ML20198H820
| ML20198H820 | |
| Person / Time | |
|---|---|
| Site: | Limerick  |
| Issue date: | 12/31/1985 |
| From: | Leitch G PECO ENERGY CO., (FORMERLY PHILADELPHIA ELECTRIC |
| To: | |
| References | |
| NUDOCS 8601310101 | |
| Download: ML20198H820 (145) | |
Text
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UNIT NO. 1 REPORT OF INITIAL PLANT STARTUP Q DECEMBER, 1984 - REVISION 1 O
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D PHILADELPHIA ELECTRIC COMPANY D
D LIMERICK GENERATING STATION UNIT NO. 1 DOCKET NUMBER 50-352 D
0 REPORT OF INITIAL PLANT STARTUP - REVISION 1 DECEMBER, 1984 3
J SUBMITTED TO THE UNITED STATES NUCLEAR REGULA'IDRY COMMISSION 1 a PURSUANT TO '
l '~' FACILITY OPERATING LICENSE NO. NPF-39
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O Rev. 1 December 1985 O
O PHILADELPHIA ELECTRIC COMPANY LIMERICK GENERATING STATION UNIT NO. 1 O STARTUP REPORT O
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G. M. Leitch, Manager Limerick Generating Station O
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l TABLE OF CONTENTS l PAGE l 1. INTRODUCTION 1-1
? 1.1 Report Abstract 1-2 1.2 Limerick Plant Description 1-3 Table 1.2-1 Limerick 1 Plant Parameters 1-4
'3 l.3 Initial Test Program 1-5 Fig. 1.3-1 Operational Power / Flow Map 1-7 1.4 Major Startup Test Program Administrative
[y Controls 1-9
- 2.
SUMMARY
2-1 2.1 Overall Evaluation 2-2 g Table 2-1 Limerick 1 Milestones 2-3 Table 2-2 Startup Test Program Chronology 2-5 l Table 2-3 Startup Test Performance Dates 2-10 g l Table 2-4 Scram Summary 2-12
- 3. STARTUP TEST PROCEDURES 3-1 3.1 Startup Test Procedure Format and Content 3-2 3 3.2 Acceptance Criteria 3-3
- 4. RESULTS 4-1 4.1 STP-1, Chemical and Radiochemical 4-2 3 Table 4.1-1 ' Chemical and Radiochemical Data Sheet 4-4 4.2 STP-2, Radiation Measurements 4-13 4.3 STP-3, Fuel Loading 4-14 4.4 STP-4, Shutdown Margin Demonstration 4-17 3
4.5 STP-5, Control Rod Drive System 4-19 1
4.6 STP-6, SRM Performance and Control Rod Sequence 4-23
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4.7 STP-9, Water Laval Referenca Leg Temperature 4-25 4.8 STP-10, IRM Performance 4-27 4.9 STP-ll, LPRM Calibration 4-30 l 4.10 SUP-12, APRM Calibration 4-33 l 4.11 STP-13, Process Computer 4-37 l 4.12 STP-14, Reactor Core Isolation Cooling System 4-42 Table 4.12-1 RCIC Test Results Summary 4-46 l
l 4.13 STP-15, High Pressure Coolant Injection System 4-47 l Table 4.13-1 HPCI Equipment Problems 4-51 l Table 4.13-2 HPCI Test Results Summary 4-54 l 4.14 STP-16, Selected Process Temperatures 4-55 l 4.15 STP-17, System Expansion 4-58 4.16 STP-18, TIP Uncertainty 4-64 l
l 4.17 STP-19, Core Performance 4-65 l 4.18 STP-20, Steam Production 4-67 l 4.19 STP-21, Core Power - Void Mode Response 4-68 l 4.20 STP-22, Pressure Regulator 4-70 l 4.21 STP-23, Feedwater System 4-72 l 4.22 STP-24, Turbine Valve Surveillance 4-76 l 4.23 'STP-25, Main Steam Isolation Valves 4-78 l 4.24 STP-26, Relief Valves 4-81 l 4.25 STP-27, Main Turbine Trip 4-83 l 4.26 STP-28, Shutdown From Outside the Control Room 4-86 l '4.27 STP-29, Recirculation Flow Control System 4-88 l 4.28 STP-30, Recirculation System 4-90 ii
l 4.29 STP-31, Loss of Turbina Generator and Offsite Power 4-93 l 4.30 STP-32, Essential HVAC System Operation and Containment Hot Penetration Temperature Verification 4-95 l 4.31 STP-33, Piping Steady State Vibration 4-100 l 4.32 STP-34, Offgas Performance Verification 4-105 l 4.33 STP-35, Recirculation System Flow Calibration 4-107 l 4.34 STP-36, Piping Dynamic Transients 4-108 l 4.35 STP-70, Reactor Water Cleanup System 4-112 l 4.36 STP-71, Residual Heat Removal System 4-114 1
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SECTION 1 INTRODUCTION 1-1 1
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1.1 REPORT ABSTRACT Thic Startup Repor t, uritten to comply with Technical Specifications paragraph G.9.1.1 thru 6.9.1.3, consists of a summary of the Startup Test Program portion of the Initial Tect Program parformed at Unit 1 of the Limerick l Generating Station. Tais Revision 1 (December 1985) includes the events starting with initial fuel loading and ending uith the completion of Test conditions 4 and 5.
Changes and additions to the original (Revision 0, September 198 5) repor t are identified by a vertical revicion bar symbol in the margin. Since Limerick Unit 1 has not completed the Startup Test Program, supplementary reports vill be submitted on three month intervals as required by Technical Specification G 9.1.3.
The report addresses each of the Startup Tests identified in chapter 14 of the FSAR and includes a description of the moacured values of the operating conditions or characterictics obtained during the test program with a comparison of these values to the Acceptance Criteria.
Alco included is a deccription of any corrective actions required to obtain saticf actory operation.
Thic repor t also provides a brief deccription of the plant, a deccription of the Startup Tect Procedure format and the objectivec of each tect.
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l.2 LIMERICK PLANT DESCRIPTION The Limerick Generating Station is a two unit nuclear power plant. The two units share a common control room, refueling floor, turbine operating deck, radwaste system, and other auxiliary systems.
The Limerick Generating Station is located on the east bank of the Schuylkill River in Limerick Township of Montgomery County, Pennsylvania, approximately 4 river miles downriver from Pottstown, 35 river miles upriver from Philadelphia, and 49 river miles above the confluence of the Schuylkill with the Delaware River. The site contains 595 acres - 423 acres in Montgomery County and 172 in Chester County.
Each of the LGS units employs a General Electric Company boiling water reactor (BWR) designed to operate at a rated core thermal power of 3293 MWt (100% steam flow) with a corresponding gross electrical output of 1092 MWe.
Approximately 37 MWe are used for auxiliary power, resulting in a net electrical output of 1055 MWe. See Table 1.2-1 for Limerick Plant Parameters.
The containment for each unit is a pressure suppression type designated as Mark II. The drywell is a steel-lined concrete cone located above the steel-lined concrete cylindrical pressure suppression chamber. The drywell and suppression chamber are separated by a concrete diaphragm slab which also serves to strengthen the entire system.
The Architect Engineer and Constructor was Bechtel Power Corporation.
The plant is owned and operated by the Philadelphia Electric Company.
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TABLE 1.2-1 Limerick 1 Plant Parameters Parameter Value Rated Power (MWt) 3293 Rated Core Flow (Mlb/hr) 100 Reactor Dome Pressure (psia) 1020 Rated Feedwater Temperature (Deg. F) 420 Total Steam Flow (Mlb/hr) 14.159 Vessel Diameter (in) 251 Total Number of Jet Pumps 20 Core Operating Strategy Control Cell Core Number of Control R .-ds 185 Number of Fuel Bundles 764 Fuel Type 8x8 (Barrier)
Core Active Fuel Length (in) 150 Cladding Thickness Iin) 0.032 Channel Thickness (in) 0.100 MCPR Operating Limit 1.22 Maximum LHGR (KW/ft) 13.4 Turbine Control Valve Mode Full Arc Turbine Bypass Val,ve Capacity (% NBR) 25 Relief Valve Capacity (% NBR) 87.4 Number of Relief Valves 14 Recirculation Flow Control Mode Variable Speed M/G Sets 1-4
1.3 INITIAL TEST PROGRAM The Initial Test Program encompasses the. scope of events l that commences with system / component turnover and I terminates with the completion of power ascension testing. l The Initial Teat Program is conducted in two separate and I sequential subprograms: the Preoperational Test Program and the Startup Test Program. At-the conclusion of these subprograms the plant is ready for normal commercial power operation. Testing during the Preoperational and Startup Test Programs is accomplished in four distinct and sequential phases.
Major Test Phases - Initial Test Program
- a. Phase I - Preoperational Testing
- b. Phase II - Initial Fuel Loading and Zero Power Testing
- c. Phase III - Low Power Testing
- d. Phase IV - Power Ascension Testing Preoperational testing is completed during the Preoperational Test Program. Initial fuel loading and zero power testing, low power testing, and power ascension testing are completed during the Startup Test Program.
Startup Test Program That part of the Initial Test Program which commences with the start of nuclear-fuel loading and terminates with the completion of power ascension testing.
Initial Fuel Loading and Zero Power Testing Phase That part of the Startup Test Program which includes chemical and radiological baseline data collection just prior to nuclear fuel loading, the movement of fuel assemblies from the fuel pool to the reactor core, and reactor open vessel tests. Initial criticality is achieved in this test phase.
Low Power Testing Phase That part of the Startup Test Program which includes the initial reactor heatup to rated reactor temperature and pressure and testing up to and including 5 percent rated reactor power.
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Powar Arcrnsion Test Phnce That part of the Startup Test Program during which testing is performed at various power levels from 5 percent up to and including 100 percent rated reactor power. Testing during the Power Ascension Test Phase is accomplished in five distinct and sequential Test Plateaus.
Test Plateau A - Plant conditions cannot exceed those defined as Test Condition 1.
Test Plateau B - Plant conditions cannot exceed those defined as Test Condition 2.
Test Plateau C - Plant conditions cannot exceed those defined as Test Condition 3.
Test Plateau D - Testing at plant conditions up to and including 100% power (Test Conditions 4, 5 and 6).
Test Plateau E - Warranty Run - final Test Plateau of the Startup Test Program, commencing following the completion of 100% rod line testing The definition of Test Condition is provided in Figure 1.3-1, sheets 1 and 2.
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100 A. NATUMAL CIRCULATION . j S. MINIMUM RECIRCULATION PUMP SPEED ., j C. ANALYTICAL LOWER , LIMIT OP MASTER POWER FLOW CONTROL D. ANALYTICAL UPPER LIMIT OP MASTER POWER FLOW CONTROL 140 -
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TYPICAL STARTUP PATH -TC2 , MINIMUM POWER LINE 20 -
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Operational Power / Flow Map Figure 1.3-1 Sheet 1 1-7 l
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TEST CONDITION (TC) REGION DEFINITIONS Test Condition No. Power-Flow Map Region and Notes 1 Before or after main generator synchronization between 5% and 20%
thermal power within +10, -0% of M-G Set minimum operating speed line in Local Manual mode.
2 After main generator synchronization between the 45% and 75% control rod lines between M-G Set minimum speeds for Local Manual and Master Manual modes.
3 From 45% to 75% control rod lines -
core flow between 80% and 100% of its rated value.
4 On the natural circulation core flow l line - within +0, -20% of the intersection with the 100% power rod line.
5 Within +0, -5% of the 100% control rod linet - within -0, +5% of the analytical lower limit of Master Flow Control.
6 Within +0, -5% of rated 100% power -
within +0, -5% of rated 100% core flow rate.
Figure 1.3-1 Sheet 2 1-8 l
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1.4 MAJOR STARTUP TEST PROGRAM ADMINISTRATIVE CONTROLS Startup testing and power escalation is sequenced in seven distinct Test Plateaus.
- 1. Test Phase II - Initial Fuel Loading and Zero Power Testing (Test Condition Open Vessel)
- 2. Test Phase III - Low Power Testing (Test Condition Heatup)
- 3. Test Plateau A - Test Condition 1
- 4. Test Plateau B - Test Condition 2
- 5. Test Plateau C - Test Condition 3
- 6. Test Plateau D - 100% Rod Line Testing
- 7. Test Plateau E - Warranty Run A Test Plateau Review is performed prior to commencing startup testing in the next higher plateau. The following items shall be completed prior to the Test Plateau Review:
- a. All Startup Tests scheduled for the current Test Plateau have been implemented or deferred, the analyses have been completed, and the test results have been reviewed and approved.
- b. All Startup Test Change Notices affecting tests scheduled for the current Test Plateau have been approved.
- c. All Test Exception Reports affecting tests scheduled for the current Test Plateau have been resolved.
A list of all tests scheduled to be run during a specific Test Plateau is contained in Startup Test Procedure 99.
This proceddre was the primary means to document that all major administrative controls were satisfied.
Startup Test Change Notices (STCN) were written to document test procedure changes which were not made via a complete revision to the test procedure. STCN's were processed and approved independent of test results.
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Tant Exc:ption R porto (TER) ware writtGn to docum:nt th2 description and resolution of all test exceptions as well as the subsequent actions required to close out the exception. The processing and approval of Test Exception Reports was independent of test results. All test exceptions which were resolved but not completely closed prior to the Plateau Review were evaluated and carried over into subsequent test phases.
Major modifications to the Startup Test Program as set forth in the low power license could not be made without receiving prior NRC approval. Major modifications were defined as:
- a. Elimination of any safety-related test.
- b. Modifications of objectives, test methods or acceptance criteria for any safety-related test.
- c. Performance of any safety-related test at a power level different from that stated in the FSAR by more than 5% of rated power.
- d. Failure to satisfactorily complete the entire initial startup test program by the time core burnup equals 120 effective full power days.
- e. Deviation from initial test program administrative procedures or quality assurance controls described in the FSAR.
- f. Delays in the test program in excess of 30 days (14 days if power levels exceed 50 percent) concurrent with power operation.
One modification to the Startup Test Program involved deletion of STP-37, Main Steam System and Turbine Performance and Plant Dynamic Response Verification. This change was made after determining that the objectives of the procedure and requirements of Regulatory Guide 1.68 were being met by other existing STP(s). An appropriate revision to'FSAR Chapter 14 has been initiated.
Another modification to the Startup Test Program involved (1) deleting the performance of subtest STP-1.4, the Reactor Water Cleanup System (RWCU) Performance Testing, during Test Condition 3 and (2) deleting the performance of subtest STP-30.4, Recirculation Pump Runback. These changes were made after determining that the requirements of Regulatory Guide 1.68 were being met by other existing STP(s) and performance of these two subtests were not necessary. These changes were reported to the NRC in a letter dated December 11, 1985.
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SECTION 2 1
SUMMARY
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2.1 OVERALL EVALUATION l
The Limerick Generating Station Unit 1 Startup Test Program l has been successful to date. The Startup Test Program i commenced with fuel loading on October 26, 1984. Test 1 Condition (TC) Heatup was completed on March 4, 1985.
Additional low power testing was performed during the period April 1 through April 17, 1985 in conjunction with the initial roll and testing of the Main Turbine Generator.
The full power license was obtained on August 8, 1985 immediately followed by the commencement of TC 1 testing.
Testing through TC 4 and 5 was successfully completed on November 30, 1985.
All testing identified in Chapter 14 of the FSAR for Test l Conditions Open Vessel, Heatup and TC 1 through 5 have been performed. Individual test results are described in section 4. Open items resulting from test performance are documented by Test Exception Reports and will be resolved and closed at a later date.
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TABLE 2-1 LIMERICK 1 MILESTONES Jul - 1970 Start Construction, Temporary Permit Jun - 1974 NRC 1ssue Construction Permit Dec - 1976 RPV Set Jul - 1982 Start Preoperational Test Program (Energized High Voltage Switchgear)
Aug - 1983 Code Hydro Oct - 1984 Preoperational Test Program Complete Oct 26, 1984 Received Low Power License Oct 26, 1984 Start Fuel Load Nov 13, 1984 Complete Fuel Load Nov 25, 1984 Install RPV Head, Cold Shutdown (Operational Condition 4)
Nov 30, 1984 Complete Vessel Hydro Dec 21, 1984 Complete Prerequisites for Initial Criticality Dec 22, 1984 Initial Criticality Dec 22, 1984 Open Vessel Testing Complete Dec 30, 1984 Commence Test Condition Heatup Testing Jan 14, 1985 Establish Initial Rated Pressure and Temperature Mar 4, 1985 Complete Low Power Testing Apr 1, 1985 Commence Test Condition Heatup retests.
Apr 11, 1985 Initial Main Turbine Roll .
Apr 13, 1985 Initial Generator Synchronization (with reactor power <5%)
Apr 17, 1985 Complete Test Condition Heatup Retests.
Aug 8, 1985 Received Full Power License 2-3 i
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TABLE 2-1 (cont'd)
LIMERICK 1 MILESTONES Aug 10, 1985 Commenced Test Condition 1 Testing Aug 16, 1985 Complete Test Condition 1 Testing.
Court Orders Full Power License Stay Prohibiting Testing Above 5% Power.
Aug 21, 1985 Third Circuit Court of Appeals Lifts Full Power License Stay.
Aug 22, 1985 Commenced Test Condition 2 Testing.
l Sep 17, 1985 Complete Test Condition 2 Testing l Sep 24, 1985 Commenced Test Condition 3 Testing l Nov 14, 1985 Complete Test Condition 3 Testing l Nov 15, 1985 Commenced Test Condition 5 Testing l Nov 30, 1985 Complete Test Condition 5 Testing l Commenced Test Condition 4 Testing l Nov 30, 1985 Complete Test Condition 4 Testing 2-4
TABLE 2-2 STARTUP TEST PROGRAM CHRONOLOGY Oct 18, 1984 Commenced first Startup Test, STP-5.1, "CRD Insert - Withdrawal Checks".
Oct 26, 1984 Received Low Power License.
Oct 26, 1984 Commenced Fuel Loading at 2230.
Oct 31, 1984 Experienced first "RPS Trip" due to IRM B Upscale caused by reconnecting cable.
Nov 9, 1984 Experienced second "RPS Trip" due to loss of power to RPS channels B and D caused by electrical fault in static inverter.
Nov 13, 1984 Last fuel bundle loaded at 0054.
Nov 25, 1984 RPV head installed. Entered Operational Condition 4.
Nov 27, 1984 Commenced operational hydrostatic test.
Nov 29, 1984 Completed operational hydrostatic test.
Dec 21, 1984 Entered Operational Condition 2 Commenced reactor startup at 2305.
Dec 22, 1984 Initial criticality achieved at 0318.
Dec 29, 1984 Completed Plateau Review of Test Condition Opan Vessel (Phase II - Initial Fuel Loading and Zero Power Testing).
Dec 30, 1984 Commenced Test Condition Heatup Heated reactor to 275 degrees F.
Inspected drywell piping to evaluate freedom of expansion.
Jan 2, 1985 Increased reactor pressure to 100 psig.
Jan 5, 1985 Increased reactor temperature to 450 degrees F. ,
Jan 6, 1985 Increased reactor pressure to 600 psig.
Performed scram timing of selected CRD's.
Jan 9, 1985 Increased reactor pressure to 800 psig.
Performed scram timing of selected CRD's.
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TABLE 2-2 (cont'd.)
