ML17277B727
| ML17277B727 | |
| Person / Time | |
|---|---|
| Site: | Columbia  |
| Issue date: | 04/17/1985 |
| From: | Powers C WASHINGTON PUBLIC POWER SUPPLY SYSTEM |
| To: | Martin J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V) |
| References | |
| NUDOCS 8505030723 | |
| Download: ML17277B727 (179) | |
Text
<<<<<<<<l<<<<
Washington Public Power Supply System P.O. Box 968 3000 George Washington Way Richland, Washington 99352
~ I509I,372-5000 Docket No.
50-397 April 17, 1985 Mr. John B. Martin, Administrator Region V Office of Inspection and Enforcement US Nuclear Regulatory Commission 1450 Maria Lane Walnut Creek, California 94596
Subject:
WASHINGTON NUCLEAR PLANT - UNIT 2 FINAL STARTUP REPORT
References:
1)
Plant Technical Specification 6.9.1.1 2)
Interim Startup Report, Dated October 18, 1985 3)
Interim Startup Report, Dated January 18, 1985 Reference 1) requires a
Startup Report of Plant startup and power ascension testing to be submitted nine (9) months following initial reactor criticality.
The first criticality of WNP-2 occurred on January 19, 1984 and reports were submitted on October 18, 1984 and January 18, 1985 which addressed testing through Test Condition 3.
Subsequent reports are required to be submitted every three months until all testing leading to commencement of commercial operation has been reported.
The purpose of this correspondence is to provide you with the final test reports for those tests which FSAR Table 14.2-4 specified to be performed during the Power Ascension Test Program and special tests specific to WNP-2.
WNP-2 has completed the Power Ascension Test Pro-gram and has met all Level 1
acceptance criteria.
This report is being submitted as the final report and summarizes the entire testing program.
8505030723 8504i7 PDR ADDCK 05000397 P
J
.~
~ 'Ap
t Administrator Page 2
WASHINGTON NUCLEAR PLANT - UNIT 2 FINAL STARTUP REPORT If there are any questions regarding this submittal, please do not hesitate to contact me.
C.M.
Powers (M/D 927M)
WNP-2 Plant Manager CMP'MRW:mm
Enclosure:
Report (2 copies) cc:
Director Office of Inspection and Enforcement U.S. Nuclear Regulatory Commission Washington, DC 20555 Attn: Document Control Desk Report (36 copies)
0 m
~ ~
~i ~
I 'N n
'I 1
s April 1, 1985 DISTRIBUTION: W/0 ENCLOSURI
" Documeiit. Coritrol (50-397)
LB¹2 Reading EHylton.
RAuluck DOCKET NO(S).
5P 397 Hr. G. C. Sorensen, tanager ll Regulatory Programs
'ashington Public Power Supply System P.O.
Box 968 3000 George Washington Way
. $@]gptl., 9ash1n9ton 99352 a
l<PPSS Nuclear Project No. 2 The following documents concerning our review of the subject facility are transmitted. for your information.
Notice of Receipt of Application, dated D Draft/Final Environmental Statment, dated
/
D Notice of Availabilityof Draft/Final Environmental Statement, dated D Safety Evaluation Report,,or Supplement No.
, dated D Notice of Hearing on Application for Construction Permit, dated D Notice of Consideration of Issuance of Facility Operating License, dated Eg Monthly Notice; Applications and Amendments to Operating Licenses Involving no Significant Hazards Considerations, dated ~
~'
Application and Safety Analysi's'Report, Volume D Amendment No.
to Application/SAR dated D Construction Permit No. CPPR'-
, Amendment No.
D Facility Operating License No.
, Amendment No.
D Order Extending Construction Completion Date, dated dated
, dated
Enclosures:
As stated cc:
See next page Office of Nuclear Reactor Regulation C3FF>Ce~
SURNAMe+
DATe+
NRC FORM 318 (1/84) NRCM 0240
~
~ ~ ~ ~ \\
~
~ ~
4 I
N I
C l
~
k I
b "A
FINAL STARTUP REPORT TABLE OF CONTENTS
1.0 INTRODUCTION
1.1 Purpose 1.2 Plant Description 1.3 Startup Test Program Description 1.4 Power Ascension Test Program Data Recording Methods 2.0
SUMMARY
OF THE STARTUP TEST PROGRAM 2.1 Startup Test Program Chronology of Significant Event 2.2 Startup Test Program Scram History 2.3 Power Ascension Test Completion Dates 2.4 Test Results Documentation 3.0
SUMMARY
OF TEST RESULTS 3.1 General Power Ascension Test Description 3.2 Test Number 1
Chemical and Radiochemical 3.3 Test Number 2
Radiation Measurements 3.4 Test Number 3
Fuel Loading 3.5 Test Number 4 Full Core Shutdown Margin 3.6 Test Number 5
Control Rod Drive System 3.7 Test Number 6
SRM Performance and Control Rod Sequence 3.8 Test Number 10 IRM Performance 3.9 Test Number ll LPRM Calibration 3.10 Test Number 12 APRM Calibration 3.11 Test Number 13 Process Computer 3.12 Test Number 14 RCIC System Page 28 28 28 33 37 39 42 43 46 50 8505030>>3,
TABLE OF CONTENTS (Contd) 3.13 Test Number 16A Reactor Vessel Temperature 3.14 Test Number 16B Water Level Measurements 3.15 Test Number 17 System Expansion 3.16 Test Number 18 Core Power Distribution 3.17 Test Number 19 Core Performance 3.18 Test Number 20 Steam Production 3.19 Test Number 21 Core Power - Void Mode Response 3.20 Test Number 22 Pressure Regulator 3.21 Test Number 23A Water Level Setpoint Changes 3.22 Test Number 23B Loss of Feedwater Heating 3.23 Test Number 23C Feedwater Pump Trip 3.24 Test Number 23D Maximum Runout Capability 3.25 Test Number 24 Turbine Valves Surveillance 3.26 Test Number 25A MSIV Functional Test 3.27 Test Number 25B Reactor Full Isolation Test
~Pa e
54 57 65 67 70 72 77 83 85 87 90 96 3.28 Test Number 26 3.29 Test Number 27 Relief Valves 97 Turbine Trip and Generator Load Rejection 102 3.30 Test Number 28 Shutdown from Outside the Control Room 106 3.31 Test Number 29A Flow Control - Valve Position Control 107 3.32 Test Number 29B Recirculation Flow Loop Control 113 3.33 Test Number 30A Recirculation System - One Pump Trip 122 3.34 Test Number 308 Recirculation System - RPT Two Pump Trip 125 3.35 Test Number 30C Recirculation System Performance 129 3.36 Test Number 30D Recirculation Runback 133 3.37 Test Number 30E Verification Recirculation System - Non-Cavitation 134
-b-
TABLE OF CONTENTS (Contd) 3.38 Test Number 31 Loss of Turbine Generator and Offsite Power 3.39 Test Number 33 Drywell Piping Vibration 3.40 Test Number 34 Reactor Internal Vibration 3.41 Test Number 35 Recirculation System Flow Calibration 3.42 Test Number 70 Reactor Water Cleanup System 3.43 Test Number 71 Residual Heat Removal System 3.44 Test Number 72 Drywell Atmosphere Cooling System 3.45 Test Number 73 Cooling Water System 3.46 Test Number 74 Offgas System 4.0 SPECIAL TESTS 4.1 Moderator Temperature Coe fficient Measurement 4.2 In-Plant SRV Load Test 4.3 Sacrificial Shield Wall Verification 4.4
. Loose Parts Monitoring Baseline
~Pa e
135 139 145 146 149 152 154 156 159 163 163 163 164 164
TABLE OF CONTENTS (Contd)
Tables 1-1 WNP-2 Plant Specification 1-2 Test Condition Region Definition 2-1 WNP-2 Significant Event of Startup Test Program 2-2 WNP-2 Startup Test Schedule 2-3 Maintenance Outage During HNP-2 Startup Testing 2-4 WNP-2 Scram Summary 2-5 Power Ascension Test Performance Dates 3-1 Chemical and Radiochemical Test Results 3-2 WNP-2 No Cleanup Test TC-6 Summary 3-3 Offgas Activity Data at 100% Power 3-4 WNP-2 Fuel Loading Problem Summary 3-5 CRD Scram Time Measurement Summary 3-6 CRD Scram Times from Power
'-7 SRM Performance 3-8 IRM Performance Data 3-9
" Process Computer Program Verification Result 3-10 Summary of RCIC Cold guick Start Test 3-11 Summary of RCIC System Control Settings 3-12 Summary of Selected Process Temperature Measurement 3-13 Summary of Water Level Measurement 3-14 Main Steam Thermal Expansion Displacement 3-15 Recirc.
Loop Thermal Expansion Displacement 3-16 Summary of TIP Uncertainty Analysis Results 3-17 Core Performance Summary
~Pa e
10 12 14 18 30 31 32 35
'41 41 42 44 52 56 58 61 63 66
-d-
TABLE OF CONTENTS (Contd)
Tables 3-18 Steam Production Data 4
3-19 Core Power - Void Mode Response Data 3-20 Final Pressure Control System Setting 3-21 Pressure Regulator Test Results 3-22 Feedwater Level Control System Settings 3-23 Feedwater Level Control Valve - Open Loop Flow
Response
Summary 3-24 Feedwater Pump Turbine - Open Loop Flow Response Summary 3-25 Feedwater Maximum Runout Capabil ity Summary 3-26 MSIV Closure Times 3-27 SRY Performance Data 3-28 Summary of Turbine, Trip and Generator Load Rejection Test Results 3-29 Valve Position Control Data 'A'oop - TC3 3-30 Valve Position Control Data 'B'oop - TC3 3-31 Valve Position Control Loop 'A'esponse Summary - TC6 3-32 Valve Position Control Loop 'B'esponse Summary - TC6 3-33 Recirc.
Flow Control System Final Settings 3-34 Flow Control Loop Response Summary 3-35 Neutron Flux Control Loop Response Summary 3-36 Scram Margin Verification (100% L.L) 3-37 Recirculation One Pump Trip Results 3-38 Hanford RPT Coastdown Requirement 3-39 Recirculation System Performance 3-40 Loss of A-C Test Results
~Pa e
68 71 74 75 79 79 80 86 91 100 105 109 110 112 116 117 118 119 124 128 132 137
TABLE OF CONTENTS (Contd)
Tables.
~Pa e
3-41 Chronology of Significant Events During the Loss of A-C Test 138 3-42 Steady State Drywell Piping Vibration Data - Main Steam Lines 141 3-43 Steady State Drywell Piping Vibration Data - Recirculation Loops 142 3-44 Transient Drywell Piping Vibration Data - Main Steam Lines 143 3-45 Transient Drywell Piping Vibration Data - Recirculation Loop 144 3-46 Recirculation Flow Instrumentation Adjustments 3-47 RHR System Performance Data 3-48 RHR Heat Exchanger Data 3-49 Local Drywell Air Temperatures 3-50 Offgas System Design Parameters and Results 147 153 153 155 160
TABLE OF CONTENTS (Contd)
~Fi ere 1-1 Power - Flow Map 1-2 Plant Computer System I 1 1 us tr a tions Page 2-1 Power Histogram of MNP-2 Startup Test Program 3-1 Cycle 1 Cold Shutdown Margin vs Core Average Exposure 3-2 Rated Steam Output Curve 3-3 Pressure Regulator Static Data 3-4 Feedwater Turbine 'A'ontrol Gain Curve 3-5 Feedwater Turbine 'B'ontrol Gain Curve 3-6 Turbine Valve Surveillance Results 3-7 MSIV Surveillance:
Peak Reactor Dome Pressure 3-8 MSIV Surveillance:
Peak Neutron Flux 3-9 MSIY Surveillance:
Peak Heat Flux 3-10 MSIV Surveillance:
Peak Steamline Flow 3-11 Bypass Valve Calibration Curve 3-12 Recirculation Flow Control Linearization - Loop A 3-13 Recirculation Flow Control Linearization - Loop B
3-14 Hanford RPT Coastdown Requirement Compared with Test Data From Loop A 3-15 Hanford RPT Coastdown Requirement Compared with Test Data From Loop B
3-16 Total Core Flow vs Total Loop Flow 3-17 Core dP vs Total Core Flow 3-18 Jet Pump Flow Distribution 3-19 RMCU Bottom Head Flow Indication 22 38 69 76 81 82 89 92 93 94 95 101 120 121 126 127 130 131 148 151
1. 0 INTRODUCTION 1.1
~Pur ose The purpose of this report is to provide a concise summary of the Power Ascension Test Program. conducted on MNP-2.
Included in this report are sections which cover general plant and power ascension test program descriptions and specific test results.
1.2 Plant Descri tion Washington Public Power Supply System Nuclear Project No.
2 (WNP-2) is located within the Hanford Reservation of the Department of Energy (DOE), Benton County, Mashington, approximately 12 miles north of the city of Richland.
The station utilizes a Direct-Cycle Forced Circula-tion Boiling Mater Reactor (BWR) provided by General Electric (GE).
WNP-2 is rated at 3323 MMt with design power of 3468 MWt.
The gross electrical power output is rated approximately at 1150 MWe with design output of 1205 MWe.
The Nuclear Steam Supply System designed and supplied by General Electric Co. is designated as a
BWR/5 product line with a 251-inch inside-diameter reactor pressure vessel and 764 fuel assemblies in the reactor core.
Significant plant parameters are specified for informational purpose in Table 1-1.
1.3 Startup Test Pro ram Description After the Preoperational Test Phase has been completed, the Power Ascen-sion Test Phase begins.
The Power Ascension Test Phase begins with fuel loading and extends to commercial operation.
This phase is subdivided into the following four parts:
a.
Open Vessel Testing (Fuel loading and low power physics tests) b.
Initial heatup to rated pressure and temperature c.
Power Ascension tests d.
Warranty demonstration.
The tests conducted during the Power Ascension Phase consist of Major Plant Transients, Stability Tests, and a remainder of tests which are directed towards demonstrating correct performance of the nuclear boiler and numerous auxiliary plant systems while at power.
Certain tests may be identified with more than one class of tests.
The general objectives of the Power Ascension Test Phase are as follows:
a.
to achieve an orderly safe initial core loading; b.
to accomplish all testing and measurements necessary to deter-mine that the approach to initial criticality and subsequent power ascension is safe and orderly;
s 1
TABLE l-l WNP-2 PLANT SPECIFICATION PARAMETER Rated Core Thermal Power (MWt)
Rated Total Core Flow (MLB/HR)
Reactor Dome Pressure (PSIA)
Rated Feedwater Temperature
( F)
Total Steam Flow (MLB/HR)
Vessel Diameter (IN)
Total Number of "Jet Pumps Number of Nozzles per Jet Pump Jet Pump Design M-Ratio Rated Recirculation Pump Flow (GPM)
Number of Control Rods Number of Fuel Bundles Fuel Type
'ore Active Fuel Length
( IN)
Cladding Thickness
( IN)
. Channel Thickness (IN)
MCPR Operating Limit MCPR Safety Limit Normal Single Loop Operation MLHGR (KW/ft)
Turbine Governor Valve Mode Turbine Bypass Valve Capacity
(% NBR)
Safety Relief Valve Capacity
(% NBR)
Number of SRV's Recirculation Flow Control Mode VALUE 3323 108.5 1020 420 14.296 251 20 5
2.33 47200 185 764 Bx8PR 150 0.032 0.100 1.24 1.06 1.07
- 13. 4 Partial ARC 25 111. 5 18 Flow Control Valves
c.
to conduct low power physics tests sufficient to ensure that test criteria have been met; d.
to conduct initial heatup and hot functional testing so that hot integrated operation of all systems is shown to meet test acceptance criteria; e.
to conduct an orderly and safe power ascension program, with requisite physics and systems testing, to ensure that the plant operating at power meets test acceptance criteria; and f.
to conduct a successful warranty demonstration program.
The overall program was comprised of open vessel testing and six test conditions which are for the most part characterized by differences in plant and power/core flow conditions.
The power-flow map illustrated in Figure 1-1 displays the test conditions established during power ascen-sion testing.
To assist in the evaluation of proper plant performance from the test results obtained during the Startup Test Program, a set of criteria for each test has been established.
These criteria are a result of a combi-nation of factors such as safety analysis assumptions, engineering judge-ments or expectations, and contractural commitments.
Safety concerns are considered Level 1 while other considerations are typically Level 2 or Level 3.
Satisfactory compliance with these criteria assure that the plant meets the stated purpose of the Startup Test Program.
Portions of various tests are conducted to provide baseline data and as such do not employ an acceptance criteria.
Definition of these Level 1, Level 2 and Level 3 criteria and required action in the event of a violation are defined as follows:
Level 1 Criteria The values of process variables assigned in the design of the plant and equipment are included in this category.
If a Level 1 criterion is not satisfied, the plant will be placed in a hold condition which is satisfactory and safe based upon prior testing.
A Nonconformance Report (NCR) will be made to document the situation.
Plant oper-ating or test procedures or the Technical Specifications may guide the decision or the direction to be taken.
Startup testing compat-ible with this hold condition may be continued.
Resolution of the problems must immediately be pursued by appropriate equipment adjustment or through offsite engineering support if needed.
Fol-lowing resolution, the applicable test portion must be r epeated to verify that Level 1 requirement is satisfied.
A description of the problem resolution must be included in the NCR documenting the suc-cessful test.
Level 2 Criteria The limits considered in this category are associated with expecta-tions in regard to the performance of the system.
If a Level 2 cri-terion is not sati sfied, plant operating and startup testing plans would not necessarily be altered.
An investigation of the related adjustments, as well as the measurement and analysis method would be initiated.
If all Level 2 requirements in a test are ultimately met, there is no need to document a temporary failure in the test
- report, unless there is an educational benefit involved.
Following resolution, the applicable test portion must be repeated to ver ify that the Level 2 requirement is satisfied.
If a certain controller-related Level 2 criterion is not satisfied after a reasonable ef-fort, then the control engineers may choose to document the result with a full explanation of their recommendations.
All Level 2 cri-teria violations shall be documented on a Plant Deficiency Report (PDR).
This report must discuss alternatives of action, as well as the concluding recommendation, so that it can be evaluated by all related parties.
The conduct of the Startup Test Program was governed by Volume 8 Section 2.0 "Power Ascension Test Program Administration", of WNP-2 Plant Proce-dure Manual (PPM).
This procedure outlines the relationships between the respective startup ogranizations, test execution, as well as documenta-tion review and approval of procedures.
Documents such as USNRC Regula-tory Guides 1.68, Rev.
2, 1978, Operating License, Technical Specifica-tions, Plant Procedure Manual, Chapter 14 of the WNP-2 Final Safety Analysis Report and Startup Test Specifications formed integral parts of the Controlling Power Ascension Test Program Administration Procedure.
The Startup Test Specification (STS) provides the recommended test pro-gram required to demonstrate safe efficient plant operation.
The Power Ascension Test procedures were prepared by WNP-2 Technical Staff with the technical assistance of General Electric site personnel.
The procedures specified the required initial conditions, procedural
- steps, analytical techniques, and suppor ting information for the perfor-mance of each test.
General Electric site personnel, as the Nuclear Steam Supply System vendor representative, has reviewed the Power Ascen-sion Test procedures to further verify their adequacy and to confirm that the General Electric Test Specification requirements were fully met.
for those procedures dealing with the
- BOP, Burns and Roe Inc. as the A/E, reviewed and concurred with the test procedure content.
Within this framework of procedures and controlling documents, the Startup Test Program was satisfactorily conducted demonstrating safe operation, proper system performance as well as adequate plant operation using the normal operating procedures and personnel.
A training program was conducted during the PAT in compliance with the position stated in the WNP-2 FSAR, Appendix B, TMI Issue I.G.1.
The program provided
- 1) instruction on the content and goals of the
- PATP,
- 2) for selection of special tests designed to demonstrate abnormal scenarios, and
- 3) for utilization of the experience gained during the test program.
1.4 Power Ascension Test Pro ram Data Recording Methods The primary mechanism for recording data for tests which provided con-trol systems tuning/optimization, system performance demonstrations, and plant response to major transients was the Transient Data Acquisition System (TDAS).
This system receives approximately 950 analog and digital plant signals.
The signals are hard-wired from either the control room or remote locations, such as drywell piping displacement measurement
- signals, to TDAS remote modules.
The signal output from the remote modules is transmitted through fiber-optic cables to the TDAS Central Control Unit (CCU).
The TDAS Central Control Unit (CCU) controls the monitor, record, and data transfer functions.
Data is transfered from the TDAS CCU to a minicomputer for data reduction, analysis and display.
The hardware configuration of the plant computer system is shown in Figure 1-2.
Other secondary means of data acquisition included plant process com-
- puter, magnet tape recorder, and manual data taking.
All of these methods provide documentation of the successful completion of NNP-2 Power Ascension Test Program.
TABLE 1-2 TEST CONDITION REGION DEFINITIONS Test Condition Power Flow Ma Re ion and Notes
'2 Before main generator synchronization from 5 to 20 percent thermal power and operating on recirculation pump low frequency power supply (25% pump speed).
After main generator synchronization from 50 to 75 percent control rod lines, at or below the analytical lower limit of Master Flow Control mode and with the lower power corner within bypass valve capacity.
From 50 to 75 percent control rod lines above 80 per-cent core flow, and within maximum allowed recircula-tion control valve position.
On the natural circulation core flow line within + 5 percent of the intersection with the 100 percent power rod line.
From the 100 percent loadline to 5 percent below the 100 percent loadline and between minimum flow at rated recirculation pump speed (mi nimum valve posi-tion) to 5 percent above the analytical lower limit of the automatic flow control range.
Within 0 to -5 percent of rated 100 percent thermal
- power, and within + 5 percent of rated 100 percent core flow rate.
Increased Core Flow Region Power between cavitation interlock and 100% power, core flow between 100% and the constant flow control valve position that gives 110.5X core flow at 100%
power.
POWER FLOW MAP 130 120 110 100 90 80 O
70 z
W 60 PERCENT VALVEPOSITION 0
0 NATURALCIRCULATION 1
0 25 PERCENT PUMP SPEED 2
100 3
0 100 PERCENT PUMP SPEED 4
11 5
17 6
28 TCS 7
37 8
48 9
60 A
73 B
96 3
01
. TWO PUMP OPERATION N
JET PUMP NO2ZLE CAVITATIONLINE S
JET PUMP SUCTION CAVITATIONLINE R
'RECIRC PUMP CAVITATIONLINE INCREASED CORE FLOW OPERATION gC TC8 j
v C
100 TC4 40 30 20 10 0
TC2 N
R 0
10 20 30 40 50 60 70
- 80 90 100 110 PERCENT CORE FLOW 850c;07.1A Hev I
Figure 1-1
PLANT COMPUTER SYSTEM PRESENT COMPUTER CONFIGURATION BLD. 88 WNP-2 CONTROL ROOM TERMINET 200 7 B/W TERMINALS G.D.S.
COLORGRAPHIC TERMINALWITH TOUCH PAD
~
TRANSIENT DATA ACQUISITIONSYS.
CENTRAL CONTROL UNIT (POP 11/44)
REMOTE
~ 000 ~
UNIT asses REMOTE
~ 0 ~ 0 ~
UNIT sees SMALL SCALE
~
RECOADING
~
DEVICE
~
2 PARALLEL COI.ORGRAP HID TERMINALWITH TOUCH PAD isooaeeeee TO DOWNTOWN PRIMES 2 PCM AECOADERS 2 DISK UNITS 040
~ 000 ~ 00 ~
REMOTE UNIT
~
REMOTE
~ 0 UNIT PRIME 750 4MB MEMORY
~0 PROCESS COMPUTER DISK 0
000000000000000000
~
~ INTERFACES 0
0 0
0
~ 0 ~ 00 ~ 00 ~ 00 ~ 0 ~ 0 ~ 0
~000 ~ 0 ~ 00 ~ 00 ~ 000 ~ 0
~ 0 ~ 0 ~ 0 ~ 0 ~ 0000 ~ 00 ~ 0
~ 0 ~ 00 ~ 000 ~ 0 ~ 0 ~ aaol
~ 0 ~ 00 ~ oos ~ 0 ~ 0 ~ 00 ~ 0
~000000000000000
~ 0 0000000
~ 00000 ~ oes ~ 0000 ~ 0 ~
~000000000000
~ 0 ~ 0 ~
T,S.C.
MATRIXPRINTER B/W TEAMINAL COLORGRAPHIC TERMINAL COLORGRAPHIC TERMINAL 3 300MB DISKS MAGNETICTAPf 2 MATRIX PRINTERS LINEPRINTER COLORGRAPHIC TERMINAL 2 B/W TERMINAL PRINTER/PLOTTER RS232
~ 000 ~ 00 ~ 00 ~ 000 (9800 BAUD)
DRUM MAGNETICTAPE OPERATORS CONSOLE 2 B/W CATS B TERMINET 200 CARD READER CARO PUNCH LINE PRINTER 4 TREND RECORDEAS E.O.F.
MATRIXPRINTER 8/W TERMINAL COLORGRAPHIC TERMINAL COLORGRAPHIC TEAMINAL DOSE ASSESS-MENT B/W TERMINAL MATRIXPRINTER COLORGRAPHIC TERMINAL Figure 1-2 850207.2A
2.0
SUMMARY
OF THE STARTUP TEST PROGRAM 2.1 Startu Test Pro ram Chronolo of, Si nificant Events
,2 2
2.3 The WNP-2 Startup Test Program began on December 25, 1983 with commence-ment of Fuel Loading and concluded on December 12, 1984 with the comple-tion of the Warranty Run.
A chronology of significant events of 'the
, Startup Test Program is presented in Table 2-1.
A total of 354 days, slightly shorter than the industrial average of 388 days, were required to complete all the testing originally scheduled for 161 days.
Table 2-2 presents the comparision of the actual testing days with the scheduled testing days at each test condition.
Several major problems which resulted in significant delays are summarized in Table 2-3.
A Power Histogram of the whole power ascension testing is displayed in Figure 2-1.
Startu Test Pro ram SCRAM Histor Twenty-eight scrams occurred during the Startup Test Program.
Table 2-4 contains a brief description of each scram including date, cause and whether it was planned or unplanned.
In all, 22 unexpected scrams oc-curred while 6 were a normal course of the Startup Test Program.
Power Ascension Test Com letion Dates 2.4 As an aid to illustrate Startup Test Program progress, Table 2-5 contains Power Ascension Test completion dates as a function of test condition.
Comparison of the dates in this table with the tests specified in the Table 14.2-3 of WNP-2 Final Safety Analysis Report indicates that all required tests were completed.
Test Results Documentation During the course of the Power Ascension Test Program an Apparent Test Results form was generated immediately following the completion of a test at each test condition to document the acceptance of the test results.
