 mils ( limi t (2. 0 mils) . Blowdown mode performance data are given in Table 5.2.33-2.
Table 5.2.33-2 RWCU BLOWDOWN HODE PERFORMANCE DATA Parameter Measured Value Limit NRHX Outlet Temp 100 oF L104 oF NRHX Inlet Temp 509 oF 545 oF RACS Flow ( NRHX) 530 GPM 527 GPM RACS Outlet Temp ( NRHX) 176 oF L180 oF RACS Inlet Temp ( NRHX) 90 oF 95 oF RHX Inlet Temp 464 oF 545 oF O RWCU Suction Flow RWCU Blowdown Flow 122 GPM 92 GPM 124 GPM 93 GPM 5-129
5.2.34 Test No. 33 RESIDUAL HE AT REMOV AL SYSTEM ( RHR)
A. OBJECTIVES
- 1. Verify that the performance of the RHR Heat Exchangers meets the design intent while operating in the Suppression Pool Cooling Mode and in the Shutdown Cooling Mode.
- 2. Demonstrate that head spray flow can achieve the rated flow rate.
B. ACCEPTANCE CRITERIA Level 1 ,
None Level 2
- 1. The RHR System shall be capable of operating in the Suppression Pool Cooling and Shutdown Cooling Modes at the Heat Exchanger capacity determined by the flow rates and temperature differentials indicated on the process diagrams.
C. DISCUSSION The RHR sytem was tested in the Suppression Pool Cooling Mode and the Shutdown Cooling Mode.
[
Suppresston Pool Coolino Mode l
l The Residual Heat Removal System Suppression Pool Cooling Mode test was performed in TC-3 and TC-6 with the RHR System initially lined up in the standby mode per the system i
operating procedure. Avarage suppression pool temperature l was verified to be > 90oF, and the Safety Auxiliaries Cooling l system ( S ACS) heat exchanger outlet and bypass temperature controller was adjusted to achieve an RHR HX cooling water supply temperature that was 25( t5) oF below the average l suppression pool temperature, but not less than the minimum l operational SACS Heat Exchanger outlet temperature of 40oF.
One RHR heat exchanger loop was then placed in the suppression pool cooling mode while system flows and temperatures were recorded every 5 minutes over a 30 minute period. The RHR loop was then removed from the suppression pool cooling mode, and the other RHR loop was tested in the same manner.
5-130
3 The performance in TC-3 produced an anomaly in the data.
The calculated RHR heat exchanger "B" heat transfer rate, based upon RHR and SACS cooling water data, was inordinately large due to an excessive data update period on the Control Room information Display System ( CRIDS) computer. Re-performance of the test in TC-6 using more frequently updated CRIDS ( Control Room Information Display Sys t e m) data resulted in a reduction of the calculated capacities for both hedt exchangers. The results are given in Table 5.2.34-1.
Table 5.2.34-1 SUPPRESSION POOL COOLING MODE HEAT EXCHANGER CAPACITY. ( MBtu/ hr)
CRITERION IG _1. I.G - (_
"A" RHR HX (1 AE205) L26.0 31.4 28.0 "B" RHR HX ( 1BE205) L26.0 39.1 32.0 Shutdown Coolino Mode
)/ The Residual Heat Removal System Shutdown Cooling Mode test was performed in TC-6.
RHR HX "A" data was taken while in the shutdown cooling mode using normal plant operating procedures. The data were incorporated into the test
,y. procedure and evaluated per the procedure. An Occurrance
_ List ( OL) entry was written because the SACS inlet temperature of 70oF was below the process diagram temperature of 85oF. However, this was acceptable because the heat exchanger capacity, calculated using a 70oF SACS inlet water, was then adjusted to the process diagram temperature conditions in the procedure calculations.
RHR HX "B" data was taken when in the shutdown cooling mode while performing a controlled reactor cooldown from outside
- the control room at the Remote Shutdown Panel. A minor
! problem developed when SACS inlet temperature data was inadvertantly not recorded. However, the SACS inlet temperatures were calculated- using a heat balance calculation on the shell ( reactor water) side of the heat i exchanger (i.e., heat transfer from shell side = heat transfer to tube side).
O 5-131 a
.,,w,-.._,-.,--_.,.,_ _ - , . , , , - . , , . . - _ - - , - - - - - - - - , , . _ _ - . , - - - - - - - - . - - - - -
0 The heat exchanger capacities, adjusted to process diagram temperature conditions, exceeded the mininum test criteria.
The results are given in Table 5.2.34-2. The differences in the heat exchanger capacities were primarily due to the difficulty of obtaining accurate temperature data during the high cooldown rates which results when an RHR loop is placed in service at the process diagram flow rates with low decay heat (due to low fuel exposure) in the core. This difficulty has also been observed at several other BWRs during power ascension testing. However, the data clearly show that the capacity of both heat exchangers exceeds the required capacity. .
Table 5.2.34-2 SHUTDOWN COOLING MODE HEAT EXCHANGER CAPACITY. ( mbt u/ hr)
CRITERION TC-6 "A" RHR HX ( 1 AE205) L203.8 256 "B" RHR HX ( 1 BE205) L203.8 336 Head Soray Flow The ability of the RHR system to deliver rated spray flow ( 1000 GPM) was satisfactorily demonstrated while RPV head e in the Shutdown Cooling Mode. The head spray test was performed separately from the heat exchanger tests.
O 5-132
5.2.35 Test No. 34 DRYWELL AND STEAM TUNNEL COOLING i
b V A. OBJECTIVE
- 1. Verify the ability of the drywell cooling system to maintain design temperature conditions during normal operation, during post-reactor shutdown operation with the reactor building ventilation system ( RBVS) in the purge mode, following a reactor trip without a loss of offsite power, and f ollo wi ng a reactor scram in conjunction with a loss of offsite power.
- 2. Verify the abilit,y of the RBVS augmented by the steam tunnel cooling system to maintain design temperature conditions in the steam tunnel during normal operation.
- 3. Verify that the temperature of the drywell shieldwall concrete at selected penetrations is maintained at or below the maximum allowed values during normal operation.
B. ACCEPTANCE CRITERIA Level 1
- 1. The drywell average air temperature shall not exceed i
135oF.
i Level 2
- 1. During normal operation, no location in the drywell shall be >150oF. Temperatures in the vicinity of the recirculation pump motors shall be (13 5 o F.
- 2. During normal operation, the maximum point to point circumferential temperature differential in the annulus between the reactor vessel and bioshield shall be (10 o F.
- 3. During normal operation, the maximum point to point circumferential temperature differential at the refueling bellows bulkhead shall be (10 o F.
- 4. During normal operation, the maximum steam tunnel air temperature shall be L12 0 o F.
l 5. During normal shutdown operation, with the RBVS in purge mode, the maximum drywell air temperature shall l be (104 oF; and the minumum drywell air temperature shall be L4 0 o F.
- 6. For up to 30 minutes following a reactor trip without O the loss of offsite power, beneath the reactor vessel shall be (165oF.
the ma xi mum temperature
- 5-133
' l 1
- 7. For the first 85 seconds following a reactor scram with a loss of offsite power, the maximum ambient temperature in the drywell shall be L170oF except for L218oF in the area under the' reactor vessel. At 30 minutes the maximum ambient temperature in the drywell shall be L170oF except for L178oF in the area under the reactor vessel. After 30 minutes, the ambient temperature in the drywell shall stabilize at L154of except for under the reactor vessel where the temperature shall stabilize at (139oF.