STARTUP TEST PROGRAM CHRONOLOGY Jan 10, 1985 Initially reached rated reactor pressure and temperature.
Jan 31, 1985 SCRAM #1. While valving in instrument for " Jet Pump Developed Head" RPS trip on Low Level 3 resulted from perturbation to common reference leg shared by Reactor Protection System instruments.
Commenced outage.
Feb 16, 1985 Completed Outage. Resumed Heatup testing.
Mar 1, 1985 SCRAM #2. Reactor was manually scrammed on completion of active Heatup testing.
Entered Low Power Outage.
Mar 4, 1985 Drywell piping inspected (freedom of expansion) after cooldown. Test Condition Heatup Complete.
Apr 1, 1985 Completed Low Power Outage.
Commenced Test Condition Heatup Retests.
Apr 11, 1985 Initial Main Turbine Roll Apr 13, 1985 Initial Generator Synchronization Apr 17, 1985 Reactor Shutdown at completion of Test Condition Heatup retests. Commenced Outage.
Jul 31, 1985 Completed Plateau Review of Test Condition Heatup (Phase III - Low Power Testing).
Aug 8, 1985 Received Full Power License Aug 10, 1985 Commenced Test Condition 1 Testing (IRM/APRM Overlap)
Aug 12, 1985 Placed Reactor Mode Switch in Run, entered Operational Condition 1. Increased reactor power to 10%.
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STARTUP TEST PROGRA!! CIIRO!! OLOGY l
Aug 21, 1985 Completed Plateau noviou of Test Plateau A l (Tect Condition 1). Third Circuit Court of Appeals liftc Stay on Full Power Licence.
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Aug 22, 1985 Tont condition 2 testing commenced at 24% power, on the 50% rod-line.
l Sep 6, 1985 SRV capacity tost at ented pressure, STP-26.2 Sep 7, 1985 Turbine trip uithin Bypass Valvo capacity at 21.5%
power for STP-27.1 Sep 11, 1985 SCRAtt 5 3. Lou reactor unter level. Condensato I pump trip caused low feed pump cuction proscure reculting in a food pump trip.
Plant cooldown from Remote Shutdoun panel for STP-28.2 l Sep 12, 1985 Restarted reactor SCRA!! # 4. !!anual scram f rom Remote Shutdown panel for STP-28.1.
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l Sep 13, 1985 Restarted reactor.
1 Sop 16, 1985 SCRA!! # 5. Locc of Of f site Power test, STP-31.1 at 20% power completed. Reactor scrammed on low reactor unter levol.
l l l Sep 17, 1985 Rectarted reactor.
l *est condition 2 testing completed.
l Sep 23, 1985 Test condition 2 plateau review completed.
l Sep 24, 1985 Test condition 3 testing commenced.
l Sep 25, 1985 Recirc flow raised to 100%; 42% power.
SCRA!! # G . Turbino trip from 50% power for STP-ll Oct 8,1985 27.3
! Commenced Outage for condencer inspection and l foeduator cleanup.
l Oct 14, 1985 Completed Outage. Rectarted reactor.
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TABLE 2-2 (cent'd)
STARTUP TEST PROGRAM CilRONOLOGY l Oct 15, 1985 SCRA!! 07. At 3% power on low roactor water level during reactor startup.
l Rostarted reactor.
- l 11ov 7, 1985 Doublo Recirc Pump trip for STP-30.2 l Nov 9, 1985 !!PCI Cold Quick Start to Reactor Vessel, STP-15.5.
!!ov 14,1985 SCRAM #8. Turbino trip from 75% power for STP-27.3.
l Toct Condition 3 tocting completed.
l !!ov 15,1985 Rostarted reactor.
l Tect Condition 3 plateau review completed.
l Toct Condition 5 tocting commenced.
l 11ov 1G, 1935 !anual reactor chutdoun.
l Commenced outage for CIV repairc.
l !!ov 10,193 5 Completed outage. Roctorted reactor.
l tiov 20,1985 f.tanual reactor chutdown.
l Commenced outage for IR!! detector replacement.
!!ov 24, 190 5 Completed outage. Replaced 1 SRf! and 3 IRM detectors.
l Itostarted reactor.
l tiov 26, 1935 Bypace valvo capacity test at 35% power for STP-27.2.
l trov 27,1 >83 Rods at 100% rod-line, 64% power, 54% core flou.
l !!ov 30, 1905 Toct Condition 5 tocting completed.
Double Rocirc pump trip to natural circulation.
ll Tect condition 4 tocting commencod.
l Toct Condition 4 tocting completed.
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TABLE 2-4 SCRAM
SUMMARY
No. Date T.C. Cause 1 1/31/85 H/U Unplanned #1 - scram on RPS Low Level 3 due to valving in instrument for
" Jet Pump Developed Head" which had common reference leg with Narrow Range Reactor level.
2 3/01/85 H/U Planned #1 - Manual scram on completion of T.C. Heatup in conjunction with commencing maintenance outage.
3 9/11/85 2 Unplanned #2 - scram on low level, due to loss of feed water. Condensate pump trip caused feed pump trip due to low feed pump suction pressure.
4 9/12/85 2 Planned #2 - Manual scram from Remote Shutdown panel during STP-28.1.
5 9/16/85 2 Planned #3 - scram on low level during Loss of Site Power test, STP-31.1.
6 10/08/85 3 Planned #4 - Turbine Trip from 50% power during STP-27.3 7 10/15/85 3 Unplanned #3 - scram on low level during plant startup.
8 11/14/85 3 Planned #5 - Turbine trip from 75% power during STP-27.3.
2-11
1 1
i SECTION 3 STARTUP TEST PROCEDURES 1
3-1
3.1 STARTUP TEST PROCEDURE PORMAT AND CONTENT Starcup Test Procedures are generally written to demonstrate and verify the performance of a system or control system, to monitor the unit's response to a major transient, or to perform a specific activity. Because of the nature of Startup testing, and to facilitate procedure control, each Startup Test Procedure consists of a Main Body and one or more Subtests.
The 6.ain Body of a Startup Test Procedure provides an overall test description, lists the test objectives, references and acceptance criteria and contains information necessary to successfully prepare for the implementation of Subtests.' The Main Body consists of the following sections:
- 1. Objectives
- 2. Description
- 3. Acceptance Criteria
- 4. References
- 5. Procedure
- 6. Appendices (optional)
The Subtests contain the step-by-step instructions necessary for final preparations for the test, the actual performance of the test, and the analysis of data collected during the test. A Subtest consists of the following sections:
- 1. Discussion
- 2. Precautions
- 3. Test Equipment
- 4. Prerequisites
- 5. Initial Conditions
- 6. Test Instructions
- 7. Analysis
- 8. Appendicen (optional)
A Startup Test Procedure contains as many Subtests as required to' satisfy all the Acceptance Criteria listed in the Main Body and to effectively conduct testing at various plant conditions. If the same Identical subtest was performed more than once, provisions were made to identify plant conditions at which the Subtest was implemented.
3-2
302 ACCEPTANCE CRITERIA Acceptance criteria may be either quantitative or qualitative. Quantitative acceptance criteria specify that test or equipment expected values are in accordance with test requirements (FSAR, equipment specification, test specifications, etc.). These criteria state expected l
values such as flows, temperatures, pressures, currents, voltages, etc., required under specific conditions. Such values are specified as maximums or minimums, or tolerances are provided. Qualitative acceptance criteria specify test or equipment functions (an event does or does not occur),
such as automatic start, sequencing, or shutdown occurring under specified conditions.
Acceptance criteria are categorized as Level 1 or Level 2 l which are defined below:
l l a. A Level 1 criterion normally relates to the value l of a process variable assigned in the design of l the plant, component, systems or associated l
equipment. If a Level 1 criterion were not satisfied, the plant would be placed in a suitable hold condition, until resolution was obtained. Tests compatible with the hold condition would be continued. Following resolution, applicable retesting would be reperformed to verify that the requirements of the Level 1 criterion were satisfied.
I
- b. A Level 2 criterion is associated with expectations relating to the performance of systems. If a Level 2 criterion were not satisfied, operating and testing plans would not necessarily be altered. Investigations of the measurements and of the analytical techniques used for the predictions would be performed.
3-3 f
I
SECTION 4 RESULTS 1
l l
ll 4-1
4.1 STP-1, CHEMICAL AND RADIOCHEMICAL i
OBJECTIVES The principal objectives of this test are a) to secure information on the chemistry and radiochemictry 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 entire reactor system meet specifications 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, 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 measurements of specific nuclides, and special chemical tests.
ACCEPTANCE CRITERIA Level 1 Chemical factors defined in the Technical Specifications and Puel Warranty must be maintained within the limits specified.
The activity of gaseous and liquid effluents must conform to licenne limitations.
Water quality must be known at all times and must remain ;
within the guidelines of the Water Quality Specifications. !
Level 2 None 4-2
RESULTS STP-1.1, Pre-Fuel Lord Data Chemical and radiochemical characteristics of reactor water, stored makeup water, standby liquid, closed cooling system water, and floor drain water were measured. Results showed that all water chemistry values were within applicable limits. Baseline data for stack effluents and radiological dose rates were established. All test acceptance criteria were satisfied. Refer to Table 4.1-1 for test results.
STP-1.2, Chemistry Data Chemical and radiochemical characteristics of reactor water, control rod drive water, condensate demineralizer influent and effluent, feedwater, stored makeup water and floor drain water were measured at various times during power ascension. With two test exceptions, results showed that all water chemistry values were within applicable limits. Baseline data for North and South stack effluents and radiological dose rates were established. Differential pressure across each condensate filter /demineralizer was monitored to observe operation and performance and to predict rates of scale and corrosion product buildup. All test acceptance criteria were satisfied. Refer to Table '
4.1-1 for test results.
STP-1.3, Gaseous Effluent Sampling and Analysis l In Test Condition i and 3 offgas radiation monitor readings were compared with readings from grab samples taken at the same locations to develop a corelation between the two.
Additionally, the radiolytic gas production rate was determined. There are no acceptance criteria associated with this test.
l STP-1.5, Radiation Buildup on Piping t'
Radiation levels on the Reactor Recirculation, Main Steam Lines and Reactor Water Cleanup System piping and components was obtained following reactor shutdown. These readings were recorded 5 days following reactor shutdown with 391.4 Equivalent Full Power Hours (EPPH) of reactor operation.
No acceptance criteria were verified in this test.
Analysis consisted of obtaining baseline radiation data for radiation buildup evaluation.
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Notes for Chemical and Radiochemical Data Sheets 1
NOTE (1) Conductivity Chloride pH at 25 umho/cm at 25 ppb Degrees C Degrees C Pre-Fuel Load Limits 53.0 5500 5.3-7.5 Limits for Power Operation 51.0 $200 5.6-8.6 Limits for Startup $2.0 $100 5.6-8.6 or Hot Shutdown Limits applicable at $10.0 5500 5.3-8.6 all other times NOTE (2)
Concentrations of radioactive material released in liquid effluents to unrestricted areas are limited to levels specified in 10CFR Part 20 Appendix B, Table II, Column 2 for nuclides other than dissolved or entrained noble gases.
Summary of Test Exceptions and Recommendations:
- a. Control Rod Drive water (Condensate Demineralizer Effluent) l dissolved oxygen was 80 ppb in TC Heatup, compared with a recommended maximum of 50 ppb. -
Corrective Action: Investigate possible sources of air in-leakage. Source of air in-leakage identified and corrected during initial roll of the Main Turbine. Subsequent dissolved oxygen levels within required limit,
- b. Feedwater metals were not analyzed because the necessary in-line sampling equipment had not been installed at the time of the test.
Corrective Action: This sample head, designed to holo a filter and ion exchange paper for crud and filtrate metals l analysis, has been installed. Samples were taken in subsequent test conditions, i
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4.2 STP-2, RADIATION MEASUREMENTS OBJECTIVES The objectives of this test are to a) determine the background radiation levels in the plant environs prior to operation for base data to assess future activity buildup and b) monitor radiation at selected power levels to assure the protection of personnel during plant operation.
ACCEPTANCE CRITERIA .
Level 1 The radiation doses of plant origin and the occupancy times of personnel in radiation zones shall be controlled consistent with the guidelines of the standards for protection against radiation as outlined in 10CFR20
" Standards for Protection Against Radiation".
Level 2 None RESULTS STP-2.1, Radiation Surveys Radiation Surveys were taken in the plant environs prior to fuel load and first reactor criticality, at rated temperature and pressure (critical at <5% CTP), at test condition 2 (23.2% CTP) and at test condition 3 (48.5%
CTP). Approximately 380 Radiation Base Point (RBP) locations were surveyed and measurements were also made in transit from one RBP to the next.
All radiation dose rate rates were measured to be well less than the design values with a maximum gamma dose rate of 6 mrem /hr recorded for one RBP in TC3 for the Turbine building (zone V).
4-13
4.3 STP-3, FUEL LOADING OBJECTIVE The objective of this test is to load fuel safely and efficiently to the full core size.
ACCEPTANCE CRITERIA Level 1 The partially loaded core must be subcritical by at least 0.38% delta k/k with the analytically determined strongest rod fully withdrawn.
Level 2 None RESULTS STP-3.1, Fuel Load The initial core of Limerick Unit 1 was successfully loaded with 764 fuel assemblies in 17 days. Adequate shutdown margin was demonstrated after 144 bundles were loaded.
Control rod functional tests (STP-5.1) were performed in parallel with loading the fuel. The full core verification was performed to show that all fuel assemblies were properly loaded, oriented, and seated in the core. The Level 1 Acceptance Criterion was satisfied.
The Level 1 acceptance criterion stated that the partially loaded core must be subcritical by at least 0.38% delta k/k with the analytically highest worth control rod fully withdrawn. After 144 fuel assemblies were loaded, rods 38-19, 22-19, 30-35 and 30-27 (analytically determined to have a total worth greater than that of the highest worth control rod) were withdrawn one notch at a time while observing the nuclear instrumentation. The nuclear instrumentat, ion did not indicate a continuous positive period thus demonstrating subcriticality.
Prior to the start of fuel loading, four fuel loading chambers were assembled, placed in the core, and connected to the permanent SRM preamplifiers. The rod block setpoint was set one decade lower at lx10**4 CPS and the scram setpoint at 2x10**4 CPS due to the fact that non-saturation of the SRMs had not yet been demonstrated. The reactor protection system was placed in the non-coincidence scram mode (shorting links removed). High voltage and discriminator curves were obtained for each FLC.
4-14
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The avarage initial source pin strength (8-13-84) was 1304 curies / pin. The average source strength at the start of fuel loading was 555 curies / pin. l The entire core complement of fuel assemblies was prepared, inventoried, and stored in the fuel pool prior to the start of fuel loading. Fuel was loaded into the core from the center out in a roughly spiral pattern of increasing size.
Before fuel was loaded, each control rod was tested for position indication, coupling, and scrammed verifying proper operation of the control rod and ensuring that the blade guides did not interfere with control rod travel.
Fuel loading commenced using the LGS Core Component Transfer Authorization Sheet (CCTAS) as the guiding document. Starting near the center of the core, four fuel assemblies were loaded around the central neutron source.
The loading continued in the fuel cell units that sequentially completed each face of the ever increasing square core.
A plot of inverse count rate (1/M) was taken during fuel load to verify subcriticality through the entire fuel load.
The plot was taken after loading each fuel assembly until 16 assemblies were loaded. Subsequent to that, 1/M plots were taken every 4 assemblies until 256 fuel assemblies were loaded. After 256 assemblies were loaded 1/M plots were taken every 16 assemblies. Plotting frequencies were increased if the current 1/M plot predicted that criticality would occur prior to the next planned 1/M plot.
On several occasions during the early stages of fuel loading, criticality was predicted by the 1/M plot before the next scheduled plotting point. The reason for this was the geometrical effects encountered when less than four fuel cells are loaded and the strong effects as fuel is loaded adjacent to the neutron sources. The interpretation of the geometry affected 1/M plots allow disregarding one or more 1/M intercepts because the obvious geometric effect invalidates the theoretical basis for the 1/M plots.
Several mino.r problems were encountered with fuel loading equipment. A brief summary is given:
There were several instances of fuel bundles being stuck in ~
the Spent Fuel Storage Pool (SFSP). One bundle (LY8310 at coordinate GG-23 in SFSP) required a force of 1640 pounds to remove it from the SFSP (special approval from General Electric Co. was obtained to exceed 1200 lb grapple load limit). The bundle was inspected and found to have some scratches on the channel but was determined to be acceptable. Another bundle (LY8076 at coordinate SS-23 in SFSP) required repeated application of force by lifting the 4-15 1
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grapple until it was fread. This bundle was also inspscted and found acceptable. The SFSP locations were inspzcted while the bundles were out and indicated no obstructions to removal of the bundle.
Other bundles were thought to be " hanging up" on insertion into the core. Further inspection revealed faulty indication of grapple position.
During the fuel loading sequence, there were several problems with the SRM channels. At one poin: during the loading, SRM D was declared inoperable. Sir.ce fuel was being loaded in that quadrant, FLC A had to be respositioned to core location 09-20 to al.'.ow continuation of fuel loading in accordance with LGS Technical Specifications (SRM monitoring required in the quadrant of core alterations and one adjacent quadrant).
4-16 l
4.4 STP-4, SHUTDOWN MARGIN DEMONSTRATION OBJECTIVES The purpose of this test is to demonstrate that the reactor will be sufficiently subcritical throughout the first fuel cycle with any single control rod fully withdrawn.
ACCEPTANCE CRITERIA Level 1 The shutdown margin (SDM) of the fully loaded, cold (68 degrees F), xenon-free core occuring at the most reactive time during the cycle must be at least 0.38% delta K/K with the analytically strongest rod (or it's reactivity equivalent) withdrawn. If the SDM is measured at sometime during the cycle other than the most reactive time, compliance with the above criteria is shown by demonstrating that the SDM is 0.38% delta K/K plus an exposure dependent correction factor which corrects the SDM at that time to the minimum SDM.
Level 2 Criticality should occur within +1.0% delta K/K of the predicted critical.
RESULTS STP-4.1, In Sequence Critical The shutdown margin for the initial fuel loading was measured to be 2.3% delta K/K. This included a temperature correction factor for 150.5 Deg F of 0.00454 delta K/K and a period correction factor for 147.5 seconds of 0.000506 deltu K/K. The measured shutdown margin of 2.3% delta K/K easily meets the level 1 criterion of having a shutdown margin of greater than 0.38% delta K/K. The critical rod position (K-eff=1.00) occurred with 2260 notches withdrawn in sequence A. In order to satisfy the level 2 criterion, criticality'had to be achieved between 1378 notches withdrawn (K-eff=0.9902) and 2326 notches withdrawn (K-eff=1.0100). These notch totals represent +1.0% delta K/K
, of the predicted critical rod pattern. Criticality occurred approximately 0.51% delta K/K from predicted.
These results satisfy the level 2 criterion.
This test was performed by bringing the reactor critical and then establishing a steady positive period. By measuring the period and accounting for the moderator temperature the minimum shutdown margin for this fuel cycle 4-17 l
1 was m:asured to bn 2.3% delta K/K. ~
For this fuel cycle,
, the minimum core shutdown margin occurs at the beginning of the cycle and, therefore, the exposure correction factor ;
equals zero.