These ATR's were reviewed by Plant Operation Committee (POC) and approved by the Plant Manager prior to the POC giving authority to proceed to the next test condition.
A Nonconformance Report (NCR) was prepared for any Level 1 criteria fail-ure and all Level 2 criteria violations were documented on a Plant Defi-ciency Report (PDR).
These NCRs and PDRs were reviewed and resolved in accordance wi th the requirements of Section 1.3.12 "Plant Problems" of the Plant Procedure Manual.
In addition, a large data file, Transient Traces and Procedure File, which were generated during the test program, were retained as per PPM 1.6.0 "Plant Record Control".
All these data are summarized in the following sections of this, report.
TABLE 2-1 WNP-2 SIGNIFICANT EYENT OF STARTUP TEST PROGRAM Commence Fuel Loading fuel Load Complete Initial Criticality Initial Heatup to Rated Pressure Begin Test Condition 1 Testing Initial Main Turbine Roll Begin Test Condition 2 Testing Initial Generator Synchronization Begin Test Condition 3 Testing Begin Test Condition 5 Testing Begin Test Condition 4 Testing Being Test Condition.6 Testing Begin Warranty Run Commercial Operation 12-25-83 1-12-84'-19-84 4-19-84 5-07-84 5-08-84 5-26-84 5-27-84 8-10-84 10-17-84 10-20-84 10-30-84 12-08-84 12-13-84 TABLE 2-2 WNP-2 STARTUP TEST SCHEDULE Test Condition Total Maintenance Pl ant Actual
~Recover
~Test Da s
Schedule Days Open Vessel Preparation To Heatup Heatup TC 1
TC 2
TC 3 TC 4 TC 5 TC 6 Warranty Run Total 36 72 27 19 69 39 354
'2 39 28 164 13 13 17 36 21 22 28 3
'34 30 6
22 12 16 105*
- Exclude the scheduled maintenance outage (15 days) and scheduled heatup prep-aration (41 days).
11
TABLE 2-3 MAINTENANCE OUTAGES DURING WNP-2 STARTUP TESTING Date T.C.
4/23/84 - 4/26/84 H/U 5/13/84 - 5/15/84 TC-1 5/20/84 - 5/26/84 TC-1 6/4/84 - 6/11/84 TC-2 6/20/84 - 7/1/84 TC-2 7/10/84 - 7/30/84 TC-2 8/7/84 - 8/8/84 TC-2 8/12/84 - 8/14/84 TC-3 8/16/84 - 8/28/84 TC-3 9/10/84 - 9/17/84 TC-3 10/1/84 - 10/6/84 TC-3 10/8/84 - 10/10/84 TC-3 Oays 20 12 Descri tion o
D/W cooling modification o
DEH hydraulic modification o
Main turbine GV flange leak o
Main condenser baffle plate modification o
RHR-V-418 testable check valve repair o
Bypass valve 83 repair o
RHR pump 'B'epair o
Div. I and II DG bearing replacement o
MSR drain tank handhole flange leakage o
Main condenser tube leak o
Main condenser tube leak o
Repair FW piping hanger o
Repair FW piping hanger o
RHR-V-41B testable check valve repair o
Main turbine GV LVDT repair o
Turbine bypass valve hydraulic system troubleshoot o
Main steam relief valve vacuum breakers repair o
Main turbine bypass valves hydraulic modification TABLE 2-3 (Contd)
MAINTENANCE OUTAGES DURING WNP-2 STARTUP TESTING Date T.C.
~oa s
10/20/84 - 10/23/84 TC-4 3
11/10/84 - 11/19/84 TC-6 11/27/84 - 11/29/84 TC-6 Descri tion o
Repair RFW-FCV-15 o
Repair MSR drain line hanger o
Drywell pipe whip restraints inspection o
FW heater level controller modi fication o
Main condenser expansion joint modification o
Main condenser tube leak check o, FW heater 4C tube leak repair TOTAL 92 TABLE 2-4 MNP-2 SCRAM
SUMMARY
SCRAM DATE CONDITION CAUSE DESCRIPTION 84-01 4-23-84 Heatup IRM F Hi-Hi and CRD scram disch.
volume high level 84-02 5-02-84 Heatup Manual Neutron flux spike caused by cold FW injection during FW startup level control valve RFW-FCV-10 tuning in conjunction with existing 1/2 scram on channel
'A'ue to scram discharge vol-ume Channel Functional Test.
(Unplanned)
Manual scram to measure control rod B-2 sequence scram times.
(Planned) 84-03 5-13-84 TC-1 84-04 5-17-84 TC-1 84-05 5-18-84 TC-1 84-06 5-19-84 TC-1 Reactor High Pressure Manual Reactor High Pressure
,Reactor Low Mater,
'Level Initial turbine roll at 1640
- RPM, No.
2 bypass valve failed open and other three bypass valves over compensated to cause the reactor high pressure.
(Unplanned)
Loss of reactor feedwater
'A'peed resulted in rapid decreasing reactor water level.
(Unplanned)
Turbine bypass valve failed closed on low DEH hydraulic oil pressure when the main turbine is manually tripped.
(Unplanned)
Surveillance test of high drywell pressure switches caused actuation of the load shedding logic.
The control power to the re-actor feedwater turbine control power was lost causing feedwater pump tur-bine runback to minimum speed which caused a low level scram.
(Unplanned)
TABLE 2-4 (Contd) t SCRAM DATE COMOITIOM CAUSE 84-07 5-20-84 TC-1 Manual DESCRIPTION Perform PPM 8.2.28 shutdown from outside the control room.
(Planned) 84-08 5-28-84 TC-2 84-09 5-29-84 TC-2 84-10 6-01-84 TC-2 84-11 6-13-84 TC-2 84-12 8-01-84 TC-2 84-13 8-07-84 TC-2 Reactor Low Water Level Turbine Control Valve Fast Closure Reactor High Pressur e Reactor Low Water Level Turbine Trip and Throttle Valve Closure Turbine Control Valve fast Closure Loss of condensate booster pumps and feedwater pumps on low suction pressure during the condensate fil-ter demineralizer differen-tial pressure controller repair.
(Unplanned)
During the main turbine overspeed protection (OPC) test at 20% power, the tur-bine first stage pressure switches actuated and re-moved the less than 30%
power RPS trip bypass.
(Unplanned)
Turbine bypass valves failed closed due to DEH electron-ic circuit card failure.
(Unplanned)
Loss of condensate booster pumps and reactor feedwater pump on low suction pres-sure when RFW-fCV-15 (con-densate cleanup return to condenser) failed open.
(Unplanned)
Turbine first stage pressure switch actuated during the main turbine control trans-fer at 1650 RPM and less than 30'X power RPS trip bypass was removed.
(Unplanned)
Perform PPM 8.2.31, Loss of Turbine Generator and Off-site Power.
(Planned)
TABLE 2-4 (Contd)
SCRAM DATE 84-14 8-09-84 CONDITION CAUSE TC-3 Reactor Low Mater
'evel DESCRIPTION Loss or reactor feedwater control power due to under-voltage trip of SM-7 during circulating water pump start.
(Unplanned) 84-15 8-12-84 TC-3 84-16 8-16.-84 TC-3 "84-17 9-10-84 TC-3 84-18 10-01-84 TC-3 84-19 10-04-84 TC-3 84-20 10-06-84 TC-3 84-21 10-13-84 TC-3 Manual Main Steam Line High Rad (Channel B2) and APRM up-scale (Channel A)
RPS Power Fuses blown during execution of planned test n
Turbine Trip and Throttle Valve Closure Reactor Low Mater Level MSIV's Closure Manual Reactor was manually scrammed due to high re-actor water conductivity.
(Unplanned)
Removal of APRM Flow Unit
'A'ower supply during the surveillance caused APRMs A,C,E upscale trip in con-junction with existing 1/2 scram on main steam line high radiation surveillance test.
(Unplanned)
RPS fuses F14A,B,C,D were blown following incorrect installation of a test box to be used to simulate RRC transfer to 15 Hz.
(Unplanned)
Perform PPM 8.2.27, Turbine Generator Trip.
(Planned)
Turbine bypass valves failed open then closed to cause the reactor low water level during DEH transducer troubleshooting.
(Unplanned)
Mode switch was placed in RUN with main steam line pressure less than 831 psig.
(Unplanned)
Manual scram due to loss of DEH control of main turbine valves.
(Unplanned)
TABLE 2-4 (Contd)
SCRAM DATE CONDITION CAUSE 84-22 10-20-84 TC-5 MS IV' Cl osure DESCRIPTION Main steam line pressure decreased to below 831 psi g during the pressure regu-lator testing.
(Unplanned) 84-23 10-23-84 TC-5 84-24 10-28-84 TC-6 84-25 11-10-84 TC-6 84-26 11-27-84 TC-6 84-27 12-02-84 TC-6 IRM Hi-Hi Reactor Low Water Level MSIV's Turbine Control Valve Fast Closure Turbine Control Valve Fast Closure Cold feedwater injection
'ue to FW startup level control valve failed open.
(Unplanned)
Loss of condensate booster pumps and feedwater pumps on low suction pressure due to a condensate system flow transient.
(Unplanned)
Perform PPM 8.2.25 MSIV's Closure.
(Planned)
Reduction of condenser vacuum caused a turbine trip.
(Unplanned)
Perform PPM 8.2.27 Turbine Generator Trip.
(Planned) 84-28 12-03-84 TC-6 Reactor Low Water Level Momentary loss of level control during transfer from FW startup level con-trol valve RFW-FCV-10 to FW turbine speed control.
(Unplanned)
A
TABLE 2-5 POWER ASCENSION TEST PERFORHANCE DATES Page 1 of 4 TEST I
NO.
TEST NAME OPEN
= VESSEL HEATUP TC-1 TC-2 TC-3 TC-4 TC-5 TC-6 WARRANTY RUN 2.
Chemical 4 Radfochemlcal Radla tlon Heasurement 3.
I Fuel Loading I
I 4.
I Full Core Shutdown Hargln 5.
Control Rod Drive System 11.
LPRH Calibration 12.
APRH Callbratlon 13.
Process Computer 14.
Rclc 16A.
I Selected Process I
Tempera tures I
6.
SRH Performance A Control I
Rod Sequence I
10.
I IRH Perfonaance 12/23, 12/24/84 12/25/83-1/12/84 1/21/84 12/25/83-1/16/84 1/19-1/21/84 4/21, 4/26/84 4/11-5/07/84 4/10-4/13/84 1/21/84 4/26/84 4/22-5/04/84 5/8, 5/9/84 5/07/84 5/16, 5/26/84 5/08, 5/09/84 4/ll/84 5/09/84 3/28/84 5/1, 5/04/84 4/29, 5/I, 5/03/84 5/02/84 5/9, 5/11/84 5/2, 5/27, 5/l6, 6/02/84 5/11/84 12/22/84 4/23/84 5/23/84 7/04/84 6/16/84 8/31/84 8/30, 9/01/84 8/07/84 10/1/84 6/15/84 7/31, 8/1, 8/5/84 7/05/84 7/05/84 7/1. 7/5, 7/09/84 9/02, 9/19/84 9/19, 9/20 9/26/84 7/06/84 I 9/10 9/25ol 10/20 '
9/26/84 I
10/25/84 I
I 10/18/84 10/18/84 11/3/84 11/4-11/5/84 11/10/84, 12/02/84 11/30/84 11/03/84 ll/03/84 11/3-12/1/84 12/06/84 12/11/84
TABLE 2-5 (Contd.)
POMER ASCENS10N TEST PERFORMANCE DATES Page 2 of 4 TEST I
NO.
TEST MANE OPEN VESSEL HEATUP TC-1 TC-2 TC-3 TC-4 TC-5 TC-6 MARRANTY RUN 168.
Mater Level Ref.
Leg Temperature 17.
I System Expansion 1/19, 1/23/84 5/04/84 4/11, 4/23/84 5/09, 5/11/84 5/11/84 7/05, 8/05/84 9/30/84 6/18, 6/19, 9/19, 9/25, 7/06, 9/26, 8/06/84 10/01/84 10/20/84 10/18/84 12/03/84 11/24/84 19.
Core Perfonaance Steam Production 18.
I Core Power Distribution 5/09/84 9/02, 9/03/84 6/06/84 8/30/84 10/20/84 10/18/84 11/03, 11/05/84 11/08/84 12/10/84 12/08-12/13/84 21.
I Core Power Void ffode I Response I
22.
I Pressure Regulator 23.
Feedwater System 2/28-3/19/84 5/11/84 6/18-6/19/84 10/16/84 10/25/84 10/25/84 10/20/84 10/19/84 11/10/84 A.
Mater Level Setpofnt Change 5/05/84 5/09/84 7/02, 8/05/84 9/08, 10/15 10/16/84 10/20/84 10/18/84 11/20, 11/26/84 B..Heater Loss C.
Feedwater Pump Trfp D.
ffaxfmum Runout Capability 24.
Turbine Valve Surveillance 5/09/84 12/05/84 12/08/84 10/19/84 12/04/84 11/08, 11/09/84
TABLE 2-5 (Contd.)
POMER ASCENSION TEST PERFORHANCE DATES Page 3 of 4 TEST I
NO.
TEST NAHE OPEN VESSEL HEATUP TC-1 TC-2 TC-3 TC-4 I
TC-5 TC-6 WARRANTY RUN B.
Full Isolation 26.
I Relief Valves A.
Flow Dennnstration B.
Operational 27.
Turbine Trip/Generator Load Regect 28.
I Shutdown From Outside the I
Control Room I
29.
I Recirculation Flow Control I
System I
30.
I Recirculation System 25.
Hain Steam Isolation Valves I
A.
Each Valve/One Valve 4/20/84/
4/30/84 4/14/84 5/20/84 5/10-5/11/84 6/18/84 9/26/84 9/26/84 6/19/84 10/Ol/84 9/28-10/12/84 10/20/84 11/09/84 ll/10/84 12/02/84 11/27/84 11/23-11/25/84 A.
One-Pump Trip B.
RPT Trip of Two Pumps C.
System Perfonaance 8/04/84 9/25/84 9/26/84 9/17-9/27/84 10/20-10/25/84 12/07/84 11/08-12/07/84 D.
Recirc.
Pump Runback E.
Recirculation System Cavitation 9/09/84 8/06/84 9/26/84
TABLE 2-5 (Contd.)
POWER ASCENSION TEST PERFORHANCE OATES Page 4 of 4 TEST NO.
31.
TEST NAHE Loss of Turbine-Generator and Offsite Power OPEN VESSEL HEATUP TC-1 TC-2 8/08/84 TC-3 TC-4 TC-5 TC-6 WARRANTY RUN 33.
I Orywell Piping Vibration 34.
Reactor Internal Vibration A.
Vibration Heasurment 35.
I Recirculation Flow Calibration 8/06, 9/19, 9/25, 9/26, 10/01/84 9/10, 9/25,I 9/26, 9/27/84 9/08/84 11/10, 11/27 12/02/84
= 12/07, 12/08/84 11/04, 11/08/84 70.
Reactor Mater Cleanup System 4/30-5/01/84 71.
Residual Neat Removal System 74.
Offgas System 72.
I Orywell Atmosphere Cooling I
I 73.
I Cooling Water System 3/02-4/05/84 4/30/84 5/01/84 5/03, 5/04/84 5/08/84 6/16, I
7/31/84 I
l 8/31/84 9/04/84 12/11/84 11/3, 11/24/84 12/12/84 11/04/84
~ O CTI (ON oV CJ We U2C (D
27 1l I
Nl
~S
~O IM CI REACTOR PRESSURE (PSIQ)
V 8
~0 ORYWELLHIGH TEMPERATURE PROBLEM ORYWELLPIPING INSPECTION RX SCRAM 11ARM HleHI SEAL STEAM EVAP LVLCONTROL PROSLEII MANUALSCRAM (PPM S.2.S)
COMPLETE HEATUP TESTING (ENO OF PRESSURE PLOT)
BEGAN TC 1 TESTING (START OF POWER PLOT)
M RXSCRAMISRXNIONPRESSURE RX SCRAM ~MANUAL RX SCRAM MRX HIGH PRESSURE w
RX SCIIAM ISRX LOW LEVEL N
RxscIIAII ITUIANUALIPPM2.2.22I COMPLETE TC 1 TESTING 0
Zlx M
0Q 33 0
M Zl CO I
ZJ0Q Xl 0
~S I
I g
a CS I
I CM g
REACTOR POWER (TIIT RATEO) lO ChQ M
~I CO lO Cl CAl CO lO O
Ckl CBI Cll Cll 4
(0 O
EO IO Cl lO lO lO lO CPl DP hS CEE lO CA IO'4 hS OE CO CO CO REACTOR POWER (% OF RATED) o o
5 8
o4 8
o I
I I
I I
I I
I RX SCRAM PS LOW LEVEL RX SCRAM IS-TURBINE CONTROL VALVEFAST CI.OSURE 2
AX SCRAM I10 RX NIGH PRESSURE BEQM TC 2 TESTINQ
~
MAINCONOENSER TIIBE LEAKPROBLEM AXWTR CONOUCTIVITYPROBLEM AX SCRAM I11~X LOW LEVEL TURBINE BYPASS VALVE22 PROBLEM RHR PUMP B PROBLEM
~ ~
0 K
CO Q
-- QZl Q
C:0 CO a
0 zi Q
23-
I Qo'4 Vl CC I
CQ 4
4 CD 4I Vl 4
4'll CO CO h1 CO M4 ID ID CD ID Cs Vl IO CO M
'4 hl CO h1 IO CD CI CD ID 4
lO4 CD 4h Vl Ol
'4 CO CO h1 CO hS ID ID M
CD lO Vl CO Q
CO
'6 O
Vl IIII C
RX THERMALPOWER (IHI)
III g
I I
~D CI RX SCRAM 112 TURBINE GV FAST Cl OSURE MSR DRAIN TANKMANWAYCAP LEAKREPAIR RX SCRAM f13-TURBINE QV FAST CI-OSURE (PPM 84.81 LOOSP)
RX SCRAM Ilt~EACTOR LOW LEVEL RX SCRAM 415-MANUALSCRAM DUE RX WATER HIGH CONDUCTIVITY FEEDWATER PIPING SUPPORT FAILURE RX SCRAM f15 APRM SURVEILLANCETEST MAINCONDENSER TUBE LEAKPROBLEM CI 0
Zl K
CO OQ ZJ 0
V) 33 40 ZJQQ M
<<II III IIIv hS
<<O III
<<O Cal CIl C<<Iill~
aa
<<0 CI 4
IO 4
Cal I
4h CII COv 4
CO 4
<<0 v
l<<I CO IO
<<0 CO CI 0O REACTOR POWER (% OF RATED) 4 CI l4 M
8 o
I I
8 3
I I
DEH OSCILLATIONPROBLEM
~ GV &HUNTING
~
RX CONDUCTIVITY PROBLEM
~ RECIRC RUNBACK AECBIC ONE PUMP TRIP
~ RR RCRAII 011 RPS FUSE BLOWOUT REPAIR TURBINE QV LVDT RX WTA CONDUCTIVITY PROBLEM TURBINE BYPASS VALVEMODIFICATION
~ ONE PUMP TRIP
~TWO PUMP TRIP
~AECIACCAVITATION SEARCH ONDENSATE FCV-15 PIPING SUPPORT FAII.URE
~ RX SCRAM 418 (PPM 8.2.27 TURBINE TRIP)
APS MQ SET TURBINE BYPASS VALVEMODIFICATION RX SCRAM 119 HIGH RX PAESSURE AX SCRAM II20 MSIV ISOLATION IN RUN MODE Q
XI 40 Q
Zl 0
CO 0
fA CO aZl QQZlr O
OOK O
o k
Csl 4
4h 4
Cll 4
Cl V
CO CCI lO CI M
l4 ICI M
4h lO CII Cll ICI
'V IOal M
Cal CI Cal 4
M 4
ICI Eal 4s 4
'V CCI CCI M
CI IO ICI
~0 4l ICI Ca h1 CIC AX POWER P% OF RATED)
CI Cl I
AX SCRAM 421.MANUAL COMPLETE TC 3 TESTINQ COMPLETE TC 5 TESTINQ RX SCRAM 422.MSIV CLOSURE RX SCRAM 1l23-IRM HI4II COMPLETE TC 4 TESTIKQ START TC 8 TESTING AX SCRAM 424-RX LOW LEVEL CONDENSATE BOOSTER PUMP LOW SUCTION PROBLEM CONTROL ROD 28-51 INDICATIONPROBLEM TURBINE VALVESURVEILLANCE RX SCRAM 425.MSIV ISOLATION(PPM 8.2.25) mZ Zo O
g CCC cf
- CCC, 3
Cl I
I I
I I
I 0
X CO OQZl 0
0) 33 C
0) zj0Q 33 0
- 26
lo CCC M
Cl M
l4 CO CO CI1 CD CD CCC Cl yO CI Cal 4h 4
Cll AX POWEA (4 OF AATEO)
RX SCRAM &$4V FAST CLOSURE RX SCRAM 027&V FAST CLOSURE (PPM 8.2 27)
RX SCRAM N2IRD( VESSEL LOW LEVEL FW HEATER LOSS (PPM 8N.23B)
ONE PUMP TRIP (PPM 84.30A)
FEEOWATER PUMP TRIP (PPM 8.2.23C)
COMPLETE 100 HOUR WARRANTYTEST ENO OF POWER ASCENSION TEST PROGRAM Q
K Q
Q
'R CO Zl CO 33Q Zl 3.0
SUMMARY
OF TEST RESULTS 3.1 General Power Ascension Test Descri tion In the following sections a summary of test purpose and the associated acceptance criteria, test results and discussion of each power ascension test performed are presented.
3.2 Test Number 1 - Chemical and Radiochemical 3.2.1
- 3. 2.1.1
~
~
~
~Pur ose The principal objectives of this test are a) to secure information on the chemistry and radiochemistry of the reactor coolant, and b) to determine that the sampling equipment, procedures and analytic techniques are adequate to supply the data required to demonstrate that the chemistry of all parts of the reactor system meet specifi-cations and process requirements.
Specific objectives of the test program include evaluation of fuel performance, evaluations of demineralizer operations by direct and indirect methods, measurements of filter performance, confirmation of condenser integrity, demonstration of proper steam separator-dryer operation, measurement and calibration of the Off-Gas System, and calibration of certain process instrumentation.
Data for these purposes is secured from a variety of sources:
Plant Operating
- Records, regular routine coolant analysis, radiochemical measure-ments of specific nuclides, and specific chemical tests.
Level 1 Criteria Chemical factors defined in the Technical Specifications must be maintained within the limits specified.
The activity of gaseous liquid effluents must conform to license limitations.
Water quality must be known at all times and should remain within the guidelines of the Water equality Specifications.
3.2.1.2 Level 2 Criteria Not applicable.
3.2.2 Resul ts A summary of the reactor water, condensate, and feedwater quality throughout the Startup Test Program is presented in Table 3-1.
Steam separator-dryer performance "was determined during the no-cleanup test performed at TC-6.
The result is summarized in Table 3-2i Offgas activity data is tabulated in Table 3-3 and indicates accep-table fuel performance.
Discussion Throughout the Startup Test Program, water quality exceeded recom-mended limits in the reactor and conductivity was measured at values exceeding the limits of 1.0 umho/cm during TC-2 and TC-3.
Reactor power was also limited in several cases due conductivity approaching to the limiting value.
The conductivity problem that occurred in the early stage of Startup Test was caused by main condenser tube leakage and inadequate per-formance of the condensate filter demineralizers.
Remedial actions were taken and reactor water conductivity was reduced and maintained during subsequent test conditions.
The Reactor Mater No-Cleanup Test scheduled at TC-2 was not com-pleted due to a
RWCU pump failure while the test was in progress, preventing the RWCU system from being returned to service.
This test was repeated and completed successfully at TC-6.
The steam separator-dryer performance was evaluated during the test.
The 7.3 x 10 3X moisture carryover in the main steam compares favor-ably with the contract warranty value of 0.3%.
Data collected during operation of the offgas system did not provide a means of correlating activity flow rates to the indicated exposure rate on the offgas rad. monitors (both post and pretreatment).
The activity levels in the offgas system was too low to provide suffi-cient indication on the rad. monitors.
The HP/Chemistry Department has provided a means to continue this monitoring process for future correlation efforts.
LE 3-1 CHEMICAL AND RADIOCHEMICAL TEST RESULTS Test Condition Open Vessel
~Heate TC 1
TC 2 TC 3 TC 6 Reactor Thermal Power 2%
18K 45%
65%
100'X Reactor Water Conductivity, umho/cm
- Chloride, ppm Turbidity or Insolubles, ppm
- Silica, ppm
Iodine -133 (uCi/ml)
Filtrate - 2 Hr, cpm/ml Crud - 2 Hr, cpm/ml Condensate Conductivity, umho/cm
ppm
ppb Iron (Soluble),
ppb Dissolved 02, ppb 0.80 0.015 0.20 0.009 5E-3 1.89 0.015 0.0875
- 0. 67 0.080 0.79 1.68 0.24 0.015 0,009 0.52 0.012 9.7 1.2E-7 5.5E-6 1.1E3 7.8E1
- 0. 24
- 0. 015 22 0.096 1.0 150
- 0. 073 2.3 100 0.21 0.015 0.02 0.14 0.056 9.0 3.8E-7 2.6E-6 1.4E3 2.0E3 0.16 0.015
- 0. 81 0.092 1.5 20 0.06 0.81 20 1.48 0.015 0.75 0.280 0.010 220 5E-6 lE-4 8.4E3 2.8E3
- 0. 28
- 0. 015 20 0.083 4.1 50 0.087 12.2 40 0.79 0.018 0.20 0.77 0.010 115 1.0E-5 1.6E-4 8.0E3 1.8E3
- 0. 21
- 0. 015 844
- 0. 07 28.5 45 0.121 6.8 45
- 0. 47
- 0. 015 0.01 7 0.354 0.010 17.2 4.6E-6 7.6E-5 2.7E4 7.1E3 0.084 0.01 5 9.7 0.062 1.2 60 0,079 2.1 0.31 80
TABLE 3-2 HANFORD-2 NO-CLEANUP TEST AT TC-6:
DATA
SUMMARY
Reactor Data:
Power:
Core Flow:
Feedwa ter:
Reactor Pressure:
RMCU Flow:
Reactor Mater Level Reactor Temperature 3090, + 120 megawatt thermal (100%
= 3323 MwtT) 1.00 + 0.02 x 10 lb/hr 1.33 + 0.02 x 10 lb/hr 994 + 3 PS IG 8.42 x 10 lb/hr (rated at 1.34 x 10 lb/hr) 20.0 + 1.5 inches above reactor 520 + 3'F Results (Summary):
RWCU Half Life:
4.75 hr (predicted 4.9 hours1.041667e-4 days <br />0.0025 hours <br />1.488095e-5 weeks <br />3.4245e-6 months <br />, rated 3.1 hr)
Clean-up:
0.146 hr (predicted 0.141 hr
, rated, 0.224 hr
)
Dynamic Reactor Volume:
5.77 x 10 lbs (predicted 5.97 x 10
)
5 5
II Conductivity Increase:
0.056 umho/hr/cm Background Conductivity: 0.15 umho/cm Equilibrium Conducitvity:
0.480 umho/cm Clean-up Rate with RWCU Off:
0.032 hr Na Input Rate:
0.96 ppb/hr Cl Input Rate:
2.1 x 10 ppb/hr Na Concentration In Reactor:
6.5 ppb
+
Cl Concentration In Reactor:
0.15 ppb Na Concentration In Feedwater:
4.3 x 10 ppb Cl Concentration In Feedwater:
9.4 x 10, ppb I-133 Transport:
0.25%
I-131 Transport:
0.23%
% Carryover:
7.3 x 10 Neutron Flux:
Steam guality:
3.35 x 10 neutrons/cm /sec 99.993K 31
TABLE 3-3 OFFGAS ACTIVITY DATA AT 100%
POWER Plant Parameters Activity at SJAE (uCi/sec)
Activity at Post Filter (uCi/sec)
Offgas Flow (SCFM)
Pre-Treatment Radiation Monitor Post-Treatment Radiation Monitor Data 101
Background
6 mR/hr
'A'5 cpm
'B'3 cpm (60 to 90 cpm is background) 3;3 Test Number 2 - Radiation Measurements 3.3.1
~Pur ose The principle objectives of the radiation measurement test are as follows:
1.