- 8. The maximum allowable temperature of the drywell shield wall concrete at the main steam, feedwater, and main steam drain line penetrations shall be L200oF.
C. DISCUSSION The drywell and steam tunnel cooling system normal operation performance test was performed at 150 psig. 800 psig, and at rated pressure in TC-1, TC-2, TC-3, and TC-6. The test was performed by operating the drywell HVAC system per the system operating procedure with one fan in each cooler unit in fast speed. Equipment operating status and CRIDS (Control Room Information Display Sys t e m) temperature signals were recorded for further analysis. Each time this test was run, temperatures at the 162' and 175' elevations of the drywell failed level 2 criteria for normal operation.
During each outage insulation reworks improved on this and during the final outage a ventilation rebalancing ( taking cooler air from under the vessel and delivering to the hot spot) finally succeeded in reducing the peak temperature in the drywell from 300oF to 184oF with drywell average temperature reduced from 107oF t o 101 oF. A total of 5 points exceeded 150oF. This topic continues to be evaluated by Nuclear Systems Engineering and Nuclear Site Engineering for additional insulation and air redistribution work as well as a FSAR change to reflect maximum drywell temperature limit of 194oF.
Early in the program, it was identified that the RPV skirt temperatures were unacceptably low, but insulation rework resolved this problem.
All steam tunnel temperatures passed acceptance criteria following insulation rework and the repair of a minor steam leak. In TC-6, steam tunnel unit cooler inlet air temperature was 99.2oF, with a steam tunnel leak detection readout on Channel D of 115oF. Both of these readings are below the maximum allowance of L120oF.
O 5-134
f The drywell cooling system normal shutdown performance test
[ [' was performed in TC-2. The test was performed by operating
U- the. drywell HVAC system during normal post reactor shutdown operation per the system operating. procedure with the reactor building ventilation system ( RBVS) in the purge mode. Equipment operating status and CRIDS temperature signals were recorded for further analysis. The maximum 1
' drywell temperature at the conclusion of the test was 112oF, exceeding 104oF allowable. One other point was 107oF, and
[ all the other points were below allowable. After the
' insulation addition, ma xi mum air temperatures dropped substantially to 74oF.
- The drywell cooling system post trip performance test was performed in TC-1, TC-2, and TC-6. The test was performed
, by operating the drywell HVAC system per the system
- operating procedure, with one fan per cooler in fast speed.
l The CRIDS computer was started 20 minutes prior, to the reactor trip. All starting and stopping of fans was recorded while the test was being performed. The CRIDS l computer special log was stopped when drywell area temperatures stopped increasing. Level 2 acceptance i criteria were not met in this test due to the elevated j temperatures in the drywell prior to the start of the test.
This problem is being tracked by Nuclear Systems Engineering
( and Nuclear Site Engineering as mentioned above.
() The containment penetration performance test was performed in TC-1 TC-3, and TC-6.
cooling normal operation The g _
test was performed by operating the drywell HVAC system per i the system operating procedure, with one fan in fast speed L ,ag for each cooling unit. With drywell temperatures stable
' ( not more than a 4oF temperature rise in one hour),
printouts from the process computer, CRIDS, and GETARS were obtained and analyzed. The highest concrete temperature based on sleeve temperature at the shield wall penetrations was 116oF in TC-6. This meets the (200or allowable limit.
5-135
l 5.2.36 Test No. 35 GASEOUS RADWASTE SYSTEM A. Obj e c t i ve i Demonstrate that the Gaseous Radwaste System, utilizing either the Unit 1 or the Common Recombiner, operates within the Technical Specifications and design limi ts over the full range of plant power operation.
B. Acceptance Criteria Level 1 None Level 2
- 1. Maximum outlet flow for each Gaseous Radwaste System feed gas recombiner is less than 75 SCFM.
- 2. Ambient Charcoal Treatment System charcoal absorber temperature is operating in the range of 65t3oF.
- 3. Gaseous radwaste recombiner outlet hydrogen concentration is (0.1% at 100% power.
- 4. Dilution steam of the 3rd stage air ejection is not less than 9500 lb/hr.
o o
- 5. The system dew point is between 35 F and 45 F.
C. Discussion This test was performed on each of the recombiner trains listed listed below at the test conditions noted.
TC-1 TC-2 TC-3 TC-6 Unit 1 Recombiner Train x x Common pecombiner Train x x x x e
5-136
i Results of this test during plant operation at 1005 rated power are summarized in Table 5.2.36-1.
)
4 _.
Table 5.2.36-1 jl GASEOUS RADWASTE SYSTEM RESULTS AT RATED POWER Acceptance Actual at Description Criteria 1005 Power
~
- Gaseous Radwaste Recombiner
- 2. Ambient Charcoal Treatment 65 t3oF 74oF*
System Charcoal Absorber Temp
- 3. Recombiner Outlet Hydrogen <0.1% 4100% **
Concentration Power
- 4. Dilution Steam to 3rd Stage >9500 LB/HR 10,365.7 LB/HR l Air Ejector
- 5. System Dew Point L35oF to (45oF ***
! All beds except one were in specification.
! ** H2 anstrumentation determined to be incompatable
' with system application, leading to erroneously high indications. Actual concentrations were (0.011 as verified by grab samples.
- a In spec i n TC-3 ( 35oF) but instrument not functional in
- TC-6.
The results in Table 5.2.36-1 are re pre s e nt a t i ve of 100%
power data for both the unit and common recombiner trains.
Major problems encountered during testing are described below.
- 1. Air inleakage as high as 125 SCFM caused temporary degradation of the system. This condition was resolved by a combination of leak repairs and reverification of the valve lineup.
- 2. Hydrogen analyzers indicated abnormally high hydrogen concentrations. This was attributed to moisture in the sample and the fact that the analyzers were originally designed for a dry cryogenic offgas system, but were installed in an ambient charcoal system that inherently has some moisture. The chilled mirrors were replaced, but analyzer readings are still high compared to grab samples, i
i O 5-137
- 1 l
- 3. Hoisture carryover, caused by high inleakage flows, damaged the dewpoint instrument, flooded dp instrumentation, and caused high temperatures in the charcoal beds. The inleakage flows were brought to acceptable levels, and the instrumentation was made operable.
- 4. High third stage steam jet air ejector discharge pressures, indicative of a flow restriction caused by high inleakage and moisture buildup in the charcoal beds, were observed. This problem was resolved once the high inleakage problem was. resolved.
In summary, this system functioned as designed, and supported plant operations well when air inleakage was reduced below the design li mi t. However, at 100% power the H2 analyzers indicate approximately 0.5% hydrogen when actual hydrogen concentration is < 0. 01 % by grab sample.
This is not a problem in that grab samples continue to be taken, the instrumentation will react to a hydrogen spike, and Technical Specifications require no action below 1.0%
hydrogen, even though design requirements are < 0.1 % .
Resolution of this issue may require a different design for the H2 analyzers. Site Engineering is evaluating the problem and will determine the appropriate c orr e c t i ve ac tion ( s) to be taken.
The instances of high charcoal absorber bed temperatures are indicative of moisture in the beds. A hot nitrogen purge at the next convenient time should e li mi na t e this moisture.
l 9
5-138 i
5.2.37 Test No. 38 SAFETY AUXILI ARIES COOLING SYSTEM ( SACS)
(3 s/ A. OBJECTIVES 1 Verify SACS design provi de s sufficient performance margin to support Engineered Safety features operational requirements.
- 2. Verify SACS design provides sufficient capacity to support RHR shutdown cooling mode wi t h worst case heat transfer rate and a mature core.