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4.5 STP-5, CONTROL ROD DRIVE SYSTEM l
OBJECTIVES The objectives of this test are to demonstrate that the Control Rod Drive (CRD) System operates properl,y over the full range of primary coolant operating temperatures and pressures, and to determine the initial operating characteristics of the CRD system.
ACCEPTANCE CRITERIA Level 1 Each CRD must have a normal withdraw speed less than or equal to 3.6 inches per second, indicated by a full 12 foot stroke in greater than or equal to 40 seconds.
The mean scram time of all operable CRD's must not exceed the following times (Scram time is measured from the time the pilot scram valve solenoids are de-energized):
Position Inserted to From Fully Withdrawn Scram Time (Seconds) 45 0.43 39 0.86 25 1.93 05 3.49 The mean scram time of the three fastest CRD's 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 to From Fully Withdrawn Scram Time (Seconds) 45 0.45 39 0.92 25 2.05 05 3.70 Level 2 Each CRD must have normal insert and withdrawn speeds of 3.0 + 0.6 inches per second, indicated by a full 12 foot stroke in 40 to 60 seconds.
With respect to the control rod drive friction tests, if the differential pressure (dp) variation exceeds 15 psid for a continuous drive in, a settling test must be performed, in which case the differential settling pressure 4-19
should not be less than 30 psid nor should it vary by more than 10 psid over a full stroke.
RESULTS STP-5.1, Insert - Withdraw Checks One week before fuel load, functional checks were performed on each CRD. These checks consisted of measuring CRD insertion and withdrawal times, measuring insertion and withdrawal drive flows (running and stall), checking for proper coupling, and verifying proper RPIS operation.
Eight rods initially did not meet the Level 2 Acceptance Criterion; six rods had withdrawal times greater than 60 seconds, one rod had an insertion time greater than 60 seconds, and one rod had an insertion time less than 40 seconds. After adjusting the needle valves (on the appropriate directional control valves), all of these 8 rods satisfied the Level 2 Acceptance Criterion on retest.
Functional checks of all CRDs were repeated during fuel load at the completion of the loading of each control cell.
Six rods initially did not meet the Level 2 Acceptance Criterion; three rods had withdrawal times greater than 60 seconds, two rods had insertion times less than 40 seconds, and one rod had both of these problems. After adjusting the needle valves (on the appropriate directional control valves), all of these rods satisfied the Level 2 Acceptance Criteria on retest.
STP-5.2, Zero Reactor Pressure Friction Testing Following the completion of fuel loading and CRD functional checks, each CRD was friction tested. All CRDs satisfied the Level 2 Acceptance Criteria. However, one CRD did have a dp variation greater than 15 psid during a continuous insertion requiring performance of a settling test; the CRD (02-31) did satisfy the Level 2 Acceptance Criteria for settling testing.
STP-5.3, Zero Reactor Pressure Scram Testing Following completion of friction testing, each CRD was scram tested. All applicable Level 1 Acceptance Criteria were satisfied since the average scram times to position 45, 39, 25 and 05 for all operable control rods were less than 0.43, 0.86, 1.93 and 3.49 seconds, respectively, and the maan scram times of the three fastest rods in every 2 x 4-20
2 crray to position 45, 39, 25 and 05 wsre less than 0.45, 0.92, 2.05 and 3.70 seconds, respectively. The maan scram time of all operable CRDs and associated criteria are listed below:
Position Inserted to Mean Scram Time Level 1 Criteria Prom Fully Withdrawn (Seconos) (Seconds) 45 0.26 0.43 39 0.44 0.86 25 0.89 1.93 05 1.60 3.49 STP-5.4, Scram Testing of Selected Rods From the results of previous CRD testing, four rods were selected for further testing.
This test was performed at the following test conditions:
at zero reactor pressure with accumulator pressure just above the low pressure alarm point; at 600 psig reactor pressure with normal accumulator pressure; and at 800 psig reactor pressure with normal accumulator pressure. Each control rod was scrammed three times at every test condition. All scram times were less than 7.0 seconds.
STP-5.5, Rated Reactor Pressure Friction Testing At rated temperature and pressure, all CRD's were individually friction tested. Only 3 CRDs required settling tests and each of these satisfied the applicable Level 2 Acceptance Criterion.
STP-5.6, Rated Reactor Pressure Scram Testing At rated tem'perature and pressure all CRDs were individually scram tested. All CRDs satisfied the applicable Level 1 Acceptance Criteria. The mean scram times of all CRDs are as follows:
4-21 l
Avsrage Maximum Allowable Elapsed Scram Average Elapsed Scram Position Inserted to Time to Position Time to Position From Fully Withdrawn (Seconds) (Seconds) 45 0.33 0.43 39 0.63 0.86 25 1.37 1.93 05 2.46 3.49 STP-5.7, Rated Reactor Pressure Insert / Withdraw Checks and Scram Testing of Selected Rods From the results of STP-5.5 and 5.6, four rods were selected for further testing.
Each selected CRD satisfied the applicable Level 1 and Level 2 Acceptance Criteria on insert and withdrawal speeds and all scram times (with zero accumulator pressure) were less than 7.0 seconds. The insert and withdrawal speeds are summarized below:
Stroke Time Insert Withdraw Selected Rod (sec) (sec) 10-39 45.1 43.6 26-39 48.5 43.6 30-35 48.1 42.6 38-27 43.2 56.8 STP-5.8, Scram Timing of Selected Rods During Planned Scrams of The Startup Test Program The four rods tested in STP-5.7 were tested in this test.
The scram time for these rods was measured during full core scrams in conjunction with STP-28.1, Shutdown from Outside the Control Room at T.C. 2, and STP-27.3, Turbine Trip at T.C. 3. All scram times were less than 7.0 seconds.
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4.6 STP-6, SRM PERFORMANCE AND CONTROL ROD SEQUENCE OBJECTIVES The objective of this test is to demonstrate that the operational neutron sources, SRM instrumentation, and rod withdrawal sequences provide adequate information to achieve criticality and increase power in a safe and efficient manner.
ACCEPTANCE CRITERIA Level 1 ,
There must be a neutron signal to noise count ratio of a ,
least 2:1 on the required operable SRMs. .
There must be a minimum count rate of 3 counts /second on the required operable SRMs.
Level 2 i None ,
RESULTS STP-6.1, SRM Signal to Noise Ratio and Minimum Count Rate Determination STP-6.2, Approach to Criticality - SRM Response to Control Rod Withdrawal -
STP-6.3, SRM Non-Saturation Demonstration Prior to initial critical testing, the shorting links were removed placing the RPS in the noncoincident scram mode.
In addition, the SRM rod block and scram setpoints were conservatively adjusted one decade less than their normal values (set to lx10**4 and 2x10**4 CPS, respectively).
Prior to rod withdrawal, each SRM was withdrawn to ,
demonstrate'SRM signal to noise ratio and minimum count.
For each SRM, the observed minimum count rate and signal to !
noise ratio is identified in the following table.
i e
4-23 t
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Min.
Count SRM Rate S/N A 14 139 B 15 149 C 18 179 D 14 139 These results satisfy the Acceptance Criteria.
Control rods were then withdrawn in accorcance with the approved RWM rod sequence for startup. During control rod withdrawals, to avoid rod blocks or scrams, SRM detectors were partially withdrawn, as required, to maintain the observed count rate greater than 100 CPS and less than 1x10**4 CPS. In addition, during the control rod withdrawals from all rods-in to criticality, SRM channel readings were recorded for each control rod withdrawal.
Upon achieving criticality, the SRM count rate was increased until SRM/IRM overlap was demonstrated. Reactor power was maintained in the intermediate range and the shorting links were installed returning the RPS to the coincident scram mode. SRM nonsaturatation was then demonstrated by bypassing each SRM and inserting it into the core until the observed count rate exceeded 3x10**5 CPS. SRM rod block and scram setpoints were then restored to their normal values.
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4.7 STP-9, WATER LEVEL REFERENCE LEG TEMPERATURE OBJECTIVES The objectives of this test are to measure the level instrumentation reference leg temperature, recalibrate the water level instruments if the measured temperature is significantly different from the value assumed during the initial end points calibration, and to obtain baseline data on the Narrow Range and Wide Range water level instrumentation.
ACCEPTANCE CRITERIA Level 1 None Level 2 The difference between the actual reference leg temperature (s) and the value(s) assumed during initial calibration shall be less than that amount which will result in a scale end point error of 1% of the instrument span for each range. ,
RESULTS STP-9.1, Reference Leg Temperature Comparison With the reactor at rated temperature and pressure in Test Condition Heatup, the following parameters were recorded from various plant instruments and temporary test equipment and subsequently analyzed: reactor water level, reactor building temperature, and drywell temperature readings.
The difference between the measured reference leg temperatures and the temperatures assumed during the initial instrument calibration were less than the amounts that produced a scale end point error of 1% of the measured instrument span for each range, thereby satisfying the acceptance criterion.
l STP-9.1 was performed in TC-1, 2, 3, 4 and 5 to determine whether changes in plant conditions had affected reactor water level end point calculations. The principal variables are reference leg temperature and reactor building temperature. There were small changes in the sets of temperatures from assumed initial calibration conditions. Consequently, end point calculations were made only for those instruments on the reference leg with the l largest temperature change. A calculation was made to 4-25 i
d3tarmina th3 tmount of refersnca 1Gg timp2rature chang 2 rGquircd to cause a 1% of ecale and point error. In occh test condition, 1 through 5, the temperatures of the reference leg and the Reactor building were well within the i l ranges calculated not to produce an end point error of 1%.
l Therefore, the applicable acceptance criteria were satisfied.
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4.8 STP-10, IRM PERFORMANCE OBJECTIVES Ine objectives of this test are to' adjust the Intermediate Range Monitoring (IRM) System to obtain an optimum overlap with the SRM and APRM systems.
ACCEPTANCE CRITERIA Level 1 Each IRM channel must be on scale before the SRM's exceed their rod block setpoint.
Each APRM must be on scale before the IRM's exceed their rod block setpoint.
Level 2 Each IRM channel must be adjusted so that one-half decade overlap with the SRM's is assured. ,
Each IRM channel must be adjusted so that one decade overlap with the APRM's are assured.
RESULTS STP-10.1, SRM/IRM Overlap SRM/IRM overlap was demonstrated during the sequence of testing that began with initial criticality and ended with SRM non-saturation testing. Rods were pulled and the SRM's were partially withdrawn when the count rates approached the lowered SRM rod block setpoint (1x10**4 CPS).
Following each detector withdrawal, a normalized count rate was calculated so that the fully inserted SRM count rate could be determined. Rods were then pulled until all IRM downscale lights cleared (5/125 of full scale on Range 1) and the increase in count rate was terminated. Data was then taken which adequately demonstrates the SRM/IRM overlap. On'ce overlap was satisfactorily demonstrated, RPS was taken out of the noncoincident scram mode by the installation of the shorting links.
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Tha following indications ware rccordsd after SRM count rotos waro stabilizsd Normalized Range 1 Reading Reading SRM (CPS) IRM (0-40 scale)
A 3.24x10**4 A 3.5 B 4.39x10**4 B 3.0 C 1.35x10**4 C 4.0 D 2.07x10**4 D 2.5 E 3.6 P 3.5 G 5.0 H 4.5 Similar results were obtained after final gain adjustments were made during Test Condition 2.
All IRM readings were above the downscale value of 5/125 (1.6 on 0-40 scale).
The applicable Level 1 criterion was satisfied when each IRM channel was on scale before the SRM's exceeded the normal rod block setpoint of lx10**5 CPS (normalized reading).
The applicable Level 2 criterion was verified when the IRM downscale lights cleared and all SRM's indicated less than 5x10**4 CPS (half decade from rod block setpoint).
STP-10.2, IRM Range 6-7 Continuity During the initial reactor heatup, with IRM's A-H on range 6, reactor power was increased and stabilized to acquire readings between 50 to 80/125. Then each IRM was switched to range 7 and the reading observed. If the readings on channels 6 and 7 did not agree within 15%, the IRM in question was bypassed and the high frequency preamplifier (R-44) was adjusted as necessary.
All IRM's, with the exception of IRM B (which was inoperative), were left with a range 7 reading within 15%
of the corresponding range 6 reading. Each high frequency a amplifier for IRM ranges 7 through 10 had to be adjusted to satisfy the +5% test objective. IRM B was satisfactorily adjusted durTng a subsequent startup.
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Following adjustmant of all IRM channale, tho as left 4
readings were recorded as indicated below:
Range 6 Range 7 Reading Reading IRM (0-125 scale) (0-40 scale)
A 70.0 7.0 B 70.0 7.0 C 70.0 7.0 D 75.0 7.4 E 84.0 8.5 F 57.0 5.8
- G 84.0 8.5 H 53.0 5.5 This test was also conducted during Test Condition 2 after final gain adjustments were made. Similar results were obtained.
i STP-10.3, IRM/APRM Overlap l IRM/APRM overlap was demonstrated during the initial power increase above 5% CTP in Test Condition 1.
All IRM's except "C" were left with adequate IRM/APRM i
overlap. Each IRM high frequency amplifier gain had to be adjusted to satisfy the test objective. See table below.
Range 8 Reading APRM Gain IRM (0-125 scale) Reading Adjustment A 102 7.7 yes B 102 7.5 yes C Inop. 7.6 D 100 8.5 yes E 98 7.3 yes F 100 9.1 yes G 101 yes H 100 yes With the exception of IRM C, which was inoperative at the time of the test, all applicable acceptance criteria were satisfied. Similar results were obtained in Test Condition 2 after final gain adjustments were made. IRM C is now in service and will be tested in a subsequent Test Condition.
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_ _ _ _ __-. . _ ~ - _ _ _ _
l 4.9 STP-ll, LPRM CALIBRATION !
OBJECTIVES l
The objectives of this test are to calibrate the Local Power Range Monitoring (LPRM) System and to verify LPRM '
Flux Response. ;
ACCEPTANCE CRITERIA Level 1 None Level 2 Each LPRM reading will be within 10% of it's calculated value.
RESULTS STP-ll.1, Verification of Proper Connection of LPRM Detectors and Readout Equipment The purpose of this test was to observe and document Local Power Range Monitor (LPRM) response to flux changes and proper connection to the readout equipment. This test was performed in conjunction with control rod scram and friction testing at rated pressure during Test Condition Heatup. As each control rod was individually friction and scram tested, the response of each LPRM detector in the nearest LPRM string was observed on panel 10C603.
165 of the 172 LPRM detectors properly responded to local changes in neutron flux (adjacent control rod movement),
thus assuring proper connection to the LPRM readout equipment. The seven remaining LPRM detectors (16-19A,24-49A, 24-49B,24-41A, 24-41B,32-57A and 32-57B) did not -
respond to local changes in neutron flux and were retested at a higher power level in Test Condition 1 (see STP-ll.4).
There are no acceptance criteria associated with this test.
STP-ll.2, LPRM Calibration Without The Process Computer The purpose of this test was to calibrate the LPRM system, in Test Condition 1, such that the indication was .
proportional to the neutron flux at each detector. Gain adjustment factors (GAF) for each detector were calculated by using the off line computer program, Backup Core Limits Evaluation. Of the 172 LPRM's, twelve detectors were 4-30
bypacced and declared ino pe r able . 108 of the remaining detectors had final gar's > 0.9 and i 1.1, thuc catisfying the applicable acceptance criteria. 52 of the detectors had final GAF'c outside of the acceptance criteria limits.
Immediately follouing the completion of Tect Condition 1, at approximately 23% CTP, an additional LPRM calibration uns performed utilizing the Process Computer. These resultc uere satisf actory uith only three operable LPRM's uith GAF's outside of the 0.9 and 1.10 limits. These three LPRM's and the bypassed detectors vill be addressed by cubsequent calibrations.
l STP-ll.3, LPRM Calib' ration Uith Process Computer This test was performed during Test Condition 3 at 70% core thermal pouer. The purpose of this test is to provide documentation and verification of proper LPRM calibration using the Process Computer in accordance with Plant Surveillance Test Procedure ST-3-074-505-1, TIP Calibration '
of LPRMs. Using the process computer program OD-1 a complete set of TIP traces is stored. The individual LPRM amplifier input calioration currents required to provide a full scale meter reading on each LPRM meter are then determined. The process computer program P-1 is used to calculate the correct LPRM readings and the amplifier input currents are then divided by the LPRM Gain Adjuctment Factorc (GAPC ) to determine new input calibration currents.
l The OD-1 is reperformed and neu LPRM GAPS are determined.
The acceptance criterion uas catisfied for all LPRMs with the e::ception of the follouing LPRMs which were inoperative and bypasced: _
48-17D 48-49A 40-33A 32-41A 40-41A lG-17A 32-49D 16-33A 16-09A 32-49C SG-17B 32-33C l 40-33C l These LPRMc, uith the e::ception of 32-41A and SG-17B, were l cubsequently returned to service and the acceptance I criteria satisfied by performance of ST-3-074-505-1. These l inoperative LPRMc will be calibrated and returned to l service upon repair.
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STP-ll.4, LPRM Op3 rational Verification During Rod Withdrawal The purpose of this test is to document the response of those LPRM detectors that failed to properly respond to changes in flux during the performance of STP-ll.l. With the reactor operating at approximately 11% CTP in Test Condition 1, control rods were moved adjacent to the LPRM's of interest and detector response was observed. All seven detectors responded properly to local changes in neutron flux. There were no acceptance criteria verified in this test.
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4.10 STP-12, APRM CALIBRATION OBJECTIVES The objective of this test is to calibrate the Average Power Range Monitor (APRM) System.
ACCEPTANCE CRITERIA Level 1 The APRM channels must be calibrated to read equal to or greater than the actual core thermal power.
Technical specification and fuel warranty 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 15% of rated thermal power.
Level 2 If the above criteria are satisfied, then the APRM channels will be considered to be reading accurately if they agree with the heat balance or the minimum value required based on peaking factor, MLHGR, and fraction of rated power to within (+7,-0)% of rated power.
RESULTS STP-12.1, Constant Heatup Rate APRM Calibration The purpose of this test was to perform an initial calibration of the APRMs and to verify APRM rod block and scram setpoints. The C.in Adjustment Factors used for the calibration were calculated using a core thermal power determined from a constant reactor coolant heatup rate heat balance. All acceptance criteria were satisfied.
The first part of this test involved taking plant data every 10 minutes during a reactor heatup. The heatup was established'and maintained by withdrawing control rods for 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> and 50 minutes. The data used to calculate core thermal power (CTP) was the data taken during the 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> period in which the heat up rate was the most constant.
During this 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> period, the average heatup rate was 58 degrees F/hr.
For each data set in this 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> period, a core thermal power was calculated. Using this CTP, an APRM gain adjustment factor (AGAF) was calculated for each APRM, for each data set. These AGAFs were averaged providing an 4-33 l
avaraga AGAP for cach APRM. While thcsc calculations were being performed, steady state plant conditions were established for the calibration.
Each APRM was then calibrated taking the as found reading, multiplying it by the AGAF, and adjusting the gain until the meter read this product (desired reading). However, on ,
.each APRM, the gain was reduced to its minimum value before i the APRM reading reached the desired reading; the result was that each APRM was reading greater than actual CTP.