To determine the background radiation levels in the plant environs prior to operation for use as baseline data for activity build-up.
2.
To monitor radiation at selected plant locations during initial power ascension and subsequent power operation to assure the protection of personnel.
3.
To provide sufficient data on exposure rate and dose equivalent rates to allow comparison of the actual dose rates with design dose rates throughout the plant.
3.3.1.1 Level 1 Criteria 3.3.1.2 3.3.2 The radiation doses of plant origin and the occupancy times of per-sonnel in radiation zones shall be controlled consistent with the guidelines of the standards for protection against radiation as out-lined in 10CFR20, NRC General Design Criteria.
Level 2 Criteria Not applicable.
Test Results 3.3.3 The maximum observed radiation measurements occurred at 100% power.
The points were R5-15 (Main Reactor Mater Cleanup Suction Isolation, above RMCU pump room),
and T2-2 (Column F6 8 E7, 471'le.) in which the readings were 1000 mR/hr and 800 mR/hr, respectively.
Discussion A complete standard survey of all designated locations was performed in the open vessel condi.tion to determine the background radiation levels in the plant environs prior to startup.
During the initial heatup and at 20, 50, 75 and 100% power, gamma dose rate, and where appropriate, neutron dose rate measurements were performed.
This established contamination buildup trends and identified areas of unexpected high radiation.
Several areas in the reactor building and one point in the turbine building had higher than desired gamma fields.
Administrative action was taken to limit access to those areas as defined in 10CFR20.
3.4 Test Number 3 - Fuel Loadin 3.4.1
~Per ese
~
~
The purpose of this test is to load fuel safely and efficiently to the full core size.
3.4.1.1 Level 1 Criteria The partially loaded
'core must be subcritical by at least 0.38'X delta k/k with the analytically strongest rod fully withdrawn.
3.4.1.2 Level 2 Criteria Non applicable.
3.4.2 Results 3.4.3 Partial core shutdown margin was demonstrated with 144 bundles loaded.
Minimum shutdown margin was 4.09% delta k/k with the analytically strongest rod fully withdrawn.
Discussion Fuel loading commenced with the loading of the first bundle at 0656 on 12/25/83.
Loading was completed 19 days later with the seating of the last of the 764 fuel bundles at 1700 on 1/12/84.
After the first 144 bundles had been loaded in a 12 x 12 array at the center of the core a partial core shutdown margin demonstration was suc-cessfully performed.
The test also verified that the shutdown mar-gin will be met throughout the loading process.
Control rod functional and subcriticality check were performed on all 185 control rods as each fuel cell was loaded.
After the core was fully loaded the seating, orientation and location of all bundles was verified to be correct.
Overall, the fuel load went smoothly taking a total of 446 hours0.00516 days <br />0.124 hours <br />7.374339e-4 weeks <br />1.69703e-4 months <br /> compared to the schedule of 367 hours0.00425 days <br />0.102 hours <br />6.068122e-4 weeks <br />1.396435e-4 months <br />, based on 50 bundles per day.
Table 3-4 lists the problems encountered that became critical path, adding up to a total of 115 hours0.00133 days <br />0.0319 hours <br />1.901455e-4 weeks <br />4.37575e-5 months <br />.
Most of the problems were of a mechanical or electrical nature involving either the refueling bridge or the neutron monitoring system.
TABLE 3-4 WNP-2 FUEL LOADING PROBLEM
SUMMARY
Page 1 of 2 DATE 8
OF HRS DELAY 12-25-83 40 12-27-83 PROBLEM DESCRIPTION Loss of refueling grapple "loaded" interlock.
Surveillance Test Pro-cedure inadequacy.
SRH "C" high and period alarm indi-cations on H13-P603 were inoperable.
RESOLUTION Recalibrated the load cell to account for the weight of the mast while sub-merged.
Revised Surveillance Test Procedure.
Miring change/correcti on required.
12-28-83 12-30-83 12-31-83 12 Refueling bridge interlock precluded bridge from moving over core.
Lost IRM "D" indication on P603 panel.
Problem was traced to a loose ground-ing wire in the drawer RWM became inoperable and haulted the partial shutdown margin demonstration.
Replaced damaged cable which lost continuity when over-stretched.
Restored IRM "D" by securing the grounded wire.
Reset by re-initiating the process computer.
12-31-83 01-01-84 Bundle LJT 422 had nick indication on the nose piece.
Further investigation revealed that it was acceptable.
FLC "C" cable hose clamp turned loose.
Secured the hose clamp.
01-02-84 01-03-84 The flexible drive shaft for the grapple was disassembled.
The newly installed pin on the flex-ible drive shaft was inspected and found to be moving out of coupling hold.
Examination discovered that a lock pin was missing.
A pin was installed.
Restored the pin with a clamp to hold the pin in place.
01-04-84 After 43% of core loaded, attempted to transfer FLC to SRM detector, but without success.
The neutron flux level was too low for SRM's to register acceptable count rate.
Decided to continue loading using with FLC's.
TA 3-4 MNP-2 FUEL LOADING PROBLEM
SUMMARY
Page 2 of 2 DATE 0 OF HRS DELAY 01-09-84 01-10-84 01-11-84 01-12-84 PROBLEM DESCRIPTION Refueling bridge power failed.
Refueling grapple slack cable inter-lock setpoint drifted.
SRM "A" failed to respond to neutron flux in the core.
Bundle LJT 795 would not go in.
Suspected fuel support casting was mi saligned.
RESOLUTION Power was restored.
Reset load switch setpoint and per-formed interlock check.
Replaced the detector and put SRM "A" in service.
Inspected the core bottom with under-water camera to clarify any suspected misalignment.
Successfully loaded the bundle by changing the cell load-ing sequence.
3.5 Test Number 4 - Full Core Shutdown Mar in 3.5.1
~Pur ose The purpose of this test is to demonstrate that the reactor will be subcritical throughout the first fuel cycle with any single control rod fully withdrawn.
3.5.1.1 Level 1 Criteria The shutdown margin of the fully. loaded, cold (68'F or 20'C), 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 reactivity equivalent) withdrawn. If the shutdown margin is measured at some time 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 which corrects the shutdown margin at that time to the minimum shutdown margin.
3.5.1.2 Level 2 Criteria Criticality should occur within +
1% delta k/k of the predicted critical.
3.5. 2, Results 3.5.3 The full core shutdown margin with the analytically strongest rod withdrawn was determined to be 2.716% delta k/k.
A 0.015% delta k/k difference was observed between the actual and theoretical critical eigenvalues.
All test criteria were satisfied.
Discussion The fully loaded core was made initially critical on 1/19/84 by withdrawing control rods in the B sequence.
A 750 second period was observed with Group 3 Rod 26-11 withdrawn to notch position 04.
The SRM/IRM overlap was verified and the shorting links installed to remove the reactor protection system out of the noncoincidence scram mode.
Later, the reactor was.again brought supercritical on 1/21/84 by withdrawing control rod 26-27 to position 08.
SRM measurements were taken to determine the reactor period.
The average period was found to be 96 seconds with moderator temperature at 85'F.
Actual core keff was then determined with the correction terms for period and moderator temperature.
II Figure 3-1 illustrates core reactivity with the analytically strongest rod fully withdrawn as a function of core average expo-sure.
The figure indicates an additional margin of 0.26'X delta k/k should be added to the 0.38% delta k/k criteria to obtain the required shutdown margin at the time of most reactive core.
- However, the measured shutdown margin has adequately satisfied the acceptance criteria.
CYCLE EXPOSURE {GWD/ST} CYCLE 1 COLD SHUTDOWN MARGtN VS. CORE AVERAGE EXPOSURE
.04
.96 hC
.02 r
0.0026
.97 hC Ill IL0V ClIll IVIll KK
.98 <V
.01 0
4 5
6 7
CYCLE EXPOSURE (GWD/ST)
.99 10 Figure 3-1 850207.9A
3.6 Test Number 5 - Control Rod Drive System 3.6.1
~Pur use The primary objectives of the control rod drive system tests are as follows:
1.
to demonstrate that the control rod drive system operates properly over the full range of primary coolant temperatures and pressures from ambient to operating; and 2.
to determine the initial operating ch'aracteristics of the entire CRD system.
3.6.1.1 Level 1 Criteria Each CRD must have a normal withdrawal speed less than or equal to 3.6 inches per second indicated by a fully 12 foot stroke in greater than or equal to 40 seconds.
The mean scram time of all operable CRDs with functioning accumu-lators must not exceed the following times:
(Scram time is measured from the time the pilot scram valve solenoids are de-energized).
Position Inserted From Full Withdrawn 45 39 25 05 Scram Time (Seconds)
- 0. 430 0.868 1.936 3.497 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 45 39 25 05 Scram Time (Seconds)
- 0. 455 0.920 2.052 3.706 The scram insertion time of each control rod from full out to posi-tion 5, based on de-energization of the scram pilot valve solenoi ds as time zero, shall not exceed 7.0 seconds.
3.6.1.2 Level 2 Criteria Each CRD must have a normal insertion or withdrawal speed of 3.0 +
0.6 inches per second indicated by a full 12-foot stroke in 40 to 60 seconds.
Mith respect to the CRD friction tests, if the differential pressure variation exceeds 15 psid for a continuous drive in, a settling test must be performed, in which case, the differential setting pressure should not be less than 30 psid nor should it vary more than 10 psid over a full stroke.
Lower differential pressures are indicative of excessive friction.
3.6.2 Test Results 3.6.3 A summary of the single rod scram tests conducted during open vessel and heatup test phases is presented in Table 3-5.
Table 3-6 presents a summary of measured scram times of the four CRDs selected during heatup testing to be monitored in conjunction with planned reactor scrams.
Discussion During and after fuel loading all 185 CRDs were functionally and scram tested.
Normal withdraw/insert times were found to range from 40 to 57 seconds.
Each CRD was friction tested with the maximum variation observed for the entire stroke length equal to 13 psid.
During heatup CRDs selected on the basis of previously demonstrated slow scram or functional speeds were scram tested to confirm that no significant binding from thermal expansion of the core components occurred.
In addition, the scram speeds of selected CRDs were moni-tored for measurable changes during the course of the Startup Test Program.
No significant change in operating characteristics of the CRD system was observed indicating proper system performance.
Table 3-5 CRD SCRAM TIME MEASUREMENT
SUMMARY
Reactor Pressure Accumulator Pressure Mean Time to Notch Position:
0.0 si 600 si Pslg Pslg 800 si Psl 9 960 si Psl g 45 39 25 05 Number of Rods Tested 0.26 sec 0.44 sec 0.90 sec 1.64 sec 185 0.287 sec 0.537 sec 1.239 sec 2.586 sec 0.294 sec 0.653 sec 1.530 sec 2.627 sec 0.276 sec 0.608 sec 1.413 sec 2.545 sec 185 0.292 sec 0.613 sec 1.367 sec 2.600 sec Table 3-6 CRD SCRAM TIMES FROM POWER Reactor Power (MWt)%
Reactor Pressure (psi g)
Date Performed 957(29%)
2226(67%)
3227(97'X) 31 83(96%)
909 963 980 1001 9/7/84 10/1/84 11/10/84, 12/2/84 Mean Time to Notch Position (Sec) 45 39 25 05 0.290 0.612 1.347 2.503
- 0. 304 0.604 1.322 2.421
- 0. 230 0.518 1.210 2.277
- 0. 323 0.623 1.373 2.490 Number of Rods Tested Initiating Event 4
4 ST I-27GLR ST I-27TT ST I-25MS IV 4
ST I-27GRL GRL = Generator Load Rejection TT
= Main Turbine Trip
- 41
3.7 Test Number 6 - Source Ran e Monitor Performance and Control Rod rawa e uence
~Pur ese The major objective of this test is to demonstrate that the opera-tional sources, SRM instrumentation, and rod withdrawal sequences provide adequate information to achieve criticality and increase power in a safe and efficient manner.
3.7.1.1 Level 1 Criteria There must be a neutron signal count-to-noi se count ratio of at least 2:1 on the required operable SRMs.
There must be a minimum count of 1/2 counts/second on the required operable SRMs.
The IRMs must be on scale before the SRMs exceed their rod block setpints.
3.7.1.2 Level 2 Criteria 3.7.2 Not applicable Test Results Source range monitor performance during fuel loading is summarized in Table 3-7.
Initial SRM trip points were 1
x 104 and 5 x 104 cps for the rod block and scram functions.
Following a nonsatura-tion demonstration above 7.5 x 105 cps, the setpoints were raised to 1
x 105 cps and 2 x 105 cps, respectively.
Table 3-7 SRM PERFORMANCE Parameter SRM A SRM B
SRM C
SRM D
Pre-Amp Gain:
Discriminator Setting(Y):
High Voltage Setting(V):
Count Rate in Core (CPS):
Signal-to-Noise Ratio:
1 7.5 350 25 249 1
8 375 33 164 1
7.5 375 70 466 1
8 350 20 104 See Test Number 10 for results to verify adequate SRM to IRM overlap.
3.7.3 Discussion Proper SRM performance was confirmed during fuel loading through the initial criticality.
During the initial criticality SRM D was found to be failed.
Examination of the SRM revealed a failure in the con-nection between the detector cable and the detector mechanism caused by excessive vibration during the insertion and withdrawal of the detector.
Necessary adjustments of the drive mechanism were made to preclude recurrence.
The control rod withdrawal sequences were monitored through gener-ator synchronization to about 45% rated power.
The withdrawal sequences utilized the Banked Position Withdrawal (BPW) method in order to minimize individual control rod worth as well as notch worth.
Adherence to BPW during control rod withdrawal assures com-pliance wi,th rod drop accident constraints.
For the data obtained through 45% power, some minor modifications to the withdrawal sequences were made.
This was done to minimize core total peaking factor during power ascension.
3.8 Test Number 10 -
IRM Performance 3.8.1
~Per ose The purpose of this test is to adjust the Intermediate Range Monitor System to obtain an optimum overlap with the SRM and APRM systems.
3.8.1.1 Level 1 Criteria 3.8.1.2 Each IRM channel must be on scale before the SRMs exceed their rod block setpoint.
Each APRM must be on scale before the IRMs exceed their rod block setpoint.
Level 2 Criteria 3.8.2 3.8.3'ach IRM channel must be adjusted so that a half decade overlap with the SRMs and one decade overlap with the APRMs are assured.
Test Results Test data on IRM-SRM and IRM-APRM overlap is presented in Table 3-8.
The IRMs were verified to indicate approximately 100 on range 10 at approximately 40% thermal power.
Discussion The IRM system was adjusted to provide adequate overlap with both the SRM and APRM systems.
Range 6-7 correlation was established to verify proper adjustment of detector preamplifier gain during the initial heatup.
A verification of the IRM indications with reactor powe~ was provided so that the operator could estimate reactor power when operating in the intermediate neutron range.
The calibration is strongly dependent upon rod pattern and power distribution but is
- sufficiently accurate for this purpose.
Table 3-8 IRM PERFORMANCE DATA IRM/SRM OVERLAP VERIFICATION IRM Detector Reading.
Range 65 2
D E
F 50 55 65 2
2 2
50 2
55 2
SRM Detector A '
C D
Reading (CPS) 6xl04 7xl04 2xl04 3xl04 IRM Detector Reading Range A
8 17.5 12 10 9
IRM/APRM OVERLAP VERIFICATION C
D E
F 22 22 22 24 10 10 10 10 17 9
- 19. 5 9
APRM A
8 C
D E
F Reading
(%)
7.0 5.2 7.0 4.0 5.2 5.2 IRM Detector A
Reading-Range 6
50 Reading-Range 7
5 IRM RANGE CORRELATION VERIFICATION C
D E
F 90 66 65 99 9.3 6.5 6.5 10 G
H 62 65 6.2 6.7 Reading Range 104 93 '00 102 100 107 10 10 10 10 10 10 Rx Thecal Power (X,)
39.35 IRM/THERMAL POWER CALIBRATION IRM Detector A
B C
D E
F G
H 100 100 10 10 3.9 Test Number 11 -
LPRM Calibration 3.9.1
~Pur ose The major objectives of this test are as follows:
l.
Verify proper response of the Local Range Power Monitoring (LPRM) System to local changes in the reactor power level.
2.
Calibrate the LPRM system.
3.9.1.1 Level 1 Criteria Not applicable 3.9.1.2 Level 2 Criteria 3.9.2 Each LPRM reading will be within + 10'X of its calculated
- value, as determined by a process computer or offline calculation from Tr a-versing Incore Probe power distribution data.
Test Results 3.9.3 Initial LPRM calibration currents were established at 400 uA.
Fol-lowing the first core power distribution calcualtion, LPRM gain ad-justment factors (GAFs) 'ranged from 0.34 to 0.76.
With a complete LPRM gain adjustment and subsequent recalibration the LPRM GAFs ranged from 0.79 to 3.02.
Further attempts at LPRM calibration were postponed until higher reactor power levels were reached, at which time all LPRM GAFs were brought within the desired 0.90-1.10 range'.
Discussion LPRM operability and correct location response were confirmed during heatup by observing individual indications as adjacent control rods were moved.
Prior to the verification of the process computer calculations, the GE Mark III computer
- program, BUGLE, was used to perform the LPRM calibration.
At a reactor power of 42'X rated, all LPRM GAFs were adjusted to between 0.90 and 1.10.,
3.10 Test Number 12 - APRM Calibration 3.10.1
~Per ose The purpose of this test is to calibrate the Average Power Range Monitor System.
3.10.1.1 Level 1 Criteria The APRM channels must be calibrated to read equal to or greater than the actual-core thermal power.
Technical Specification limits on APRM scram and rod block shall not be exceeded.
In the startup mode, all APRM channels must produce a scram at less than or equal to 15K of rated thermal power.
3.10.1.2 Level 2 Criteria If the above criteria are satisfied then the APRM channels will be considered to be reading accurately if they agree with the heat bal-ance or the minimum value required based on peaking factor MLHGR, and fraction of rated power to within (+7, -0)% of rated power.
3.10.2 Results 3.10.3 During the initial heatup, with a constant heatup rate of 55'F/hr and a reactor heat capacity of 0.35 MWt Hr/'F the preliminary core thermal power was calculated to be 24.85 MWt, 0.75'5 of rated power.
All APRM's were adjusted to read between 1.8 and 2.3 times higher than real power.
When power level was increased to a point where an accurate manual heat balance could be performed, the APRM's were recalibrated to provide accurate thermal power indications.
After the process computer was verified to be functional, the APRM's were adjusted to indicate the actual thermal power as determined by the process computer heat balance program OD-3.
Di scussion Throughout the Startup Test Program technical specification compli-ance for APRM, SCRAM and Rod Block setpoints was obtained by adjust-ment to the APRM outputs, so that the gain adjustment factor (GAF) was always equal to or less than the 'T'actor.
The 'T'actor is a ratio of fraction of rated thermal power (FRTP) divided by the maximum fraction of limiting power density (MFLPD).
In addition, the APRM scram clamp was maintained at nominally 20K above the test plateau power level.
These efforts ensured safe plant operation during the test program.
s s
3.11 Test Number 13 - Process Com uter 3.11.1
~Per ese The major objective of this test is to verify the performance of the process computer under plant operating conditions.
3.11.1.1 Level 1 Criteria Not applicable 3.11.1.2 Level 2 Criteria Programs OD-l, Pl and OD-5 will"be considered operational when:
The MCPR calculated by Back, Up Core Limits Evaluation (BUGLE) and the process computer either:
1.
Are in the same fuel assembly and do not differ in value by more than 2% or 2.
For the case in which the MCPR calculated by the process com-puter is in a different assembly than that calculated by BUCLE, for each
The maximum LHGR calculated by BUGLE and the process computer either:
1.
Are in the same fuel assembly and do not differ in value more than 2% or 2.
For the case in which the maximum LHGR calculated by the pro-cess computer is in a different assembly than that calculated by BUCLE, for each
The MAPLHGR calculated by BUGLE and the process computer either:
l.
Are in the same fuel assembly and do not differ in value by more than 2% or 2.
For the case in which the MAPLHGR calculated by the process computer is in a different assembly than that calculated by BUGLE, for each assembly the MAPLHGR and MAPLHGR calculated by the two (2) methods shall agree within 2%.
The LPRM gain adjustment factors calculated by BUGLE and the process computer agree to within two percent (2%).
The remaining programs will be considered operational upon success-ful completion of static and dynamic testing.
3.11.2 Test Resul ts Initial TIP alignment and computer interface parameters were ad-justed such that the difference between the physical top of the TIP detector and the top of the TIP tubing was 2 inches
( I Turn), core bottom was established 141 inches below core top and the interface parameter
( I Tube) was set to 3 inches.
During heatup, proper alignment was confirmed by observing correspondence of spacer-induced flux dips with correct physical dimensions.
Proper opera-tion of the TIP-process computer interface was confirmed by compar-ing TIP X-Y recorder traces with OD-1 edits.
The process computer dynamic system test case was performed at 42%
rated power and verified power di stribution, exposure accounting, and thermal limits calculations.
Subsidiary programs were verified throughout the remai nder of the startup.
A comparison between the process computer and BUCLE calculations of important parameters is presented in Table 3-9.
3.11.3 Discussion Detailed verification of all process computer functions was per-formed to ensure proper operation of the system.
Power distribu-tion, exposure accounting, and thermal limits calcualtions were con-firmed by comparison with both manual calculations and BUGLE results using identical inputs.
These checks displayed excellent agree-ment.
At the conclusion of the Startup Test Program the process computer was completely verified and operational.
Table 3-9:
PROCESS COMPUTER Parameter MCPR MLHGR (kW/Ft)
Location 25-42 24-42-4 40% Power B
Value Value
% Deviationa 2.960 2.961
-0.03 5.72 5.72 0.0 Location 47-16 47-16-5
- 1. 578 1.572
+0.38 12.15 12.20
-0.41 98'X Power Value Value X Deviation MAPLHGR (Kw/Ft)
PBUH (Mw) 25-42-4 25-42
'.00 2.44 4.94 2.44
+0.20 0.0 47-16-5 47-16 10.26 10.71 5.306 5.324
-0.37
-0.34 W
(MLb/Hr LPRN GAF I
25-42 24-41-D 0.98 0.98 0.0689 0.0688
+0.15 0.0 47-16 48-17-D 1.68 1.70 0.1282 0.1284
-0.016
+1.2 D
P.C. - BUGLE
3.12 Test Number 14 - RCIC S stem 3'.12.1
~Pur ose The purpose of this test is to verify the proper operation of the Reactor Core Isolation Cooling (RCIC) System over its expected oper-ating pressure range.
3.12.1.1 Level 1 Criteria The average pump discharge flow must be equal to or greater than 600 gpm'after thirty seconds have elapsed from automatic initiation at any reactor pressure between 150 psig and rated.
The RCIC turbine must not trip off or isolate during auto or manual start tests.
If any Level 1 criteria are not met, the reactor operation will be restricted to the power level defined by WNP-2 FSAR Figure 14.2-5.
This restriction is in addition to any restrictions defined by the Technical Specification.
3.12.1.2 Level 2 Criteria The Turbine Gland Seal Condenser System shall be capable of prevent-ing steam leakage to the atmosphere.
The differential pressure switch for the RCIC steam supply line high flow isolation trip shall be adjusted to actuate at the value speci-fied in Plant Technical Specification (about 300%).
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.
In order to provide an overspeed trip avoidance margin, the tran-sient start first and subsequent speed peaks shall not exceed 5%
above the rated RCIC turbine speed.
3.12.2 Test Results The RCIC system performance of five (5) cold quick start tests is summarized in Table 3-10.
The final controller settings which were acceptable at all test pressures are shown in Table 3-11.
The RCIC Turbine Gland Seal Condenser System capability of preventing steam leakage to the atmosphere was verified by observation and detection of the leak detection system in the RCIC equipment room.
Extended operation of up to 30 minutes at rated flow conditions was demon-strated to ensure the adequacy of the turbine oil cooling system to maintain a stabilized oil temperature during such operation.
Auto-matic transfer of pump suction from condensate storage tank to sup-pression pool upon CST low level was also demonstrated at rated pump discharge flow.
The RCIC steam supply line high flow isolation trip setpoi nts were determned to be 225.05 inch of water, equivalent to 300'X of the maximum steady state steam flow.
- However, the actual setpoi nts were adjusted to be less than 290% steam flow to include the allowance for instrumentation drift and calibration accuracy.
3.12.3 Discussion The problems encountered during the RCIC system testing involved several turbine trips on overspeed and high exhaust pressure.
The overspeed trip problem was found to be caused by a ground fault of a lead connection at the EGR actuator.
The grounding of the EGR coil, resulting in a demand input voltage drop from 9 volts to 7.5 volts, slowed down the response of the turbine governor valve and caused the turbine overspeed trip.
This problem was resolved with proper wiring of the EGR coil lead.
The high turbine exhaust pressure was caused by the malfunctioning of two drain lines.
The exhaust line drain was found plugged upstream of the trap by debris.
The other condensate drain upstream of steam admission valve was not function-ing due to a collapsed float in the steam supply drain pot.
It was discovered that an incorrect level switch had been installed.
A 1200 psi rated Magnetrol level switch was installed for the drain pot.