B. ACCEPTANCE CRITERIA Level 1
- 1. The SACS shall have sufficient heat removal capacity (132.5 MBTU/ HR) so that the temperature of the reactor primary system can be reduced to 125oF ( reactor outlet temperature) 20 hours after control rods have been inserted when maximum SACS Water Temperature is 95oF, and the core is " mature".
Level 2
- 1. The SACS shall have heat removal capacities of at least l r- 389.29 ,MB TU/ HR for two loops in operation (4 heat
- (_,T/ exchangers) and 201.39 MBTU/ HR for one loop in
, operation ( 2 heat exchangers).
C. DISCUSSION l This test was performed for each SACS loop individually once f in TC-3, and again in TC-6.
SACS performance test was initiated by placing the Safety and Auxiliary Cooling System in normal operation per the system operating procedure, and then closing the loop A( B)
SACS heat exchanger bypass valve i HV245 A( B)] at remote control panel 1 C( D) C201. After allowing conditions to stabilize (less than 1oF change per 15 mi n. ) , CRIDS l readings ( or equivalent) were obtained and recorded for the SACS loop under test. The SACS heat exchanger bypass valve
! was then restored to normal operation and testing declared complete. Analysis of the data were performed to obtain heat transfer rate, log mean temperature difference ( LMTD) .
correction factor ( F) for 2 shell/4 tube heat exchangers.
coefficient of heat transfer, coefficient of heat transfer
( considering fouling, and, heat transfer rate using design l temperature and tube fouling.
O 5-139
In TC-3, the SACS heat exchanger loops A&B failed to meet the Level 2 acceptance criteria for heat removal capacity for two loops in operation ( 4 heat exchangers), and Loop A/B in operation ( 2 heat exchangers). Entrained nitrogen due to nitrogen overpressure from the accumulators in the system was later identified as having the potential to affect system performance. Procedural changes were implemented to ensure adequate venting of SACS to prevent e xcessi ve nitrogen accumulation in the system. Testing was reperformed in TC-6 on November 11, 1986 for Loop "A", and December 6, 1986 for Loop "B". The results were satisfactory, as shown in Table 5.2.37-1.
Permanent changes, including the possible elimination of the ni t r oge,n accumulators, are under engi neering e valuation.
Table 5.2.37-1 SACS HEAT REMOVAL CAPACITY ( MBTU/ HR)
Criterion TC-3 TC-6 Level i Level 2 Loop A(2 Hx' s ) L 132.5 L 201.39 166.94 206.84 Loop B ( 2 Hx' s ) L 132.5 L 201.39 161.51 224.73 Two Loops (4 Hx' s) N/A L 389.29 328.45 431.57 8
9 5-140
/ 5. 2.38 Test No. 40 CONFIRMATORY TEST OF SAFETY RELIEF VALVE s- DISCHARGE A. OBJECTIVES
- 1. Confirm the analytical assumptions and methodologies described in the Plant Unique Analysis Report ( PUAR) ,
and show that the SRV discharge related loads and responses presented in the PUAR are conservative at L25% reactor power.
- 2. Verify that all instrumentation and recording devices necessary for data collection are operational.
B. ACCEPTA5CE CRITERIA l
8 l ACCEPTANCE CRITERIA e
i i________________________________________________
! SENSOR l LEVEL 1 LEVEL 2
._______________________i________________________________________________
! Press. Trans!P1,P2..P3! Pressure -
35 psi l Pressure - 23 psi .
l Press. Trans:P9* l Pressure - 27 psi l Pressure -
18 psi l l l Stress l Strain l Stress l Strain l l l ( ksi) l ( micro in/in)! ( ksi) l ( micro in/ in) .
. . . . . i N i . .__________i_____________i_________i_____________
) l Strain Gauges l S13. SIS l 18 l 600 l 0 l 300 l
l l l ( membrane) l l l l l l l ;
l l l Strain Gauges l S16. S18 ! 45 l 1,500 l 30 l 1,000 l l l l ( membrane l l l l 1 l l l and l l l l l l l b e ndi ng) l l l l l l l l l l l l Strain Gauges! S61, S62 l 1150 ki psl 470 l 750 kips! 310
. . . i e i ,
, i_____________i_________i__________i______________________i_____________.
l
C. QISCUSSION An instrument shakedown test was performed in TC-2 on September 11, 1986, to verify acceptable signal response of all instrumentation and recording devices necessary to perform the confirmatory test. Analysis of test data indicated that test signal amplitudes were only 20% of i specified values. Additional investigation indicated that i the pressure sensors were not operating correctly and strain gauge signals were extremely noisy. Subsequently during the l plant outage between TC-2 and TC-3 the instrumentation in question was rewired and recalibrated resulting in i performance within specification limits.
l
.l 5-141
The confirmatory test was performed in TC-2 on September 11, 1986, and in TC-3 on November 2, 1986. This test was perf ormed by cycli ng SRV-F013H ope n f or 20 seconds, closed for 60 seconds, open for 10 seconds, and then closed. This sequence was performed 4 times with a hold time of at least 3 hours between sequences to allow the suppression pool temperatures to cool and stabilize. In TC-2 the test was aborted due to unacceptable data from the instrument shakedown test and again in TC-3 due to failure of the acous tic moni tor on SRV-F013H. However, for the TC-3 test, p r e li mi na ry, unfiltered, off-line data was collected for approximately 50% of the strain gauges, the accelerometers and pressure sensors. The results of these tests were summarized in a 10CFR50.59 safety evaluation, prepared by NUTECH Engineers Inc., to permit commercial operation of the HCGS.
PSE&G elected to replace the pressure sensors during an outage just prior to the warranty run and the test was repeated after TC-6 on December 20, 1986, with the following results:
TEST SIGNAL ANALYSIS l SIGNAL l l HAX ABSOLUTE l SIGNAL l NUMBER l l VALUE RECORDED l WITHIN ACCEPT AN '
l l l DURING TRANSIENT l CRITERIA
- i. i________________i___________________i__________________. .
l l ID l l DATA l UNITS l LEVEL 1 l LEVEL 2l l _ _ _ _ _ _ _ _ l _ _ _ _ _ _ _ _ l _ _ _ _ _ _ _ l _ _ _ _ _ _ _l _ _ _ _ _ _ _ _ _ _ _ l _1_Q R _ E _ _ l _1_ Q R _ U _ ;
l AND 681 l and P3 l l l l l l l l l l l l l l l 687 l P9a l l 13.0 l PSI l Y l Y l l l l l l l l l l 606 l S13 l l 45 l micro in/in! Y l Y l l l l l l l l l 608 l S15 l l 140 l micro in/in! Y l Y l l l l l l l l l l 639 l S16 l l 50 l micro in/in! Y l Y l l l l l l l l l 641 l S18 l l 135 l micro in/inl Y l Y l l l l l l l l !
l 660 l S61 l l 70 l micro in/inl Y l Y !
l l l l l l l l l 661 S62 l l 90 l micro in/inl Y l Y l
________i_______________.__________________i_________________.
- If not available, use maximum value of P1, P2 and P3, since these pressures are the maximum SRV pressure which can exist within the suppression pool.
O I
5-142 k
7- - - _
l In addition to the above, NUTECH provided a preliminary t report in which approximately 25% of the recorded sensor time histories were re vi e we d for each SRV actuation. The sensors consisted of:
- 1. Pressure sensors P1, P2 & P3 to measure the peak
_. quencher bubble pressure and P15 to measure the torus
! shell pressures and as a check on the data recorded
! during the November 2 and 3, 1986 test.