The APRMs were calibrated during steady state conditions as follows:
As Found As Left Reading Reading (Expanded Desired (Expanded APRM AGAF X10 Scale) Reading X10 Scale)
A 0.324 2.9 0.94 1.00 B 0.246 3.0 0.74 1.05 C u.263 3.1 0.82 1.05 D 0.211 4.0 0.84 1.40 E 0.228 3.5 0.80 1.15 P 0.237 3.6 0.85 1.30 The rod block and scram setpoints for each APRM channel were checked to verify that they would cause a rod block and scram at 12% and 15% indicated CTP, respectively. All APRMs satisfied this criteria with one exception. APRM B produced a rod block at an indicated meter reading of 12.5%
rated CTP. The input voltage to the meter was then checked and found to be 0.894 volts which corresponds to an actual CTP of 11.2%.
The scram and rod block setpoints on each APRM channel were recorded as follows:
Rod Block Scram APRM Setpoint Setpoint A 11.5 15 B 11.2 15 l C 11 14
! D 11.5 14 l E 12 15 F 12 15 4-34 l
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STP-12.2 Lou Pouer APPL! Calibration This test uas performed at Test Conditi'on l'at appro::imately 20t CTP. The purpose of the test uas to calibrate the APR!! channels against core thermal pouer.
This test was conducted by performing a heat balance using appropriate process computer points and instrument readings. Core thermal pouer uns calculated to be 698.82 1111t .
All APR!!s vere calibrated to read greater than actual core thermal pouer as shoun belou:
Final Reading APRI! (t rated CTP)
A 21.5 B 22.0 C 22.0 D 22.5 E 23.0 F 22.5 In addition, the flou biased scram and rod bloch setpoints vere verified to be less than the allouable values given in Technical Specifications. All applicable acceptance criteria vere satisfied.
- l STP-12.3, Iligh Pouer APR!1 Calibration l STP-12.3 uns performed three times at 47%, 60% and 63% CTP l during Test Conditions 2, 3 and 5 respectively.
The purpose of this test uas to calibrate the APRI! channels against core thermal power. This test uas conducted by performing a heat balance utilizing the process computer j program CD-3.
All APR!!'s vere calibrated to read greater than actual core thermal power as shoun belou:
l Final Reading (% Rated CTP)
AP RI-I TC 2 TC 3 TC 5 A 48.0 61 63 B 48.0 60.5 62 C 48.0 62 64 D 48.4 61 64 E 48.0 61 63.5 l F 48.2 60 63 l In addition, the flou biased scram and rod block setpoints l uere verified to be less than the allouable values given in
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Technical Sp:cifications. All cpplicable ccc:ptance criteria were satisfied.
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4.11 STP-13, PROCESS COMPUTER OBJECTIVES The objective of this test is to verify the performance of the Process Computer under plant operating conditions.
ACCEPTANCE CRITERIA Level 1 None Level 2 The MCPR calculated by BUCLE and the Process Computer either:
are in the same fuel assembly and do not differ in value by more than 2% or for the case in which the MCPR calculated by the Process Computer is in a different assembly than that calculated by BUCLE, for each assembly, the MCPR and the CPR calculated by the two methods shall agree within 2%.
The maximum LHGR calculated by BUCLE and the Process Computer either:
are in the same fuel assembly and do not differ in value by more than 2%, or for the case in which the maximum LHGR calculated by the Process Computer is in a different assembly than that calculated by BUCLE, for each assembly, the maximum LHGR and the LHGR calculated by the two methods shall agree within 2%.
The MAPLHGR calculated by BUCLE and the Process Computer either:
are in th'e same fuel assembly and do not differ in value by more than 2%, or l
for the case in which the MAPLHGR calculated by the Process Computer is in a different assembly than that calculated by BUCLE, for each assembly, the MAPLHGR and APLHGR calculated by the two methods shall agree within 2%.
l The LPRM gain adjustment factors calculated by BUCLE and i
the Process Computer agree to within 2%.
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l RESULTS STP-13.1, Static System Test Case The Static System Test Case associated with Process Computer /TIP machine interface was satisfactorily performed. Proper OD-1 operation, including interface with the TIP machines, agreement between computer and TIP machine index settings, and generation of CRT and typer ,
messages, was demonstrated. There are no acceptance l criteria associated with this test.
STP-13.1 consisted of loading a plant simulator overlay to modify the OD-1 program and subroutines so that simulated values for plant parameters could be used prior to actual plant operation during Test Condition Open Vessel. OD-1 was then run with various simulated plant conditions such as low feedwater flow and unknown control rod positions to verify that the appropriate failure checks were made and the correct CRT and typer messages were generated. The TIP machines were then operated to verify proper computer /TIP machine interface. The TIP indexes were switched to each position to verify that the computer correctly monitored the index settings. Various TIP operation failure checks, such as waiting too long to start a traverse, stopping the traverse mid-core, moving a control rod, failing the simulated TIP signal, and varying the APRM signal, during traverses, were also tested. Finally, a complete set of TIP traverses was performed.
STP-13.2, TIP Alignment at Rated Temperature The TIP Alignment test at Test Condition Heatup was performed with the reactor operating at rated temperature and pressure. There were no acceptance criteria, but the purpose of this test was to determine if the core top (NCCT) and core bottom (NCCB) limits or the x-y plotter span required adjustments. Each of the TIP guide tubes was probed, and the full-in index position (NCFI) at hot conditions was verified to be greater than or equal to the value at cold conditions. No limit adjustments were required, bu't several TIP channels required plotter adjustments. TIP machine E could not be tested at this time due to moisture in the guide tubes.
Following repair, TIP Machine E was successfully tested at rated temperature and pressure in Test Condition 1. No core limit adjustments or X-Y plotter adjustments were required. ,
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STP-13.3, Program Testing at Test condition 1 Program Testing uns performed during Te~st Condition 1 at 19.5% of rated core thermal power. During this test the TIP core limits vere checked against the limits set in STP-13.2, TIP Alignment at Rated Reactor Pressure, performed during Test Condition !!catup. The average difference between the axial TIP traces, and the design values, were found to be less than or equal to one inch, therefore, no change to the TIP core limits were necessary.
A complete OD-1, Whole Core LPRf1 Calibration and BASE distribution was per formed confirming correct TIP-Computer interface. The operation of OD-10, LPRM Alarm Trip Recalibration could not be performed due to a power reduction and was successfully performed during subsequent power operation. There were no acceptance criteria for this test.
l STP-13.4, Dynamic System Test Case This test was performed during Test Condition 2 in order to perform basic operational chechs on the Process Computer using actual plant data. There vere no acceptance criteria for this test. Analysis consisted of evaluation of proper Process Computer program functions. The following checks t
vere performed:
- 1. Correct initialization of the Process Computer was verified including verification that all exposure data l uas zero.
l 2. Proper scanning by plant sensors.
( 3. The Process Computer uns proven to be able to l initialize data using OD-15.
- 4. The operability of programs enabled by OD-15 were verified (P-4, OD-5, OD-7, OD-8, OD-15, OD-19, and OD-20).
I 5. The ability of the Process Computer to correctly l perform a whole-core LPR!i calibration was verified by l l checking the results against manual calculations.
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( 6. The Process Computer power distribution and core thermal limits calculations uere verified to be Correct.
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- 7. The Prococc Computer programa P2 and P3 vere verified to be performing properly.
- 8. The proper operation of the LPRM digital filtering initialization function and the LPRM drif t diagnostic tect uns verified.
The follouing Procons Computer programc vere declared operational upon successful completion of thic test:
l P-1, P- 5, OD-1, OD- G , OD-10, OD-12, OD-14, OD-l G , OD-17 l STP-13.5, Program Testing at Test Condition Tuo Thic test unc initially performed during Test Condition 2, and uns reperformed at 48% core thermal power during Test Condition 3 due to indeterminate recults obtained in Test p g ion 2.
This tect per formed an operability check on OD-2 and OD-9 by verifying that the computer read variables from the correct positionc in the Process Computer core memory and that the computer's calculations were correct. OD-2 and OD-9 ucre declared operational upon successful completion of this test. There vere no acceptance criteria for this test.
1 l STP-13.G, Program Tecting at Test Condition Three This test uns performed at 71.8% core thermal pouer during Test Condition 3. The purpose of this test is to verify the operation and calculations of the P-1 program and OD-10, Option 22 edits for asymmetric rod pattern conditions.
The test compared valuco of the symmetric and asymmetric modes for the P-1 program and the OD-10, Option 22 edit.
All asymmetric values uere uithin 15% of the symmetric valuce verifying the operability of these programs in the acymmetric mode. There vere no acceptance criteria for thic tect.
l STP-13.8, Acceptance Criteria Verification This test uns performed once during Test Condition 2 at 22.6% core thermal power and tuico during Test Condition 3 at 48% and 71.3t core thermal power. This tect calculatec 4-40
the values of the thermal limits using the process computer and using an offline method, Back Up Core Limits Evaluation (BUCLE).
All acceptance criteria were satisfied with the exception i of the following: In Test condition 3, at 71.3% core thermal power, the values calculated by the two methods for LPRM Gain Adjustment Factors (GAFs) did not agree to within
+ 2%. With a maximum deviation of 3% observed, these results were evaluated as acceptable with a possible cause identified as system round off errors coupled with performance of this test not immediately following an OD-1, Whole Core LPRM Calibration. STP-13.8 will be reperformed in Test Condition 6 at which time these parameters will be evaluated again.
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4.12 STP-14, RCIC SYSTEM OBJECTIVES The objectives of this test are to verify the proper operation of the Reactor Core Isolation Cooling (RCIC)
System over its expected operating pressure and flow ranges, and to demonstrate reliability in automatic starting from cold standby when the reactor is at power conditions.
ACCEPTANCE CRITERIA Level 1 l
The average pump discharge flow must be equal to or greater than 100% rated value after 30 seconds have elapsed from automatic initiation at any reactor pressure between 150 psig and rated.
The RCIC turbine shall not trip or isolate during auto or manual start tests.
Level 2 In order to provide an overspeed and isolation trip l avoidance margin, the transient start first and subsequent i
speed peaks shall not exceed 5% above the rated RCIC turbine speed.
The speed and flow control loops shall be adjusted so that l
the decay ratio of any RCIC system related variable is not greater than 0.25.
i The turbine gland seal condenser system shall be capable of preventing steam leakage to the atmosphere.
The delta F switches for the RCIC steam supply line high flow isolation trip shall be calibrated to actuate at the value specified in the plant technical specifications (about 300%).,
The RCIC system must have the capability to deliver specified flow against normal rated reactor pressure without the normal AC site power supply.
RESULTS STP-14.1, RCIC Functional Demonstration CST to CST at 150 psig 4-42
STP-14.2, Functional Demonstration and Controller
] Optimization at Rated Pressure CST to CST STP-14.3, Stability Check CST to CST at 150 psig STP-14.4, Controller Optimization During RPV Injection at Rated Pressure
. STP-14.6, RCIC Cold Quick Start at Rated Pressure - CST to RPV l STP-14.7, Surveillance Tests CST to CST
- STP-14.8, RCIC Endurance Run l.
STP-14.9, Loss of AC Power to RCIC Components.
The results of RCIC testing during Test Condition Heatup
! were satisfactory. All problems noted during the tests
- were resolved. Minor steam leakage previously observed I around the turbine shaft on the governor end has been resolved and proper gland seal condenser operation #
verified.
l l The initial RCIC subtest, STP-14.1, was a RCIC run at a j reactor pressure of 150 psig from Condensate Storage Tank l (CST) to CST. The test consisted of a manual start, flow I
steps in manual and automatic, and a quick start. All l
. acceptance criteria were satisfied.
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)i The next RCIC subtest, STP-14.2, was a RCIC run at 920 psig reactor pressure from CST to CST. This test consisted of a manual start, inner and outer loop control system tuning, flow steps in manual and automatic, and a quick start. A
- Level 2 acceptance criteria was not met due to a small steam leak at the RCIC turbine governor bearing end.
The following RCIC subtest, STP-14.3, was a RCIC run at 150 l
psig reactor pressure from CST to CST. The subtest consisted of a quick start followed by automatic and manual l flow step changes to check RCIC stability after tuning in i
STP-14.2. There were Level 2 test exceptions with oscillatory behavior observed in flow, control valve position, and EGM output signals during the automatic flow
, decrease step. These parameters were evaluated and 1 l considered acceptable. Another problem noted during the i subteat was the flow controller demanding full flow due to l turbine control valve binding, which was subsequently i
resolved.
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The next RCIC suhtest, STP-14.4, was a vessel injection at 920 psig reactor pressure. During the manual RCIC start I
divergent oscillations were seen when the flow controller
- was placed in automatic. A turbine trip then occurred on low cuction pressure which did not satisfy the Level 1 criteria. The RCIC system was retuned and the required quick start succes sfully completed. A Level 2 acceptance criteria was not met with minor steam leakage on the turbine governor end.
The following subtest, STP-14.5, was a reactor vessel injection at 150 psig. For this test, all acceptance criteria were satisfied.
The next RCIC subtest, STP-14.6, consisted of two cold quick starts, at rated pressure, to the reactor vessel with no RCIC operation for 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> beforehand. The first cold quick star t was succes sf ully completed . There was a Level 2 test exception due to transient start first speed peak (5000 RPM) being greater than the limit of 4725 RPM. An evaluation was made of the data and a second cold quick start was succes sfully ccnducted 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> later with a first speed peak of 4200 RPM. The 5000 RPM speed peak was evaluated as acceptable. ;
On dae second cold quick start steam '. leakage was again seen around the turbine governor end. In addition, RCIC steam flow delta P switch isolation setpoints were verified to be set conservatively.
The last RCIC subtest in Test Condition Heatup was STP-14.7, the RCIC surveillance f rom CST to CST at 15 0 psig .
The subtest was conducted with all acceptance criteria satisfied.
l STP-14.7 was perfo rmed again in Test Condition 1 with th e reactor at rated pressure. All level 1 and level 2 criteria were satisfied except fo r the speed peak lim it of 4725 rpm was exceeded. The speed peak on this run was 5301 rpm. A test exception was written and two hot quick s tar ts were pe r fo rmed to the vessel. Speed peaks of 4813 rpm and 4537 rpm were obtained. A third hot quick start was performed to the CST. The resulting speed peak was 5 034 rpm. Since RCIC was still operable per plant technical specifications, testing continued. Fur ther investigation of the speed peaks is being condu ct ed .
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l STP-14.8, RCIC Endurance Run and STP-14.9 Loss of AC Power to RCIC Components were performed in parallel with STP-14.7 in Test Condition 1. STP-14.9 and 14.8 consisted of a l quick start to the CST, followed by continuous operations '
for 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> and 15 minutes, and finally, two consecutive quick starts to the reactor vessel. The above mentioned testing was successfully performed with no AC power supplied to RCIC components, including the room cooler. 1 All applicable acceptance criteria were satisfied with RCIC oil temperature, room temperature and battery voltage remaining within the prescribed limits.
Equipment problems encountered during the RCIC testing that j required system modification, consisted of binding of the RCIC turbine control valve and turbine governor end gland seal leakage. The binding of the control valve was solved by shimming the servo, allowing freer stroke, and the relocation of the servo helped to more correctly align the I control valve linkage. The steam leakage from the turbine governor end has been resolved and proper gland seal condenser operation verified.
A RCIC test results summary is provided in Table 4.12-1.
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TABLE 4.12-1 RCIC TEST RESULTS
SUMMARY
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Level 1 ~ LEVEL 2 TEST DATE T.C. PRESSURE TIME Td TRIP 3 PEED O5dILLAiIUNS ' SEAL DELf5'P "
f PSIG RATED FLOW PEAK LEAKAGE SWITCH 130 sec. 14725 SETTINGS 14.1 1/03/85 HU 150 _ _
11.5 _ __ _
, __ _ NO 2555 NONE _NONE _ N/A i
14.2 1/11/85 HU RATED. 17.5 NO 4400 _NONE YES N/A 1 2
) 14.3 2/18/85 HU 150 21.7 YES 2357 ACCEPTABLE _ NONE N/A '
- 3 14.4 2/27/85 HU RATED 18.6 YES 4211 NONE YES N/A 14.5 3/01/85 HU 150 5.6 NO 2422 NONE YES N/A 1 14.5 4/03/85 HU 150 6.8 NO 2290 NONE NONE N/A 1 4 4 (
1 14.6 4/06/85 HU RATED 18.8 YES 4462 NONE NONE N/A 5
14.6 4/09/85 HU RATED 18.7 NO 5000 NONE NONE N/A j 14.6 4/12/85 HU RATED 18.6 NO 4200 NONE YES OK 1
- 14.7 4/17/85 HU _150 7.1 NO 2423 NONE NONE N/A i
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14.7 8/15/85 1 RATED 17.4 NO 5301 N/A N/A N/A l NOTES 1
- 1. Manual turbine trip on loss of manual control due to control valve binding.
4 2. Minor limit cycles observed on step change. Accepted as is.
- 3. Following manual start, when controller placed in auto, divergent oscillations occurred resulting in a low suction pressure turbine trip. Control system retuned and test completed successfully. -
- 4. Turbine trip on low suction pressure during cold quick start. Listed results are for a successful hot quick start which followed. ~
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- 5. High speed peak evaluated as acceptable with adequate margin to overspeed trip maintained.
l 6. STP-14.8 and 14.9 performed concurrently.
! 7. Speed peak to be resolved at a later date.
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4.13 STP-15, HPCI SYSTEM OBJECTIVES The objectives of this test are to verify the proper operation of the High Pressure Coolant Injection (HPCI) i' System over its expected operating pressure and flow ranges, and to demonstrate reliability in automatic starting from cold standby when the reactor is at rated pressure conditions.
ACCEPTANCE CRITERIA Level 1 The average pump discharge flow must be equal to or greater l than 100% rated value after 30 seconds have elapsed from automatic initiation at any reactor pressure between 200 psig and. rated.
The HPCI turbine shall not trip or isolate during auto or manual start tests.
Level 2 In order to provide an overspeed isolation trip margin, the transient first peak shall not come closer than 15% (of '
rated speed) to the overspeed trip, and subsequent speed' peaks shall not be greater than 5% above the rated turbine speed.
The speed and flow control loops shall be adjusted so that the decay ratio of any HPCI system related variable is not greater than 0.25.
The turbine gland seal condenser system shall be capable of preventing steam leakage to the atmosphere.
The delta P, switches for the HPCI steam supply line high flow isolation trip shall be calibrated to actuate at the value specified in plant technical specifications (about 300%).
RESULTS STP-15.1, Functional Demonstration CST to CST at 200 psig STP-15.2, Functional Demonstration and Controller Optimization at Rated Pressure CST to CST 4-47
STP-15.3, Stability Check CST - CST at 200 psig STP-15.7, HPCI Endurance Run The results of HPCI testing during Test Condition (TC)
Heatup, TC3 and TC5 were satisfactory. All problems noted during the tests were resolved. Minct steam leakage observed at the stop valve stem and control valve lifting rod bushing during TC Heatup has been resolved and proper gland seal condenser operation verified.
An outage was commenced after the initial phase of Test Condition Heatup. During this outage various modifications to components and instrumentation were performed. The most prominent modification was the addition of a bypass line in the HPCI hydraulics. All Heatup testing was performed prior to the modifications with the exception of the final performance STP-15.2 which was conducted after the modification at rated pressure.
The initial HPCI subtest, STP-15.1, was a HPCI run at a reactor pressure of 200 psig from Condensate Storage Tank (CST) to CST. This test consisted of a manual start, flow steps in both automatic and manual, and a quick start.