The consequence of accumulation of condensate in the steam supply line without proper drainage resulted in excessive exhaust pressure causing the trip.
Upon fixing both drain line problems, cold and hot quick start tests of the RCIC system were successfully performed.
The RCIC pump discharge flow exhibited a peak-to-peak limiting cycle of 200 GPM during low flow operation (below 400 GPM pump discharge flow) with remote shutdown panel flow controller (C51-R600) in con-trol.
'Since the controller has been tuned for an optimal perform-ance at rated flow condition where the RCIC system is normally oper-ated, this deviation will not adversely affect the actual RCIC sys-tem operation and is considered to be acceptable.
The RCIC pump performance at rated flow was verified under all required operating conditions as indicated by the data in Table 3-10.
51
T 3-10
SUMMARY
OF RCIC COLD (}UICK START TEST COLD START NO.
TEST MODE Date Performed Reactor Pressure (PSIG)
CST to RPV 05/16/84 930 CST to RPV (RSP) 06/02/84 950 07/01/84 155 07/05/84 928 07/09/84 928 CST to CST CST to CST CST to CST Time to Rated Flow (SEC)
(Limit Less Than or equal to 30 sec)
Turbine Speed (RPM)
Peak Steady Pump Discharge Pressure (PSIG)
Pump Suction Pressure (PSIG)
Pump Discharge Flow (GPM)
(Limit Greater Than or equal to 600 GPM) 20 4333 4250 1030 17 617 22 4458 4250 1043 20 600 20 2400 2400 250 17 655 18.5 4500 4300 1050 20 610 19 4650 4580 1200 18 600
TABLE 3-11
SUMMARY
OF RCIC SYSTEM CONTROL SETTINGS RCIC Flow Controller E51-R600 (control room)
Gain Resets/min DIAL
.08 40 ACTUAI
. 083 27.9 RCIC Flow Controller C61-R601 (RSP)
Gain Resets/min
.083 30
.083 27.9 Woodward EGM Controller Gain Stability Idle Voltage 10 9
-0.9 10 9
-0.9 EGR Actuator Needle Valve (turns) 3/4 3/4 3.13 Test Number 16A - Selected Process Tem eratures 3.13.1
~
~
~Per ose The purposes of this test are to
- 1) assure that the measured bottom head drain temperature corresponds to bottom head coolant tempera-ture during normal operations,
- 2) identify any reactor operating modes that cause temperature stratification,
- 3) determine the
. proper setting of the low flow control limiter for the recirculation pumps to avoid coolant temperature stratification in the reactor pressure vessel bottom head region,
- 4) familiarize the plant per-sonnel with the temperature differential limitations of the reactor system.
Level 1 Criteria The reactor recirculation pumps shall not be started nor flow in-creased unless the coolant temperatures between the steam dome and bottom head drain are within 145'F.
3.13.1. 2 The recirculation pump in an idle loop must not be started, active loop flow must not be raised and power must not be increased unless the idle loop suction temperature is within 50 F of the active loop suction temperature.
If two pumps are idle, the loop suction temp-erature must be within 50 F of the steam dome temperature before pump startup.
Level 2 Criteria 3.13.2 During two pump operation at rated core flow, the bottom head temp-erature as measured by the bottom drain line thermocouple should be within 30'F (17 C) of the recirculation loop temperatures.
Test Results At rated pressure and temperature the test was performed for both two-pump and single RRC pump operation.
First the FCV's were decreased to their minimum positions resulting in a maximum tempera-ture differential between steam dome and bottom head drain of 48'F for two-pump operation and 59 F for single loop operation.
Next the RMCU flow was decreased from 270 GPM to 93 GPM for two-pump opera-tion and 270 GPM to 115 GPM for single pump operation, resulting in a maximum temperature differential of 82'F and 92'F respectively.
The CRD flow was then increased from 64 GPM to 76 GPM for two-pump operation and 60 GPM to 75 GPM for single-pump operation, resulting in a maximum temperature differential of 100'F and 104 F
respectively.
Table 3-12 presents the selected temperature measurement results during the steady state operation throughout the test program and following one-pump and two-pump trips at various power levels.
Discussion The.vessel temperature measurement data indicated that no antici-pated operating condition such as subcooling change or pump trip exists in which Technical Specification limits on reactor tempera-ture are likely to be exceeded.
All data confirmed that the vessel temperature differentials are within acceptable limits.
TABLE 3-12 SUWRY OF SELECTED PROCESS TEHPERATURE MEASUREHENT Test Condition Test Hode Recirculation Pump Speed (Hz)
Heatup 1
2 3
3 3
Steady Steady Steady Steady One Pump Two Trip Steady State Steady One Pump Stats
~Tsl 4
6 6
Pump A Pump 8 Recirculation Loop Suction Temperature
( F)
Loop A Loop 8 Reactor Bottom Head Drain Temperature Reactor Steam Dome Saturation Temperature T, Saturated Steam - Bottom Head Drain T, Recirculation Loop Suction - Bottom Head Drain 15 15 530 535 515 540 25 15 15 520 520 500 538 38 18 60 60 520 519 538 18 60 60 530 530 515 542 27 12 60 0
520 520 510 540 30 10 15 15 518 518 501 539 38 17 509 508 593 537 44 16 60 60 530 530 518 544 26 12 0
60 517 515 507 541 34 10
3.14 Test Number 16B - Water Level Reference Le Tem erature Measurement 3.14.1
~Per oee The purpose of this, test is to measure the reference leg temperature and recalibrate the affected level instruments if the measured temp-erature is different than the value assumed during the initial cali-bration.
3.14.1.1 Level 1 Criteria I
Not applicable 3.14.1.2 Level 2 Criteria The indicator readings on the narrow range level system should agree within + 1.5 inches of the average readings or the reading calc-ulated 7rom the correct reference leg temperatures.
The wide and upset range level system indicators should agree within 6 inches, of the average readings or the readings calculated from
%e correct reference leg temperatures.
3.14.2 Test Results 3.14.3 The Reference Leg Temperature Measurement data indicated that the actual temperatures of drywell and reactor building were in good agreement with the initial calibration assumptions, thus no adjust-ment of calibration settings is necessary.
Table 3-13 summarized the water level measurements throughout the test program.
Discussion At rated temperature and pressure the reference leg temperature of the wide range and narrow range instruments was verified to be con-sistent with the value assumed for initial calibration.
Level indi-cations were recorded during steady state operation at each test condition throughout the test program.
Minor adjustment of the level instruments to their calibration settings was required to ensure proper indication for compliance with the acceptance criteria.
The water level measurement data indicates that the variation between narrow range and wide range level was a function of core flow and reactor power.
The wide range level indication deviation from the narrow range level indication increases with increasing core flow on a constant rod line as well as increasing power on a
constant flow line.
These phenomena were well explained as being caused by the jet pump velocity effect and the subcooling change in the vicinity of the instrument tap for the wide range level instru-mentation and is typical of similar BWR's.
At 100% power and core flow, the wide range water level indication was 16 inches below that indicated by the narrow range level instrument.
ABLE 3-13
SUMMARY
OF WATER LEVEL MEASUREMENT Test Condition Heatu 1
2 3
5 6
Reactor Power
('X)
Core Flow (X)
Reactor Pressure (PSIG)
Feedwater Temperature
('F)
Core Subcooling (BTU/LB)
Average Drywell Temperature
('F)
Average Reactor Building Temperature
('F)
Average Wide Range Level (In.)
Average Narrow Range Level
( In.)
33.1 35.6 34.1 35,9 4.6 16 26 33 965 934 78 90 5
18
- 99. 7 110. 7 72.5 74 40 41 922 332 27 120 90 31.8
- 34. 9 65 87 950 373 16 126
- 88. 9 22.1
- 35. 7 37.4 36.5 30.6 36.1 19.3 35.3 40 72 99 28 55 98 947 966 978 330 380 410 38 36.5 18.7 121 121.5 131.7 76 74
3.15 Test Number 17 - System Ex ansion 3.15.1 3.15.1.1
~Per ese The purpose of this test is to
- 1) verify that piping systems and components that are unrestrained with respect to thermal expansion,
- 2) verify that suspension components are functioning in the speci-fied manner,
- 3) provide confirmatory data for the calculated stress levels in nozzles and weldments,
- 4) perform in inspection to sat-isfy ASME Section XI, IMF-220 post heatup (shakedown) inspection requirements, and
- 5) satisfy the inspection requirements for the condensate and feedwater systems per Regulation Guide 1.68.1.
Level 1 Criteria Thermally induced displacement of system components shall be un-restrained, with no evidence of binding or impairment.
Spring hangers shall not be bottomed out or have the spring fully stretched.
Snubbers shall not reach the limits of their travel.
The displace-ments at the established transducer locations used to measure pipe deflections shall not exceed the allowable values.
The allowable values of displacement shall be based on not exceeding ASME Section III Code stress allowables.
3.15.1.2 Level 2 Criteria 3.15.2 Spring hangers will be in their operati'ng range (between the hot and cold settings).
Snubber settings must be within their expected operating range.
The displacements at the established transducer locations shall not exceed the expected values.
Test Results The visual inspection of the drywell piping of NSSS and the auxili-ary system was conducted prior to heatup, at an intermediate temp-erature of 250'F and rated temperature during initial heatup, and following a reactor shutdowh after a minimum of 3 thermal cycles.
These walkdowns have verified that the selected drywell piping sys-tems and components are unrestrained with respect to thermal expan-sion.
Each pipe whip restraint was verified to have sufficient clearance and final torqueing of the holddown bolts was completed following clearance verification.
In addition, the RPV stabilizer clearances were properly adjusted for the relative growth between the vessel bracket and the stabilizer yoke.
During the initial heatup and the following thermal cycle, displace-ment of the instrumented piping systems were monitored to confirm that the pipe suspension is working as designed and that the pipe is free of obstructions.
These movements are summarized in Table 3-14 and 3-15.
Discussion The drywell inspection performed during the initial heatup revealed piping interferences on HPCS and feedwater piping.
Heatup testing was held until the identified interference problems were rectified.
No further evidence of blockage or, binding of the piping was observed during the subsequent inspections.
The settings on the pipe supports (both snubber and hanger) were recorded at cold and rated conditions to en0ure the proper operation of the pipe suspen-sion systems.
In some instances piping displacements from instrumented locations exceeded the Level 2 limits.
Data of the criteria failures were reviewed and evaluated to be acceptable by GE piping engineering and Supply System engineering.
Piping movements after several thermal cycles were found to be consistent in both magnitude and direction with the movement as measured during the initial heatup.
Only a modest number of Level 2 violations were recorded through all phases of the thermal expansion tests and no Level 1 violations were found.
As defined by PPM 8.2.17, a Level 2 violation is a low level deviation from anticipated test'criteria which requires the test engineer's investigation and rationalization.
A Level 2 violation does not involve an overstress condition, whereas a Level 1 viola-tion may involve exceedance of ASME allowable stress limits.
In the case of thermal expansion, a Level 1 violation typically results from support system binding or other interference to system expan-sion.
As an example, Level 2 thermal expansion deviations were typically resolved by comparison of the actual system temperatures versus the conservative upper bound temperatures assumed by the A/E for his piping design calculations.
In all cases, an acceptable physical rationalization of the Level 2 violations has been pro-vided.
In. summary, it is concluded that the PAT program has demon-strated that all visually inspected and remotely monitored piping systems are responding in an acceptable manner to thermal loads as predicted by the A/E and GE.
Visual inspections, consisting of pipe walkdowns by VT-384 qualified inspectors, were performed on the hot piping systems identified out-side the drywell to ensure unrestrained thermal growth.
The systems inspected are as follows:
l.
2.
3.
5.
Main Steam Including MSLC Feedwater and Portions of Condensate RWCU RHR Shutdown Cooling Supply and Return RCIC Steam Supply The inspections were successfully performed providing acceptable results.
Copies of all the visual inspections performed have been sent to the NRC as part of the PSI program report.
TABLE 3-14 DRYWELL PIPING THERMAL EXPANSION DATA SHEET System Reactor Recirc Loop A Data Point 1RA X 1RA Y 1RA Z Baseline (ambient)
-.007
- .ITI Int. (200 to 300'F)
-.052 Int.
(400 to 500'F)
-.180 At 100'X Power Values
~ 2
=.Ul 1000'F Rated+
(545'F)
-.225
~08 2RA X (Reference only, 2RA Y to check RPV 2RA Z expansion) 3RA X(E-W) 3RA Y 3RA Z(N-S) 4RA.X 4RA Y 4RA Z
-.022
+. ++
+. 009
-.tm4
+.++
-.006
- .070
+.137
=.ITI
+.148
- .045
-.171
- .007
+.369
- .05l
+.416
-. 523
=.003
+.32
+.38
=.09
- .05
-. 46
+. 448
- .353
=.054
+. 508
- .TUU
+. ++)
-.629
+++
Reactor Recirc Loop B
Main Steam Loop A (For Reference only to check RPV expansion) 1RB X
1RB Y
1RB Z 2RB X
2RB Y
~ 2RB Z 3RB X(E-W) 3RB Y
3RB Z(N-S) 4RB X(E-W) 4RB Y
4RB Z(N-S) 1MSA X(E-W) 1MSA Y 1MSA X(N-S) 2MSA X 2MSA Y 2MSA Z
-. 001
+++I
-.005
- .UTO
-. 006
- .003
- .006
+. 005
- .UUI
-. 002041.
-. 002
- .080
+.++
+.071
=;r86
-.178
.877-
-.168
- .048
+.037
. UUU
+."040
+++
-.084
+++
+.157
=.76l
-.522
=.8T8
-. 462
- .0l74
+.113
+++
+.195
+++
-.174
+. ++
+.18
,Dmp
- .03
-. 42
- .45
- .U4
-. 43
=.r5
+.03
- .01
+47 N/A N/A
~NA
+.181
- .884
- .038
-. 612
+. ++
-. 548
- .Ogl
=.f85
+.145
+.++
+++)
+.21 7
+++
-.189
+++
NOTE:
Di splacements shown are in inches.
- 61
TABLE 3-14 (Contd) eIe Main Steam Loop B
Main Steam Loop C
Main Steam Loop D
Data Point 1MSB X
1MSB Y
1MSB X
2MSB X
2MSB Y
2MSB Z
1MSC X
1MSC Y
1MSC X
2MSC X(E-W) 2MSC Y
2MSC Z(N-S) 1MSD X
1MSD Y 1MSD X
2MSD X 2MSD Y
2MSD Z Baseline (ambient)
-.001
+++
+.002
+.++
-. 016
- .UIIH
-.023
- .mI7
-.131
- .mII
-. 001
- .GH2 Int.
(200 to 300'F)
-.104
++. ++
+.120
+++
-.299
+++
+. 001
+, ++
B
-.310
+++
- .622
-.113
+. ++
Int.
(400 to 500'F)
-. 367
+, 2++
+. ++
+. 355
+++I
=.T67
-.707
+, ++I
-. 009
+II+
-.705
++. II+
-. 206
+. ++
At 100'X Power Values N/A
~NA H7A N/A H7A HTA N/A H7A N/A II7A N/A HTA HTA N/A II7A IVX 1000'F Rated+
(545'F)
-.461
+. 331
+.II+
+. 411
-.806 eII
+. 005
+, ++
-. 814
+++I
-. 255
+. ++
NOTE:
Displacements shown are in inches.
e Table 3-15 DRYWELL PIPING THERMAL EXPANSION DATA SHEET System Data Point Basel ine Intermediate Rated (ambient) 25% Power)
(100% Power)
Feedwa ter Line A H. Feedwater Line A 1FWA X(E-W) 1FWA Y 1FWA Z(N-S) 2FWA X 2FWA Y 2FMA Z 1FMB X(E-W) 1FMB Y, 1FWB Z(N-S) 2FWB X(E-W) 2FWB Y
2FWB Z(N-S)
.+.003
+. ++
-.036
- .m7
+++)
+.240
-. 345
+. 41
-.90 Intermediate data F/W Temp. 300'F Rated data F/M Temp. 413'F NOTE:
Feedwater piping will reach rated temperature only when at rated reactor power.
The intermediate temperature levels will be at.25K power testing during T/C 2 and'ated at 100% power during T/C 6.
System I. Shortest SRV Discharge Pipe (1B)
Longest SRV Discharge Pipe'(3C)
K. RCIC Steam Supply (150 psig/366 F
for Immediate Data)
L. Reactor Water Cleanup Data Point lSRV X(E-M) 1SRV Y
1SRV Z(N-S) 2SRV X(E-M) 2SRV Y
2SRV Z(N-S) 1RCIC X
1RCIC Y
1RCIC Z RWCU X(E-W)
RWCU Y
RMCU Z(N-S)
Baseline (ambient)
+. 003
+++
-.013
+++
+.001
- .%7
+.003
=.aaa
+.++
Intermediate (200 to 300'F)
-. 059
-.053
-.025
+.050 Rated (545'F)
-.266
+.0~
+. 006
~.31m
-.045
+.I
+.305
- .m2 t1.
RHR Shutdown 1RHR X(E-W)
Cooling System 1RHR Y
(Suction) 1RHR Z(N-S)
+.014
-.012
+. ++
+. 038
-.110
+.193
-.386
- .T89 N.
RHR Return (A Loop) 2RHR X(E-W) 2RHR Y
2RHR Z(N-S)
+.007
- .rsa
+.108
+.293 3.16 Test Number 18 - Core Power Distribution e
3.16.1
~Per ose The major objectives of th'.s test are as follows:
1.
To confirm the reproducibility of the Traversing In-Core Probe (TIP) system readings.
2.
To determine the core power distribution in three dimensions.
3.16.1.1 Level 1 Criteria Not applicable 3.16.1.2 Level 2 Criteria The total TIP uncertainty (including random noise and geometric un-certainties) obtained by averaging the uncertainties for all data sets must be less than 6X.
NOTE:
A minimum of two and a maximum of six data sets may be used to meet the above criteria.
3.16.2 Test Results At both 72% and 98'X power the core power distributions in sequence A
were symmetrical.
Bundle powers from symmetrical locations were comparable.
A summary of the TIP uncertainty analysis performed at 72% and 98%
power is presented in Table 3-16.
TABLE 3-16
SUMMARY
OF TIP UNCERTAINTY ANALYSIS RESULTS Parameter Total TIP Uncertainty 3.20%
Random Noise Component 1.42%
Geometric Component 2.87%
RESULTS 2.30%
1.43%
1.80%
Avg.
- 2. 75%
- 1. 43%
2.34%
Level 2
Criteria 6.0%
3.16.3 Discussion The random hoise'component of total TIP uncertainty was determined by calculating the standard deviation of six sets of common channel traverses on each of five TIP machines at 72% power and five sets of common channel traverses on each of five TIP machines at '98% power.
The total TIP uncertainty was calculated by computing the standard deviation of 19 sets of symmetric pair ratios from a complete core scan.
The geometrical component was determined from the measured data given that total TIP uncertainty is the statistical sum of the random noise and geometric components.
3.17 Test Number 19 - Core Performance 3.17.1
~Pur oee The major objectives of this test are as follows:
1.
to evaluate core thermal power and flow rate; and 2.
to evaluate the following core performance parameters:
MLHGR-Maximum Linear Heat Generation Rate MCPR-Minimum Critical Power Ratio MAPLHGR-Maximum Average Planar Linear Heat Generation Rate 3.17.1.1 Level 1 Criteria The Maximum Linear Heat Generation Rate (MLHGR) of any rod during steady state conditions shall not exceed 13.4 Kw/ft.
The steady state Minimum Critical Power Ratio (MCPR) shall be equal to or greater than the MCPR limit times the kf factor determined from Figure 3.2.3-1 in the WNP-2 Technical Specifications with MCPR limit equal to 1.24.
All Average Planar Linear Heat Generation Rates (APL'HGRs) for each type of fuel as a function of Average Planar Exposure shall not exceed the limits shown in Figures 3.2.1-1, 3.2.1-2 and 3.2-1.3 in the WNP-2 Technical Specifications.
Steady state reactor power shall be limited to 3323 MWt and values on or below the analyzed flow control line.
3.17.1.2 Level 2 Criteria Not applicable 3.17.2 Test Resul ts A summary of core performance parameters from throughout the startup test program is presented in Table 3-17.
TABLE 3-17 CORE PERFORMANCE
SUMMARY
Parameter Core Thermal Power (MMt)
Core Flow (MLb/hr)
Core Inlet Subcooling (Btu/Lbm) 22.3 22.6 17.6 38.3 29.1 18.4 18.6 TEST RESULTS arranty 575 974 2412 1348 2346 3221 3277 36.0 38.4 93.6 30.0 59.5 106.5 '06.8 MCPR MLHGR (Kw/Ft)
MAPLHGR (Kw/Ft)
Total Peaking Factor 3.70 2.05 2.58 2.27
- 2. 24 5.087 3.021 1.970 2.298 1.826 1.554 3.50 5.24 8.31 5.85 8.93 12.14 3.03 4.46 7.36 5.23 7.94 10.67 1.404 11.97
. 10.74 2.17
.17.3
~
~
Discussion Prior to completion of the process
- computer, DSTC, core thermal limits evalua-tion was performed using BUGLE.
Test Condition 1 and 2 results reported were generated in this manner.
Subs quent results are from process computer edits.
3.18 Test Number 20 - Steam Production 3.'I8.1
~Pur ose The major objective of this test is to demonstrate that the Nuclear Steam Supply System for WNP-2 is providing steam in sufficient quantity and quality to satisfy all appropriate warranties as defined in the contract GE and WPPSS.
3.18.1.1 Level 1 Criteria The NSSS parameters as determined by using normal operating pro-cedures shall be within the appropriate license restrictions.
The NSSS will be capable of supplying steam in an amount and quality corresponding to the final feedwater temperature and other condi-tions shown on the Rated Steam Output Curve (Figure 3-2).
The Rated Steam Output Curve provides the warrantable reactor vessel steam output as a function of feedwater temperature, as well as warrant-able steam conditions at the outboard main steam isolation valves.
3.18.1.2 Level 2 Criteria Not applicable 3.18.2 Test Results During the 100 hr warranty demonstration it was determined that the Nuclear Steam Supply System delivered an average of 14.050 Mlb/hr steam flow at a quality of 99.86% with a steam line pressure at the second MSIV of 989.1 psia.
Feedwater temperature and enthalpy were 412.25'F and 389.27 Btu/Lbm, respectively.
Average inputs from three 2-hour test runs within the 100-hour run are listed in Table 3-18.
F 18.3 Discussion The 100-hr warranty demonstration was performed at an average power level of 3302.6 MWt (99.4%).
Steam flow was extrapolated at 100%
power and adjusted to account for differences in system parameters between the rated, heat balance (Figure 1.1-1 in the WNP-2 FSAR) and actual test conditions.
TABLE 3-18 STEAM PRODUCTION DATA Parameter Feedwater Flow (Mlb/hr,)
Feedwater Temperature
('F)
Feedwater Pressure (psia)
Feedwater Enthalpy (btu/ibm)
CRD Flow (Mbl/hr)
CRD Temperature
( F)
CRD Pressure (psia)
CRD Enthalpy (btu/ibm)
Cleanup System Flow (Mlb/hr)
Cleanup System Inlet Temperature
('F)
Cleanup System Outlet Temperature
('F)
Cleanup System Inlet Enthalpy (btu/ibm)
Cleanup System Outlet Enthalpy (btu/ibm)
Recirculation Pump Power (Mw)
A B
Steam Flow (Mlb/hr)
Reactor Pressure (Psia)
Steam Enthalpy (btu/ibm)
Main Steam Line Pressure (psia)
Run 13.8968 412.00 1094.7 388.98 0.0325
" 107.17 1269.7 78.46
- 0. 0945 527.4 441. 7 520.90 421.40 6.23 6.14 13.9293 1006.7 1192.6 983.7 Data Run
- 14. 0761 412.75 1099.7 389.81
'.0325 109.90 1279.35 81.20
.1029 528.3 440.9 522.01 420.40
- 6. 23 6.14 14.1086 1014.2 1192.3 990.7 Run 14.0789 412.02 1099.7 389.02 0.0325 109.06 1287.00 80.44
.13226"'29.2 438.7 523.11 418.59 6.21 6.11 14.1114
'1015.2 1192.4 992.9 RATED STEAM OUTPUT CURYE Rated Core Thermal Power:
3323 MWt 11317.7 x 106 Steam Output Equation:
Wpv
+ 39,000 1191.5 - hf Steam Conditions at Exit ot Second Isolation Valve:
Moisture 0.3%
Pressure 985 psia Enthalpy
- 1191.5 Btu/lb (Consistent with 1967 ASME Steam Tables)
FEEDWATER ENTHALPY,hf, Btu/Ib 300 320 340 360 380 400 14.4 14.2
~ ~ ~
~--f
~ t.- ~
~ ~
14.
x 13.8 CO p
~ ~
~
~
~
~
~ ~
13.6 0
13.4
~ ~ ~
~
~
~
~
Wpv VS hfw Wpv VS. tfw 13.2 N
p 13.
0 CI W
12.8
~
~i 12.6 12.4 380 360 300
'20 340 400 420 FINALFEEDWATER TEMPERATURE, tf, 'F Figure 3 850207.11A
3.19 Test Number 21 - Core Power-Void Mode Res onse 3.19.1
~Per ose The major objective of this test is to measure the stability of the core power-void mode dynamic response and to demonstrate that its behavior is within specified limits.
The. core power void response, that results from a combination of the neutron kinetics and core thermal hydraulic dynamics, is least stable near the natural circu-lation end of the rated 100 percent power rod line.
A fast change in the reactivity balance is obtained by a pressure regulator step change and by moving a very high worth rod only 1 or 2 notches.
Both local flux and total core response were evaluated by monitoring selected LPRM's during the transient.
3.19.1.1 Level 1 Criteria The decay ratio must be less than 1.0 for each process variable that exhibits oscillatory response.
3.19.1.2 Level 2 Criteria The decay ratio must be less than or equal to 0.5 for each total core process variable and local hydrodynamic channel (LPRM) that exhibits oscillatory response.
3.19.2 Test Results 3.19.3 The results of the dynamic response measurements from the natural circulation and high power/low flow test conditions are summarized in Table 3-19.
The test data indicates that the core response to local reactivity perturbations is well damped while the response to whole core reactivity perturbations is within acceptable limits.
Discussion Test condition 4 results were obtained in the natural circulation condition at 39.4X thermal power and 27.1% core flow.
Test condi-tion 5 results were obtained along the 100% load line.