, 2. 20 strain gauges located at points of maximum strain observed during the November 2 and 3, 1986 tests; and
- 3. 4 accelerometers to measure clean shell response.
I The average of the maximum measured response from each sensor was compared to the acceptance criteria. The i
preliminary report notes that the measured negative bubble pressures and torus shell pressures are slightly greater than expected. Dut is still well within design limits. The slightly greater negative pressures do not appear to have special significance with respect to the structural response since there was good correlation between the measured
~
strains and predicted strains which confirms that the PUAR calibration factors have been conservatively applied in the i structural analysis. The report also notes that there was 4
h
\~/
good correlation between the measured frequency and the predicted frequency, quencher and that the peak bubble
~
measured clean shell radial and tangential accelerations are I. enveloped by the predicted values of 3.3g radial and 0.18g tangential. Tables 5.2.38-1 and 5.2.38-2 summarize the strain and acceleration results, respectively.
The results presented above indicate that the PUAR predictions are conservative. The final test report covering the analysis of all test data will be available at a later date and will be addressed under separate letter to j the NRC.
l l
l i
O 5-143
l Table 5.2.38-1 PRELIMINARY RESULTS FROM DECEMBER 20, 1986 TEST -
COMPARISON OF MEASURED VS PREDICTED STRAINS ( Micro in/in) l l SVA : CVA l i i i i (c...A.n.
. .g l l DIRECTION l TEST l ANALYSIS l TEST l TEST l AutYSIS ! TEST l i................'............i......'..........'..........,......,..........,...........,.
l Tons Shell l l l l l l l l
! 200 lLangitudinali 44 l 40 l 0.9te l 29l 39 l 1.34 l l (1 l Hoop l 120 l 1.01 l 79! :
L.,3,16) ,
,..) ,
, . !!9 !.
95 l 1.24 l Tans Shall l ? l l l l l. l l20eAbcve20 : Haan l 108 l 126 l 1.17 i 72l 140 1.94 l lReactstSide l l l l l l l l l(2!2439,42) l l ! l l l l l i................'................... ..........,..........,......,..........,...........,
i . .
lIcNsSheti l l l l l l l l l 30s Abeve 300 l Haap l 37 ' 133 t 1.53 62l 131 l 2.11 l lA.1 Dc feact ! l l l l l ! l
.,e, ,.4, ;J.,.6 J 1 i i i i
=....... . .........'.................c..........>...........>
' '1 tere! Col m i l l l ! l l l 457 to 52)
- Anal l 73 l
- 00 l 1.37 l 46l 76 l 1.65
, ,,4.3ar
. . . , , , , i . .
- ::as; l Ana! l 65 l 36 l 1.32 43! 77 : 1.79 l 2.- ,
.................'..............................s..........>......'..........*...........'
Overstress is 4 micro in/in or 120 pai. This is approximately 0. 6 % of membrano allowable and is insignificant.
CVA - Consecutive Valve Actuation SVA -
Single Valve Actuation O
5-144
- - - . . _ - . . -.._ - ~. . -_- _ _ _ . . . . . - - . . - - .__ . . . - -..
4 i-j i i l Table 5.2.38-2 1
.' PRELIMINARY RESULTS FROM DECEMBER 20, 1986 TEST-I MAXIMUM MEASURED ACCELERATIONS ( g) i i
i l l SVA : MEAN l CVA PEAN l
' i................ ..... i
! it! MT3 ' MI5l MT7 !SVA ACCEL.: MT2: MT4:MT6: MT5!CVAACCEL.: ;
.. ....... ......r..... .......... .......... ..... .. . ..... '
. ...... ... i
, l Rahal l l ! ! l l l ! ! ! !
l l A3 !!.05l0.9l0.9l0.7! 0.5 !0.8l0.7l0.45:0.7l 0.6 l i
- i
! 45 l1.7010.7:0.4:0.6l 0.6 l 0.4 : 0.4 0.6 :
- ..........>...........<....c.....'.......... .....,.....,.....,.....,..........*i n . > n
- lTa.iintial! l ; ! ! : i ! l
! A4 l0.05!0.05!0.05:0.05i 0.10 l0.02 l0.05 l0.02 l0.05 l 0.07:
l ,
46 l0.15!0.13l0.!5:0.!!l l0.10 l0.10 !0.1 10.1 : !
] ....................'....'.....'..........'...'.....'...'.....'..........'
i P
r 5-145 i
5.2.39 Test No. 41 MAIN TURBINE FIRST STAGE PRESSURE A. OBJECTIVES Determine the main turbine first stage pressures equivalent to 20% and 30% of rated thermal power and adjust the following setpoints:
- 1. Low power setpoint for RSCS.
- 2. Low power alarm setpoint for RSCS.
B. ACCEPTANCE CRITERIA None C. DISCUSSION This test was performed in TC-2 over a power range from 14.7% to 31.8% of rated. React se heat balance and turbine first stage pressure data were obtained at several power levels and from their relationship the Instrument Calibration Data (ICD) cards were r e vi s e d. RPS instruments were then recalibrated as necessary. In all cases the initial (as found) instrument calibrations were conservative.
The main turbine first stage pressures at 20% and 30% of rated reactor power were 82.6 psig and 1 5 ', . 7 psig, re s pe c t i vely, with incorporation of a 6 psi head correction.
A linear relationship between first stage pressure and percent reactor power was derived by the Least-Squarco-Ftt method and is as f ollows:
First Stage Pressure ( psig) = (7.707 x5 Power) - 65.54-Head Correction.
During performance of this test, the primary source for first stage pressure data was found t o gi ve excessively high
- values. As an alternative source, the Control Room Information Display System ( CRIDS) was selected. The accuracy of the CRIDS data was found to be acceptable based on a post-test calibration check.
l i
i 5-146 l
5.2.40 Test No. 42 VENTILATION SYSTEMS PERFORMANCE TESTS
\
j A. OBJECTIVE 1 Demonstrate that the HVAC Systems in the Reactor.
Turbine, and Auxiliary Buildings, as well as the
, Service, Radwaste, and Technical Support Center ( TSC) areas will maintain design ambient air temperatures j within the various rooms.
B. ACCEPTANCE CRITERIA Level 1 l None l
l Le ve l 2 i
Reactor Buildino Areas
- 1. For all areas not specified otherwise below, the l
temperature shall be maintained between 60oF and 104oF.
- 2. The Reactor Water Cleanup Rooms shall
(~')
-(,j _
between 60oF and 110oF.
be maintained
- 3. The Standby Liquid Control Rooms shall be maintained
, between 70of and 10 4 o F.
- 4. The ECCS equipment rooms shall be maintained between 60oF and 115oF.
- 5. The steam pipe chase areas shall be maintained between 60oF and 120oF.
Turbine Buildino Areas
- 1. Electrical equipment rooms and general areas shall be maintained between 55oF and 104oF.
- 2. Mechanical equipment rooms shall be maintained between 55oF and 120oF.
- 3. The battery charger room ( s) and some mechanical areas shall be maintained between dooF and 110oF.
- 4. The main steam pipe tunnel area shall be maintained between 55of and 130oF.
O 5-147
Auxiliary Buildi no ( Intlud i na TSC. PSP. and Radwaste Areas)
- 1. Radwaste general' areas,, compartments, and electrical equipment rooms shall' be maintained between 40oF and 104oF.
- 2. Radwaste filter rooms, tank compartments, e va pora t or and pipeways shall be maintained between 40oF and ,
115 o F.
- 3. Radnaste Control Room and maintenance offices shall be mair.tained between 68oF and 80oF.