Problems, which are outlined in Table 4.13-1, were encountered with CST to Suppression Pool (SP) suction valve swap overs and a Level 2 criteria was not met due to gland seal steam leakage. All other applicable acceptance criteria were satisfied.
The next HPCI subtest, STP-15.2, was a HPCI run at 920 psig reactor pressure from CST to CST. This test consisted of a manual start, inner and outer loop tuning, flow steps in manual and automatic, and a quick start. This subtest encountered several problems including suction valve swap overs from CST to SP, divergent oscillations during tuning, hydraulic control problems and low suction pressure trips.
Due to these problems, several tests were necessary before satisfactory results were obtained for system performance and acceptance criteria. The hydraulic control problems, as outlined,in Table 4.13-1, were resolved as a result of a bypass line modification that bypassed Auxiliary Oil Pump Oil around the EUR and directly to the control valve. As a result, this subtest was repeated after the modification with the results shown in Table 4.13-1.
. The next HPCI subtest, STP-15.3, was a HPCI run at 200 psig reactor pressure from CST to CST. This subtest consisted of a quick start followed by flow step changes in automatic and manual to check HPCI stability at low reactor pressure after control system tuning. The test initially did not meet the Level 1 criteria of time to rated flow but was 4-48 l
successfully completed during a retest (see Note 4 Table 4.13-2). After the hydraulic bypass line modification, HPCI stability was tested during a functional test at 190 and 200 psig to reconfirm the results of STP-15.3.
The last subtest performed during Test Condition Heatup was STP-15.7, the HPCI Endurance Run. For this test the system was to be run CST to CST for approximately 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> or until pump and turbine oil temperatures stabilized. The system was run successfully for 75 minutes at which time all oil temperatures had stabilized.
STP-15.4, Controller Optimization During RPV Injection at Rated Pressure This test was performed at 68% rated power during TC3 with the HPCI pump discharging to the reactor vessel. This test consisted of verifying the HPCI flow controller response by introducing flow demand step changes in both automatic and manual flow control. All applicable acceptance criteria were satisfied with no control system tuning required.
Additionally, the peak HPCI turbine exhaust pressure was shown to be at least 10 psig below the high exhaust pressure turbine trip setpoint, thus ensuring an adequate margin to trip was maintained. The HPCI steam flow delta P switch isolation setpoints were also verified to be set conservatively.
STP-15.5, HPCI Cold Quick Start at Rated Pressure - CST to RPV This test was performed at rated reactor pressure during TC3 in order to fully demonstrate the operation of the HPCI system under anticipated conditions. It consisted of a cold (no HPCI operation for at least 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />) quick start to the reactor vessel. This test was performed twice; the first performance was unsuccessful due to not satisfying a Level 1 Acceptance Criterion of time to rated flow <25 seconds (actual time - 31.3 seconds). Following thTs first run, the ramp generator slope (control system inner loop) and proportional gain (control system outer loop) were reduced. In addition, the time to rated flow acceptance criterion was re-evaluated by General Electric Co. and revised from 25 seconds to 30 seconds to agree with the plant Technical Specification limit.
This test was then repeated at 68% rated power and all applicable acceptance criteria were satisfied with time to rated flow of 21.3 seconds. Additionally, the peak HPCI turbine exhaust pressure was shown to be at least 10 psi 4-49 L
below tho high Gxhnuot prsscure trip sotpoint, thus ensuring that an adequate margin to trip was maintained.
l STP-15.6, HPCI Surveillance Tests - CST to CST This test was performed twice - once in TC3 and once in TC5. It was performed in order to acquire surveillance data with the final HPCI controller settings for future HPCI surveillance tests; this data will be used to gauge system performance in the future.
During TC3, this test was performed at rated reactor pressure following completion of STP-15.5. All applicable acceptance criteria were satisfied. Additionally, the peak HPCI turbine exhaust pressure was shown to be at least 10 psig below the high HPCI turbine exhaust pressure trip setpoint, thus ensuring that an adequate margin to trip was maintained.
During TC5, this test was performed at 234 psig reactor pressure. All applicable acceptance criteria were satisfied.
A discussion of problems encountered during HP.CI testing is provided in Table 4.13-1.
! Refer to Table 4.13-2 for a summary of HPCI test results.
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TABLE 4.13-1 HPCI Equipment Problems
- 1) Barometric Condenser Vacuum Pump - The pump tripped on ,
overload when required to run for more than several minutes. This caused the additional problem of allowing some gland seal steam leakage. The pump trip problem was resolved during a planned outage. The pump discharge check valve was disassembled and found to be rusted and the discharge line was full of water.
The valve was then cleaned and reassembled and the '
discharge line drained. Finally, the float in the barometric condenser was inspected and found to be :
stuck in a high water level position which indicated that the condenser water level had been higher than e:cpected . This discovery, combined with the water found in the discharge line, was evidence that the vacuum pump had been pumping water which could have caused the overload condition. Subsequent operation of the HPCI system uas performed uithout any further tripping of the Barometric Condenser Vacuum Pump.
- 2) Balance Chamber Adjustment - It was suspected that the balance chamber pressure adjus,tment of 165 psig was lou cnough to allow the observed open of the HPCI turbine stop valve on system startup. The stop valve uns observed to spike fully open and then settle out.
Adjustment to the upper end of the band at 185 psig was planned during an outage. However, during the outage the turbine stop valve bonnet was replaced and the hydraulic bypass modification (see problem 04) was completed. The bypass modification made the balance
, chamber pressure less limiting and improved performance was observed during Test Condition (TC)
Heatup with a final pressure adjustment of 108 psig in I the balance chamber at a reactor pressure of 900 psig. ,
I Reviou of transient recorder plots for TC 3 HPCI testing indicated stop valve open/close rapid transient for the following tests: STP-15.5 on 11/5 l and 11/9/05 and STP-15.6 on 11/13/85. This stop valve l performance has boon evaluated as acceptable. HPCI system performance and operability remain unaffected l due to the hydraulic bypass modification which maintains the HPCI control valve shut during this stop l valve transient.
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TABLE 4.13-1 HPCI Equipment Problems (Cont.)
- 3) Control Valve Linkage - The Control Valve Linkage caused the slow opening of the control valve on several occasions due to servo pitting and a tight fit. The HPCI servo was replaced and combined with the hydraulic bypass line modification ultimately solved this problem by insuring a more constant oil supply. This assured the control valve being driven to the correct position since the oil supply for the servo is not dependent solely on oil supply from the EGR.
- 4) HPCI Hydraulics - A modification was made during the outage to the HPCI Turbine Hydraulic System. This modification added a bypass line to send oil from the auxiliary oil pump directly to the turbine control valve instead of using the EGR to supply oil to the valve. This reduced stop valve spiking problems previously experienced since the control valve adsorbed more of the differential pressure and thus the balance chamber adjustment became less limiting.
- 5) CST to SP Suction Valve Swap Over - The suction valve swap over of HPCI from the normal line up to the CST to the SP, caused by oscillations in the CST level
, transmitter, was solved by adding a time delay to the valve swap over signal and snubbers to the instrument lines. This allows flow to stabilize after the starting surge of HPCI and therefore bypass the initial large oscillations seen by the CST level transmitter. The problem developed because of the need for the instrument taps to be located on seismic class 1 piping. This made the HPCI suction piping the best choice since the CST's were non seismic.
However, that location made the level transmitters susceptible to the effects of the HPCI starting flow surge, and necessitated the use of the time delay.
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TABLE 4.13-1 HPCI Equipment Problems (Cont.)
- 6) HPCI Low Suction Pressure Trip - the HPCI turbine tripped on low suction pressure several times during testing due to the location of the transmitter and the starting flow surges seen when running the system CST to CST. A procedural change was made to more closely simulate a vessel injection by allowing HPCI discharge pressure to reach 400 psig before opening the HVSS-1F008 (Test Loop Shutoff) valve. This allowed HPCI
, flow only after a back pressure was developed and lessened the severity of the starting flow surge. In addition, the hydraulic bypass modification limited the acceleration of the HPCI turbine. This also had the effect of limiting the starting flow surge and eliminated the HPCI turbine low suction pressure trip problem.
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TABLE 4.13-2 BPIC TEST RESULTS SUBBEARY Level 1 LEVEL 2 TEST DATE T.C. PRESSURE TINE TO TRIP SPEED PEAK OSCILLATIONS SEAL DELTA P G PSIG RATED FLOW INITIAL /SUBSEQ. LEAKAGE SWITCH
<30 sec.
<4609 <4399 SETTINGS 1
15.1 1/04/85 BU 200 18.5 YES 1400 / 3053 NONE YES N/A 2
15.2 2/26/85 BU RATED 20.1 NO 4240 / 4387 NONE YES N/A 3 -
15.2 4/05/85 BU RATED 19.8 NO 1356 / 4356 NONE YES N/A 4
15.3 2/19/85 BU 200 26.8 NO 1615 / 3000 N/A NO N/A 15.3 2/20/85 BU 200 19.7 NO 1477 / 3104 NONE YES N/A 15.4 11/09/85 3 RATED N/A NO N/A NOME NO OK 6
15.5 11/05/85 3 RATED 31.3 NO 3875 / 3938 N/A NO N/A 15.5 11/09/85 3 RATED 21.33 NO 2355 / 4007 N/A NO N/A 15.6 11/13/85 3 RATED N/A NO 2283 / 4185 N/A NO N/A 15.6 11/25/85 5' 200 N/A NO 1524 / 3119 N/A NO N/A 15.7 1/17/85 BU RATED N/A NO N/A N/A N/A N/A NOTES
- 1. One manual and one automatic trip (low suction pressure) on CST to SP suction swap during system startup. One manual trip when CST return valve (F0ll) failed to open (SP suction interlock) on startup. Successfully completed subsequent startup with results as shown.
- 2. Results shown are for the last performance of STP-15.2 prior to the hydraulic bypass modification.
i
- 3. Post hydraulic modification results.
- 4. Stop valve went shut for a short time on a momentary low suction pressure trip signal resulting in excessive time to rated flow. STP-15.3 repeated on 2/20/85.
- 5. Trip dp calculated from quick start data from STP-15.2 performed on 4/05/85.
- 6. HPCI control system adjustment Nade and STP-15.5 reperformed on 11/09/85.
r -- - _ , -r,- ---w, _ , n- -c -c ..n- --- - - --r w.- - -- -
4.14 STP-16, SELECTED PCOCESS TEMPERATURES OBJECTIVES The objectives of this test are (1) to assure that the :
measured bottom head drain temperature corresponds to bottem head coolant temperature during normal operations, (2) to identify any reactor operating modes that cause temperature stratification, (3) to 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.
ACCEPTANCE CRITERIA Level 1 The reactor recirculation pumps shall not be started, flow increased, nor power increased unless the coolant temperatures between the steam dome and bottom head drain are within 145 degrees F. ,
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 degrees F of the active icop suction temperature and the active loop flow rate is less than or equal to 50%
of rated loop flow. If two pumps are idle, the loop suction temperature must be within 50 degrees F of the steam dome temperature before pump startup.
Level 2 .
During two pump operation at rated core flow, the bottom head temperature, as measured by the bottom head drain line thermocouple, should be within 30 degrees F of the recirculation loop temperatures.
RESULTS STP-16.1, Minimum Recirculation Pump Speed Determina, tion The Selected Proceso Temperatures test at Test Condition Heatup was performed witn the reactor operating at rated temperature and pressure at approximately 51 power. There were no acceptance criteria, but the existing scoop tube positioner low upeed stop settings were shown to prevent exceeding the Technical Specification limit on the bottom head to steam dox.e temperature difference (145 Deg. P) l 4-55 6
during normal plant operation with the recirculation pumps !
operating.
The reactor steam dome pressure was constant at 930 psig throughout the test resulting in a constant steam dome saturation temperature of 536 Deg. F. The temperature difference between the steam dome and the bottom head drain varied by less than 4 Deg. F from a maximum of 18 Deg. F as recirculation speed varied from 27% to 18%, control rod drive flow varied from 60 gpm to 40 gpm, and reactor water
. cleanup flow varied from 78 gpm to 139 gpm.
The variations in recirculation, control rod drive and reactor water cleanup flows had a negligible impact on the steam dome to bottom drain temperature difference, and the Technical Specification limit of 145 Deg. F was not approached. No temperature stratification was observed; hence, the present recirculation pump low speed mechanical stop settings (18% of rated MG set speed) are acceptable.
l STP-16.2, Bottom Head Drain Temperature This test was performed during Test condition 3 at rated pressure and 62% power. The accuracy of the bottom head drain temperature was verified by comparing its measurement with the recirculation loop coolant temperature at rated flow when adequate mixing in the vessel lower head can be assumed.
The average difference in the temperatures was 6.18 degrees F. Thus the applicable acceptance criteria were satisfied.
l STP-16.3, Recirculation Pump Trip Recovery Data This test was performed three times at 73.61, 69%, and 47.9% rated power during recirculation pump trips of one pump and two pumps in Test Condition 3, and during Test condition 4,(natural circulation). The recorded data was i used to verify that adequate mixing is occurring to avoid reactor vessel thermal shock during flow increases or idle recirculation pump restarts.
All temperature differences were within the ilmits set by the acceptance criteria. The maximum steam dome to bottom head drain temperature difference was 37.7 degrees F.
during one pump operation prior to Test Condition 4. The maximum steam dome to idle recirc loop temperature difference was 39.25 degrees F. for loop B during the two 4-56
pump trip in Test Condition 3. The maximum recirc loop A to recirc loop B temperature difference was 16.9 degrees F.
during one pump operation prior to two pump recovery in Test Condition 3.
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4.15 STP-17, SYSTEM EXPANSION OBJECTIVES This test verifies that safety related piping systems and other piping systems as identified in the FSAR expand in an acceptable manner during plant heatup and power escalation.
Specific objectives are to verify that:
Piping thermal expansion is as predicted by design calculations.
Snubbers and spring hangers remain within operating travel ranges at various piping temperatures.
Piping is free to expand without interferences.
ACCEPTANCE CRITERIA Level 1 There shall be no obstructions which will interfere with the thermal expansion of the Main Steam (inside drywell) and Reactor Recirculation piping systems.
The displacements at the established transducer locations shall not exceed the allowable values.
Level 2 The displacements at the established transducer locations shall not exceed the expected values.
Snubbers and spring hangers do not become extended or compressed beyond allowable travel limits (working range) and snubbers retain swing clearance.
Measured displacements compared with the calculated displacements are within the specified range.
Residual displacements measured following system return to ambient temperature do not exceed the greater of + 1/16 in.
or + 25tof the maximum displacements measured durIng system initial heatup.
RESULTS STP-17.1, Measured Pipe Displacements (Selected BOP Systems)
The results of the testing verified that the balance-of-plant piping scoped for thermal expansion testing in the 4-58
Stcrtup Tact Progrrm, par FSAR Table 3.9.7, was frC3 to move without unplanned obstruction or restraint during heatup and cooldown, that the system piping behaved in a manner consistent with assumptions of the stress analysis, and that there was agreement between calculated and measured values of displacement.
The thermal movements of system piping were measured during Test Condition Open Vessel (baseline), Test Condition Heatup, and following reactor initial cooldown from normal operating temperature.
Piping movements were measured using both remotely monitored instrumentation and direct manual / visual methods.
Spring hangers and snubbers on specified piping segments were inspected to verify that these devices did not become extended or compressed beyond their working range.
System expansion testing was performed on selected segments of the following BOP piping systems:
- a. Main Steam (loops B and C, outside drywell)
- b. Residual Heat Removal (shutdown cooling mode supply / return, LPCI, and head spray inside drywell)
- c. Core Spray (Loop A, inside drywell)
- d. High Pressure Coolant Injection (turbine steam supply)
- e. Reactor Core Isolation Cooling (turbine steam supply)
- f. Reactor Water Cleanup (from the regenerative heat exchanger to the RPV)
Initial piping positions were determined, relative to structural reference points, prior to reactor heatup in order to estabish baseline data.
System expansion testing for Main Steam was performed during initial reactor heatup at reactor moderator temperatures of 275 degrees F, 450 degrees F, and rated -
reactor temperature and pressure. ;
i System expansion testing for High Pressure Coolant Injection and Reactor Core Isolation Cooling was performed )
at reactor moderator temperatures of 350 degrees F, 450 l degrees, and rated reactor temperature and pressure.
System expansion testing for Residual Heat Removal, Core Spray, and Reactor Water Cleanup was performed at rated reactor temperature and pressure.
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i Residual displacements for all tested system were determined subsequent to the cooldown from the initial !
reactor heatup. l Problems encountered during the performance of this test l were minor in nature and include the following
- 1. Several expansion values and residual displacements fell outside of the stated tolerances. These values were analyzed for their affect on the involved piping by Bechtel Engineering. Following this review they were deemed acceptable and required no further action.
4 2. During testing it was determined that the temperature assumptions used by Bechtel Engineering for the main steam piping did not agree with actual test conditions. The piping was assumed to be hot up to the turbine nozzles for the initial calculations.
During Test Condition Heatup the turbine stop valves are closed, thus the downstream piping is at or near ambient conditions. The actual expansions were compared against calculated valves for the prevailing conditions by Bechtel Engineering. The test data was found to be satisfactory for the existing pipe temperatures. A subsequent retest was performed during turbine operation to verify the original expansion values. The results of the retest were satisfactory.
- 3. Two abandoned whip restraints on the RCIC steam supply line were determined to present a restraint to the thermal movement of the piping. They were removed. A retest was performed during a subsequent heatup and the results were satisfactory.
- 4. The RHR head spray line initial displacements were outside of the stated tolerances. Bechtel Engineering reviewed the actual displacements and found the stresses acceptable. However, due to the line's inaccessable location (during operation), additional instrumentation was added to increase the information available for analysis. The line was retested during a subsequent heatup. The displacements were essentially the same as the initial heatup. Bechtel Engineering reviewed the retest data and found the stresses to be acceptable for all future plant operations.
STP-17.2, Measured Pipe Displacements (Feedwater and RWCU Systems) 4-60
This test monitors the feedwater piping system downstream of the high pressure heaters and RWCU piping, where expansion is controlled by feedwater temperature, during power ascension.
The results of the testing, to date, verify that the balance-of-plant feedwater piping scoped for thermal expansion testing in the Startup Test Program, per FSAR Table 3.9.7, is free to move without unplanned obstruction or restraint during the heatup thus far accomplished.
Measurements indicate that the system piping is behaving in a manner consistent with assumptions of the stress analysis and that there is agreement between calculated and measured values of displacement. Further testing is planned during Test Condition 6 (420 degrees F Feedwater Temperature) and upon return to cooldown conditions.
Thermal expansion data has been taken at Test Condition Open Vessel (Baseline Measurements), and during Test Condition 2 (275 degrees F Feedwater Temperature).
Piping movements were measured using both remotely monitored instrumentation and direct manual / visual methods.
Spring hangers and snubbers on specified piping segments were inspected to verify that these devices did not become l extended or compressed beyond their working range.
l Problems encountered during the performance of this test were minor in nature and include the following:
- 1. One remote measurement device, a lanyard potentiometer
- DT.YB.06, was determined to have failed. Following engineering evaluation, it was determined that sufficient data was available from this test and previous data to accept the test results as run. This detector has subsequently been repaired.
l l 2. One expansion value, that of DT.YB.04, fell outside of j stated tolerances. This measurement was analyzed, by Bechtel Engineering, for it's effect on the involved piping. Following this review, it was deemed acceptible and required no further action.