TABLE 3-19 CORE POWER-VOID MODE RESPONSE DATA Test Condition Perturbution CR 34-43 Insertion 36-28 Withdrawal 28-36 RM Change 10.0%
10.0%
A RM Change 0.0 0.0 Decay Ratio
'0.0 0.0 R
R Decay Change Change Ratio Pressure Regulator Failure 10.5%
12.0%
CR 46-39 Insertion 10-0 Withdrawal 0-10 Pressure Regulator Failure
- 0. 42 7.0%
0.0 0.0 7.0'X 0.0 0.0 1.9%
3.0%
0.27
- 71
3.20 Test Number 22 - Pressure Re ulator
~
~
3.20.1
~Pur ose The major objecti ves of this test are as follows:
1.
To determine the optimum settings for the pressure control loop
'y analysis of the transients induced in the reactor pressure control system by means of the pressure regulator.
2.
To demonstrate the takeover capability of the backup pressure regulator via simulated failure of the controlling pressure regulator and to set the regulating pressure difference between the two regulators to an appropriate value.
3.
To demonstrate smooth pressure control transition between the turbine control valves and bypass valves when the reactor steam generation exceeds the steam flow used by the turbine.
3.20.1.1 Level 1 Criteria The decay ratio must be less than 1.0 for each process variable that exhibits oscillatory response to pressure regulator changes.
3.20.1.2 Level 2 Criteria Pressure control system related variable may contain oscillatory modes of response.
In these
- cases, the decay ratio for each con-trolled mode of response must be less than or equal to 0.25.
The turbine inlet pressure response time from initiation of pressure setpoi nt change to the inlet pressure peak shall be less than or equal to 10 seconds.
Pressure control system
- deadband, delay, etc., shall be small enough that steady state limit cycles (if any) shall produce steam flow variations no larger than
+ 0.5% of rated steam flow.
For all pressure regulator transients the peak neutron flux and/or peak vessel pressure shall remain below the scram setting by 7.5'X and 10 psi respectively (maintain a plot of power versus the peak variable values along the 100% load line).
The variation in incremental regulation (ratio of the maximum to the minimum value of the quantity, incremental change in pressure con-trol signal/incremental change in steam flow" for each flow range) shall meet the following:
% of Steam Flow Obtained Mith Valves Mide 0 en Maximum Variation 0 to 90%
90 to 97%
90 to 99%
3.20.2 Test Results Less than or equal to 4:1 Less than or equal to 2:1 Less than or equal to 5:1 The final pressure control system settings are presented in Table 3-20.
The pressure regulator settings were not adjusted from the original values determined before initial reactor heatup.
The re-sults'of the demonstration tests performed to confirm the adequacy of these settings are presented in Table 3-21.
At 100% power steady state limit cycles were less than
+ 0.5% of rated steam flow.
Based upon regulator failure testing, a setpoint differential between the primary and secondary regulators of 3 psi was selected.
Figure 3-3 presents the relationships between main steam flow, control valve opening, and generator output to control valve demand (pressure regulator output) at a constant throttle pressure.
3.20.3 Discussion The pressure control system settings were determined based on sug-gested initial system setup in the 8anford-2 Nuclear Power Station Control Systems Design Report (GEZ-6894) and testing carried out during open vessel testing.
Based on extensive testing of the pres-sure control system during the power ascension test program, no adjustment to the original pressure regulator settings were made.
Upon reaching the 60-75% power region for the first time an insta-bility was discovered in the pressure control system.
A "knee" in the pressure regulator gain curve due to break points in the gover-nor valve function generator curves caused limit cycle behavior in the pressure control system.
Generator output swings as high as 100 MMe peak to peak were observed.
Adjustment of the function gener-ator curves for governor valves 1
and 4 reduced the gain curve knee to allow acceptable pressure control system operation.
The incremental regulation performance is shown graphically in Figure 3-3.
This performance was judged to be satisfactory.
\\
TABLE 3-20 FINAL PRESSURE CONTROL SYSTEM SETTING PRESSURE REGULATOR PRESSURE REGULATOR A
B Gain (X psi)
Lead (Tl) second Lag (T2) second Dial Actual'ial Actual Dial Actual 31.6 3.33 Tu
= 1.93 3.0 8
= 2.
x 0.21 7.4 31.9 3.33 Tu
= 1.93 3.0 B = 2 x 0.21 7.4 Steam Line Compensator To T3 1/2 0.11 3 0.32 1.5 0.2 0.113 0.28 1.5 0.2
TABLE 3-21 PRESSURE REGULATOR TEST RESULTS Parameter Test Condition 1
Recirc Flow Control Mode POS 2
POS TEST RESULTS POS FLX 4
POS POS POS FLX Power
(%)
Core Flow (%)
Reactor Pressure (psi g)
Test Mode:
17.2
- 32. 3 937 27.0 63.5 63.5 38.6 30.4 79.8 79.8 27.6 920 964 964 929 66.7
- 53. 5 963 97.2 97.2 95.9 95.9 972 972 GV, Setpoint Change Peak Dome Pressure (psig)'eak APRM (X)
Time to Peak Press.
(sec)
Maximum Decay Ratio GV+BPV, Setpoint Change Peak Dome Pressure (psig)
Peak APRM (%)
Time to Peak Press.
(Sec)
Maximum Decay Ratio BPV, Setpoint Change Peak Dome Pressure (psig)
Peak APRM ('X)
Time to Peak Press.
(Sec)
Maximum 'Decay Ratio GV, Regulator Failure Peak Dome Pressure (psig)
Peak APRM (%)
Time to Peak Press.
(Sec)
Maximum Decay Ratio GV+BPV, Regulator Failure Peak Dome Pressure (psig)
Peak APRM (X)
Time to Peak Press.
(Sec)
Maximum Decay Ratio BPV, Regulator Failure Peak Dome Pressure (psig)
Peak APRM (5)
Time to Peak Press.
(Sec)
Maximum Decay Ratio 949 25.6 5.0 0.65*
956 25.6 3.9 0.41*
930 43.5 3.3 0.44+
925
- 34. 2 5.0 0.39 934 35.5 5.8 0.24 937 40.7
- 0. 22 937
- 31. 2 0.0 935 32.6 0.0 963 954 955 94 79 39 4.8 3.0 3.4 0.0 0.0 0.41*
937 42 5.0 0.0 944 42 6.8 0.23 966 958 946 82 72 53 2.2 0.0 0.0 0.34*
944 38 15.4 0.0 946 42 4.2 0.2 970 78 2.8 0.0 965 70 5.2 0.0 971 71 6.4 0.0 976 80 1.0 0.0 1000 991 104 105 2.7 3.2 0.0 0.0 990 994 100 103 7.0 7.0 0.0 0.0 996 997 ~
104 105 ~
7.0 4.0 0.0 0.0 995 997 103 105 1.2 1.2 0.0 0.0 997 1002 101 102 10.0 10.0 0.0 0.0 997 1001 100 104 4.6 2.9 0.0 0.21
- Each decay ratio 7.25 was evaluated as acceptable.
I I
PRESSURE REGULATOR STATlC DATA 100 95 90 80 70
-14.0 13.0 60
~1200 5
g 50 R
W O
0+
40 35 30 MAIN STEAM FLOW GENERATING
- OUTPUT, GV OPENING
-1100
-1000 900
- 800 g
- 700 >
I 600 g0 0
- 500 g 400
-11.0
-10.0 lL
-9.0 ~
- 8.0 N0
-7.0 ~
V)
- 6.0 p
- 5.0
~ 4.0
- 300
- 3.0
- 200
- 2.0
- 100
- 1.0 0
1 2
3 4
5 6
7 8
9 10 GV OEMAND (V) 0
- 0.0 Figure 3-4 850207.12A
3.21 Test Number 23A - Water Level Set oint and Manual Flow Chan es
- 3. 21.1
~Per ose The purpose of this test is to verify that the feedwater system has been adjusted to provide acceptable reactor water level control.
3.21.1.1 Level 1 Criteria The transient response of any level control system-related variable to any test must not diverge.
3.21.1.2 Level 2 Criteria 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.
The open loop dynamic flow response of each feedwater actuator (tur-bine or valve) to small (less than 10%) step disturbances shall be:
1.
Maximum time to 10% of step disturbance 1.1 sec 2.
Maximum time from 10% to 90% of a step disturbance 1.9 sec 3.
Peak overshoot
('X of step disturbance) 4.
Settling time, 100%,
+5%
15'X 14 sec The average rate 'or response of the feedwater actuator to large
(
20% of pump flow) step disturbances shall be between 10% and 25%
rated feedwater flow/second.
This average response rate will be assessed by determining the time required to pass linearly through the 10% and 90% response points.
At steady-state generation for the 3/1 element
- systems, the input scaling to be mismatch gain should be adjusted such that level error due to biased mismatch gain output should be within +1 inch.
The dynamic response of each individual level or flow sensor shall be as fast as possible.
Band width must be at least 4.0 radians/
second (faster than 0.25 second equivalent time constant),
except for the steam flow sensors which must have band width of at least 1.0 radian/second (faster than 1.0 second equivalent time constant).
3.21.2 Test Results All transient response of the level control system related variables to the step change did not diverge.
The decay ratio of the tran-sient response of the level controller at the final settings as shown in Table 3-22, was less than 0.25 or evaluated as acceptable.
The open loop dynamic flow response of the startup level control valve was determined to be acceptable even with the exception of slightly excessive overshoot.
The result is indicated in Table 3-23.
The open loop dynamic flow response of the feedwater turbine speed control indicates that the acceptance criteria were met except that excessive overshoot was observed on the flow response of feedwater pump 'A'.
Table 3-24 summarizes the test results.
The average rate of response of the feedwater pump to large (less than 20%) step di sturbance were 15K and 14'X rated feedwater flow/second for pump 'A'nd '8'espectively.
The steam flow/feedwater flow mismatch gain was verified to be acceptable by measuring the level error due to biased mismatch gain.
The level error was found to be 0.7 inch at steady state rated conditions.
The feedwater system and the level control system gain data was ob-tained during the power escalation to rated power.
The gain curves, as shown in Figures 3-4 and 3-5, produced a linear relationship between the FW loop flow and the level controller output over the operating range.
3.21.3 Discussion During an unplanned scram transient, the feedwater turbines were tripped on L-8.
Investigation revealed that the turbine minimum speed (2500 RPM) was too high. It was necessary to lower the mini-mum speed to 2000 RPM in o. der to prevent the feedwater pump from continuously filling the vessel to the L-8 trip following the reactor scram.
The feedwater turbine control (Moodward Governor) was respanned to a range of 2000 RPM to 5000 RPM for a 4-20 MA con-trol output signal.
The speed loop gain change had negligible effect on the flow loop response.
The open loop test performed fol-lowing the gain change indicated that the flow response was within the same order of magnitude as previously tested.
The system is desirably set for as fast a response as possible.
The slightly excessive overshoot was considered acceptable as the reactor water level was adequately controlled.
TABLE 3-22 FEEDWATER LEVEL CONTROL SYSTEM SETTINGS Master Controller (C34-K633)
Proportional Gain (Kp)
Reset Gain (R/M)
Actual 1.03 0.1 x 10 Dial 1.9 x 1
.09 x 10 Control System
~Re ort 3%/in.
1.5 Startup Level Controller (C34-K645)
Proportional Gain Reset Gain (R/M)'95
.35 1.4 x 1
.08 x 10 3%/in.
1.5 TABLE 3-23 STARTUP LEVEL CONTROL VALVE OP M
OW R
S 0 S
SUMMARY
Time to 10% of *A Step, second Time from 10% to 90% of A Step, second Peak Overshoot,
% of Step Settling Time, 100% + 5%, second Measured 0.5
- 0. 75 25 Acceptance Criteria 1.9 15 14.
TABLE 3-24 FEEDWATER PUMP TURBINE OPEN OOP OW R
PO
SUMMARY
~Pum Criteria Initial Fl ow (GPM) 7 x 103 10 x 103 13 x 103 16 x 103 7 x 103 10 x 103 13 x 103 16 x 103 Step Size
(%)
+12
-10
+ 9
-11
+ll
-10
+10 9
+10
- 9
+ 7
- 8
+ 7
- 7
+ 7
- 7 Delay Time (Sec) 0.6 0.6
- 0. 25 0.2 0.5 0.5 0.5 0.4 0.6 0.6 0.8 0.7 0.8 0.6 0.5 0.6
Response
Time (Sec) 1.0 0.2 0.4 0.6 0.5 0.3 0.5 0.4
- 0. 42 0.9 1.4 1.4 1.0 1.0 1.0 1.0 1.9 Overshoot
('X) 25.4 58.3 24.7 34.0 23 42 ll 36 12.5 9.1 13.6 11.1 12 0
15%
Settl ing Time (Sec) 2.4 2.4 2.0 2.0 1.6 1.5 2.1 2.0
- 1. 64 1.8 1.6 1.7 2.4 3.1
- 3. 05 2.7 14 sec P
e FEEDWATER TURBINE CONTROL GAIN CURVE LOOP '='-A"-
m 12 10
-5000 a
I 80 0
70 0
0 50 0
40 30 K
0 qV F
4000 +
O LQ CL, M
-3000 1u2 lOK
-2000 f K
-1000 10 0
10 20 30 40 50 60 70 80 90 100 MASTER CONTROLLER OUTPUT (%)
Figure 3-5 850207.13A
FEEDNATER TURBINE CONTROL GAIN CURVE LOOP "B" 120 6000 110 10 CI I
90 K
II.
8 O
~O 70 O
60 OO50 4
0 30 K
20 yO
+e 0
qV
-5000 4000 ~
4000 ~K I
-2000 ~
-1000 10 0
10 20 30 40 50 60 70 80 90 100 MASTER CONTROLLER OUTPUT (%)
Figure 3-6 850207.14A
3.22 Test Number 23B - Loss of Feedwater Heatin 3.22.1
~Pur ose The major objective of this test is to demonstrate adequate plant response to 'a feedwater temperature loss.
3.22.1.1 Level 1 Criteria For the feedwater heater loss test, the maximum feedwater tempera-ture decrease due to a single failure case must be less than or equal to 100'F.
The resultant MCPR must be greater than the fuel thermal safety limit of 1.06.
The increase in simulated heat flux cannot exceed the predicted Level 2 value by more than 2%.
The predicted value will be based on the actual test values of feedwater temperature change and power level.
- 3. 22.1. 2 Level 2 Criteria 3.22.2 The increase in simulated heat flux cannot exceed the predicted value referenced to the actual feedwater temperature change and power level 'in the Transient Safety Analysis Design Report.
II Test Results The maximum feedwater temperature decrease due to the worst single failure case (loss of extraction steam to both high pressure heaters) was 34.11'F.
Approximately ten minutes elapsed between the isolation of the high pressure heater's extraction steam and the stabilization of the feedwater temperature at its new, lower, value.
The minimum critical power rate (NCPR) decreased from a pre-transient value of 1.732 to 1.675, leaving adequate margin to the fuel thermal safety limit of 1.06.
The actual increase in simulated heat flux was 4.47% of rated, 0.83% of rated less than the predicted value.
- 3. 22.3 Di scuss ion The loss of feedwater heating test transient was initiated by simul-taneously opening extraction steam dump valves BS-DY-6ASB and clos-ing extraction steam valves BS-Y-6AEB.
The transient response was within the predicted response and all criteria were satisfied.
3.23 Test Number 23C - Feedwater Pum Tri 3.23.1
~Por oee The major objective of this test is to demonstrate the capability of the automatic core flow runback feature to prevent low water level scram following the trip of one feedwater pump.
3.23.1.1 Level 1 Criteria Not applicable 3.23.1.2 Level 2 Criteria 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.
3.23.2 Test Results The partial loss of feedwater transient was initiated by tripping the "A" turbine driven reactor feed pump while the reactor was oper-ating at 98.7% rated power.
The recirculation flow runback occurred when water level dropped to 3'l.5 inches (level 4) coincident with less than two feedpumps running.
The minimum water level reached during the transient was 24.7 inches.
This corresponds to a 11.55 inch level margin above the low level scram setpoi nt (13 inches) at 100% rated power.
The feed pump trip was initiated from stea@
state conditions with the feedwater control system in 3-element and the recirculation con-trol system in master manual.
The resulting transient generally followed the predicted response.
3.24 Test Number 23D - Maximum Runout Ca ability 3.24.1
~Pur ese This test calibrates the feedwater flow and determines if the maxi-mum feedwater runout capability is compatible with the licensing basis.
3.24.1.1 Level 1 Criteria Maximum speed attained shall not exceed the speeds which will give the following flows with the normal complement of pumps operating.
l.
135%
NBR at 1075 psia 2.
[135% +.2 (1075-P)j NBR at P rated, psig 3.24.1.2 Level 2 Criteria The maximum speed must be greater than the calculated speeds required to supply:
1.
With rated complement of pumps
-115%
NBR at 1,075 psi.
2.
One feedwater pump tripped condition
-68%
NBR at 1,025 psia.
3.24.2 Test Results 3.23.3 The feedwater turbine high speed limit would be acceptable 5450 RPM but was set conservatively at 5075 RPM.
The feedwater pump maximum runout capability was calculated and summarized in Table 3-25.
Discussion During power ascension to 100K power feedwater turbine and pump data was taken every 2% power increment.
A system demand curve was gen-erated by fitting a curve through the test data and extrapolating to maximum speed.
This curve was then adjusted for the reactor pres-sure specified in the acceptance criteria and superimposed on a
family of pump head curves at different pump speeds.
Intersection of these curves determined pump runout flows.
The high speed limit of 5450 RPM was determined to be acceptable.
A very conservative limit of 5075 RPM was implemented by WNP-2..
Both of these limits would allow the feedwater system to meet all the acceptance criteria and still allow acceptable plant maneuverability.
TABLE 3-25 FEEDWATER MAXIMUM RUNOUT CAPABILITY
SUMMARY
Reactor Pressure Fee dwa ter Pum 5075 RPM Cal cul ated 5450 RPM Calculated Required Level 1
Level 2
1075 PSIA 1020 PSIA 1025 PSIA 1025 PSIA A+B A+B 11 9%
122'X 73%
73%
128%
131'X 82%*
82%*
135%
146%
NA 115%
NA 68%
68%
- From best estimate of demand curve, 3 condensate
- pumps, 3 booster
- pumps, 1025 PSIA.
3.25 Test Number 24 - Turbine Valve Surveillance 3.25.1
~Pur oee
'The major objectives of this test are as follows:
1.
to determine the maximum power at which periodic surveillance testing of the main turbine control valves can be performed without causing a reactor scram; 2.
to determine the valve testing procedure which may be used as a
guidance for preparing the surveillance procedure; 3.
to establish baseline data for evaluating test condition prox-imity to the PCIOMR envelope during future testing activity.
3.25.1.1 Level 1 Criteria The decay ratio of any oscillatory response must be less than 1.0.
3.25.1.2 Level 2 Criteria Peak neutron flux; less than 7.5% below scram trip setting (118%).
Peak heat flux; less than or equal to 5% below scram trip setting
(.66 Wrt + 51%), where Wrt is the percent of recirculation flow.
Peak vessel pressure; less than or equal to 10 psi below scram trip setting (1037 psig).
Peak steam flow; less than or equal to 10% below the high flow iso-lation trip setting (104 psid).
Decay ratio of any oscillatory response must be less than.25.
NOTE:
The data collected relative to the PCIOMR limits will be used 7or determining proximity to the preconditioned or threshold power level during furture surveillance testing.
3.25.2 Test Results Results of governor valve and throttle valve closure tests along the 100% load line are displayed in Figure 3-6.
Bypass valve and inter-ceptor/reheat stop valve testing results are not included as the data showed very little reactor system response during these tran-sients.
The maximum power level for valve survellance was deter-mined to be 80% with the DEH in mode 4.
3.25.3 Discussion Turbine valve surveillance tests were successfully performed at 65%
and 80% power along the 100% load line.
While attempting to perform the governor valve test at 85% power,"'imit cycles developed in most pressure control system related process variables.
Valve closure testing was halted and 80% power was set as the maximum power level at which turbine valve surveillances are to be performed.
It is believed that the limit cycles occurred at 85% power due to the closure of GV 2 of 3 concurrent with GV 1
and 4 passing through a
break point in their gain curves.
No limit cycles or oscillations occur during the turbine valve surveillance test when conducted at 80'X power.
In addition, data evaluation determined that an increase in power level to greater than 85K to preclude the.limit cyclying may not have provided sufficient margins as defined by the Level 2
criteria.
80% power was thereby selected as the required power level for the technical specification turbine valve surveillance testing and the appropriate procedures were revised.
TURBINE VALVESURVEILLANCERESULTS 12 12 120 I
100-K 9
I bC 80.
IL O
LLI I
~
10
LLI hC 80.
LLI LL r//
r r/
////
//////////////////////////'///
110 100 90 CI LLII-0 +
lL:
~i 70 O
LLIz 50 A
<<C Lll V)
R 0 ~
1100 1080 C9 1060 cO Lll 1040 K CO LO
'020 LLIK 0
1000 QO 980 ~
960 70.
920 8
50 80 70 80 90 0
100 900 REACTOR POWER (% RATED)
GOVERNOR VALVE THROTTLE VALVE APRM:
0 0
HEAT FLUX:
0 a
DOME PRESSURE:
A STEAMLINEFLOW:
V V
Figure 3-7 850207.15A
1 s
3.26 Test Number 25A - MSIV Functional Test 3.26.1
~Per ose The major objecti ves of thi s test are as follows:
1.
to functionally check the Main Steam Isolation valves for proper operation at selected power levels; 2.
to determine MSIV closure time;.
3.
to determine the maximum power at which full closure of a single MSIV can be performed without a scram.
3.26.1.1 Level 1 Criteria The MSIV stroke time (ts) shall be no faster than 3.0 seconds (aver-age of the fastest valve in each steam line) and for any individual valve ts shall be between 2.5 and 5.0 seconds.
Total effective clo-,
sure time for any individual MSIV shall be tsol plus the maximum instrumentation delay time as determined by pre-operational test and shall be less than or equal to 5.5 seconds.
3.26.1.2 Level 2 Criteria The reactor shal not scram or isolate.
During full closure of individual valves peak reactor vessel pres-sure must be 10 psi (0.7 kg/cm2) below the scram setpoint, peak neutron flux must be 7.5X below the scram setpoint, and steam flow in individual line must be 10K below the isolation trip setting.
The peak heat flux must be 5% less than its trip point.
3.26.2 Test Results 3.26.3 Valve closure times of all ei ght MSIV's from three test points are presented in Table 3-26.
During these tests both RPS and position indicating limit switches were observed for indication of proper valve and logic operation.
Results of the single valve fast closure tests indicate the MSIV single valve full closure surveillances can be performed at below 85% power.
Discussion Figures 3-7, 3-8, 3-9, and 3-10 depict the results of data extrapo-lation to determine the maximum power level where MSIV single valve full closure surveillance can safely be performed.
Presented are peak reactor pressure, peak neutron flux, peak simulated heat flux, each as a function of power level.
The extrapolation indicates that at 85% power and above the required margins to scram are not satis-fied for the steam line flow parameter.
TABLE 3-26 MSIV CLOSURE TIMES Valve Description Inboard A, F022A Outboard A, F028A Inboard B, F022B Outboard,B, F028B Inboard C, F022C Outboard C,
F028C Inboard D, F022D Outboard D, F028D eatu (Secon s) 4:031 3.753 4.031
- 4. 309 3.763 3.614 4.031 3.700 TEST RESULTS
% Power Secon s
3.817
- 3. 599 4.115
- 4. 441 4.251 3.617 4.061 3.617
% Power econ s
3.655 3.841 3.446 4.213 3.910 3.564 3.711 3.601 91
MSIV SURVEiLLANCE:
PEAK REACTOR DOME PRESSURE 1050 1040 SCRAM (1037 PSIG) 1030 CRITERIA (1027 PSIG) 1020 C5 1010
~~
1OOO O
Cl CCO 990 K
~ PEAK VALUE
~ STEADY STATE 980 970 960 650207.16A 950 50 60 70 80 90 100 REACTOR POWER (% RATED)
Figure 3-8 110 120
MSIV SURVEILLANCE:
PEAK NEUTRON FLUX 130 120 SCRAM LEVEL (1 18%)
110 X~ 100 OKI-90 80 70 60 50
~ PEAK VAI.UE e STEAOY STATE CRITERIA (110.5%)
I I
I I
I I
I I
94%
I I
I I
I I
I I
I I
I I
I I
t I
I I
I 850207.17A 50 60 70
'80 90 100 REACTOR POWER (%)
Figure 3-9 110 120
MSIV SURVEILLANCE'EAKHEAT FLUX
'20 110
~ PEAK VALUE
~ STEADY STATE 100 113.5%
108.5%
No 90 X
I m
80 70 ib yW o
s~ p~
x>i o>
gQ o+
0 I
I I
I I
I I BS%
I I
I I
I 60 50 50 60 70 80
~
90 100 REACTOR POWER (% RATED) 110 120 850207.18A Figure 3-10
= MSIV SURVEILLANCE: PEAK STEAMLINE FLON- ---
5.0 SCRAM LEVEL (4.9 MLb/hr.)
4.76 850207.19A
~ 4.50 O 4.26 LL ill R
~ 4.00 IM 3.75 3.60 3.25 3.00 50 60 CRITERIA (4.41 MLb/hr.)
I I
I I
I I 86.6%
I I
I I
I I
I I
I I
I I
I I
I I
I I
70 80 90 100 REACTOR POWER (%)
Figure 3-11 110 120
3.27 Test Number 25B - Reactor Full Isolation Test 3.27.1
~Per ose The major objective of this test is to determine the reactor tran-sient behavior resulting from the simultaneous full closure of all MS IV'.
3.27.1.1 Level 1
Criteri a Reactor must scram to limit the severity of the neutron flux and simulated fuel surface heat flux transient.
3.27.1.2 Feedwater control system settings must prevent flooding of the steam line.
The recorded MSIV full closure times must meet the functional test criteria.
This criteria is discussed in Test Number 25A of this report.
The positive change in vessel dome pressure occurring within 30 seconds after closure of all MSIV valves must not exceed the'level 2
criteria by more than 25 psi.
The positive change in simulated heat flux shall not exceed the level 2 criteria by more than 2% of rated value.
Level 2 Criteria The temperature measured by the thermocouples on the discharge side of the safety/relief valves must return to within 10'F of the temp-erature recorded before the valve was opened.
for the full MSIV closure from full power predicted analytical re-sults base beginning of cycle design basis analysis, assuming no equipment failures and applying appropriate parametric corrections, will be used as the basis to which the actual transient is com-pared.
The following table specifies the upper limits of these criteria during the first 30 seconds following initiation of the indicated conditions.
Initial Conditio'ns Criteria Dome Power Pressure
(%)
(psia) 100 1020 Increase In Heat Flux (X) 0.0 r
Increase In Dome Pressure psl 125 Initial action of RCIC and HPCS shall be automatic if low water level (L2) is reached, and system performance shall be within specification.