- 4. Radwaste Charcoal Tank Rooms shall be maintained g between 63oF and 67oF.
- 5. Radwaste Battery' Charger Room shall be maintained between 4GoF and'85oF. /
- 6. Radwaste Battery Room shall b is maintained between 72oF and 82oF.
- 7. Machine Shops and Panel Areas shall be meintained between 40oF and 100oF.
- 8. Auxiliary Building service areas shall be ma i n b a'i ne d ' a s f ollo ws:
- a. Offices, shops, decontaet tiated areas and controlled corridors -
between 68c? and 80oF.
1
- b. Equipment rooms -
between 60oF anc 104oF.
- c. Showers.and toilet areas -
between 66of and 85oF.
- 9. Technical Support Center equipment rorm shall be maintained between 90oF and 104oF.
- 10. Technical Support Center office and panel areas shall be maintained between 66oF and 80oF with a rela t i : >e humidity of between 20% and 50's.
- 11. Remote Shutdown Panel room shall be maintained between 74oF and 78oF with relative humidity of between 40% and 60%. .
O 5-148
7_ _ . _ _ _ _ _ _ - . - _ - - - - -
_. p . - - _ - - ._ - _ _ _
y-hh' i /,, C. ? DISCUSSION O.!a- Reactor Buildina Ventilation l
'The reactor building ventilation test was performed in TC-3 '
{ at 505 power and in TC-6 at 1005 power. The ventilation system was in its normal lineup except for a limited number of rooms, and the ECCS pumps were operating in order to I provide a heat load. The tests successfully demonstrated that the ventilation system can maintain the reactor building areas at design ambient air temperatures.
,_ During performance of the test in TC-6. two areas were found
- to be at temperatures which were less than the mi numi m required temperature. The areas were the Refuel floor ( 59oF
- vs - ' 60oF) and the Core Spray Pump Room ( 54. 7oF vs 60oF) .
} Upoe re vi e w by Nuclear Site Engineering, the measured l temperatures were determined to be acceptable especially for l, the Core spray Pump Room where the unit cooler was placed in Run instead of the Auto / Auto Load which is the normal mode.
l In addition, the acceptance criterion minimum temperature (60oF) was determined to be too high by 20oF when compared to t'h e design specification and was reduced to 40oF, accordingly, i
The FSAR equipment qualificat - an ( EQ) requirements in two l areas were also not met. The areas were the RHR heat j , exchanger room ( 79.1 oF vs 79. 0oF max) and the pi pe chase b . 4321 (92oF vs 91 oF max) . Nuclear Site Engineering reviewed j these results and determined that the maximum temperature
- for the RHR heat exchanger room could be changed to 81 o F.
, Also, Engineering twice re-measured the pipe chase and found f '
the temperature at 86.8oF and 86.1oF, respectively. These temperatures are less than the maximum value ( 91 oF)
. the^efore r no further action is required.
Turbine Buildino Ventilation The turbine building ventilation test was performed in TC-6
- - m at 1005 power with the ventilation system lined up in its j ' normal configuration. The test demonstrated the acceptable
} capability of the ventilation system except f or five areas l where there were Level 2 acceptance criterion failures. The j steam jet air ejector room, the sixth stage feedwater heater rooms, and the steam seal evaporator room all had measured i ambient temperatures which exceeded their respective i
criteria values as summarized below:
4 i Room Criteria Measured l SJ4E Room 110oF 120.6oF 6A FW Heater Room 120of 149oF i 6B FW Heater Room 120oF 162oF ,
! 6C FW Heater Room 120er 160oF l\ Steam Sec.1 Evaporator Room 120of 140oF i
l i,
5-149
_.R_._._..__ _ _ _ _ _ - - _ _ . - . _ _ _ -
These areas were identified to System Engineering for evaluation and correction. Additional lagging, insulation and possible unit coolers are alternatives for reducing the ambient temperatures in these areas.
Radwaste. Auxiliary Buildino. and Technical SuoDort Center Ventilation This test was started in TC-3 but could not be completed until TC-6 due to lack of system completion ( Auxiliary Building Service Area remodeling) In the Auxiliary Building Radwaste area, several rooms had temperatures which were too low ( by 2oF) . The temperatures were corrected by adjusting thermostats and instructing personnel on the correeb- -operation of the e q ui pme n t . All other areas and rooms evaluated via this test passed the acceptance criteria, therefore the ventilation systems in these areas are capable of maintaining design ambient air temperatures ac well as those in'the Auxiliary Building.
Several problems incurred during the test were corrected prior to proceeding with the test, including correction of a fan lineup, completion of air balancing following completion of a design change, and correction of a controller which had been set up as direct acting rather than reverse acting. Other problems involved discrepancies between the ' vendor design document ( DITS) , the FSAR, and EQ requirements regarding the correct room temperature. These problems have been transmitted to Nuclear System Engineering for evaluation. Recommendations for a revision to FS AR Table 3.11 -1 C, Enveloping Plant E nvi r onme nt al Conditions -
Auxiliary Building, and design changes to correct the discrepancies were also transmitted.
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(O,) 5.2.41 Test No. 43 LPCI AND CORE SPRAY LINE BREAK A. OBJECTIVE Obtain baseline data to verify the RHR LPCI and core spray line break differential pressure setpoints.
B. ACCEPTANCE CRITERIA None C. DISCUSSION Low PrWssure Coolant Injection ( LPCI) and Core Spray ( CS) line b re ak detection system baseline operating data were obtained in TC-Heatup, 1, 2, 3, and TC-6 to verify that the trip setpoints for the respective "line break" alarms are correct.
The Core Spray system has two flow paths to the vessel.
Each of the four RHR loops support an independent LPCI loop flow path to the vessel. There is a dp cell across the two Core Spray flow paths, and a dp cell across the A&C and B&D LPCI lines. These dp cells tap off the injection lines downstream of the air operated check valves, sensing the pressure in the upper shroud, sbove the core. The pressure O+ in the downcomer region is higher than that within the
~ shroud. Should an injection line break occur in the downcomer region, it would pressurize the broken CS or LPCI loop, and cause a high dp indication. During normal operation, the dp units ideally indicate zero. However, this is not always the case because of turbulence, gravity effects, height differentials, etc.. There can also be momentary dp's that exceed the setpoints of the trip units.
All differential pressure data were either zero or nearly zero, as expected, and well within the calibration tolerance of the dp instrument loop. The data were also within the Technical Specification limit values as presented below:
Test Condition Limit liu, 1 1 1 1 Core Spray, paid 4. 4 0.12 0.125 0. 2 0.245 0. 2 LPCI A, paid 1. 0 0.025 0 0.1 0.15 0.115 LPCI B, psid 1. 0 0.16 0.14 0.15 0.19 0.195 These data wero given to Systems Engineering to verify that the instrement trip setpoint values are adequate.
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l 5.2.42 Test No. 44-1 MAIN TURBINE AND GENERATOR IKITIAL STARTUP A. OBJECTIVES
- 1. Provide additional instructions for operator control of the main turbine generator and exciter initial roll, excitation and synchronization.
- 2. Provide a checkout of operations department system operating procedure for main turbine.
- 3. Provide initial equipment baseline data.
B. ACCEPTANCE CRITERIA None C. DISCUSSION Main turbine initial startup was performed in TC-Heatup, with the exception of stop and control valve tightness tests which were performed in TC-1 During the initial roll to rated speed (1800 r pm) , a turbine trip due to high vibration was experienced. After rebalancing, the turbine was successfully rolled to rated
. speed. Logic problems with the turbine gear oil pump ( TGOP) were corrected to allow the TGOP to operate in AUTO without defaulting to RUN.