3TP-17.3, Measured Pipe Displacements (Main Steam Inside Drywell and Reactor Recirculation)
This subtest provides the means for collecting thermal expansion data on the Main Steam lines (inside the drywell) and Reactor Recirculation piping under specific conditions.
Data collection was accomplished using the Emergency 4-61 t
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Response Facilities Data System (ERFDS) and the specific system remote monitoring instrumentation (Lanyard Potentiometers and Resistance Temperature Devices, RTD's) installed on each Main Steam line and Recirculation loop. j l
Thermal expansion data collection was taken at Open Vessel '
and Test Condition Heatup 275 + 25 DEG F, 425 + 25 DEG F, and normal operating temperature.
Remotely monitored instrumentation are in two locations on each steam line and four locations on each reactor recirculation loop. For these NSSS triaxial transducers, Level 1 limits are calculated for the existing pipe temperature and Level 2 limits apply only at rated conditions. All Level 1 limits were mat at 275 Deg F. At 425 Deg F, point SB-LZ on the B Main Steam Line did not meet its Level 1 limit. A combination of visual inspections of steam line "B" and re-evaluation of the criteria by GE Plant Piping Design resulted in a revision to the Level l criteria for SB-LZ. Permission was granted to continue testing and heatup to rated conditions. For Heatup at rated conditions, 19 remotely monitored points fell outside of their Level 2 limits. These test exceptions were documented and discussed with GE Plant Piping Design. The resolution was to monitor all NSSS transducers during the second and third heatup cycles. The test results for all these cycles clearly illustrate that the. piping expansion was nearly identical for all heatup cycles monitored. The piping movements experienced during the first, second and third heatups were judged to be acceptable by GE Plant Piping Design.
STP-17.4, Visual Pipe Inspections (Main Steam Inside Drywell and Reactor Recirculation)
This test monitored the main steam inside drywell and recirculation piping systems by visual inspections of the piping, hangers and snubbers during Test Condition Open Vessel (baseline data), Test Condition Heatup (at 275 + deg F and normal operating temperature), and following two-complete heatup cycles.
Visual inspections of the Recirculation and Main Steam piping and supports at T.C. Open Vessel showed no evidence of obstructions to normal system expansion. No cables were found stretched, no position indicators were out of their travel range., and no hangeli were bottomed out.
Visual inspections were performed during Heatup at 275 Deg F, at Rated Temperature, and shutdown after two heatup 4-62 i'
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cyclcs ware complete. Of tha 110 piping reatraints
'~
associated with this test, a total of seven Main Steam and
- q Recirculation hangers were found to be outside of their hot and cold design settings. This data was evaluated by
- Plant Piping Design and was determined to be accep!OC1,GE 93 All snubbers were within their normal operating katigo. No hangers were found fully extended or compressed and no cables were found stretched. No restrictions to thermal -
expansion were noted.
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l 4.16 STP-18, TIP UNCERTAINTY I OBJECTIVES The objective of this test is to determine the reproducibility of the Traversing Incore Probe system readings.
ACCEPTANCE CRITERIA Level 1 None l
Level 2 The total TIP uncertainty (including random noise and geometrical uncertainties) obtained by averaging the uncertainties for all data sets shall be less than 6%.
RESULTS l STP-18.1, Tip Uncertainty Determination In this test, the random noise, geometric, and total TIP uncertainties were calculated from TIP data taken during TC 3 when the TIP system was operated in conjunction with the Process Computer programs OD-1, OD-2, and OD-10. For the random noise component, six TIP traverses were performed on the common channel for each TIP machine but only four and l five successful OD-2 and OD-10, Option 59 edits were obtained for TIP machines 2 and 3, respectively.
Therefore, the uncertainties were calculated using the four l consecutive TIP traces from each TIP machine. The applicable Level 2 criterion was easily satisfied. The values of the uncertainites are listed below:
Geometric Uncertainty = 3.152%
Random Noise Uncertainty = 0.943%
Total TIP Uncertainty = 3.290%
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4.17 STP-19, CORE PERFORMANCE OBJECTIVES The objectives of this test are to:
a) Evaluate the core thermal power and core flow )
rate; and b) Evaluate whether the following core performance parameters are within limits:
Maximum Linear Heat Generation Rate (MLHGR), !
Minimum Critical Power Ratio (MCPR),
Maximum Average Planar Linear Heat Generation Rate (MAPLHGR).
ACCEPTANCR CRITERIA Level 1 The Maximum Linear Heat Generation Rate (MLHGR) of any rod during steady-state conditions shall not exceed the limit specified by the Plant Technical Specifications (13.4 kw/ft).
The steady-state Minimum Critical Power Ratio (MCPR) shall exceed the minimum limit specified by the Plant Technical Specifications.
The Maximum Average Linear Heat Generation Rate (MAPLHGR) shall not exceed the limits specified by the Plant Technical Specifications.
Steady-state reactor power shall be limited to the rated core thermal power (3293 MWt).
Core flow shall not exceed its rated value (100 Mlb/hr).
Level 2 None RESULTS STP-19.1, Core Performance - BUCLE Calculation In Test Condition 1, the off-line computer program, Backup Core Limits Evaluation (BUCLE), was used to calculate the core thermal limit parameters MLHGR, MCPR, and MAPLHGR. A manual heat balance was also performed to calculate the 4-65 l
retctor core thermal power. All acc3ptanca criteria woro satisfied.
The reactor core thermal power and core flow rate during the test were 724 MWt and 43 Mlb/hr, respectively. These were less than the Level 1 criterion limits of 3293 MWt and 100 Mlb/hr.
The values of MFLPD, MFLCPR, and MAPRAT were calculated to be 0.262, 0.307, and 0.242, respectively, using the off-line computer program BUCLE. Since all of these thermal limit parameter ratios were less than 1.0, the Level 1 acceptance criteria were satisfied.
l STF-19.2. Process Computer Calculation This test was performed at 38%, 60%, 42t, and 62% core thermal power during-Test Conditions 2, 3, 4, and 5 respectively. The purpose of this test is to verify the process computer calculation of thermal limits using core performance parameters and heat balance data. All acceptance criteria were satisfied as shown below:
Test Condition 2 3 4 5 Limit Core thermal power (%) 38.6 60.1 41.9 62.3 100 Core flow (%) 46.7 88.98 39.98 54.41 100 CMFLPD 0.475 0.567 0.362 0.536 1.00 CMFCP 0.556 0.534 0.580 0.695 1.00 CMAPR 0.466 0.547 0.363 0.531 _ 1.00 4-66 l
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4.18 STP-20, STEAM PRODUCTION OBJECTIVES The objectives of this test is to demonst' ate that the Nuclear Steam Supply System (NSSS) is providing steam sufficient to satisfy all appropriate warranties as defined in the NSSS contract.
ACCEPTANCE CRITERIA Level 1 The NSSS parameters as determined by using normal operating procedures shall be within the appropriate license restrictions.
The NSSS will be capable of supplying 14,159,000 pounds per hour of steam of not less than 99.7% quality at a pressure of 985 psia at the discharge of the second main steam isolation valve, as based upon a final reactor feedwater temperature of 420 degrees F and a control rod drive feed flow of 32,000 pounds per hour at 80 degrees F. The reactor feedwater flow must equal the steam flow less the control rod drive feed flow.
Level 2 None RESULTS STP-20 has not been performed at this time. Results will be discussed in a supplement to this report.
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4.19 STP-21, CORE POWER-VOID MODE RESPONSE OBJECTIVES The objective of this test is to measure the stability of the core power-void dynamic response and to demonstrate that its behavior is within specified limits.
ACCEPTANCE CRITERIA Level 1 The decay ratio of any oscillatory core variable must be less than 1.0 at all test points.
Level 2 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 0.50.
RESULTS STP-21.1, Core Power - Void Mode Response to Control Rod Movement This test was performed at test conditions 4 and 5 to observe reactor response (specifically APRM.and LPRM) to a control rod movement which produced an LPRM change of approximately 5% from steady state values. Recirculation pumps were tripped (natural circulation) in Test Condition 4 and at minimum speed in Test Condition 5. Choice of a control rod to affect an LPRM response took into consideration the control rods notch worth and proximity to most limiting assemblies, and, thereafter, the LPRM was chosen to be near the control rods tip.
For Test Condition 4, the LPRM 32-41-C was used to monitor the continuous insertion of control rod 30-39 from notch position 26 to 16 (5 notches). The LPRMs reading dropped from 27 to 21.
For Test Condition 5, the LPRM 32-25-C was used to monitor the insertion of control rod 30-23 from notch positions 24 to 18 (3 notches final). The control rod was inserted an amount of notches, and then withdrawn, until a 5%
difference from steady state was obtained. The LPRM's reading were 39 (initial), 38 (1 notch), 37 (2 notches) and finally 34 (3 notches).
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i During these events reactor transient response was recorded and core stability was demonstrated to be acceptable. ,
1 All acceptance criteria were satisfied for both test conditions.
]
STP-21.2, Core Power - Void Mode Response to Reactor Pressure Changes This test was performed at Test Conditions 4 and 5 to :
observe reactor response (specifically APRM and LPRM) to a rapid change in core pressure (an approximate 10 psi setpoint step change to the pressure regulator in control).
Recirculation pumps were tripped (natural circulation) in Test Condition 4 and at minimum speed in Test Condition 5.
For these transients, the Turbine Load Limit and Load Set were set high to allow only control valves to control reactor pressure.
For both test conditions, pressure regulator "A" was placed in control with a pressure setpoint bias of 3 psi.
During these pressure changes, reactor transient response was recorded and core stabflity was demonstrated to be acceptable.
l All acceptance criteria were satisfied for both tests.
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4.20 STP-22, PRESSURE REGULATOR OBJECTIVES The objectives of this test are as follows:
To demonstrate optimized controller settings for the pressure control loop by analysis of the transients induced in the reactor pressure control system by means of the pressure regulators set point changes.
To demonstrate the take-over capability of the back-up pressure regulator upon failure of the controlling pressure regulator, and to set spacing between the setpcints at an appropriate value.
To demonstrate smooth pressure control transition between the turbine control valves and the bypass valves when reactor steam generation exceeds the steam flow used by the turbine.
To demonstrate the stability of the reactivity-void feedback loop to pressure perturbations in conjunction with STP-21, Core Power Void-Mode Response.
ACCEPTANCE CRITERIA Level 1 The transient response of a'ny pressure control system related variable to any test input must not diverge.
l l Level 2 Pressure control system related variables may contain oscillatory modes of response. In these cases, the decay ratio for each controlled mode of response must be less than or equal to 0.25. (This criterion does not apply to tests involving simulated failure of one regulator with the backup regulator taking over.)
The pressure response time from initiation of pressure setpoint change to the turbine inlet pressure peak shall be
<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 percent of rated steam flow.
The peak neutron flux and/or peak vessel pressure shall remain below the scram settings by 7.5 percent and 10 psi l
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i respectively for all pressure regulator transients performed at Test Condition 6.
The variation in incremental regulation (ratio of the maximum to the minimum value of the quantity, " incremental change in pressure control signal / incremental change in steam flow", for each flow range) shall meet the following:
% of Steam Flow Obtained With Valves Wide Open Variation 0 to 85% $4:1 85% to 97% $2:1 85% to 99% $5:1 RESULTS STP-22.1, Pressure Regulator Response - Control Valve Operation (Test conditions 2, 3, 4, and 5)
STP-22.2, Pressure Regulator Response - Control Valve and Bypass Valve Operation (Test Condition 3)
STP-22.3, Pressure Regulator Response - Bypass Valve Operation (Test Conditions 1, 2, 4, and 5) l These tests were performed during the Test Conditions noted. System response to nominal 10 psi step changes and i failure to the backup regulator (TC 1, 2 and 3 only) were l recorded and analyzed. All acceptance criteria were satisfied. The transient response to test inputs did not diverge thus satisfying the Level 1 criterion. With respect to the applicable Level 2 criteria, the following was observed:
- 1) All pressure control system decay ratios were less than 0.25.
- 2) The maximum response time to pressure setpoint changes was 8.875 seconds for STP-22.2, during Test Condition l 3, which is within the required 10 second criterion.
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- 3) The pressure control system did not display steady state limit cycles. Steam flow variations were not greater than +0.5% of rated steam flow.
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4.21 STP-23, FEEDWATER SYSTEM OBJECTIVES The objectives of this test are:
To demonstrate that the feedwater system has been adjusted to provide acceptable reactor water level control.
To demonstrate an adequate response to a feedwater temperature reduction.
To demonstrate the capability of the automatic core flow runback feature to prevent low water level scram following the trip of one feedwater pump at high power operation.
To demonstrate that the maximum feedwater runout capability is compatible with the licensing assumptions.
ACCEPTANCE CRITERIA Level 1 The transient response of any level control system-related variable to any test input must not diverge.
For the feedwater heater loss test, the maximum feedwater temperature decrease due to a single failure case must be
<100 deg. F. The resultant MCPR must be greater than the Tuel thermal safety limit.
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 changes and initial power level.
Maximum soeed attained shall not exceed the speeds which will give the following flows with the normal complement of pumps operating.
- a. 135% NBR at 1075 psia
- b. 146% NBR at 1020 psia Level 2 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.
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1 Tha op:n loop dynamic flow response of each feedwater actuator (turbine) to small (<10%) step disturbances shall ,
be:
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- a. Maximum time to 10% of a step disturbance $1.1 sec l
- b. Maximum time for 10% to 90% of a step disturbance $1.9 sec
- c. Peak overshoot (% of step disturbance) 115%
- d. Settling time, 100% 15% 4 sec 114 The average rate of response of the feedwater actuator to large (>20% of pump flow) step disturbance <, shall be between 10 percent and 25 percent rated reedwater flow /second. This average response rate will be assessed by determining the time required to pass linearly through the 10 percent and 90 percent response points.
As steady-state generation for the 3/1 element systems, the input scaling to the mismatch gain should be adjusted such that the level error due to biased mismatch gain output should be within $1 inch.
The increase in simulated heat flux cannot exceed the predicted value referenced to the actual feedwater temperature change and initial power level.
The reactor shall avoid low water level scram by three .
I inches margin from an initial water level halfway between the high and low level alarm setpoints.
l The maximum speed must be greater than the calculated speeds required to supply:
- a. With rated complement of pumps - 115% NBR at 1075 psia
- b. One feedwater pump tripped conditions - 68% NBR at 1025 psia.
RESULTS STP-23.1, FW System Startup Controller Level Step l
STP-23.1 was successfully performed during TC-1. The level control system did not diverge as a result of any test j input, and therefore, complied with the single Level 1 r
criterion for this subtest. The Level 2 criterion, however, was not satisfied for a level controller step input of -5 inches. The observed decay ratio was 0.33 rather than the required 0.25. A test exception was l
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written to accept the 0.33 decay ratio as it did not significantly affect system operation. A controller step input of +5 inches displayed the required decay ratio.
l STP-23.2, Feedwater System Manual Flow Step l STP-23.2 was run for each pump (5, E and C) in Test Condition 2 (28% and 43% power) and Test condition 3 (68%
power). In these subtests, positive and negative flow steps were introduced using a function generator on the inputs of the lA, 1B, and 1C Reactor Feed Pump Turbine (RFPT) speed controllers. The transients were monitored and recorded to verify compliance with the acceptance criteria.
The Test Condition 2 testing was performed at lov enough pouer and feedwater flow levels that did not allow complete evaluation of control system performance, but was sufficient to support ascension to Test Condition 3.
Test Condition 3 testing for RFPT A demonstrated that all of the control system-related variables were uell damped in their response to the transients. All of these variables had decay ratios less than or equal to 0.25. Further, it uas determined that the open loop dynamic flow response tests of each feedwater actuator to small step disturbances and the average rate of responses of the actuators to largo disturbances achieved adequate results for this test I condition. -
Test Condition J testing for RFPT B demonstrated that all of the control system-related variables were adequately l damped in their response to the transients. It also demonstrated that the average rate of responses of the feedwater actuator (turbine) to large step disturbances vere within the acceptance criteria. Further, it was determined that a steady state hydraulic oscillation c::isted in the "B" feeduator system making the controller j appear to respond with a decay ratio greater than 0.25 and made settling time indeterminant. These oscillations also affected the open loop flow response criteria for rise time for the 5% step change. Since the oscillations are not considered a control related problem, the "as is" conditions has been considered not to cause a degredation l of level control ability and will be evaluated further in l Test Condtion 6.
Test Condition 3 testing for RFPT C demonstrated that all of the control system-related variables were well damped in l their response to the transients. It also demonstrated .
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that all of these variables had decay ratios less than or equal to 0.25. Further, it was determined that the open loop dynamic flow responses of the feedwater actuator to small step disturbances was the best reasonably achievable '
i and provided an adequate response to control reactor water level. The average rate of responses of the actuators to large disturbances is expcoted to provide acceptable margins to high and low water level trips and will be evaluated further in Test conditica G.
In summary, all of the fecdwater control systems demonstrated reasonable results such that the intent of the te' sting is satisfied. Control system performance will be evaluated again in Test Gondition 6.
l STP-23.3 Feeduater System Level Setpoint Changes This test uas performed at 27% and 71% core thermal power in Test Conditions 2 and 3 respectively.
In this subtest, the Master Feedwater Controller was used to demand positive and negative step changes in Reactor Water Level in one and three element control. Also, reactor unter level was observed when switching between one and three element control.
There were no divergent control system related variable responses to any transient. The decay ratio for each
! variabic was less than or equal to 0.25 and the steady l state reactor unter level error due to switching betueen one and three element control remained within the applicable criteria. All testing was performed with catisfactory results.
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4.22 STP-24, TURBINE VALVE SURVEILLANCE OBJECTIVES The objectives of this test are to demonstrate acceptable procedures and maximum power levels for periodic surveillance testing of the main turbine control, stop and bypass valves without producing a reactor scram.
ACCEPTANCE CRITERIA Level 1 -
None Level 2 Peak neutron flux must be at least 7.5% below the scram trip setting.
Peak vessel pressure must remain at least 10 psi below the high pressure scram setting.
Peak steam flow in each line must remain 10% below the high flow isolation trip setting.
RESULTS l STP-24.1, Stop Valve Testing The Stop Valve Testing was performed in Test Condition 3.
In this test, each Main Turbine Stop Valve (MSV) was stroked from full open to full closed and back open, to verify a 7.5% peak neutron trip margin, a peak vessel pressure margin of 10 psi below the trip setpoint, and a peak steam flow of 10% below the high flow isolation setting. This was accomplished using the test pushbuttons on the EHC Turbine Control Panel.
l All acceptance criteria were satisfied.
l STP-24.2, Control Valve Testing The Control Valve Testing was performed in Test Condition
! 3. This test called for individual cycling of each Main Turbine Control Valve (CV) from its initial position to fully closed and then returning to its initial position.
Reactor pressure is maintained by repositioning other CVs l
or Bypass Valves as demanded by the pressure regulator.
Recorded data was used to determine that the peak neutron 4-76
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flux was at least 7.5% below the scram trip setting, peak vessel pressure remained at least 10 psi below the high pressure scram setting, and peak steam flow in each line remained 10% below the high flow isolation trip setting.