Recirculation pump trip shall be initiated when reactor water level 2 is reached.
3.27.2 Test Results 3.27.3 During the full isolation test from 97% power the dome pressure rise was 79 psi.
Four safety/relief valves opened during the initial transient and five more were opened manually to control pressure later in the test.
Minimum water level was -42 inches which caused the RCIC system to initiate.
Water level reached a maximum of +93 inches which tripped all sources of water to the vessel and pre-vented flooding of the main steam lines.
Discussion The MSIV full closure transient followed predicted analytical re-sults very closely in that no increase in simulated heat flux was observed and peak reactor pressure was within criteria limits.
Major systems worked properly with two minor exceptions, RCIC initi-ation occurred at -42 inches reactor water level instead of -50 inches (level 2) and one safety/relief valve opened at 1069 psig, 7
psig below the design lowest SRV setpoint.
Both were later cor-rected by instrument recal ibration.
3.28 Test Number 26 - Relief Valves 3.28.1
~Pur use The purpose of this test is a) to verify the proper operation of the main steam relief valves, b) to verify that the discharge piping is not blocked, c) to verify their proper seating following operation, d) to obtain signature information of relief valve response for subsequent comparisons, and e) to determine their capacities.
3.28.1.1 Level 1 Criteria There should be positive indication of steam discharge during the manual actuation of each valve.
The sum of capacity measurements from all relief valves shall be equal to or greater than 15.8 x 106 lb/hr at an inlet pressure of 103% of 1,205 psig.
The total flow capacity of the safety relief valves used in the Automatic Depressurization system must be equal to or greater.
than 4.8 x 106 lb/hr at 1,125 psig when the valve having the highest measured capacity is assumed to be out of service.
Level 2 Criteria Relief valve leakage shall be low enough that the temperature mea-sured by the thermocouples in the discharge side of the valves re-turns to within 10'F (5.6'C) of the temperature recorded before the valve was opened.
The thermocouples are expected to be operating properly.
The pressure regulator must satisfactorily control the reactor tran-sient and close the control valves or bypass valves by an amount equivalent to the relief valve di scharge.
Each relief valve shall have a capacity between 90K and 122.5% of its expected value corrected to,an inlet pressure of 103% of 1,205 psig.
No more than 25K of the relief valves may have an individual cor-rected flow rate that is between 90 and 100% of their expected flow rates.
The transient recorder signatures for each valve must be analyzed for relative system response comparison.
Test Results During the initial heatup proper operation of the safety relief valves was verified by demonstrating that relief valve steam was discharged to the suppression pool and that the valves reseated after actuation.
This was accomplished by cycling each relief valve and recording tailpipe temperatur e prior to and after relief valve actuation.
In addition, accoustic monitors were tuned to adequately indicate the discharge of steam to the suppression pool and the reseating of the relief valves.
At about 50% power the capacity of each SRV was measured.
The results are presented in Table 3-27.
Total SRY capacity extrapo-lated to 1256.3 psia was 18.35 x 106 Lb/Hr.
The total capacity of SRV's used in ADS was 5.7 x 106 Lb/Hr.
All individual relief valves except MS-RV-2D have the corrected flow rates within the Level 2 acceptance ranges.
The capacity of MS-RV-2D was found to be 0.2 x 106 Lb/Hr less than the expected flow rate.
A correlation of steam flow and bypass valve position was first established by measuring the feedwater flow change with varying reactor thermal power level which changed, the bypass valve posi-tion.
The relationship of feedwater flow and bypass valve position is shown in Figure 3-11.
The SRV capacity was determined by the steam flow change as measured by the difference between the initial and final bypass valve positions.
The capacity of MS-RV-2D was found to be outside the Level 2 accep-tance range.
The total SRV capacity was found to be 14% higher than required.
In addition, MS-RV-2D is not an ADS valve.
Therefore the deviation was considered as acceptable.
The curve depicting BPV position versus changes in feedwater flow (Fig. 3-11) is provided to present data collected in determining total BPV capacity.
The data used to determine SRV capacity ranged from 5 to 50% total BPV position The data points are listed below; Total Bypass Position
(%)
Feedwater Flow (Mlb/Hr)
Differential 4.6 8.8 14.1 18.7 23.1 28.2 33.5 39.6 44.9 49.4
.18
.28
.35
.46
.53
.62
.83 1.1 1.33 1.55 TABLE 3-27 SRV PERFORMANCE DATA Relief Valve MS-RY-3B NS-RV-4D MS-RY-2B MS-RV-3C MS-RV-2A NS-RV-1A MS-RV-1D MS-RV-1C MS-RV-4C MS-RV-5C MS-RV-3A NS-RV-2D MS-RV-2C NS-RV-1B NS-RV-4B NS-RV-4A MS-RV-5B MS-RV-3D BPV Total
Response
17.62 17.54 17.20 16.90 16.85 17.42 16.42 17.05 14.59 17.19 16.85 13.50 16.64 17.20
~17. 24 17.54 17.57 16.83 SRV Capacity (x 106Lb/Hr 1.10 1.04 1.05 1.04 1.04 1.05 0.98 1.05 0.93 1.04 1.04 0.71 1.03 1.05 1.05 1.05 1.06 1.04
- 100-
BYPASS VALVECALIBRATIONCURVE 4.0 3.5 3.0 CC IQ
> a5 C9 2.0 O
WI-1.5 1.0 0,5 0
10 20 30 40 50 60 70 80 90 100 TOTAL BYPASS VALVEPOSITION Figure 3-12
-101-850207.20A
3.29 Test Number 27 - Turbine Tri and Generator Load Rejection 3.29.1
~
~
3.29.1.1
~Pur ese The purpose of this test is to demonstrate the response of the reactor and its control systems to protective trips in the turbine and the generator.
1 Level 1 Criteria
'I For turbine and generator trips above 50% nuclear boiler rated steam flow, there must be a delay of less than 0.1 seconds fol-lowing the beginning of control or stop valve closure before the beginning of bypass valve opening.
The bypass valves must be opened to a point corresponding to approximately 80 percent of their capacity within an additional 0.2 seconds, or 0.3 seconds total, 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 two recirculation pump drive flow coastdown transient dur-ing the first six seconds must be bounded by criteria specified in Power Ascension Test 8.2.30, Recirculation System Perfor-mance.
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 2% of rated value.
6.
The total time delay from start to breakers throttle valve or governor valve motion to the complete suppression of electrical arc between the fully open contacts of the circuit breakers (3A, 3B, 4A, 4B) shall be less than or equal to 190 milli-seconds.
3.29.1.2 Level 2 Criteria 1.
There shall be not NSIV closure in the first three minutes of the transient and operator action should not be required in the period to avoid an NSlV isolation.
- 102-
2.
3.
4.
5.
6.
The positive change in vessel dome pressure and in simulated heat flux which occurs within the first 30 seconds after the initiation of either generator or turbine trip must not exceed the predicted values from the MNP-2 Transient Safety Analysis Design Report.
NOTE:
Predicted values will be referenced to actual test con-ditions of initial power level and dome pressure, and will use BOL (Beginning of Life) nuclear data.
Morst case design or technical specification values of all hardware performance shall be used in 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 heat flux will be corrected for the actual measured values of these two parameters.
Electrical load transfers should occur as designed.
The reactor should not scram for initial thermal power at less than or equal to 25% of rated.
The measured bypass capacity (in percent of rated power) shall be equal to or greater than used for FSAR safety analyses (3,576,000 ibm/hr).
Recirculation LFMG sets shall take over after the initial re-circulation pump trips and adequate vessel temperature di.f-ference should be maintained.
7.
8.
Feedwater level control shall avoid loss of feedwater due to possible high level (L8) trip during the event.
Low water level (L2) total recirculation pump trip, HPCS and RCIC should not be initiated.
9.
The temperature measured by thermocouples on the discharge side of the safety/relief valves must return to within 10'F of the temperature recorded before the valve was opened.
In addition the acoustical monitors should indicate the valve is closed after the transient i s complete.
3.29.2 Test Results During the Generator Load Rejection test within bypass valve capa-city, the pressure regulator performed adequately; maintaining pres-sure at 920 psig with a transient peak of 958 psig.
The reactor did not scram and the electrical load transferred properly.
The results of high power turbine trip and generator load rejection are contained in Table 3-28.
- 103-
Discussion The two recirculation pump RPT trip showed the drive flow coastdown was faster than the minimum ECCS coastdown criteria during the tur-bine trip and generator load rejection test.
The test exception was analyzed and accepted by General Electric Transient Performance Engineer (refer to test 308 discussion of this report).
A temporary procedure was written to simulate a
RFH pump trip and auto level setdown during a scram.
This would provide data that would be useful in designing the features necessary to the feedwater control system that precluded the system from tripping following a scram.
The indicated level transient immediately following a scram had on past scrams caused a feedwater turbine trip on Level 8.
The temporary feedwater procedure was performed during the generator load rejection test at TC-6.
The operating feedwater pump however, eventially tripped on level 8.
The reason for level 8 trip of the second feedwater pump is because of the low reactor decay heat and the resulting drop in reactor pressure that enabled feedwater to continually feed the vessel.
At higher decay heat levels, the existing control system setting could possibly be sufficient.
Additional attention and design changes are currently under investigation.
The load rejection transient was simulated by utilizing the main generator trip pushbutton at TC-6.
The turbine overspeed reached 1900 RPM at the time of the turbine trip.
A slow bypass valve opening time condition during testing in Test Condition 3 was caused by the DEH Isolation Amplifier to BPV 2 and 4
causing excessive signal response time delay compared to the signal conditioning circuit for the 1
5 3 valves.
This was corrected and the BPV opening time was later demonstrated to be within 300 milli-seconds criteria.
During the BPV response time troubleshooting
- process, modifications were made to improve BPV response.
The main steam bypass valve individual accumulators were increased from 1
gallon to 2-1/2 gallon rated capacity.
The DEH hydraulic oil supply line to the accumulators were also rerouted to eliminate about 150 psig pressure drop from the DEH pumps to the bypass valves.
- 104-
TABLE 3-28
SUMMARY
OF TURBINE TRIP AND GENERATOR LOAD REJECTION TEST RESULTS ACTUAL RESULT CRITERIA LEVEL 1 LEVEL 2 TC-3 TC-6 Time between control valve closure and bypass valve opening Time between stop valve closure and bypass valves at 80'X capacity Minimum water level to prevent steamline flooding and reactor feed pump trip Recirculation pump coastdown bounded by criteria curves
.1 (sec)
.3 (sec) 107 inches 6 (sec) n/a n/a 55 inches n/a 0.093 (sec)
- 2. 742 Average 52 "
6 sec transient 0 sec ECCS 0.010 (sec) 0.168 (sec)
Average 55", L-8 Trip 6 sec transient 0 sec ECCS Positive change in vessel dome pressure within 30 seconds of turbine trip Positive change in simulated heat flux 96 (psi)TC-3 71 (psi)TC-3 134.5(psi)TC-6 109.5(psi)TC-6 0%
65 (psi) 0%
68 (psi) 0%
Total delay from start of control valve motion to the complete suppres-sion of electrical arc MSIV isolation shall not occur in the first 3 minutes, nor, shall operator take action to avoid MSIV trip Measured bypass val ve capacity shall be assumed value in FSAR Recirc transfer to LFMG Low uater level recirc pump trip, HPCS and RCIC shall not initiate Discharge side of S/RV must return in 10'F of initial
.190 sec n/a n/a n/a n/a n/a n/a no isolation'o operator action 3.565 Mlb/hr transfer to LFMG, no temperature stratification
-50 inchs 10'F 0.175 (sec) no isolation no operator action II 3.6 mlb/hr transfer to LFMG, no temperature stratification
- 3 inches no SRV actuation 0.150 (sec) no isolation no operator action 3.6 mlb/hr transfer to LFMG, no temperature stratification
+
1 inch MS-RV-3B below 215 F
with initial 207'F
- 105-
3.30 Test Number 28 - Shutdown From Outside the Control Room 3.30.1
~Per ose 4
The major objecti ves of this test are. as follows:
To demonstrate that the reactor can be brought down from a normal initial steady-state power to the point where cooldown is estab-
- lished, and to demonstrate that the reactor vessel pressure and water level can be controlled from outside the control room.
3.30.1.1 Level 1 Criteria Not applicable 3.30.1.2 Level 2 Criteria During a simulated main control room evacuation, the reactor must be brought to the point where cooldown can be initiated, and the reactor vessel pressure and water level must be controlled using equipment and controls, outside the main control room.
3.30.2 Test Results 3.30.3 During TC-6, the reactor was scrammed following the turbine load reject test at 100K power.
At this point in the test program it was decided to enter into a short outage for various repairs and perform the RHR SDC portion of this test.
The testing at TC-6 amounted to successfully entering into RHR shutdown cooling.
That activity was completed.
During TC tl, the ability to maintain reactor level with the RCIC system and pressure with SRV's at the remote shutdown panel was verified.
RHR suppression pool cooling was also placed in ser-vice at that time.
The combination of each of the tests provided valuable information leading to a revision to the procedure used to evacuate the control room 8 utilize the remote shutdown equipment.
The revision was also successfully demonstrated on the MNP-2 simu-lator which provided for additional minor procedure changes.
Discussion During TC-1 the reactor was manually scrammed and the MSIV's were closed prior to evacuating the control room.
Operators located at the Remote Shutdown Panel in the Radwaste Building monitored the ensuing reactor transient.
No action was required in the main con-trol room to maintain the plant in a safe condition.
The relief valves were operated from the Remote Shutdown Panel and RCIC was initiated to demonstrate operability.
The RHR system was placed in suppression pool cooling mode of operation from the Remote Shutdown Panel.
Following the reactor scram at TC-6, the RHR B loop was placed into shutdown cooling mode from the Remote Shutdown Panel after reactor pressure was reduced to 75 psig.
The mi,nimum required 50'F/hr cool-down rate was maintained which demonstrated the ability to cooldown the reactor from outside the main control room.
- 106-
3.31 Test Number 29A - Flow Control-Yalve Position Control 3.31.1
~Pur oee The purpose of this test is to demonstrate the recirculation flow control systems capability while in the valve position (POS) mode.
3.31.1.1 Level 1 Criteria The transient response of any recircultion system-related'variables to any test input must not diverge.
3.31.1.2 Level 2 Criteria 3.31.2 1.
Recirculation system related variables may contain oscillatory modes of response.
In these
- cases,
'the decay ratio of each controlled mode of response must be less than or equal to 0.25.
2.
Maximum rate of change of valve position shall be 10 + 1'X/sec.
During TC-3 and TC-6 while operating on the high speed (60 Hz)
- source, gains and limiters shall be set to obtain the following response.
3.
Delay time for position demand step shall be:
For step inputs of 0.5% to 5X less than or equal to 0.15 sec.
4.
Response
time for position demand step shall be:
For step inputs of 0.5X to 5% less than or equal to 0.45 sec.
5.
Overshoot after a small position demand input (1 to 5%) step shall be less than lGX of magnitude of input.
'I Test Results The transient response of any recirculation system-related variable to any step change did not diverge.
The decay ratio of the tran-sient response of the valve position loop was always less than 0.25.
The maximum stroking rate of the flow control valve in both opening and closing directions was 10.5%/sec.
The valve response results during TC-3 and TC-6 are summarized in Tables 3-29 through 3-32.
In addition, the position loop deadband was found to be less than 0.2% of full stroke.
-107-
3.31.3 Discussion The delay time and response time of the flow control valve response were not within the Level 2 acceptance limits.
However, in many cases the combination of these two has satisfied the intent of the individual criteria.
The peak overshoot was satisfied for the larger step (5%).
The overshoot for smaller steps (0.2X and 0.5X) was approximately double the criteria.
In general the valve posi-tion control loops were optimized such that Level 2 criteria were satisfied.
The small deviations from the Level 2 criteria are con-sidered to be insignificant and acceptable.
A problem of excessive valve duty cycle was encountered during early stage of testing.
In order to rectify the problem an FDDR which was recommended by GE was implemented.
In the FDDR the integral gain circuit was removed from the velocity servo controller and the derivative gain from the position controller.
As a result of this modification the valve duty cycle was eliminated.
- 108-
TABLE 3-29 VALVE POSITION CONTROL DATA 'A'OOP - TC-3 VALVE POSITION 15 15 15 15 15 15 25 25 25 25 25 25 50 50 50 50 50 75 75 75 75 75 75 STEP SIZE 0.5(D) 0.5(U) 1(D)
-1(U) 5(D) 5(U) 0.5(D) 0.5(U) 1 (D) 1(U) 5(D) 5(U) 0.5(D) 0.5(U) 1(D) l(U) 5(D) 5(D) 5(U) 0.5(D) 0.5(U) 1(D) 1(U) 5(D) 5(U)
D TIME (sec)
- ~0.15 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.15 0.15 0.2 0.15 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.3 0.2 0.2 0.2 0.2 RSO TIME (sec)
- 40.45 0.35 0.3 0.2 0.2 0.5 0.5 0.45 0.3 0.2 0.2 0.55 0.6 0.1 0.2 0.4 0.2 0.55 0.44 0.6 0.44 0.2 0.3 0.2 0.2 0.55 0.6 OVER-SHOOT
- ~10%
10 10
- 13. 9 11 4
3 25 7
13.3 13.3 3
3 20 20 16.6 21.7 5
4.5 4.5 20 13 10 16 3
3 OMB.
DELAY 8(
RESPONSE
- >0.6 0.55 0.5 0.4 0.4 0.7 0.7 0.65 0.5 0.35 0.35 0.75 0.75 0.3 0.4 0.6 0.4 0.75 0.64 0.8 0.64 0.4 0.6 0.4 0.4
- 0. 75 0.8
- Acceptance Criteria (D)
= down; (U)
= up
-indicates data inclusive 109
TABLE 3-30 VALVE POSITION CONTROL DATA 'B'OOP - TC-3 I L VALVE POSITION 15 I
15 I
15 I
15 15 I
15 I
25 I
25 I
25 I
25 I
25 I
25 I
50 I
5o 50 I
50 50 50 75 I
75 75 75 75 75 I
STEP SIZE 0.5(D) 0.'5(U) 1(D) 1(U) 5(D) 5(U) 0.5(D) 0.5(U) 1(D) 1(U) 5(D) 5(u) 0.5(D) 0.5(U) l(D) 1(U) 5(D) 5(D) 0.5(D) 0.5(U) 1(D) 1(U) 5(D) 5(U)
D TIME (sec)
- '.15 0.4 I
0.5 I
0.25 I
0.25 I
o.2 I
o.2 I
o5 I
o4 I
0.2 I
o3 I
0.2 I
o.2 0.4 I
o.4 I
0.3 I
0.3 O.2 I
0.2 I
o.2 I
o.3 O.2 I
o.2 I
o.2 I
0.2 I
I I
I I
I I
I I
I I
I I
I I
I I
I I
I I
I I
I I
-R S
0 S
TIME (sec)
- ~0.45 0.5 0.4 0.3 0.3 0.4 0.4 0.3 0.3 0.3 0.2 0.4 0.4 0.3 0.3 0.35 0.2 0.4 0.4 0.4 0.3 0.3 0.3 0.4 0.4 OVER-SHOOT
- -10%
- 13. 3 I
33.3 I
17 I
20 I
I 5.0 I
5.0 I
lo I
I lo I
I 10 I
I 17 I
I 4
I I
4 I
I lo I
I lo I
I lo I
I I
I 4
I I
4 I
I 10 I
I 10 I
I 10, I
I 125 I
I 2
I I
2 I
I I
OMB.
DELAY &
RESPONSE
- ='0.6 0.9 0.9 0.55 0.55 I
0.6 I
0.6 0.8 I
o7 I
0.5 o.5 I
0.6 I
0.6 I
0.7 0.7 I
0.65 I
0.5 0.6 I
0.6 I
0.6 I
0.6 I
0.5 0.5 0.6 I
0.6 I
I
- Acceptance Criteria (D)
= down; (U) = up
- indicates data inclusive 110
TABLE 3-31 VALVE POSITION CONTROL LOOP A RESPONSE
SUMMARY
TC-6 Recirc
~Loo FCV Position Initial Core Flow Step Size Delay Time (Sec)
Response
Time (Sec)
Overshoot
('X)
Setting Time (Sec) 23'X 23%
23'X 23%
23%
23'X 37'X 37K 37'X 37%
37%
37%
64%
64%
64K 64%
64%
64%
60'X 60K 60'X 60%
60'X 60K 75%
75K 75'X 75'X 75'X 75K 95'X 95%
95%
95'X 95'5 95%
-0. 5X
+0.5%
1'X
-0.5%
+0. 5'X 1'X
-0. 5%
+0. 5X 1%
+
1%
0.7 0.6 0.2 0.3 0.2 0.2 0.5 0.5 0.3 0.2 0.2 0.2 0.5 0.4 0.2 0.2 0.2 0.3 0.4 0.5 0.4 0.4 0.4 0.5 0.5 0.4 0.5 0.4 0.4 0.3 0.5 0.8 0.5 0.5 0.5 0.4 37.5 27.5 22.2 16.7 8.2 3.3 10.0 6.9 4.5 10 1.6 2.4 0
-0 4.2 4.7 1.5 1.2 0.8 2.5
- 1.4 0
1.4 0
0 0
0 0
0 0
0 Acceptance Criteria
-~ 10%
T 3-32 VALVE POSITION CONTROL LOOP 8
RESPONSE
SUMMARY
TC-6 Recirc
~Loo Initial FCV Core Position Flow Step Size Del ay Time (Sec)
Response
Time (Sec)
Overshoot
(%)
Setting Time (Sec)
.8 8
8 8
-8 8
8 8
8 8
8 8
8 8
8 8
8 8
22'X 22%
22%
22K 22'X 22K 39K 39'X 39%
39'X 39K 39'X 67'X 67%
67K 67'X 67K 67'X 60%
60K 60%
60'X 60%
60%
75K 75%
75'X 75'5 75'X 75'X 95'X 95K 95'5 95K 95'X 95'X
-0.5%
+0.5%
1'X
-0.5%
+0.5%
1'X
-0. 5'X
+0. 5'X 1'X
+
1'X 5X
+
5%
0.3 0.2 0.2 0.2 0.2 0.2 0 4 0,4 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.3 0.2 0.4 0.4 0.5 0.4 0.4 0.4 0.4 0.3 0.4 0.4 0.3 0.2 0.4 0.3 0.4 0.4 8.3 18.3 13.5 15 5.5 4.5
- 18. 2 40.9 16 4.5 5.3 13.8 29.3 9.2 17.4 2:4 5.0 1.0 1.7 1.0 1.0 0.7 0.3 1.4 1.3 1.4 1.2 0.3 3.6 4.2 2.9 0.5 Acceptance Criteria
= 0.15 10%
3.32 Test Number 298 - Recirculation Flow Loo Control 3.32.1
~Per ose The purpose of this test is to a) demonstrate the core flow sys-tem's control capability over the entire flow control range, in-cludingg both core flow neutron flux and load following modes of operation, and b) determine that all electrical compensators and controllers are set for desired system performance and stability.
3.32.1.1 Flow Loo Criteria Level 1 Criteria The transient response of any recirculation system-related
- variable, to any test input must not diverge.
Level 2 Criteria A.
The decay ratio of the flow loop response to any test inputs shall be less than or equal to 0.25.
B.
The flow loops provide equal flows in the two loops during steady-state operation.
Flow loop gains should be set to correct a flow imbalance in less than 25 seconds.
C.
The delay time for flow demand step (less than or equal to 5X) shall be Oe4 seconds or less.
D.
The response time for flow demand step (less than or equal to 5%) shall be 1.1 seconds or less.
E.
The maximum allowable flow overshoot for step demand of less than or equal to 5X of rated shall be 6% of the demand step.
F.
The flow demand step settling time shall be less than or equal to 6 sec.
3.32.1.2 Flux Loo Criteria Level 1
The flux loop response to test inputs shall not diverge.
Level 2
A.
Flux overshoot to a flux demand step shall not exceed 2% of rated for a step demand of less than or equal to 20% of rated.
- 113-
B.
The delay time for flux response to a flux demand step shall be'ess than or equal to 0.8 sec.
C.
D.
The response time for flux demand step shall be less than or equal to 2.5 sec.
The flux setting time shall be less than or equal to 15 sec.
for a flux demand step less than or equal to 20% of rated.
3.32.1.3 SCRAM Avoidance and General Criteria Level 1
Not applicable Level 2
for any one of the above loops'est maneuvers, the trip avoidance margins must be at least the following:
A.
For APRM 7.5%
B.
For simulated heat flux 5.0%
3.32.1.4 Flux Estimator Test Criteria Level 1
Not applicable e
Level 2
A.
Switching between estimated and sensed flux should not exceed 5
times/5 minutes at steady-state.
B.
During flux step transient there should not be switching to sensed flux or if switching does occur, it should switch back to estimated flux within 20 seconds of the start of the transient.
3.32.1.5 Flow Control Valve Duty Test Criteria Level 1
Not applicable Level 2
The flow control valve duty cycle in any operating mode shall not exceed 0.2% Hz.
Flow control valve duty cycle is defined as:
Integrated Valve Movement in Percent
(% Hz) x time span in secon s
- 114-
3.32;2 Test Results The response of all the recirculation flow control system related parameters to any step change in each control mode exhibited stable transient with a decay ratio less than 0.25.
Table 3-33 summarizes the final setting of each controller.
The recirculation loop flow response to the flow controller demand step change showed that the Level 2 acceptance criteria were met with the following exceptions;
- 1) the flow delay time and response time criteria were exceeded and
- 2) the maximum flow overshoot ex-ceeded the Level 2 criteria.
Table 3-34 indicates the results.
The function generators were re-verified after the adjustment on the valve actuators.
Figures 3-12 and 3-13 indicate gain curves for the function generators exhibit a linear relationship between the func-tion generator input and recirculation loop flow.
With the exception of the slight excessive flux overshoot for flux demand step all the Level 2 criteria for the flux loop were satis-fied.
The flux estimator was demonstrated to adequately adjust to minimize the valve cycle due to neutron flux noise.
Table 3-35 indicates the flux loop test results.
Sufficient scram avoidance margins of neutron and heat flux were demonstrated for operation in flow and flux modes.
The minimum scram margin of neutron and heat flux were 13.8% and 11.5% respec-tively.
Table 3-36 summarizes the test results.
3.32.3 Discussion The recirculation flow control system was initially tuned on the 75%
load line and minimal changes on the controller were made since the system adjustments made in TC 83.
The controller settings were ver-ified again in TC 86 along the 100%, load line.
A well-behaved and stable response was demonstrated at these final settings.
The established test criteria is provided to support the Automatic Load Following (ALF) mode of operation.
WNP-2 has elected not to use the ALF mode and therefore the accept'ance criteria could be significantly relaxed.