Main generator excitation was pe r f o rrac e in TC-Heatup f ollowi ng the main turbine initial startup test, with the l unit at rated speed (1800 r pm) and the generator breaker and l
generator field breaker open. Adjustments and checks were performed on the exciter, regulator, and field current limit followed by synchronization of the generator to the grid.
Finally, adjustments were made to the reactive current compensation and under reactive ampere li mi t ( U. R. A. L. ) .
l Approximately one minute after the exciter field breaker was closed, the control room exciter ground annunciator illuminated. The ground was isolated to the field exciter relay and repaired. Subsequcnt to the test a ground was found in the generator wi ndi ngs. The ground only appears when the turbine is stopped and disappears as soon as the l turbine is running. It is planned to be repaired during an upcoming outage.
O S-152
During operation with full load on the turbine generator, l'_c\ the vibration levels at some bearings were near the upper and of the acceptable range. Vibration data were taken, and balance shot were added to the end plane of one of the low pressure stages ( " B") during a recent plant shutdown following completion of the test program. An evaluation of the effect of the added balancing weight will be made when the plant returns to full load.
A discrepancy exists between the vibration levels indicated in the control room and those indicated by special test instrumentation located at the turbine-generator. The differences are expected to be resolved when new vibration cards are installed in the Turbine Supervisory Instrumentation ( TSI) circuitry.
During performance of the power ascension procedures, the plant operating procedures for the turbine generator were verified and revised as appropriate.
= ,
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5.2.43 Test No. 44-2 STEAM SEAL EVAPORATOR INITIAL TESTING A. OBJECTIVE 1 Verify the proper operation of the steam seals and the steam seal evaporator systems on both auxiliary and nuclear steam.
- 2. Provide initial baseline equipment data.
B. ACCEPTANCE CRITERIA Level 1 None Level 2 The steam seal evaporator is capable of providing steam to the steam seal system while the main condenser air removal system maintains a vacuum on the main condenser.
C. DISCUSSION The testing was performed in three distinc phases relating to the test condition required. The status of the labyrinth seals was determined in Test Condition Open Vessel. The test consisted of reducing Steam Seal supply pressure until a change in Main Condenser Vacuum was detected, then reducing steam packing exhauster suction pressure until steam was detected. Testing was conducted using steam from the auxiliary boiler.
In Test Condition Heat-up, the steam seal evaporator ( SSE) was heated up for the first time and placed into service.
Proper operation of the controls associated with nuclear steam admission to the SSE were also verified.
The final phase of this test was performed at a power level greater than or equal to 50% main generator output. Proper operation of the extractor steam bleeder trip valves ( BTV) ,
which function to provide nuclear steam to the SSE, was also verified.
During the testing at 70% power, it was noted that the pressure differential switch associated with the admission of extraction steam to the steam seal evaporator was cycling occasionally. The differential pressure for the switch is developed by the BTV' s and associated piping. The flow, and resulting differential pressure, was unable to maintain the 5 PSID needed to maintain the B TV' s open. Adjustment of the
{
setpoint was required to correct this problem. i i
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O The test- results satisfied the acceptance verified the proper operation of the steam seal on both auxiliary and nuclear steam.
criteria and evaporator O
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m 5.2.44 Test No. 45 SEISMIC MONITORING SYSTEM A. OBJECTIVE Obtain Seismic Monitoring System baseline operating data.
S. ACCEPTANCE CRITERIA Level 1 None Level 2 None C. DISCUSSION This test was performed in Test Conditions Open Vessel, Heatup, and Test Conditions 1 through 6.
Seismic Monitoring System baseline operating data were obtained using the time history triaxial accelerograph magnetic tape recorders, the triaxial response spectrum annunciator panel, and response spectrum recorder etched plates.
Steady state operating data were recorded during cold shutdown, at rated reactor pressure, and during power operation at TC-2, 3, 4, and 6. Transient operating data were recorded during safety relief valve testing, HPCI injection to the reactor pressure vessel, single and two recirculation pump trip tests, shutdown from outside the control room test, loss-of-offsite power test, MSIV full isolation test, and generator load rejection test. Data were also recorded during Residual Heat Removal, Core Spray, and Service Water system pump starts and stops.
During the testing, problems were encountered in the
, operation of the playback recorder due to circuit board card l Callures, relay switch failures, and power supply l malfunctions. These problems were corrected, and acceptable
! baseline data were collected for all of the specified plant l operating conditions.
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5.2.45 Test No. 46 LOOSE PARTS MONITORING
(}
A. OBJECTIVE Obtain baseline data signatures on all primary and backup channels of the Loose Parts Monitoring System during steady state and transient plant conditions.
B. ACCEPTANCE CRITERIA Level 1 None Level 2 None C. DISCUSSION The Loose Parts Monitoring Test was performed to functionally checkout this e q ui pme n t during the power ascension program, and to gather baseline data at a number of different steady state and transient conditions. The data were used by System Engineering to determine alarm O_ setpoints.
steady state conditions:
Baseline data were recorded at the following
- 1. Cold Shutdown with the reactor vessel head installed
( TC Open Vessel)
.=
- 2. Both reactor recirculation pumps at minimum speed prior to criticality ( TC He a t u p) .
- 3. Twenty-five percent reactor power, minimum recirculation pump speed ( TC-2) .
- 4. Fifty percent rated core flow ( TC-2) .
- 5. Fifty percent rated reac tor power ( TC-3) .
- 6. Seventy-five percent rated core flow ( TC-3) .
- 7. Seventy-five percent rated reactor power ( TC-6) .
- 8. Rated reactor power and core flow ( TC-6) .
Baseline data were also recorded during the following transients:
D 2. Turbine Stop Valve Trip Test.
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5
- 4. Rectre System Two Punp Trip.
- 5. MSIV Full Isolation Test.
- 6. Full Power Generator Lt,ad Rejection Test.
l During the testing, some primary and secondary sensor cables were found to be interchanged, and problems were found in the X-Y plotter alignment. These problems were corrected.
A primary sensor was found to be inoperable. The sensor will be replaced at the first convenient outage. Acceptable baseline data were collected at al'l of the specified plant operating conditions.
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5.2.46 Test No. 47 SRV ACOUSTIC MONITOR BASELINE DATA A. OBJECTIVE Obtain full open Safety Relief Valve ( SRV) baseline data for the SRV Position Monitoring ( Acoustic) system.
B. ACCEPTANCE CRITERIA Level 1 7
Hone Level 2 C. DISCUSSION Safety Relief Valve Acoustic Monitor baseline data were obtained in Test Conditions 1, 2, 3 and 6. The baseline data were obtained during manual 10 second openings of each SRY, and during planned scrams during which SRV openings occurred.
The tests performed in Test Conditions 1 and 2 identified several problems wi t h the response of the sensors
( accelerome ters) . Three sensors ( L, P and R) did not O respond output values.
test properly.
in TC-2, Several sensors responded at very Also, during the Loss-of-Offsite Power ( LOP) non 1 -E power to the Acoustic Monitor low Panel
( 10C6 0 5) was lost. The panel was re wi red to an -alternate supply to provide continuous power during a LOP event.
At the completion of TC-2 the sensors on L, P and R were replaced and all sensors were relocated ( to within one to two feet of the SRVs) and recalibrated. During TC-3 the baseline data for each sensor was obtained and found to be satisfactory. The data indicated a small level of response by some sensors to other SRVs being opened, i.e., crosstalk.
Table 5.2.46-1 summarizes these results.