The testing in Test Condition 3 was completed successfully and all acceptance criteria were satisfied.
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4.23 STP-25, MAIN STEAM ISOLATION VALVES OBJECTIVES The objectives of this test are to functionally check the Main Steam Isolation Valves (MSIV's) for proper operation at selected power levels, to determine the MSIV closure times, and to determine the maximum power level at which full closure of a single MSIV can be performed without causing a reactor scram.
The full isolation is performed to determine the reactor transient behavior that results from the simulraneous full closure of all MSIV's at a high power level.
ACCEPTANCE CRITERIA Level 1 MSIV stroke time shall be no f.13ter than 3.0 seconds. MSIV closure time shall be no slower than 5.0 seconds.
The positive change in vessel dome pressure occurring within 30 seconds after closure of all MSIV's 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.
Feedwater control system settings must prevent flooding of the steam lines.
Reactor must scram to limit the severity.of the neutron l flux and simulated heat flux transients.
Level 2 The reactor shall not scram. The peak neutron flux must be at least 7.5 percent below the trip setting. The peak vessel pressure must remain at least 10 psi below the high pressure scram setting.
The reactor 'shall not isolate. The peak steam flow on each line must remain 10 percent below the high steam flow isolation trip setting.
The temperature measured by thermocouples on the discharge side of the safety / relief valves must return to within 10 degree F of the temperature recorded before the valve was opened.
The positive change in vessel dome pressure and simulated heat flux occurring within the first 30 seconds after the 4-78
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j
closure of all MSIV valves must not exceed the predicted values. Predicted values will be referenced to actual test conditions of initial power level and dome pressure and will use beginning of life nuclear data.
If water level reaches the reactor vessel low water level (Level 2) setpoint, RCIC and HPCI shall automatically initiate and reach rated system flow.
Recirculation pump trip shall be initiated if water Level 2 is reached.
RESULTS STP-25.1, MSIV Functional Test b
This test was performed during Test Conditions Heatup, 1 and 2, functionally checking the Main Steam Isolation Valves (MSIVs) and measuring their closure times. During Test Condition 1, MSIV F022A did not meet the criteria for stroke time (2.84 seconds actual versus 3.0 seconds criteria). Subsequent adjustments were made and MSIV F022A was retested at similar conditions during Test Condition 2, giving satisfying results. During the tests, the reactor did not scram and peak APRM readings remained at least 7.5%
below the scram setpoint. The scram setpoint for Test Condition Heatup was 15%, and, for Test Condition 1, the scram setpoint was 61% (69.2% for MSIV F022A retest). The reactor,did not isolate and the peak steam flow on each line remained less than 126% (10% below the high steam flow isolation trip setpoint). The peak vessel pressure remained less than 1027 psig (10 psig below the high pressure scram setpoint). All applicable acceptance criteria were satisfied. .
l STP-25.2, Full Closure of Fastest MSIV This test was performed during Test Conditions 3 and 5 to demonstrate the highest power level at which the fastest MSIV (F022B)'could be closed without causing a scram.
During the tests, the reactor did not scram and peak APRM readings remained at least 7.5% below the scram setpoint.
The scram setpoint for Test Condition 3 was 116.5%, and, for Test Condition 5, the scram setpoint was 78.8%. The reactor did not isolate and the peak steam flow remained less than 126% (10% below the high steam flow isolation trip setpoint). The peak vessel pressure remained less than 1027 psig (10 psig below the high pressure setpoint).
All applicable acceptance criteria were satisfied. The 4-79
l tc2t will bo parformsd cgnin et the predicted powar levol ,
of approximately 80% during Test Condition 6. l l
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4.24 STP-26, RELIEF VALVES OBJECTIVES The objectives of this test are a) to verify that the Relief Valves function properly (can be manually opened and -
closed, b) to verify that the Relief Valves reseat properly after actuation, c) to verify that there are no major blockages in the Relief Valve discharge piping, and d) to demonstrate system stability to Relief Valve operation.
ACCEPTANCE CRITERIA Level 1 There should be a positive indication of steam discharge during the manual actuation of each Relief Valve.
The flow through each Relief Valve shall compare favorably with value assumed in the FSAR accident analysis at normal ,
operating Reactor pressure.
Level 2 Pressure control system-related variables may contain ,
oscillatory modes of response. In these cases, the decay ratio for each controlled mode of response must be less ,
than or equal to 0.25.
. The temperature measured by the thermocouples on the discharge side of the valves shall return to within 10 DEG F of the temperature recorded before the valve was cpened.
During the low pressure functional test, the steam flow through each Relief Valve, as measured by Bypass
- Valve '
position, shall not be less than 90% of the average Relief Valve steam flow.
During the rated pressure functional test, the steam flow through each Relief Valve, as measured by Generator Gross MWe, shall not be lower than the average valve response by more than 0.:5% of rated MWe.
RESULTS STP-26.1, Relief Valve Low Pressure Test During Test Condition Heatup with reactor pressure at 300 poig, each Relief Valve was manually cycled to verify proper operation. Each valve was maintained open for apprcximately 10 seconds to allow system variable to stabilize.
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i Positive indication of Relief Valve discharge was verified by review of transient plots of Dypass Valve position. The steam flow through each valve, as measured by Bypass valve position, was greater than 90% of the average Relief valve flow.
During the initial Relief Valve lif t, with reactor pressure at 375 psig, Bypass Valves went fully shut. The Relief ,
valve was immediately shut. Reactor' pressure was then reduced to 300 psig, additional Dypss Valve capacity was obtained, and the test was successfully completed.
All applicable acceptance criteria were satisfied with the l following exceptions: Relief Valves C, D, G, J, L and S did not meet the Level 2 criterion for discharge side temperatures returning to within 10 Deg. F of the initial temperature. Valve position, as indicated by the Acoustic Monitoring System, indicated that all valves were fully shut. Final resolution is pending disposition of the Test Exception Report.
l STP-26.2, Relief Valve Rated Pressure Test This test was performed during Test Condition 2. Each relief valve was manually cycled and maintained open. for approximately 10 seconds to allow system variables to stabilize. Positive indication of Relief Valve discharge l was verified by the change in gross generator output (Mue).
All relief valves actuated and flow through each valve compared favorably with the value assumed in the PSAR accident analysis at normal operating reactor pressure I satisfying the Level 1 criteria.
All Level 2 criteria were satisfied with the following exceptions: 1) Relief Valves B, C, F, G, K, M and N did not meet the criterion for discharge side temperatures returning to within 10 degrees F of the initial temperature. Final reGolution is pending disposition of the Test Exception Report. 2) The data point for Relief l
valve PSV41-1F013-D was inoperable so temperature data could not be taken. All acoustic monitors indicated that relief valves (including PSV41-lF013-D) were closed
{ follouing their opening for this test.
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4 4.25 STP-27, MAIN TURBINE TRIP j OBJECTIVES The objectives of this test are to demonstrate the response of the Reactor and its control systems to protective trips of the Main Turbine and to evaluate the response of the bypass and safety / relief valvas.
ACCEPTANCE CRITERIA Level 1 For Turbine and Generatcr Trips at power levels greater than 50% Nuclear Sciler Rated, there should be a delay of less than 0.1 seconds following the beginning of Control or Stop Valve closure before the beginning of Bypass Valve opening. The Bypass Valves should be opened to a point corresponding to greater than or equal to 80% of their capacity within 0.3 seconds from the beginning of Control or Stop Valve closure motion.
Feedwater Systen settings must prevent flooding of the steam lines following these transients.
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.
The positive change in simulated Heat Flux shall not exceed the Level 2 criteria by more than 2% of Rated Value.
The recirculation pump and motor time constants for the two pump drive flow coastdown transient should be <4.5 seconds from 1/4 to 2 seconds after the pumps are tripped.
The total time delay from the start of the Turbine Stop valve or Control Valve motion to the complete suppression of the electrical arc between the fully open contacts of the RPT circuit breakers shall be less than or equal to 175 milliseconds.
Level 2 There shall be no MSIV closure during the first three minutes of the transient and operator action shall not be required during that period to avoid the MSIV closure.
The positive change in vessel dome pressure occurring within the first 30 seconds after the initiation of either Generator or Turbine Trip must not exceed predicted values.
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The positivo change in simulated Heat Flux occurring within the first 30 seconds after the initiation of either Generator or Turbino Trip must not exceed predicted values.
Fecdwater level control shall avoid loss of feeduater flow due to a high (LS) water level trip during the event.
Low (L2) water level recirculation pump trip, HPCI and RCIC shall not be initiated.
The temperature measured by thermocouples on the discharge side of the Relief valves must return to within 10 Degree F of the temperature recorded before the valve was opened.
For the Turbine Trip within the Bypass Valves capacity, the Reactor shall not scram.
The measured Bypans Valvo capability shall be equal to or greator than that used in the PSAR analysis (25% of Nuclear Boiler Rated Steam Plow).
RESULTS l STP-27.1, Turbino Trip Within Bypass Valve Capacity This test was performed at 22% corc thermal power during Test Condition 2. The main turbine was tripped manually by depressing the Turbine Trip pushbutton which shut the four
!!ain Turbine Stop and Control valves. The bypass valves opened to maintain pressure control and the reactor did not i scram, thus satisfying the single Level 2 acceptance criterion.
\ STP-27.2, Bypass Valvo Capacity Check This test was performed at 77% and 37% core thermal power during Test conditions 3 and S respectively. The bypass valvo capacity Level 2 acceptance criterion was not satisfied in Test condition 3. An engineering analysis was performed by General Electric which demonstrated that the bypass valve capacity was not safety or operationally limiting at the value obtained. A retest was performed in l Test Condition 5 utilizing an improved test method.
In Test Condition 5 reactor power was increased while generator output uas held constant. As power increased I bypass valves opened to maintain reactor proscuro. A plot was obtained of the change in reactor power versus bypass valvo position.
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l From thin graph the capacity of the bypass valvoc uns determined. Total bypacc valvo capacity unc calculated to bc 27.3% of rated core thermal power, thus satisfying the applicable acceptance criterion.
1 l STP-27.3, Turbino Trip at Test Condition 3 This test was performed at 75% core thermal power during Test Condition 3. The turbine was tripped by manually pulling the Front Standard Trip !!andle which caused the four Main Turbine Stop and Control Valves to close.
All Level 1 acceptance criteria were met with the exception of the follouing: tio simulated heat flux signals were available. The Plant Operational Review Committoc (PORC) has determined that IIeat Flux Level 1 and Level 2 critoria vero satisfied based on an evaluation by the General Cloctric Plant Operational Performance Engineer.
All Level 2 acceptance criteria were catisfied uith tho exception of the follouing: 1) see the above comment for the level 1 heat flux criterion 2) the maximum reactor unter level uns greater than lovel 8 at 60 inches.
Additional feeduater control cystem testing vill be per formed in Test Condition 6. Foodwater level control system performance vill be evaluated during the Turbine Trip at Test Condition G (STP-27.4) .
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4.26 STP-28, SHUTDOWN FROM OUTSIDE THE CONTROL ROOM OBJECTIVES The objectives of this test are to demonstrate that the Reactor a) can be safely shutdown from outside the Control Room, b) can be maintained in a Hot Standby condition from outside the Control Room and c) can be safely cooled from hot to cold shutdown from outside the Control Room. In addition, it will provide an opportunity to demonstrate that the procedures for Remote Shutdown are clear and comprehensive and that operational personnel are familiar with their applications.
ACCEPTANCE CRITERIA Level 1 None Level 2 During a simulated Control Room evacuation, the Reactor must be brought to the point where cooldown is initiated and under control, and Reactor vessel pressure and Water level are controlled using equipment and controls located outside the Control Room.
The Reactor can be safely shutdown to a Hot Standby condition from outside the Control Room using the minimum shift crew complement.
The Reactor coolant temperature and pressure can be lowered sufficiently (at a rate that does not exceed the Technical Specification Limit) from outside the Control Room to permit operation of the Shutdown Cooling Mode of the Residual Heat Removal System.
The Shutdown Cooling Mode of the Residual Heat Removal System can be initiated from outside the Control Room with a heat trans,fer path established to the Ultimate Heat Sink, ,
The Shutdown Cooling Mode of the Residual Heat Removal System can be used to reduce Reactor coolant temperature at a rate which does not exceed the Technical Specification Limit.
RESULTS l STP-28,1, Reactor Shutdown to Hot Standby Demonstration 4-86
This cubtest uns implemented in Test Condition 2 at 16.9%
rated thermal power. A reactor scram, f ull !!SIV isolation and turbine trip was initiated f rom the Auxiliary Equipment Room in accordance uith Special Event procedure SE-1 with 1 the Remote Shutdown Panel manned.
Reactor Pressure Vessel (RPV) parameters were stabilized initially at 830 psig and +54 in. water level. No automatic Relief valve lifts occurred.
A controlled Depressurization/Cooldown uas initiated in accordance with SE-1 and maintained for 35 minutes. Final l RPV parameters were obtained at 610 psig and +42in. uater level.
The applicable Level 2 acceptance criteria were satisfied during the performance of this subtest. All system operations from the Remote Shutdown Panel were satisfactory.
l STP-28.2, Reactor Cooldown Demonstration This subtest was implemented in Test Condition 2, separrtely from STP-28.1. Initial RPV parameters were 210 ,
psig pressure and > GO in. indicated (at Remote Shutdoun T panel) water level. .
Controlled cooldown/depressurization was initiated using RCIC/ Relief Valves until a final RPV pressure of 70 psig was obtained. At that point, the Shutdown Cooling mode of j RHR was initiated in accordance with SE-1. '
Cooldown/depressurization was continued in Shutdown Cooling until a greater than 50 degrees F RPV temperature decrease uc s obtained in that mode. Final RPV parameters were obtained at 20 psig and >60 in. indicated RPV level (read
(; at Remote Shutdoun panel).
During this subtest, the remaining Level 2 acceptance i criteria were satisfied.
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4.27 STP-29, RECIRCULATION FLOW CONTROL SYSTEM OBJECTIVES The objectives of this test are to demonstrate the flow control capability of the plant over the entire pump speed range, in both Individual Local Manual and Combined Master Manual operation modes and to determine that the l controllers are set for the desired system performance and stability.
ACCEPTANCE CRITERIA Level 1 The transient response of any recirculation system-related variable to any test input must not diverge.
Level 2 A. scram shall not occur due to Recirculation flow control maneuvers. The APRM neutron flux trip avoidance margin shall be >7.5% when the power maneuver effects are extrapolated to those that would occur along the 100% rated rod line.
The decay ratio of any oscillatory controlled variable must be <0.25.
Steady-state limit cycles (if any) shall not produce turbine steam flow variations greater than +0.5% of rated steam flow.
The speed demand meter must agree with the speed meter within 6% of rated generator speed.
RESULTS l STP-29.1, Local Manual Recirculation Flow Control The Local Manual Recirculation Flow Control tests were performed du' ring the ascension to Test Condition 3. In these subtests, the Recirculation Flow Control Systems' responses to step changes in generator speed demand, together with related reactor parameters response, were recorded to verify stability. Nominal +5% generator speed demand steps were injected into the recIrc flow control loops where the delta speed versus delta demand curves show the greatest gain. A voltage step generator was used to introduce the transients.
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For "A" Loop, there were no divergent oscillations. No scram occurred and the APRM neutron flux trip avoidance margin was acceptable. The decay ratios of the oscillatory variables were acceptable. Dynamic oscillations were tested acceptable, but the steady state oscillations require further analysis which will be addressed by testing in a subsequent Test Condition. Also, the speed meter output and demand signals did not agree within the required 6%. The RPM to volts calibration on the tachometer will be reverified in a subsequent Test Condition.
For "B" Loop, there were no divergent oscillations. A scram did not occur and the margin to scram was acceptable.
Decay ratios and dynamic oscillations were acceptable, but the steady state oscillations require further analysis.
The speed demand meter agreed adequately with the speed meter for "B" Loop. Steam flow oscillation analysis could not be performed due to difficulties in retrieving recorded data. Additional testing in subsequent test conditions will address these open items.
l STP-29.2, Master Manual Recirculation Flow Control The Master Manual Recirculation Flow Control test was performed in Test Condition 3. The test is performed by introducing an approximately +5% speed demand by setting the local controllers operating in manual at +5% of the Master Controller setting and switching the local controllers to automatic.
This testing was successfully performed with all acceptance criteria satisfied.
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4.28 STP-30, RECIRCULATION SYSTEM OBJECTIVES The objectives of this test are to:
~
Obtain recirculation system performance data during steady-state conditions, pump trip, flow coastdown, and pump restart.
Verify that the feedwater control system can satisfactorily control water level on a single recirculation pump trip without a resulting turbine trip and associated scram.
Record and verify acceptable performance of the circuit for a two-recirculation pump trip.
Verify the adequacy of the recirculation runback to avoid a scram upon simulated loss of one feedwater pump.
Verify that no recirculation system cavitation will occur in the operable region of the power-flow map.
ACCEPTANCE CRITERIA Level ,1 The reactor shall not scram during the one pump trip recovery.
The recirculation pump and motor time constant for the two pump drive flow coastdown transient should be <4.5 seconds from 1/4 to 2 seconds after the pumps are tripped and 13.0
~
seconds from 1/4 to 3 seconds after the pumps are tripped.
Level 2 The reactor water level margin to avoid a high level trip shall be 13.0 inches during the one pump trip.
The APRM mar, gin to avoid a scram shall be 37.5% during the pump trip recovery.
. The core flow shortfall shall not exceed 5% at rated power.
l The measured core delta P shall not be >0.6 PSI above l prediction. l l
The calculated jet pump M ratio shall not be <0.2 points i below prediction.
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The drive flow shortf all shall not exceed 5% at rated power.
The measured recirculation pump efficiency shall not be >0%
points below the vendor tested efficiency.
The nozzle and riser plugging criteria shall not be exceeded.
The recirculation pumps shall runback upon a trip of the runback circuit.
Runback logic shall have settings adequate to prevent recirculation pump operation in areas of potential cavitation.
RESULTS l STP-30.1, Recirculation System One Pump Trip The Recirculation System One Pump Trip was performed in Test Condition 3 at 73% pouer. In this test, a single recirculation pump was tripped to demonstrate the ability to avoid a high reactor water level with resultant main turbine and reactor feedwater pump trip.
During this subtest a reactor scram did not occur. Also,
- the reactor water level margin to high level trip was 2 3.0 inches and the APRM margin to scram was > 7.5% during the pump trip recovery. All applicable acceptance criteria were satisfied.
l STP-30.2, Recirculation Pump Trip (RPT) of Two Pumps The Recirculation Pump Trip (RPT) of Two Pumps was performed in Test Condition 3 at 69% power. In this test, both recirculation pumps were simultaneously tripped using the RPT Breaker trip circuit. The recirculation flow coastdown was monitored to verify that the flow reduces quickly enough to limit the reactor power spike and not so quickly that flou reduction precedes the drop in heat flux l which could cause a limiting Critical Pouer Ratio (CPR) l transient.
Both recirculation pumps were tripped and data was recorded. The subsequent data reduction showed that the l l pump and meter time constant was <4.5 seconds from 1/4 to 2 l seconds f rom pump trip and >3.0 seconds from 1/4 to 3 seconds after the pump trips.