If and when WNP-2 elects to use the ALF
- mode, the system will need additional testing and tuning.
Sum-marizing, the system is deemed adequate for the current power operation.
-115-
TABLE 3-33 RECIRC FLOW CONTROL SYSTEM FINAL SETTINGS Dsa Setting sn Turns POSITION CONTROLLER Proportional Gain Derivative Gain COMPONENT RV 4 RV 5 1.0 n/a
- 1. 75 n/a VELOCITY SERVO CONTROLLER Proportional Gain Integral Gain RV 10 RV 11 8.0 n/a 8.0 n/a FLOW CONTROLLER Reset Gain (KI)
FLUX CONTROLLER Lead Lag Integral Gain (KI)
Proportional Gain (KP)
Gain (KP)
RV 6 RV 12 RV 13 RV 14 RV 15 RV 8 5.0 0.5 2.8 1.0 2.0
- 5. 95
- 116-
TABLE 3-34 FLOW CONTROL LOOP
RESPONSE
SUMMARY
Recirc
~Leo Initial Loop Core Flow Flow Step Size Delay
Response
Time (Sec)
Time (Sec)
Overshoot
(%)
Setting Time (Sec)
A A
A A
A A
B B
B B
B B
A/ASB
- A/ASB
- B/AEB
- B/ASB
- 53'X 53'X 71'5 71%
95%
95'4 54%
54%
70%
70'X 94%
94'5 53%
53'X 72%
72%
60%
60%
75%
75'4 95%
95'X 60%
60%
75%
75%
95%
95%
60%
60%
75%
75%
-5%
+5%
-5'5
+5%
-5%
+5%
-5%
+5%
-5%
+5%
-5%
+M
-5%
+5%
-5'X
+5'X 0.2 0.6 0.0 0.4 0.6 0.2 0.5 0.6 0.2 0.4 0.8 0.8 0.6.
0.7 0.8 0.5 1.0 1.2 1.5 2.0 1.3 1.4 4 4 1.4 1.4 1.0 1.4 1.4 6.0 1.9 1.5 15.6 0
0 0
0 2.8 10 0
0 15 0
10 4.0 4.0 0
0 0.6 0
0 0
0 0
0.4 0
0 0
0 0
0 oI Acceptance Criteria
- Maximum of Combined Loops 0.4 6.0
-117-
TABLE 3-35 NEUTRON FLUX CONTROL LOOP
RESPONSE
SUMMARY
Initial Neutron Core Flow Flow Step Size De1ay Time (Sec)
Response
Time (Sec)
Overshoot
(%)
Setting Time (Sec) 75%
75%
85%
85K 98%
98%
60%
60%
75%
75%
95'X 95%
+5%
-5%
+5%
-5%
0.9 0.7 0.6 0.6 2.6 0.8 0.4 0.5 0.2 0.3 2.8 0.2 2.8 3.2 2.0 5.0 1.2 2.8 3.6 0.7 0.6 0.4 2.0 Acceptance Criteria 0.8 2
5
= 2.0%
15
-118-
TABLE 3-36 SCRAM AVOIDANCE MARGIN VERIFICATION (100% L.L)
Control Mode Initial Core Flow Step Size Scram Avoidance Margin APRM Heat Flux FLO FLO FLO FLO FLO FLO FLX FLX FLX FLX FLX FLX 60%
60%
75%
75%
95%
95%
60%
60%
75%
75%
95%
95%
2%
5%
2%
M 2%
5%
2%
2%
M 2%
5%
- 38. 4'X
- 24. 8%
31%
16%
13.8%
13.9%
39.6%
39.8%
30.4%
27.8%
13.8%
20%
14.8%
15.6%
14.4%
11.5%
11.7%
12.1%
14.4%
- 13. 4'X
- 13. 4%
17.0X Acceptance Criter ia
.~5%
- 119-
RECIRCULATION FLOW CONTROL LINEARlZATIONLOOP "A" VALVEPOSITION (%)
10 20 30 40 50 60 70 80 90 100 10
- -10 90 e
80-K 0~
70-
~O 60-0 u.
50-LL O0 40-0 0
30 IL Ill 20 O
6' I
4 I
0 C0 I
0 K
z Lll
-2 O
I~
4 0
U 6
10-8 10 8
6 4
2 0
.2
-4
-6
-8
-10 FUNCTION GENERATOR INPUT (VOLT) 850207.21 A Figure 3-13
- 120-
RECIRCULATION FLOVf CONTROL LINEARIZATIONLOOP "8" VALVEPOSITION (%)
0 10 20 30 40 50 60 70 80 90 100 10
- -10 B
LLL 80-K 0
70-g 60-O LL.
50-LL.
OO 4
O 30-LL:
ILL CC 2
O 4 06 I
4 LL I
O
..2 0
0 a
R 2
Q LLL zO e
4 l
R 6
LL 8
10 8
6 4
2 0
-2
.4
.6
-8
.10 FUNCTION GENERATOR INPUT (VOLT)
Figure 3-14
- 121-850207.22A
3.33 Test Number 30A - Recirculation System-One Pum Tri 3.33.1
~Per ese
~
~
The major objectives of this test are as follows:
A.
To obtain recirculation system performance data during the pump trip, one pump operation, and pump restart; B.
To verify the feedwater control system can satisfactorily con-trol water level without resulting in a turbine trip and/or scram.'.33.1.1 Level Criteria 1
The reactor shall not scram during the one pump trip recovery.
3.33.1.2 Level 2 Criteria 1.
The reactor water level margin to avoid a high level turbine trip shall be greater than or equal to 3 inches during the one pump trip.
2.
The simulated heat flux margin to avoid a scram shall be greater than or equal to 5 percent both during the one pump trip and also during the recovery.
3.
The APRM margin to avoid a scram shall be greater than or equal to 7.5 percent during the one pump trip recovery.
4.
The maximum one pump flow shall not cause excessive reactor internal vibration.
3.33.2 Test Results No reactor scram occurred during either the pump trip or the re-covery of the tripped pump.
The feedwater control response was ade-quate to prevent the Level 8 high level turbine trip.
Reactor internal vibration data was recorded during the pump trip and subsequent single loop operation.
A preliminary report provided by a GE Vibration Engineer showed the vibrations were within the level 2 criteria.
Summary of the results are listed in Table 3-37.
- 122-
3.33.3 Discussion During the recirculation pump trips and restarts conducted in TC-3 and TC-6, recirculation system performance data was obtained to evaluate heat flux, reactor power, water level, recirculation loop flow and combined jet pump flow response.
During single loop opera-tion individual jet pump flow data was recorded at various FCV posi-tions to establish baseline flow patterns required for Technical Specification surveillance testing should extended single loop oper-ation become necessary.
FCV position versus loop flow for the inservice loop data was taken for the same purpose.'he data col-lected has been used to prepare the Technical Specification surveil-lance procedure criteria.
-123-
TABLE 3-37 RECIRCULATION ONE PUMP TRIP RESULTS Parameters Reactor Water Level Margin Test Condition TC-3 TC-6 Acce tance Criteria 311 Simulated Heat flux Scram Margin During Trip Simulated Heat Flux Scram Margin During Recovery APRM Scram Margin During Recovery 14.2%
23.8%
47.6%
12%
17%
58%
- 7. 5%
- 124-
3.34 Test Number 30B - Recirculation System-RPT Two Pump Trip 3.34.1
~Pur ose The purpose of the test is to record and verify acceptable perfor-mance of the recirculation two pump trip circuit system.
3.34.1.1 Level 1 Criteria The two pump drive flow coastdown transient during the first 6 seconds must be bounded by the limiting curves.
3.34.1.2 Level 2 Criteria Not applicable 3.34.2 Test Results Figures 3-14 and 3-15 display the results of the recirculation pumps trip flow coastdown transient and the comparision to the coastdown criteria.
Both the A and B loop drive flow coastdowns exceeded the Level 1
ECCS criteria 5 second time constant curve.
3.34.3 'iscussion Table 3-38 contains tabulated values for the criteria curves pro-vided by GE Plant Transient Performance Engineering for the above figures.
The test exception was analyzed and accepted by General Electric Transient Performance Engineering.
The basis of this con-clusion is an ECCS pump coastdown sensitivity study which showed inertial time constants as low as 3 seconds were acceptable.
The test data for both loops fell between 6 seconds and 3.5 seconds (3
seconds plus.5 second added conservatism) bounding curves and was therefore deemed to be acceptable.
The 3 second inertia time con-stant resulted in a peak clad temperature increase of less than 10 F.
The 10'F peak clad temperature increase does not impact the MAPLHGR limit.
- 125-
RPT COASTDOWN DATA FOR LOOP "A" 100 0
LI 90 K
CI 80 V)'0 I
R 60-II0 I
Iu 50 OK LLI IL 40-p X
p X
p CRITERIA A675 6 SEC PUMP INERTIA,.75 SEC SENSOR TIME CONSTANT B575 5 SEC PUMP INERTIA,.75 SEC SENSOR TIME CONSTANT C475 4 SEC PUMP INERTIA,.75 SEC SENSOR TIME CONSTANT TEST DATA P 2 PUMP RPT x TURBINE TRIP/RPT A675 B575 C475 1.0 2.0 3.0 4.0 TIME AFTER PUMP TRIP (EXCLUDING0.190 SEC DELAY) 5.0 Figure 3-14 126-6 0207.26A
100 O
90 CI Q
80 (0
70 60 0
I 5
50 OK 40-0 X
CRITERIA A615 6 SEC PUMP INERTIA, 1.5 SEC SENSOR TIME CONSTANT 8515 5 SEC PUMP INERTIA, 1.5 SEC SENSOR TIME CONSTANT C415 4 SEC PUMP INERTIA, 1.5 SEC SENSOR TIME CONSTANT TEST DATA 0 2 PUMP RPT
< TURBINE TRIP/RPT 615 515 415 1.0 2.0 3.0 4.0 TIMEAFTER PUMP TRIP (EXCLUDING0.190 SEC DELAY) 5.0 Figure 3-15
- 127-850207.27A
TABLE 3-38 HANFORD RPT COASTDOWN REQUIREMENTS TABULATED VALUES fOR CRITERIA CURVES SHOWN IN FIGURES 3-14 and 3-15 TIME A615 B515 C415 A675 B575 C475 0.32 0.40 0.56
- 0. 67 0.73 0.81 1.06 1.31 1.56 1.81 2.06 2.31 2.56 2.81 3.31 3.81 4.31 4.81 5.31 100.10 99.90 99.90
- 99. 60 99.40
- 99. 20
- 98. 00
- 96. 70 94.90 92.90 90.90 88.80 86.80 84.40 80.20 76.10 72.70 69.20 66.00 99.90 99.90 99.70
- 99. 50
- 99. 20
- 98. 90 97.80 95.90 94.10 91.60 89.30 86.80 84.40 81.60 76.90 72.60 68.60 64.90 61.40
- 99. 70 99.90 99.50 99.40 99.00 98.60 97.60 95.10
- 93. 30.
- 90. 30 87.80
- 84. 80 82.00 78.80 73.60 69.10 64.50 60.60 56.80
- 99. 80
- 99. 45
- 98. 55
- 97. 80 97.30 96.65 94.25 91.90 89.35 86.90 84.50 82.20 79.90 77.80 73.90 70.40 67.30 64.25 61.35
- 99. 60 99.30 98.20 97.25 96.65 95.75 93.15 90.35 87.50 84.70 81.95 79.30 76.90 74.40 70.15 66.45 62.90 59.65 56.75 99.40 99.15 97.85 96.70 96.00 94.85 92.05 88.80 85."65 82.50 79.40 76.40 73.90 71.00 66.40 62.50
- 58. 50 55.05, 52.15 NOTE:
Curve A615, for example, is for a 6 second pump inertia with a second sensor time constant.
See Figures 3-14 and 3-15 for description of curves.
- 128-
3.35 Test Number 30C - Recirculation System Performance 3.35.1
~Pur use The purpose of this test is to obtain recirculation system perfor-mance data under different operating conditions to verify design parameters.
3.35.1.1 Level 1 Criteria Not applicable 3.35.1.2 Level 2 Criteria 1.
The core flow shortfall shall not exceed
.5% at rated power.
2.
The measured core delta P shall not be greater than 0.6 PSI above prediction.
3.
The calculated jet pump M ratio shall not be less than 0.2 points below prediction.
4.
The drive flow shortfall shall not exceed 5'X at rated power.
5.
The measured recirculation pump efficiency shall not be greater than 8 percent below the vendor tested efficiency.
6.
The maximum nozzle and riser plugging criteria of 12% and 10%
respectively, shall not be exceeded.
3.35.2 Test Results 3.35.3 Table 3-39 summarized the recirculation system performance over the operating conditions.
Figure 3-16 indicates the relationship be-tween total core flow and total loop flow..The process computer data bank was updated with the established relationship to provide substitute core flow for the OD-3 and Pl programs.
Figure 3-17 indicates the core delta P as a function of total core flow.
Both design and actual curves agree within the tolerance of the instru-ment accuracy.
Discussion Recirculation system performance data was also obtained during single loop operation.
The data was evaluated and used to estab-lish operation boundary for single loop operation.
During natural circulation in TC-4, core flow was found to be about 6% less than predicted.
No criteria was affected.
The results also agreed wi.th LaSalle 1 test data.
e The maximum core flow achieved with both recirculation flow control valves fully open was 106% of rated.
The safety design basis for the MCPR calculation at 115% maximum core flow was not exceeded.
The recirculation flow control limiter was set to limit the maximum core flow to 102.5% of rated.
- 1'29-
TOTAL CORE FLOW YS TOTAL LOOP FLOW 100 90 80 X
ai 6
CI 0
5 40 IL O
o~
30 V~2 0
10 20 30 40 50 60 70 80 90 100 WDC (% OF RATED 31.7 x 106 )
Figure 3-16
- 130-850207.28A
CORE DP VS TOTAL CORE FLOVf CURVE "A" PREDICTEO 2
O COIL O.O1 ul CCOV CURVE "B" ACTUAL 0
10 20 30 40 50 60 70 80 90 100 TOTAI. CORE FLOW (% OF RATEO)
Figure 3-17
- 131-850207.29A
TABLE 3-39 RECIRCULATION SYSTEM PERFORMANCE Parameter Core flow shortfall
(%)
Core dP (psid)
Actual re ducted Calculated M-ratio Loop A.
Actual
~re
>c ed Loop B.
Actual M~re ~ic ed E
Drive flow shortfall
(%)
Pump efficiency
(%)
Pump A:
Actual Prrei c ted Pump B;
Actual
~re
>c ed Nozzle/Riser Plugging
('4)
N/A N/A N/A 23.29 Less than 0.6 YCT4 psid above prediction N/A N/A N/A 2.416 Shall not be less Y.336 than 0.200 point N/A N/A N/A 2.490 below prediction Y.
330'/A N/A N/A
- 3. 07 Less than 5X at rated power N/A.
80 N/A 80.81 Shall not be less lU than 8X below N/A 83 N/A 83.76 prediction lH TC-2 TC-3 TC-4 TC-6 Acce tance Criteria N/A N/A N/A
.37
. Less than 5% at rated power Maximum nozzle plugging Maximum Riser plugging N/A 6.2 N/A 8.5 N/A 5.8 N/A 8.3 12%
10%
- 132-
3.36 Test Number 30D - Recirculation Runback 3.36.1
~Per ose The purpose of this test is to verify the adequacy of the recircula-tion flow control valve runback to avoid a reactor scram upon the loss of one feedwater pump.
3.36.1.1 Level 1 Criteria 3.36.1.2 Not applicable Level 2 Criteria The recircultion flow control valves shall runback upon a trip of the runback circuit.
3.36.2 Test Results 3.36.3 The runback reduced the recirculation flow control valve position properly, core flow was reduced from 95% to 59% on the 75% load line.
The extrapolated reactor power from the 100% load line deter-mined that the existing flow control valve runback position limiter setpoint would result in a reactor power equal to 69% of rated.
Discussion A single feedwater pump trip test performed at 98.7% power during TC-6 on the 100K load line, further demonstrated the adequacy of the recirculation flow control valve runback to prevent a reactor low water level scram.
- 133-
3.37 Test Number 30E - Recirculation S stem-Non Cavitation Verification 3.37.1
~Per ose The purpose of this test is to verify that no recirculation system cavitation will occur in the operating region of the power flow map.
3.37.1.1 Level.1 Criteria Not applicable 3.37.1.2 Level 2 Criteria Runback logic shall have settings adequate to prevent operation in areas of potential cavitation.
3.37.2 Test Results 3.37.3 The recirculation pump high to low speed transfer logics were veri-fied on low feedwater flow and low differential temperature between reactor dome and recirculation suction during TC-2 and TC-3 respec-tively.
The low feedwater flow setpoint of 27.5% rated (3.93 M
lb/hr) and low differential temperature between reactor dome to recirculation suction setpoint at 9.9'F were verified to be ade-quate to prevent operation in areas of potential cavitation.
Discussion Both recirculation pumps did not transfer simultaneously in TC-2 due to the relay logic sequencing (relay race condition).
The logic was corrected so that any of the low feedwater flow, steam dome to recirculation suction low differential temperature or low level (L-3) signals will cause both pumps to transfer to the LFMG sets at the same time to provide the additional cavitation protection.
- 134-
3.38 Test Number 31 - Loss of Turbine Generator and Offsite Power 3.38.1
~Per ose The major objectives of this test are as follows:
A.
To demonstrate the reactor system transient performance during the loss of the main generator and all off-site power; and B.
To demonstrate acceptable performance of station electrical equipment.
3.38.1.1 Level 1 Criteria Reactor protection system actions shall prevent violation of fuel thecal limits.
All safety
- systems, such as the Reactor Protection
- System, the Diesel Generators, and HPCS must function properly without manual assistance, and HPCS and/or RCIC system action, if necessary, shall keep the reactor water level above the initiation level of the Low Pressure Core Spray, LPCI and ADS systems, and NSIV closure.
Diesel generator shall start automatically.
3.38.1.2 Level 2 Criteria A proper instrument display to the reactor operator shall be demon-
- strated, 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.
If safety/relief valves
- open, the temperature measured by thermo-couples on the discharge side of the safety/relief valves must return to within 10'F of the temperature recorded before, the, valve was opened.
3.38.2 Test Results Reactor transient behavior and station electrical supply system per-formance dur'ing the loss of A-'C test is summarized in Table 3-40, Loss of A-C Test Results.
A chronology of significant events during the transient is outlined in Table 3-41.
The suppression pool temperature increased by 5'F from 75 F to 80 F.
The maximum drywell temperature reached was 129 F.
Proper instrument display to the reactor operator for power, pres-sure, water level, control rod position, suppression pool tempera-ture and reactor cooling system status was maintained with no dependence on specially installed instrumentation.
- 135-
- 3. 38. 3 Discussi on The loss of turbine generator and off-site power was initiated by opening the generator output breakers while preventing transfer of the station electrical loads to the Startup and Backup Startup Transformers.
The reactor was scrammed on Turbine Control Valve Fast Closure signal.
MSIV isolation occurred 8 seconds into the transient due to under-frequency on the RPS buses.
No ECCS initia-tion nor SRV actuation during the transient.
A11 safety systems and electrical supply system performed properly.
- 136-
TABLE 3-40 LOSS OF A-C TEST RESULTS Parameter Diesel Generator Loading Time Div. I D/G Div. II D/G HPCS D/G Peak Reactor Pressure Minimum Reactor Level Value 8.252 seconds 7.202 seconds 11.102 seconds 950 psig
-10" Criteria or Set oint 10.0 seconds 10.0 seconds 13.0 seconds 1076 psig
-137-
TABLE 3-41 CHRONOLOGY OF SIGNIFICANT EVENTS DURING THE LOSS OF A-C TEST Hr.
01 01 01 01 01 01 01 01 01 01 01 01 01 min.
35 35 35 35 35 35 35 35 35 35 35 35 45 Tillle sec.
36 37 37 40 43 43 45 45 46 48 49 57 msec. 980 204 304 004 000 754 304 680 880 654 880 154 Significant Event Generator Output Breakers Open TCV Tast Closure RPS Bl Tripped Reactor
- Scram, TCV Fast Closure Control Rods Fully Inserted RCIC Manually Started RPS MG Set A Underfrequency RPS MG Set B Underfrequency Div. II D/G Loaded to SM-8 Bus Div. I D/G Loaded to SM-7 Bus MSIV's Fully Closed HPCS D/G loaded to SM-4 Minimum Water Level (-10")
Reset Scram
- 138-
3.39 Test Number 33 - Pi in Vibration 3.39.1
~Por oee The purpose of this test is to verify that the 'design stress levels due to piping vibration are not exceeded and satisfy the inspection requirements for condensate and feedwater systems per Regulation Guide 1.68.1.
3.39.1.1 Level 1 Criteria The measured vibration amplitude (peak-to-peak) of the systems monitored shall not exceed the maximum allowable displacements.
3.39.1.2.
Level 2 Criteria The measured amplitude (peak-to-peak) of vibration shall not exceed the expected values.
3.39.1.3 Visual
. Ins ection Acce tance Criteria
- 3. 39. 2 The vibration levels experienced will be evaluated as acceptable if they are too small to be detected by the naked eye with considera-tion given to the following facts:
A.
Proximity to sensitive equipment (pumps, valves, motor control
- centers, control panels, etc.).
B.
Branch connection behavior C.
Performance of nearby component supports If an acceptable assessment of the observed deflections cannot be performed and corrective measures are not available, the inspector will then obtain the magnitude and frequency of the vibration using a portable vibration instrument.
Test Results The steady state vibration amplitudes on the main steam and recircu-lation piping over the entire flow range are summarized in Table 3-42 and Table 3-43.
The transient vibration amplitudes on the main steam line piping during the relief valve actuation, 75'X turbine trip, MSIV full iso-lation and 100% generator load rejection are summarized in Table 3-44.
The transient vibration amplitudes on the recirculation piping during the pump trip and pump restart are summarized in Table 4-45.
At no time did the measured vibration amplitude for the systems monitored exceed the established maximum allowable (Level 1) or expected displacement (Level
- 2) criteria.
- 139-
Discussion The drywell piping vibration data was obtained from the dual pur-pose lanyard potentiometers used in conjunction with the system expansion test.
All vibration data was recorded on PCM tape using the Transient Data Acquisition System, which is capable of recording data at maximum sample rate of 500 samples per second, and providing a.005 inch resolution and a frequency response higher than 20 Hertz.
The PCM tape was then played back for data reduction and analysis.
All vibration data is given in respect to the local co-ordinatee system.
The acceptance criteria is also presented in the local coordinate system to provide direct comparison capability.
Other drywell piping systems that were monitored for steady-state and transient vibration are the
- RWCU, RCIC Steam Supply, SRV (2 lines) tail pipes, RHR SDC Supply and return (Loop A) and Reactor Feedwater.
The transients conducted produced no Level 2 violations.
The fol-lowing is a list of all the transients where data was collected for those systems influenced; 1.
Generator Load Reject at 25K Power (RRC 8
MS piping) 2.
Turbine Trip at 75% power (RRC 8 NS piping) 3.
Main Steam SRV Testing (NS and SRV piping) 4.
Load Reject at 100'X Power (MS,
5.
Reactor Feedpump Trip at 100K Power (FW piping) 6.
RHR Pump Start and Trip During SDC Initiation (RHR piping) 7.
NSIV Full Closure (RRC, NS and SRV piping) 8.
RRC Single Pump Standard Trip (RRC piping) 9.
RRC Simulated RPT (2-Pump Transfer to 15 Hz)
(RRC piping)
Visual inspections were performed on hot piping systems outside the drywell during steadystate and transient conditions.
The systems inspected for steady state vibration were RHR, Feedwater and Conden-.
- sate, RCIC Steam Supply and Exhaust, Main Steam and MSLC 8 RWCU.
During the load reject test, personnel were stationed in the turbine building to assess the MS, FW and Condensate systems vibration.
The RHR piping was also visually monitored during pump starts and trips.
No excessive piping vibration was noted during these tests.
- 140-
TABLE 3-42 STEADY STATE DRYWELL PIPING YIBRATION DATA Main Steam Lines Steam Flow X Criteria Sensor Identification 25%
50%
75%
100%
Level 1/Level 2
( Inch) 1MSA X Y
Z 2MSA X Y
Z 1MSB X
Y Z
2MSB XY' 1MSC X
Y Z
2MSC X
Y Z
1MSD X
Y Z
2MSD X
Y 2.6 3.0 3.7 3.3 3.7 3.1 3.3 2.1 1.6 2.8 2.8 1.9 1.6 1.4 2.1 2.
2.
3.
3.
4, 4.
4.
3.
2.8 2.8 8.3 3.9 3.9 3.0 4.0
!V!
.278/.138
.170/.084
.220/.110
.060
.030
.116/.058
.220/.110
.118/.060
. 212/.106
.03
.020
.106/.054 NOTE:
The values given are in mils (.001 inch
= one mil )
- 141
TABLE 3-43 STEADY STATE DRYMELL PIPING VIBRATION DATA Recirculation Loops Recirculation Flow Criteri a Sensor Identification S.S.
GE's 50%
75%
100%
Level 1/Level 2
(Inch) l.
1RA X
RA2 Y
Z 2.
2RA X
RA3 Y
'Z 3.
3RA X
RA4 Y
Z 4.
4RA X
RA1 Y
Z 5.
1RB X
RB2 Y
Z 6.
2RB X
RB3 Y
Z 7.
3RB X
RB4 Y
Z 8.
4RB X
RB1 Y
Z 1.2 1.4 2.1 2.3 1.6 1.8 1.8 1.6 2.1 2.1 1.9 2.1 1.4 4.0 2.5 2.
2.
2.
2.
2.
4.
3.
2.4 2.6 3.7 3.7 3.7 2.3 3.0 3.5 3.0 6.8 4.9
.102/.050
.232/.116
.1 0.0 0
.118/.060
.104/.052
.100/.050
~
~
2
.132/.116 64.032 0
.118/.060
.064/.032
.028.014 NOTE:
The values given are in mils (.001 inch
=
1 mil)
- 142
TABLE.3-44 TRANSIENT DRYWELL PIPING VIBRATION DATA Main Steam Line Sensor Identification 1MSA X Y
Z 2MSA X YZ.
1MSB X
'Y Z
2MSB X
Y Z
1MSC X
Y Z
2MSC X
Y Z
1MSD X Y
Z 2MSD X Y
Z Rated Pressure Relief Valve Test 40 16 31 30 28 30 13 75% Turbi'ne Tri 19.
3.
55.
59.
35.
42.