Baseline data were also obtained during TC-3 and TC-6 planned scrams during which SRVs opened. Results from these l tests identified that the response of SRV H monitor decays from a peak value of 604 mv to 53 mv when the, valve is open for more than 10 seconds. In addition, it was found that the peak response during subsequent opening of SRV H (low low set f unc ti on) decreased to 208 mv and then decayed to 53 m v. During the manual SRV opening tests the SRV H signal decay with reactor depressurization had been observed but the minimum value could not be quantified due to the relati vely short (10 second) opening time.
A review of all acoustic monitor traces for signal decay trends determined that the sensor on SRV H exhibited the largest signal decay. Since the acoustic monitor sensor 5-159
c.
is an accelerometer, it responds to SRV discharge pipe vibration, which is affected by several variables, including the dynamic forcing f unction ( pressure / flow), pipe system stiffness and damping ( including pi pe support effects), and sensor orientation relative to the major axes of pipe response. The combined effects of these variables is reflected in the peak response and decay characteristics of the acoustic monitor signals during an SRV opening transient. System Engineering concluded that the data obtained in TC-3 and TC-6 provioed sufficient baseline information to determine setpoint values for the SRV Position Monitoring system. Therefore, the test objectives were satisfied.
While n_ot in the scope of this test, the following discussion describes how the baseline data were used to de ri ve acceptable setpoint values for the SRV Position Monitoring system. The steady state signals measured during single SRV manual openings were reduced, as necessary, to account for observed signal decay trends for each sensor
( mos t sensors exhibited little or no signal de c 3y) . These values were multiplied by 30% to establish the upper boundary that satisfied the requirements o!? Technical Specification 4.4.2.1. The desired setpoint was datermined based on the maximum crosstalk level plus on additional margin to avoid false opening signals, due to crosstalk, without exceeding the upper boundary. The actual setpoints arrived at are given in the plant Instrument Calibration Data ( ICD) cards for each monitor channel.
Table 5.2.46-1 1
~
ACOUSTIC MONITOR RESPONSE TO MANUAL SRV OPENING SRV NO. Initial SRV Open Max.
( A B-PS V-F013_) Noise Level Response a Crosstalka*
( mv) ( mv) ( mv)
A 2 756(579) 21( SRV R)
B 2 632(491) 49( SRV F)
C 3 123(88) 18( SRV G)
D 2 605(509) 14( SRV H)
E 4 342(263) 0 F 2 404(281) 0 l G 6 895(825) 18( SRV C)
H 4 508(193) 0 l J 0 210(158) 0 K 2 550(368) 28'SRV B)
L 0 184(167) 0 M 2 325(272) 18( SRV H) l P 1 386(333) 0 R 2 161(140) 0 l
- Peak value ( f ull open " steady state" value)
- Maximum crosstalk value (SRV causing crosstalk response) 5-160 I
- 6. 0 ACCELERATED TEST PROGRAM Early in 1985, PSE&G initiated a program to accelerate the Power Ascension Test Program of the Hope Creek Generating Station. The goal was to complete the test program in 185 days, from start of fuel load to completion of the warranty test, and to maintain a high level of quality in the program. In order to accomplish this goal, several actions were taken to improve the operation and testing of the plant. These actions were drawn from the experience of other BWR startups in the U. S. performed after the TMI accident. The major elements of the accelerated program, listed below, are discussed in the remainder of this s e c t i o n.,,
- 1. Esta'blish a dedicated test organization, the Power Ascension Department, with the responsibility and authority to conduct the accelerated test program.
- 2. Establish a management team, the Shift Support Organization, and process for ensuring timely decisions and responsiveness.
- 3. Implement a test reduction program which eliminated, replaced, or simplified the required testing based on past experience.
- 4. Implement a walkdown program utilizing senior design l and operations oriented personnel from the vendors and
! the utility to identify potential system related problems in key plant systems which could be corrected prior to startup.
S. Investigate the root cause of scrams during past startups, and implement recommendations for scram reduction.
- 6. Identify key spare parts which have commonly been needed during power ascension test programs, determine their availability on site, and procure if necessary.
- 7. Identify areas where the plant Technical Specifications require overly restrictive operation l and obtain relief from the NRC.
- 8. Develop and implement a control system tuneup program which would reduce critical path test time.
O 6-1 t
e 6.1 Power Ascension Department The Power Ascension Department was established as a separate department within the Hope Creek Operations Organization with responsibility for performing all power ascension testing and related ac t i vi t i e s. The department developed the test schedules and facilitated their performance including r e s olvi ng problems as appropriate. The other HCGS departments operated and maintained the plant. The Power Ascension Department interfaced wi t h the other HCGS departments at several levels including the Shift Support Organization. The Power Ascension Department was composed of five groups as shown in Figure 6.1 - 1.
The Test Group included on-shift test coordinators and engineers who performed the tests and controlled the power ascension test schedule. The Test Group interfaced wi t h the plant operators and other personnel as required.
The Technical Group performed several functions which included conducting independent reviews of test results, staffing the Technical Re vi e w Board, interfacing with the Station Operations Re vi e w Committee ( SORC) , conducting test plateau reviews, staffing the tuneup group, and maintaining the GETARS system.
The Scheduling Group with direction from the Test Group, developed all test schedules. This group was staffed on-shift and also provided an interface with the station work planning organization.
l The NSSS and BOP vendor groups were staffed by General
( Electric Company and Bechtel Power Corporation personnel respectively. They monitored equipment performance, provided vendor review and approval of test results, and resolved problems.
- 6. 2 Shift Succort Oroan12ation l The Shift Support Organization was established, for the duration of the Power Ascension Test Program, to facilitate ac ti vi t i e s in support of plant operation and testing. The goal was to continue testing, when l possible, and resolve problems as parallel ac ti vi t i e s.
The Shift Support Organization was composed of existing plant organizations and personnel and Site Engineering, as shown in Figure 6.2-1, but structured to provide 74 hour8.564815e-4 days <br />0.0206 hours <br />1.223545e-4 weeks <br />2.8157e-5 months <br /> / day, on-shift coverage. The Duty Shift Manager, assigned from senior management personnel, headed the 6-2
- o support organization. A Work Control Group was also
. . . established to relieve the operations shift supervisors l of non-operations issues, ensure timely response to equipment problems and ensure non-critical work did not overburden operations and maintenance personnel.
- 6. 3 Test Reduction Procram The test reduction program identified twenty-six power l ascension tests which could be modified in' order to l reduce the duration of the. Power Ascension Test Program. These modifications deleted non-essential testing, replaced test procedures with existing plant surveillance procedures, and simplifed the planned tests. Each proposed modification underwent a safety evaluation and, if approved by the SORC, was submitted to the NRC. Of the 26 proposals submitted to the NRC, 16 were totally accepted, 4 were partially accepted and 6 were not accepted. The applicable changes were incorporated in Amendment 15 to the FSAR. The total test schedule savings credited to the test reduction program was 26 days.
- 6. 4 Walkdown Procram The walkdown program identified 23 critical systems for which 257 recommendations were identified, including immediate hardware / design fixes,- procedural changes and "O plant betterment hardware / design projects. All immediate recommendations that were approved by the utility were implemented, as were procedural recommendations. The vendors ( GE and Bechtel) supplied a list of areas for review based on past experience which was followed by a plant walkdown in these areas by senior design and operations personnel from the vendors and the utility. The results of this effort are best measured by outage time attributable to system / component malfunctions. Total outage time at Hope Creek was 103 days of which 40 days were spent pe r f ormi ng planned pre-startup surveillance testing.