MSIV'ull Isolation 45 30 66 35 30 T5 55 110 IPJ 100% Generator Load Rejection 24 22 36 68 72 60 16 64 90 NOTE:
Values given are in mils (.001 inch
=
1 mil)
- 143-
TABLE 3-45 TRANSIENT DRYMELL PIPING VIBRATION DATA Recirculation Loops Sensor RPT Two Identi fication
~Pum Trf 75%
One Pum Tri 100% One Pump Trip 1RA X
Y Z
2RA X Y
Z 3RA X Y
Z 4RA X Y
Z lRB X
Y Z
2RB X
Y Z
3RB X
Y Z
4RB X
Y Z
2.
3.
3.
2.
2.
2.
2.
2.
2.
2.
2.
2.
4.
T
~P~
T~
2.
3.
3.
3.
4, 9.
7.
3.
6.
3.
3.
3.
3.
4.
NOTE:
Values given are in mils (.001 inch
= one mil
)
- 144-
3.40 Test Number 34 - Reactor Internals Vibration
- 3. 40.1
~Pur use The major objectives of this test are as follows:
A.
To provide information needed to confirm the similarity between the reactor internals design and the prototype with respect to flow induced vibration; B.
To fulfill the NRC Regulatory Guide 1.20 for a vibration mea-surement program for nonprototype, Category IY reactor internals.
3.40.1.1 Level 1 Criteria The peak stress intensity may exceed 10,000 psi (single amplitude) when the component is deformed in a manner corresponding to one of its normal or natural modes but the fatigue usage factor must not exceed 1.0.
3.40.1.2 Level 2 Criteria The peak stress intensity shall not exceed 10,000 psi (single ampli-tude when the component is deformed in a manner corresponding to one of its normal or natural modes.
This is the low stress limit which is suitable for sustained vibration in the reacto~ environment for the design life of the reactor components.
3.40.2 Test Results The maximum vibration frequencies and corresponding amplitude for the jet pump riser brace and shroud were measured on the 60%,
75K and 100% load line, during extended recirculation flow, and single and dual recirculation pump trip.
The preliminary measurement analysis indicated that all vibrations were well within both Level 1
and Level 2 criteria.
3.40.3 Discussion The final vibration analysis to determine the actual mode of vibra-tion will be performed by the General Electric at their San Jose office.
The results will be presented as a final report following the completion of the detailed data analysis.
The current scheduled completion date is June 1, 1985.
Following Supply System review, the report will be forwarded to the NRC.
- 145-
3.41 Test Number 35 - Recirculation System Flow Calibration
- 3. 41.1 3.41.1.1
~Pur oee The major objective of this test is to perform a complete calibra-tion of the installed recirculation system flow instrumentation.
Level 1 Criteria 3.41.1.2 Not applicable Level 2 Criteria Jet pump flow instrumentation shall be adjusted such that the jet pump total flow recorder will provide a correct core flow indication at rated condi tion.
The APRM/RBM flow-bias instrumentation shall be adjusted to function properly at rated condition.
The flow control system shall be adjusted to limit maximum core flow to 102.5% of rated by limiting the flow control valve opening position.
3.41.2 Test Results Data in Table 3-46 documents the calibration efforts on the core flow instrumentation and represents the final system configuration.
At 100% power, it requires 41936/41492 GPM recirculation drive flow A/B to achieve 100% core flow.
The transmitter inputs into the APRM/RBM flow-bias instrumentation were recalibrated to reflect these 100% power and flow conditions.
The flow control valve opening position limit was adjusted such that 102.5% of rated core flow is the maximum core flow.
3.41.3 Discussion Prior to'erformi ng the calibration data collection, each flow instrumentation was zero checked against the instrument data sheets.
At 100% power, 100% core flow conditions the total core flow and individual loop flow recorder/indications were adjusted to comply with calculated values.
The jet pump flow distribution is plotted in Figure 3-18, the center jet pumps are exhibiting higher flows than the average jet pump flows.
This is consistent with other BMR-5 five nozzle jet pump plants.
- 146-
TABLE 3-46 RECIRCULATION FLOW INSTRUMENTATION ADJUSTMENTS Date Time Power (MWt, X)
Core Flow (M lb/hr,
%)
Loop Flows:
Loop A:
Cal c/Ind Gain Loop B:
Cal c/Ind Gain Drive Flows:
Loop A:
Cal c/Ind Gain Loop B:
Gale/Ind Gain Core Flow:
Calc/Ind Gain Double Tap Flows:
JP5
= Calc/Ind Gain JP10
= Gale/Ind Gain JP15
= Gale/Ind Gain JP20
= Calc/Ind Gain 11/4/84 2125 3259.5 (98.1) 102 (94%)
49.68/51.08 0.972 52.16/53.32 0.978 38454/37557 1.024 39513/39208 1.008 101.84/106 0.961 5.269/5.3811 0.979 4,884/4.9218 0.992
- 5. 307/5. 3662
- 0. 989 5.232/5.2785 0.991 11/8/84 2350 3323 (100%)
106.3 (98%)
- 53. 721/53. 67 1.001 53.721/53.95 0.973 40655/40099
- 1. 014 40419/40329 1.002 106.2/105.5 1.007 5.637/5.685 0.992 5.277/5.305 0.995 5.353/5.517 0.970 5.22/5.363 0.973 Average Gain 0.987 0.976 1.019 1.005 0.984 0.986 0.994 0.979 0.982 NOTES:
Drive Flows are given in GPM Calc
= Flow from JRPMP01 Edit Ind
= Flow from indication Gain
= Gale/Ind
- 147-
JET PUMP FLOW DISTRIBUTION z
1 ~1 0
CL g
1.05 COa 1.0 LL O
0 2
0.95 DATE
% CORE FLOW a 114~
94 L 11.8.84 AVERAGE 0.9 2
3 4
5 6
7 8
9 10 LOOP A JET PUMPS 1.1 O
I Cl 1.05 ch CI 1.0 0
O O
2 0.95 AVERAGE 0.9 11 12 13 14 15 16 17 18 19 20 LOOP B JET PUMPS Figure 3-18
- 148-0207.30A
3.42 Test Number 70 - Reactor Mater Cleanu System 3.42.1
~Per ose The major objective of this test is to demonstrate specific aspects of the mechanical operability of the Reactor Mater Cleanup System.
3.42.1.1 Level 1 Criteria Not applicable 3.42.1.2 Level 2 Criteria 1.
The temperature at the tube side outlet of the non-regenerative heat exchangers shall not exceed 130'F in the blowdown mode and shall not exceed 120'f in the normal mode.
2.
The pump available NPSH will be 13 feet or greater during the hot shutdown with loss of RPV recirculation pumps mode defined in the process diagram.
3.
The cooling water supplied to the non-regenerative heat exchangers shall be less than 6% above the flow corresponding to the heat exchanger capacity and the exisiting temperature differential across the heat exchangers.
The outlet tempera-ture shall not exceed 180 F.
4.
Recalibrate bottom head flow indicator, RMCU-FI-610 against RWCU flow indicator, RWCU-FI-609, if the deviation is greater than 25 gpm.
5.
Pump vibration shall be less than or equal to 2 mils peak-to-peak (in any direction) as measured on the bearing housing and 2 mils peak-to-peak shaft vibration as measured on the coupling end.
3.42.2 Test Results During normal operation with process diagram flows established, the temperature of the tube side outlet from the non-regenerative heat exchangers was 100'f while during blowdown operation it was 91'F.
The calculated pump available net positive suction head (NPSH) was 523.9 feet in the hot standby mode.
The temperature of the closed cooling water supplied to the non-regenerative heat exchangers was 62 F with the flow at 365 gpm (370 gpm predicted).
The non-regenerative heat exchanger outlet tempera-ture was 140'F.
-149-
The maximum deviation between the bottom drain flow and RWCU system flow indicator was less than 8 gpm.
The peak-to-peak vibration on RWCU pump A and B were 1.3 and 0.5 mils respectively; the peak-to-peak shaft vibrations were 0.75 mils on both pumps.
3.42.3 Discussion For the RWCU system tests, appropriate flows and temperatures were established based upon the process flow diagram.
On the BWR/5 pro-duct line the bottom head drain line flow orifice and associated flow instrumentation have been replaced with a system which relates differential pressure across the bottom head (lower-plenum-to-drain-pressure differential) to the drain line flow.
An approximate flow-differential pressure relationship was determined by drawing all the Reactor Water Cleanup Unit (RWCU) system flow through the bottom head drain and comparing the system flow indication with the differ-ential pressure measurements.
This relationship is illustrated in Figure 3-19.
The differential pressure indication was used to con-firm adequate bottom head drain flow for both test and normal opera-tion purposes.
-150-
RWCU BOTTOM HEAD FLOW INDICATION 70
~o 80 4
RO I
O 5 OK CLd0 Ill O
25 50 75 100 125 BOTTOM HEAD DRAIN FLOW (GPM) 150 Figure 3-19 850207.31 A
- 151-
3.43 Test Number 71 - Residual Heat Removal S stem 3.43.1
~Pur ose The major objectives of this test are as follows:
to demonstrate the ability of the Residual Heat Removal (RHR) System to remove residual and decay heat from the nuclear system so that refueling and nuclear servicing can be performed.
3.43.1.1 Level 1 Criteria Not applicable 3.43.1.2 Level 2 Criteria The RHR system shall be capable of operating in suppression pool cooling and shutdown cooling modes (with each heat exchanger) at the flow rate and temperature differential indicated on the process diagram.
3.43.2 Test Results A summary of the RHR system data obtained when in suppression pool cooling and shutdown cooling modes of operation is contained in Table 3-47.
The system performance levels were acceptable.
- 152-
TABLE 3-47 RHR SYSTEM PERFORMANCE DATA Parameter oop Test Data oop B
Process Diagram Value Suppression Pool Hx cooling water inlet
( F) 59.3 Hx cooling water outlet ('F) 67.8 Hx cooling water flow (GPM) 8586 Hx RHR inlet ('F)
- 91. 9 Hx RHR outlet
( F)
- 80. 5 RHR Flow (GPM) 7364 Cooling'Mode 59.6 68.4 8996 90.1 75.4 7348 95 103.2 7400 70-120 103.1 7450 Shutdown Cooling Mode Hx cooling water inlet ('F)
Hx cooling water outlet ('F)
Hx cooling water flow (GPM)
Hx RHR inlet
( F)
Hx RHR outlet ('F)
RHR Flow (GPM) 46 100 8963 286 120 2314 54.1 97.1 8859 302 141 2768 85 125 7400 335 295 7450 3.43.3 Discussion Following a reactor scram in TC-6, the RHR shutdown cooling mode was demonstrated.
RHR system was operated at a reduced rate to allow shutdown cooling operation at time intervals long enough to estab-lish steady state heat exchanger operation without exceeding reactor cooldown limit because of the low reactor decay heat inventory.
The heat removal rate data has been corrected to account for the greater than design hx cooling flow rates to provide for direct comparison to the criteria.
The RHR Heat Exchanger Duty is summarized as follows:
TABLE 3-48 RHR HEAT EXCHANGER DUTY Mode
~HX Loo Heat Removal Heat Removal Suppression Pool Cooling Suppression Pool Cooling Shutdown Cooling Shutdown Cooling 30.15 MBTU/hr 30.15 MBTU/hr 148 MBTU/hr 31.7 MBTU/hr 32.6 MBTU/hr 200 MBTU/hr B
148 MBTU/hr 160 MBTU/hr Due to the excess cooling capacity of the heat exchangers and the capability to adjust flow to meet the process diagram flow levels, the performance data is considered acceptable.
-153-
3.44 Test Number 72 - Drywell Atmos here Coolin
- 3. 44.1
- 3. 44.1.1
~Per ose The major objective of this test is to verify the ability of the Drywell Atmosphere Cooling System to maintain design conditions in the drywell during operation and post-scram conditions.
Level 1 Criteria 3.44.1.2 Not applicable Level 2 Criteria The drywell cooling system shall maintain an average ambient air temperature of 135'F or less and an 150'F or less ambient tempera-ture at any single location in containment.
3.44.2 Test Results 3.44.3 The latest survey of selected maximum local drywell temperatures is presented in Table 3-49.
This represents the existing drywell cool-ing system performance.
Discussion The drywell cooling system has a total of five cooling units of which three are located in the lower drywell area and two service the upper drywell region.
The average heat removal capacity per unit exceeded design values considerably.
The data presented on Table 3-49 was taken with all the drywell cooling units in opera-tion.
The average drywell air temperature (as measured at the air inlet to the cooling units) did not exceed the 135'F limit during the entire -test program.
The local containment temperatures exceed-ing 150'F in the lower sacrificial shield was dispositioned accept-able because no safety equipment was located in this area.
The dry-well cooling system has undergone major ducting modifications during T/C heatup and other plant modifications are being implemented to improve the systems cooling capacity.
A significant aspect of the modification reversed cooling air flow in the vessel annulus region causing an increase in what had been previously considered.
An evaluation of the reactor vessel skirt and pedestal indicated that temperatures up to 210'F or an average of the three detectors in the skirt region less than 203 F is acceptable.
These limits have been included in the operations staff surveillance process.
- 154-
TABLE 3-49 LOCAL DRYMELL AIR TEMPERATURES Location Air Tem erature Upper Ring Header Return Upper Sacrificial Shield Vessel Head Flange Head Return Duct Safety Relief Valve Area Lower Sacrificial Shield CRD Area 135 142 127 130 124 176 135
- 155-
3.45 Test Number 73 - Coolin Water S stems 3.45.1 Pur ose The obgective is to assess the heat removal performance of the Standby Service Water (SW) system, the Reactor Building Closed Cooling Mater (RCCM) System, and the Turbine Building Service Water (TSM) System.
3.45.1.1 Level 1 Criteria Not Applicable 3.45.1.2 Level 2 Criteria The system heat transport parameters either meet the requirements of the design specifications, or provide adequate cooling to the com-ponents serviced such that they operate satisfactorily.
3.45.1.3 Level 3 Criteria Not Applicable 3.45.2 Test Results A survey of selected groups of SW,
- RCCW, and TSW equipment heat transport performance data is presented in Table 73.1.
3.45.3 Discussion Each system has been assessed as providing adequate component cool-ing.
Some of the differences between the A/E design parameters selected as the acceptance criteria and the test data is a combina-tion of the following:
1.
The design conditions for flow and inlet temperature were not matched due to the current ambient conditions and a problem encountered at MNP-2 with silt accumulation in cooling system regions of low flow.
This fouling process was minimized by increasing flows to components with low design flow/velocity and therefore subject to silt fouling.
This increased the flow above design levels.
The SM controller error data is also influenced by the silting problem.
2.
Lower inlet temperatures due to the winter conditions and plant configuration created higher than design heat transport rates.
- 156-
TABLE 73.1 EQUIPMENT HEAT TRANSPORT PERFORMANCE DATA SERVICE WATER SYSTEM:
Parameter Par ameter PRA-CC-lA Heat Transport PRA-CC-1B Heat Transport DG Room lA Heat Transport DG Room 1B Heat Transport LPCS-P-1 Heat Transport RHR-P-2A Heat Transport RHR-P-2B Heat Transport RHR-P-2C Heat Transport RRA-CC-ll Heat Transport Control Room Ambient Air Temp.
Cable Spreading Room Ambient Air Temperature Radwaste Critical Switchgear Room Ambient Air Temperature RCIC Pump Room Ambient Air Temperature HPCS DG Area Heat Transport SW-P-1A Discharge Pressure SW-P-1B Discharge Pressure HPCS-P-2 Discharge Pressure CCH-CU-lA Heat Transpor t Data 4.403xl058tu/hr 4.983xl05Btu/hr 13.929x106Btu/hr 14.679xl068tu/hr 5.256xl04Btu/hr 2.704xl04Btu/hr 5.356xl03Btu/hr 4.005xl03Btu/hr 5.397x104Btu/hr 73'F 73'F 85'F 85'F 5.43xl05Btu/hr 220 psig (507.5 ft.)
210 psig (484.4 ft.)
59 psig (128.5 ft.)
3.858x105Btu/hr A/E Design 4.040xl05Btu/hr 4.040xl05Btu/hr 14.366xl06Btu/hr 14.366x106Btu/hr 3.200xl058tu/hr 2.850xl058tu/hr 2.850xl05Btu/hr 2.850xl05Btu/hr 7..128x104Btu/hr 78'F 96'F 102'F 103'F 7.366x106Btu/hr 435 ft.
435 ft.
85 ft.
N/A
- 157-
TABLE 73.1 (Condt)
Total Heat Transported by RCC System 136. 54xl 05Btu/hr REACTOR BUILDING CLOSED COOLING WATER SYSTEM:
Parameter Data A/E Design Parameter 44.39x106Btu/hr RWCU Non-Regenerative Heat Exchanger Heat Transfer Rate Drywell Coolers Heat Transport
'I 9.46xl06Btu/hr 6.03xl06Btu/hr 15.09xl06Btu/hr 5.00xl068tu/hr PLANT SERVICE WATER SYSTEM'ain Turbine Oil Cooler Controller Error Main Turbine Hydrogen Cooler Controller Error Exciter Coolers Controller Error Stator Water Coolers Controller Error TO-HX-2A,B Effluent Temperature Controller Error TO-HX-2C,D Effluent Temperature Controller Error WMA-AH-53A Effluent Air Temperature Controller Error WMA-AK-53B Effluent Air Temperature Controller Error
-11.67%
- 3. 81%
- 45. 33%
-2.15'X 0%
- 1. 82'X 14.29%
0%
- 158-
3.46 Test Number 74 - Off as System 3.46.1
~Pur use The major objectives of this test are as follows:
A.
To verify the proper operation of the Offgas System over its expected operating parameters; B.
To determine the performance of the activated carbon adsorbers.
3.46.1.1 Level 1 Criteria The release of radioactive gaseous and particulate effluents must not exceed the limit specified in the Technical Specification.
There shall be no loss of flow of dilution steam to the non-condensing stage when the steam jet air ejectors are pumping.
3.46.1.2 Level 2 Criteria The system flow, pressure, temperature, and relative humidity sHall comply with the design specifications.
The catalytic recombiner, the hydrogen analyzer, the activated carbon beds, and the filters shall be operable.
r 3.46.2 Test Resul ts 3.46.3 The system performance data were taken at steady state conditions during heatup, Test Condition 1, 3 and 6.
All applicable Level 1
Criteria were satisfied at each testing level.
Several parameters were initially outside the system design specification.
The Offgas System operating results are summarized in Table 3-50.
It was concluded that the Offgas System is capable of performing all design functions.
The Krypton-85 retention time prior to initial steam flow to the main condenser was measured equal to 136 cc/gram which satisfied the
" expected performance level of 105 cc/gram.
Discussion During the heatup and Test Condition 1, the maximum dilution steam flow to the non-condensable stage of the steam jet air ejector was 6400 lb/hr which was below the minimum required value of 8464 lb/hr.
Bypass piping was added. around the second stage air ejector steam supply and the proper dilution steam flow was obtained.
The offgas flow was reduced from 140 scfm during TC-3 to 73 scfm at TC-6 but was still higher than maximum desirable 30 scfm.
The reduction of condenser air inleakage will be a continuous effort.
- 159-
TABLE 3-50 OFFGAS SYSTEM DESIGN PARAMETERS AND RESULTS 1 of 3 Date Parameter Indicator Normal 0 eration Range Result for Test Condition Heatup 1
3 6
05/04/84 05/08/84 09/04/84 ll/04/84 Core Thermal Power
(%of 3323 tQt)
Dilution Steam (ibm/hr)
SJAE Outlet Pressure (psig)
OD3, Opt 2 MS-FI-25A(B)
OG-PIS-600A(B)
N/A 10100-10600 lb/hr 0.5-5 psig 3.5 6300 15 6400 1.5 48.7 9800 99.3 10700 1.5 Preheater Outlet Temperature
('F)
Active Recombiner Temperature
('F)
Bottom Middle Top Active Recombiner Temperature
('F)
Bottom Middle Top OG-TIS-601A(B)
OG-TRS-602 TE-3A(B)
TE-4A(B)
TE-5A(B)
OG-TRS-602 TE-3A(B)
TE-4A(B)
TE-5A(B) 325-375'F 375-830'F 375-830'F 375-830'F 375-830'F 375-830'F 375-830'F 370 365 350 340 395 395 395 418 417 420 480 480 485 625 625 625 (Loop A)
(Loop A)
(Loop A)
(Loop A) 210 302 340 235 290 335 350 400 410 325 420 460 (Loop B)
(Loop B)
(Loop B)
(Loop B)
O.G.
Condenser Condensate Outlet ('F)
O.G. Condenser Offgas Outlet ('F)
COND-TI-4 COND-TIS-6 130'F 150'F 68 87 73 90 97 97 118 110
TABLE 3-50 OFFGAS SYSTEM DESIGN PARAMETERS AND RESULTS Page 2 of 3 Parameter H2 Concentration (X)
Indicator OG-H2R-605 Normal 0 eration Ran e
0-0.1%
Result for Test Condition
~Heatu 1
3
/
Non-Detec-Non-Detec-0 table table 0.1 Offgas Flow (scfm)
Glycol Pump Disch.
Pressure (psig)
Glycol Tank Temp ('F)
OG-FR-617 GY-PI-631 GY-TRS-630 6-30 scfm 15-50 psig 32.5-35.5'F 49 34 50 33 150-170 185 140 47 33 73 30 Moisture Separator Outlet Temp
( F)
Prefilter dP (inch water)
Dryer Out Dewpoint Temp
( F)-
Regen Chiller Out Temp ('F)
OG-TRS-610A(B)
OG-DP IS-611A(B)
OG-TR-641A(B)
OG-T IS-641A( 8 )
36-45'F 1"
WC -100'F 36-45'F 39 0.5-2 42
-79 40
-86 40-60 43 0.6
-90 40-45 Adsorber Train dP (psid)
Adsorber Vessel Temp 12A, (128)
- 12A, (12B)
- 12A, (12B)
- 13A, (13B)
- 14A, (14B) 15A, (150)
OG-DP IS-612 OG-TRS-613 OG-TE-23A(B)
OG-TE-24A(B)
OG-TE-25A(B)
OG-TE-26A(B)
OG-TE-27A(B)
OG-TE-28A(B) 2.6 psid
+5
-5'F
+5 - -5'F
+5 - -5'
+5 - -5'F
+5 - -5'F
+5 -
'F (Note 1)
Not in Service Not in Service Not in Service Not in Service Not in Service Not in Service Not in Service 0-1.5 99 98 99 88 88 0.6 0.3 0
5 ~
0 2
0 16
LE 3-50 OFFGAS SYSTEM DESIGN PARAMETERS AND RESULTS e
P 3of3 Parameter Indicator Normal 0 eration Ran e
Result for Test Condition
~Heata 1
3 Adsorber Vault Temp
( F)
After Filter dP
( inch water)
Outside Air Temp ('F)
Outside Air X Relative Humidity OG-TRS-614 OG-DPIS-619
+5 -5'F 1"
WC Not in Service 0.5-2 51 90 0-20 0.5 88 18 0
0.5 40 71 Note 1:
The charcoal beds were bypassed during the heatup
4.0 SPECIAL TEST RESULTS 4.1 Moderator Tem erature Coefficient 4.1.1 4.1. 2
~Pur ose
'The moderator temperature coefficient measurement was conducted to provide a benchmark for the SIMULATE core simulator code utilized by the Supply System.
This measurement was also performed to supply temperature reactivity correction factors for estimated critical positions and supplement the data provided in the cycle management report.
Test Descri tion 4.1.3 The measurement was performed with the reactor in a just critical condition approximately one decade below the heating range.
An insequence control rod was withdrawn, placing the reactor on a posi-tive period.
The reactor was allowed to continue on this period until the moderator and doppler effects again returned the reactor to a just critical condition.
Test Results The temperature coefficient (moderator plus doppler) was measured to be -4s9 x 105 delta K/K/ F at a 210'F moderator temperature.
4.2 In-Plant Safety Relief Valve Test 4.2.1 4.2.2
~Pur ose In response to NUREG-0763, "Guidelines for Confirmatory In-Plant Tests of Safety-Related Discharges for BWR Plants",
the Supply Sys-tem committed to perform an in-plant test to measure the differences between local and bulk suppression pool temperatures during a main steam relief val ve discharge.
Test Descri tion In accordance with the NUREG-0783 guidelines, the local temperature was to be measured by a sensor mounted on the containment wal.l oppo-site the discharging quencher.
Sensor SPTM-TE-12 and the discharge piping from MSRV-3B met this geometric criteria.
The test was conducted in conjunction with the safety relief valve capacity testing performed between test conditions 2 and 3.
MSRV-3B was the first valve opened in the series of relief valve capacity measurements and was held open for 4-1/2 minutes.
Data was acquired on tape at 500 samples per second and plotted by playback at 20 samples per second
- 163-
r P,,f,".
4.2.3 Test Result At 40 seconds into the transient the largest differences between local and average suppression pool temperature was experienced at 14'F delta T.
The average difference during the 4-1/2 minute dis-charge was approximately 8'F delta T.
Acceptable performance was demonstrated by an average temperature differenece of less than 15 F delta T.
WNP-2 performance was within acceptable bounds.
4.3 Sacrificial Shield Mall (SSM) Verification To confirm the adequacy of the WNP-2 sacrificial shield wall, a special test was performed to obtain radiation measurements at specific locations inside the drywell.
The test had two objectives:
l.
To verify that voids discovered in the sacrificial shield wall were adequately filled to bring the wall to its designed radiation shiel ding capability.
2.
To verify that Class 1E safety related electrical equipment in the Primary Containment between elevations 533'nd 557'reactor core zone) will not receive a reactor lifetime radiation exposure above designed limits.
8ased on the results of the radiation measurements it was concluded that all equipment locations had radiation levels below the design criteria and radiation levels near the weld ring gap and the voids that were filled were within the design criteria verifying the sacrificial shield wall was adequately repaired 4.4 Loose Parts Detection System The primary purpose of this test was to adjust the trip threshold and sensitivity of the Loose Parts Detection System (LPDS) as primary coolant system noise varied during power ascension, to obtain optimal set~ings for normal plant operation.
Another objective was to record on magnetic
- tape, baseline noise characteristics for various operating modes to use as comparisons during plant life.
Tests were performed during test conditions
- heatup, 2,
3 and 6.
Channel gains, trip tkresholds, and filter roll-offs were adjusted to optimize system sensiti vity to noi se characteristic of metallic impacts while desensitizing the system to characteristic fluid noises.
The LPOS system was activated to record baseline data during specific plant maneuvers.
- 164-
1.
Recirculation pump motor speed changes (slow to fast and fast to slow).
2.
Recirculation flow control valve position changes.
3.
MSIV position chantes and SRV actuation.
The objectives of this test have successfully been met.
The LPDS system is adjusted such that the system is capable of detecting a loose part with a minimum of false alarm.
Also a better data base has been created to help locate loose parts and develop system behavioral trends.