The major s a vi ngs which can be directly associated with this program is the lack of critical path time lost due to the nuclear instrumentation, the main condenser, RWCU system, recirculation, offgas, the main turbine and HPCI/RCIC as compared to the approximately 30 days experienced at most sites. Examples of some specific recommendations whose implementation saved time included:
- 1. Pre-inspection of the main condenser by the supplying vendor ( Southwestern) revealed a need for additional full penetration welds in the areas of the baffles and expansion joints prior to steam O being admitted to the condenser ( also a thorough cleaning and upgrading of sacrifical anodes).
6-3
- 2. Design changes to nuclear instrumentation to eliminate noise spikes and improve reliability of power supplies.
- 3. Reworking of moisture separator turbine trip sensing lines to separate and raise the sensing points on the drain tanks to avoid spurious trips.
- 4. Addition or modification of time delay logic on secondary plant systems ( of f gas, condensate, and feedwater) to prevent spurious trips.
- 6. 5 Scram Reduction procram The scram reduction program began with a review of previous startup histories to identify areas with high scram potential. In turn, site specific recommendations were made regarding how to avoid these high potential scrams. These recommendations were integrated with the walkdown program for design changes and procedure modifications. Recommendations were also developed by analyses of the most likely scram senarios based on plant conditions in each test condition.
Examples of some of these recommendations are:
1 In the design area, items 3 and 4 of Section 6. 3 were very effective in preventing scrams from turbine trips and spurious secondary plant trips.
In addition, recirculation flow control runback reset pushbuttons were added to prevent recirculation system flow /high neutron flux scrams when resetting a locked scoop tube. This feature l is standard on most plants, but due to the Bailey control room design they were not initially i installed at Hope Creek.
- 2. In the area of procedures involving high scram risk operations, recommendations were made on IRM range switching, prevention of noise spikes on nuclear instrumentation during fuel load and initial criticality, feedwater flow /high flux scrams at low power level, attention to detail on reset of half scrams and isolations during surveillance testing, high delta P across the condensate system leading to loss of feedwater flow.
HCGS had a total of 16 scrams, of which 11 were unplanned. Of these unplanned scrams, one was forced i by Technical Specifications and one was caused by l equipment f ailure; thus, there were essentially 9 unplanned scrams which were caused by operations, I&C, l or testing personnel. These unplanned scrams were associated with reactor feedpump controls, IRM ranging, 6-4
~
/' and I&C surveillance testing. By TC-3,
(_)) more unplanned scrams other than those resulting from there were no testing or test preparation. This was due to prompt action by station management in implementing high-risk scram recommendations, and to the operating and I&C personnel.
- 6. 6 Soare Parts Procram The need for a special spare parts management program was determined in September, 1985 as a result of the large number of spare parts which were identified as necessary to prevent delays in the Power Ascension Test Program. In order to prevent material shortages from impacting critical path time, an assessment was performed of NSSS, BOP, radwaste, and turbine spare parts. This program identified each required spare part by specific part number, determined if it existed on site in sufficient quantity, obtained approval to order, ordered, and then tracked the part until it was on-site. The program status was reported to the Maintainance Manager on a weekly basis and was given high priority and assistance from General Electric spare parts personel on-site and in San Jose. This program identified over 2200 line items in the NSSS j .gg area, of which over 550 were ordered and delivered by ll' May, critically 1986, before they were needed.
needed spare parts provided by this program were the refueling bridge power cable, multiple SRM/IRM Some examples of connectors, preamps and detectors, and a RWCU pump seal.
- 6. 7 Technical Specifications Review Procram The Technical Specification review program performed a limited review of certain Technical Specifications which could affect the critical path startup testing schedule. Although the benefit of this activity was limited during the actual power ascension program, it is probable that these items will benefit future plant operation and refueling outages. Two examples are:
1 Relax SRM monitoring requirements during fuel loading This was implemented as part of the test reduction program.
- 2. Allow single loop recirculation system operation.
I
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l 6-5
- 6. 8 Control Systems Tuneue Procram The accelerated control systems tuneup program consisted primarily of:
1 Analytically determining controller settings for HPCI, RCIC, feedwater turbine control, recirculation flow control and the main turbine.
Use of these pre-determined setpoints mi ni mi z e d the effort to determine the optimum setpoints for system response.
- 2. Performing tuneups early in the power ascension program when possible. For example, initial recirculation pump speed controller tuning was performed during high speed runs of the recirculation pumps during TC-Open Vessel, in conjunction with the operational hydro.
- 3. Mai nt ai ni ng a larger ( 4) and more diverse staff for tuneup / troubleshooting, and assigning a lead tuneup engineer.
- 4. Maintaining the tuneup procedures independent of the power ascension test procedures, thus allowing more tuning flexibility.
The accelerated tuneup program, combined with the system walkdown program, allowed schedules to be generated for performing tuneups of several systems
( HPCI/ RCIC/ Recire) prior to the power ascension test schedule windows. The tuneup program thus identified and resolved most control system problems prior to performance of the power ascension test. This helped assure that the control systems were properly tuned, and reduced the perturbations to plant operations.
Tuneup testing of the HPCI/RCIC systems, the recirculation flow control system, and feedwater turbine control system, saved an estimated 15 to 30 l days in the startup test schedule.
l
- 6. 9 Acc,elerated Test Procram Results The accelerated Power Ascension Test Program resulted l in a high quality and expeditious startup. Although Table 6.9-1 illustrates some significant statistics regarding this program, the ultimate proof is in the quality of plant performance. The Hope Creek Generating Station continued to operate essentially trouble-free for over 61 days following the final I
l planned scram of the startup test program.
The specific value of this program is presented in this report, i.e., a timely, quality test program wi th f ew unresolved items. The generic value of this program is 6-6
in the lessons learned and their possible application to f uture acti vities. The key generic factors include:
- 1. Knowledge that quality and timeliness are compatible
- 2. Establish a planned program early
- 3. Obtain management commitment of the participating organizations.
- 4. Set achievable goals
- 5. Develop an integrated team
- 6. Provide incentives to reach the goals Table 6.9-1 ACCELERATED TEST PROGRAM RESULTS The accelerated Power Ascension Test Program succeeded in provi di ng an expeditious power ascension test program with a high level of quality, as shown by the following statistics.
Cateoorv Results Overall Test Program Duration 245 days Outage Ti r. a 103 days
- Scrams ( unplanned) 11**
( planned) 5 Unresolved test items at
- end of program 12
- 40 of the 103 days involved planned surveillance testing performed prior to initial criticality.
- One was a manual scram initiated by the plant operators because of a Technical Specification time limit.
l l
O 6-7
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l Power Ascension l.
l Manager !
e i i_________________i e
i i
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i e i i
.i .B i i i i
. __________i_________ i l l Technical Group l l
. . ________________ i i l l Power Ascension l l l l Technical Director l l i e i i____________________. i.
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______i__________ ______ i______
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l l NSSS Group l l Scheduling Group l l BOP Group l l Test Group l
. . i i i e i i
. ________ i i _____________ i i _______ i i ________ i
! l NSSS l l Lead Test l l BOP 1 l Test l l Operations l l Scheduler / Planner l l Manager l l Supervisor l l l Manager !
l___________________l l___________l l____________l I
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Figure 6.1 - 1, Power Ascension Department O
6-8
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! Control l l Departments ! ! Group l l Operations l l Engineering l t
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. Group , , _ _ _ _ _ _ _ _ _ _ _ _ _ , . _ _ _ _ _ _ _ _ _ _ _ _ ,I ,
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6 6-9
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