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l All applicable acceptance criteria were satisfied.
l STP-30.3, Recirculation System Performance l Recirculation System performance was performed in Test Condtion 2, Test Condition 3 and Test Condition 4. The purpose of the test was to verify that the measured pump efficiency uas not >8% below the vendor tested efficiency and that the nozzle and riser plugging criteria was not exceeded.
l The test was performed by holding the plant in a steady state condition approximately one minute while plant parameters are monitored and data recorded. The collected data is used to calculate if the above criteria are satisfied.
l All applicable acceptance criteria were satisfied.
l STP-30.5, Recirculation System Cavitation The Recirculation System Cavitation test was performed in Test Condition 3. The purpose of this test was to verify that the recirculation cavitation runback logic settings were adequate to prevent operation in possible cavitation areas. This was accomplished without taking a runback by defeating the runback circuitry, establishing core flow at
>95t, and driving in control rods to reduce reactor power and therefore reactor feed flow. Subcooled feeduater provides net positive suction head to.the recirculation l pumps at high recirculation system flow. When the runback circuitry was activated at approximately 20% feed flou, no l recirculation system cavitation uns noted.
l The applicable acceptance criterion was satisfied. l l
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f 4.29 STP-31, LOSS OF TURBINE GENERATOR AND OFFSITE POWER OBJECTIVES This test determines electrical equipment and reactor system transient performance during a loss of main turbine-generator coincident with loss of all sources of offsite power.
ACCEPTANCE CRITERIA Level 1 All safety systems, such as the Reactor Protection system, the diesel-generators, and HPCI must function properly without manual assistance, and HPCI and/or RCIC system action, if necessary, shall keep the reactor water level above the initiating level of Low Pressure Core Spray, LPCI, Automatic Depressurizatior._ System, and MSIV Closure.
Diesel generators shall start automatically.
Level 2 Proper instrumentation display to the reactor operator shall be demonstrated, including power monitors, pressure,
- water level, control rod position, suppression pool temperatures, and reactor cooling system status. Displays shall not be dependent on specially installed instrumentation.
j Reactor pressure shall not exceed 1250 psig.
l l If safety / relief valves open, the temperature measured by thermocouples on the discharge side of the safety / relief valves must return to within 10 degrees F of the temperature recorded before the valve was opened.
Normal cooling systems shall be capable of maintaining adequate drywell cooling and adequate suppression pool
! water temperature. 1 l
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RESULTS l l STP-31.1, Loss of Turbine Generator and Offsite Power l
STP-31 was performed in Test Condition 2 at 20.8% of Rated 1 Thermal Power. To perform'thJs test, the electrical distribution system was aligned to power all plant loads from the affected unit. The main turbine and the appropriate breaker were tripped to simulate a loss of turbine generator with a loss of all offsite power.
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Tha Rcactor Protection System properly inserted a scram and the reactor water level remained above the HPCI, RCIC, LPCI, ADS, and MSIV level setpoints.
All reactor operator instrumentation properly displayed the required parameters. Reactor Pressure peaked well below 1250 psig at 911.7 psig. No Relief Valves opened as determined by the acoustic monitoring system and reactor pressure response. The drywell and suppression pool cooling systems performed satisfactorily to maintain adequate temperatures and pressures in these two areas.
Diesel generators Dll, D12, D13 and D14 started automatically and properly energized their respective Safeguard buses. All acceptance criteria were satisfied.
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4.30 STP-32, ESSENTIAL RVAC SYSTEM OPERATION AND CONTAINMENT HOT PENETRATION TEMPERATURE VERIFICATION OBJECTIVES The objectives of this test are to demonstrate, under actual / normal operating conditions, that the various HVAC systems will be capable of maintaining specified ambient temperatures and relative humidity within the following areas:
a) Primary Containment (drywell and suppression chamber) b) Reactor Enclosure and Main Steam Tunnel c) Control Room d) Control Enclosure e) Radwaste Enclosure In addition, this test shall verify that the concret temperature surrounding Main Steam and Feedwater containment penetrations remains within specified limits.
ACCEPTANCE CRITERIA Level 1 The drywell area volumetric average air temperature is not to exceed 135 degrees F.
Level 2 Thedrywellarea$ndsuppressionchamberaremaintained between 65 degrees F and 150 degrees F.
The reactor pressure vessel (RPV) support skirt surrounding air temperature is maintained above a minimum of 70 degrees F.
The concrete' temperatures surrounding primary containment Main Steam line and Feedwater line penetrations are maintained at less than or equal to 200 degrees F.
All areas listed in Subtest 32.3 for the control enclosure are maintained between 65 degrees F and 104 degrees F except the battery rooms, which are maintained at 88 degrees maximum (at float charge rate) and the auxiliary equipment room, which is maintained between 74 degrees F and 78 degrees F and relative humidity between 45% R.H. and 55% R.H.
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Tha Control Room is mnintainnd at a temparaturo betwaan 74 degrees F and 78 degrees F and relative humidity between 45% R.H. and 55% R.H.
The following areas of the Reactor Enclosure are maintained between 65 degrees F and 104 degrees F: rooms 111, 118, 200, 207, 210, 304, 402, 406, 500, 506A, 5068, 506C, 506D, 507, 508, 509, 511, 519, 601, 602, 605, 612, and 618.
The following areas of the Reactor Enclosure are maintained between 65 degrees F and 110 degrees F: rooms 502, 503, 504, and 505.
The following areas of the Reactor Enclosure are maintained between 65 degrees F and 115 degrees F: rooms 102, 103, 203, 204, 108, 109, 110, 113, 114, 117, 288, 289, 501, 510, 522, 523, and 599.
The following areas of the Reactor Enclosure are maintained between 65 degrees F and 120 degrees F: rooms 209, 306, 307, 309, 407, and 518.
The following areas of the Radwaste Enclosure are maintained between 65 degrees F and 76 degrees F: rooms 410, 411, 412, 415, 417 and 418.
RESULTS STP-32.1, Primary Containment Temperature This test specifies minimum equipment configuration for system performance verification.
For Test Condition Heatup at rated reactor temperature and pressure, both chilled water loops were placed in service to maintain volumetric average temperature below 135 degrees F. The test procedure was revised to permit two pump operation for Test Condition Heatup. Test results were as follows:
Drywell Volumetric Average Temp = 127 degrees F i Highest'Drywell Temp. = 146 degrees F Lowest Drywell Temp. = 90 degrees F Max Wetwell Air Temp. = 155 degrees F*
RPV Skirt Temp. = >70 degrees F
- Level 2 criteria not satisfied. Resolved by identifying possible air space stratification and instrument inaccuracy.
Prior to entering into Test Condition 1, all external surfaces of six of the eight unit coolers were cleaned, 4-96 l
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Internal cooler surfaces inspected and chilled water temperatures / flows adjusted to improve performance.
Subsequent testing (thermal power <5%) with minimum system configuration indicated volumetric average temperature could be maintained below 135 degrees F (stabilized at 132 degrees F).
For Test Condition 3, both chilled water loops were again required to be in operation to maintain drywell temperatures within specification. Test results were as follows:
Note: With reactor power >60% two pump /two loop equipment configuration is required essentially all the time.
Drywell Volumetric Average Temp = 133 degrees F Highest Drywell Temp. = 158 degrees F*
Lowest Drywell Temp. = 102 degrees F Max Wetwell Air Temp. = 160 degrees F*
- Level 2 criteria not satisfied. Hot spot in drywell due to location of sensor adjacent to main steam piping. Hot spot in wetwell due to sensor location and air space stratification.
Additional inspections during subsequent plant outages has uncovered exposed areas of piping in need of additional or revised insulation. When time permits, modifications to the existing pipe insulation are planned. Additional testing will be performed in Test Condition 6.
l STP-32.2, Hot Penetration Concrete Temperature For Test Condition Heatup and Test Condition 3, concrete temperatures remained well under the 200 degree limit with the maximum recorded temperature of 155 degrees F on feedwater line "B (0 degree quadrant) and minimum recorded temperature of 97 degrees F on main steam line "C" (0 degree quadrant).
STP-32.3, Control Enclosure Temperature and Relative Humidity For Test Condition Heatup and Test Conditions 2 and 3, test results are as follows:
For Test Condition Heatup, test data was declared invalid due to system malfunctions including loss of relative humidity control and instrument calibration problems.
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Retest of the system ("B" CW loop) was performed in Test Condition 1 with temperatures and relative humidity in the Auxiliary Equipment room exceeding acceptance criteria.
These test exceptions were resolved through an Engineering safety evaluation, expanding the allowable temperature band to 60 to 82 degrees F and the humidity band to 30% to 90%
l relative humidity.
For Test Conditions 2 and 3, test data was acceptable based on the Engineering Safety Evaluation expanding ranges of '
temperature and relative humidity. For Test Condition 2 outside air temperature was 78 degrees F and for Test Condition 3 outside air temperature was 63 degrees F.
STP-32.4, Control Room Temperature and Relative Humidity For Test Condition Heatup and Test Condition 3, test results are as follows:
For Test Condition Heatup, initial test data was declared invalid due to system malfunctions including loss of relative humidity control and instrument calibration problems. The test (CW loops A & B) was successfully ,
reperformed following repairs to the system. Acceptance l criteria minimum temperature of 74 degrees F and maximum relatiye humidity of 55% were not met for several rooms and areas. These test exceptions were resolved through an Engineering safety evaluation, expanding the allowable temperature band to 65 to 78 degrees P and humidity band to l 30% to 90% relative humidity.
For Test Condition 3, test data was acceptable based on the Engineering safety evaluation expanding ranges of temperature and relative humidity.
i STP-32.5, Reactor Enclosure and Main Steam Tunnel l Temperature j For Test Condition Heatup and Test Condition 1 and 3, test )
results are as follows:
For Test Condition Heatup all recorded room temperatures were within acceptance criteria but test data was declared I invalid due to several system duct damper failures and temperature stratification in the main supply ducts. This
, test was reperformed (with the exception of the HPCI and RCIC rooms) in Test Condition 1 with several test l
l exceptions relating to high delta temperatures (air supply 4-98
temp / air exhaust temp) in the Main Steam Pipe Chase Area and the Reactor Water Cleanup Pump Area. During this test outside air temperatures required plant operations to maintain air supply cooling coils in service.
For Test Condition 3, when outside air temperature was 63 degrees F test exceptions were identified due to high delta temperatures in many areas of the plant and maximum temperature in the Main Steam Tunnel reached 127 degrees F (air supply cooling coils were not in service). Test exceptions are being evaluated by Engineering.
STP-32.6, Radwaste Enclosure Temperature l For Test Condition Heatup and Test Condition 3, all rooms were maintained within the temperature criteria limits with the exception of room 415 (Radwaste Control Room) which exceeded the maximum temperature by 1 degree F (Test Condition Heatup) and Radiation Chem Lab which fell below the minimum temperature by 1.5 degrees F (Test Condition 3). These test exceptions were evaluated and found acceptable.
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4.31 STP-33, PIPING STEADY STATE VIBRATION OBJECTIVE 1
The objective of this test is to verify that the steady I state vibration of Main Steam, Reactor Recirculation and )
selected BOP piping systems is within acceptable limits. J ACCEPTANCE CRITERIA Level 1 j Operating Vibration: The measured amplitude (peak to peak) of each remotely monitored point shall not exceed the ,
allowable value for that point.
Level 2 Operating Vibration: The measured amplitude (peak to peak) of each remotely monitored point shall not exceed the expected value for that point.
The steady state vibrations of visually examined balance of plant piping are acceptable if the vibration levels are judged by a qualified test engineer to be neglible.
Vibration levels judged to be potentially significant are evaluated as determined necessary by BPC Project '
Engineering.
The vibration measured by a remote accelerometer is acceptable if the acceleration frequency spectrum falls in the negligible region of the acceptance chart for that accelerometer. If the acceleration frequency spectrum crosses the negligible region boundary, the test results shall be evalcated by BPC Project Engineering.
RESULTS STP-33.1, Main Steam Piping (Inside Drywell) Steady State Vibration 1 This subtest'provided the means for collecting vibration data on Main Steam piping at steady state conditions with various nominal main steam flows. Data was recorded by the Emergency P.esponse Facilities Data System (ERFDS) from the remote monitoring instrumentation (24 lanyard potentiometers and 2 resistance temperature devices). Data was collected at Test Condition 2 (25% rated main steam flow) and Test Conditicn 3 (50% and 75% rated main steam flow). All lanyard potentiometer vibration criteria were satisfied.
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l STP-33.2, Recirculation Piping Steady State Vibration This subtest provided the means for collecting vibration data on Recirculation piping at steady state conditions with various moninal recirculation pump flows. Data was recorded by the Emergency Response Facilities Data System 4
(ERFDS) from the remote monitoring instrumentation (24 lanyard potentiometers and 3 resistance temperature devices). Data was collected at Test Condition 2 (minimum recirc flow), Test Condition 3 (50% and 75% rated recirc flow) and Test condition 5 (minimum recirc flow). All lanyard potentiometer vibration criteria were satisfied.
STP-33.3, Main Steam, Main Steam Bypass, and Feedwater Steady State Vibration The results of the testing showed that steady state vibratory response for Main Steam, Main Steam Bypass, and Feedwater Piping (BOP Scope) was within acceptable design limits.
Data was taken manually and recorded on ERFDS (Emergency Response Facilities Data System) from remotely mounted vibration sensors. Recorded data was processed as applicable, and compared with design limits.
i The test was conducted during Test Condition 2 (nominal 50%
rated power) and Test Condition 3 (nominal 75% rated pcwer). All three feedwater loops, external to the
- drywell, were tested at each power level.
No piping steady state vibratory response problems were encountered during the tests. The test results were forwarded to Bechtel Engineering for review. Based on their analysis of the test data, they deemed that the acceptance criteria had been met.
STP-33.4, HPCI Steam Piping Steady State Vibration l
The results bf the testing showed that steady state vibratory response for the HPCI Steam Piping was within acceptable design limits.
l l Data was recorded on ERFDS (Emergency Response Facility l Data System) from remotely mounted vibration sensors.
I Recorded data was processed as applicable, and compared with design limits.
The test was performed in Test Condition Heatup with the HPCI turbine running on nuclear steam at a nominal throttle 4-101 l
pressure of 920 psig and the HPCI pump discharging at rated head and flow. Pump suction was from, and discharged into, the condensate storage tank.
No piping steady state vibratory response problems were encountered during the test. The test results were forwarded to Bechtel Engineering for review. Based on their analysis of the test data, they deemed that the acceptance criteria had been met.
STP-33.5, RCIC Steam Piping Steady State Vibration The results of the testing showed that steady state vibratory response for the RCIC Steam Piping was within acceptable design limits.
Data was recorded on ERFDS (Emergency Response Facility Data System) from remotely mounted vibration sensors.
Recorded data was processed as applicable, and compared with design limits.
l The test was performed with the RCIC turbine running on nuclear steam at a nominal throttle pressure of 920 psig and the RCIC pump discharging at rated head and flow. Pump suction was from, and discharged into, the condensate storage tank.
No piping steady state vibratory response problems were encountered during the test. The test results were forwarded to Bechtel Engineering for review. Based on their analysis of the test data, they deemed that the acceptance criteria had been met.
STP-33.6, Reactor Water Cleanup Piping Steady State Vibration The results of the testing showed that steady state vibratory response for the reactor water cleanup piping was within accep' table design limits.
Data was recorded on ERFDS (Emergency Response Facility Data System,) from remotely mounted vibration sensors.
Recorded data was processed as applicable, and compared with design limits.
The test was conducted during the implementation of STP-70.2 and STP-70.3 with the reactor at rated temperature and pressure during Test Condition Heatup. The referenced STP's cover the hot shutdown mode of the RWCU System in 4-102
which bottom head drain line flow is maximized at !
approximately 120 gpm and the normal mode in which suction ;
flow from the recirculation line is maximized at l approximately 290 gpm. Two of three RWCU pumps operate during these modes. I No piping steady state vibratory response problems were encountered during the test. The test results were 1 forwarded to Bechtel Engineering for review. Based on their analysis of the test data, they deemed that the acceptance criteria had been met.
lHF-005, RHR Low Pressure Coolant Injection Steady State Vibration Test The results of the testing showed that steady state vibratory response for the RHR Low Pressure Coolant Injection Piping was within acceptable design limits.
Steady state vibrations were evaluated by qualified test engineers using visual and tactile judgement and hand held vibration monitors. These engineers were qualified to standards set by Bechtel Project Engineering.
The object of this test was to verify, by means of visual examination by qualified test engineers, that the tested piping met the steady state vibration limits.
The procedure was implemented, prior to fuel load, during operation of RHR Loops A and D with pumps 1AP202 and 1DP202, respectively, discharging to the reactor vessel at rated flow of approximately 10,000 gpm.
No piping steady state vibratory response problems were encountered during the test.
1HF-006, Co,re Spray Piping Steady State Vibration Test l The results of the testing showed that steady state vibratory response for the Core Spray Piping was within I acceptable design limits.
Steady state vibrations were evaluated by qualified test engineers using visual and tactile judgement and hand held I vibration monitors. These engineers were qualified to j standards set by Bechtel Project Engineering. l i
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The objective of this test was to verify, by means of visual examination by qualified test engineers, that the i tested piping met the steady state vibration limits. 1 The test was conducted, prior to fuel load, when both core spray pumps, LAP 206 and ICP206, were in operation and discharging to the reactor vessel at a minimum combined I rated flow of 6350 gpm.
No piping steady state vibratory response problems were encountered during the test.
I lHF-017, Head Spray Piping Steady State Vibration Test The results of the testing showed that steady state vibratory response for the RHR Head Spray Piping was within acceptable design limits.
Steady state vibrations were evaluated by qualified test engineers using visual and tactile judgement and hand held vibration monitors. These engineers were qualified to standards set by Bechtel Project Engineering.
The objective of this test was to verify, by means of visual examination by qualified test engineers, that the tested piping met the steady state vibration limits.
l The procedure was implemented, in Test Condition Open Vessel, during operation of RHR loop A running in the
- shutdown cooling mode and head spray flow at approximately 1,000 gpm.
No piping steady state vibratory response problems were encountered during the test.
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4.32 STP-34, OFFGAS PERFORMANCE VERIFICATION OBJECTIVES The objectives of this test are to verify that the Offgas Recombination and Ambient Charcoal System operates within the technical specification limits and expected operating conditions.
ACCEPTANCE CRITERIA Level 1 The allowable dose and dose rates from releases of radioactive gaseous and particulate effluents to areas at and beyond the SITE BOUNDARY shall not be exceeded.
Allowable limits on the radioactivity release rates of the six noble gases measured at the after condenser discharge shall not be exceeded.
The hydrogen content of the offgas effluent downsteam of the recombiner shall be equal to or less than 4% by volume.
The total flow rate of dilution steam plus offgas when the steam jet air ejectors are in operation shall exceed 9555 lbs/hr.
Level 2 System flows, pressures, temperatures and dewpoint shall be within expected performance values.
The preheater, catalytic recombiner, after condenser, Hydrogen Analyzers, cooler condenser, activated charcoal -
beds and the HEPA filter shall be performing their required functions adequately. The automatic drain systems function adequately.
TEST RESULTS STP-34.1, Of'fgas Performance Verification For Test Condition Heatup and Test Conditions 1, 3 and 5, results are as follows:
Dose and dose rates from releases of radioactive gaseous and particulate effluents at the site boundary have all been within Technical Specification Limits. Isotopes analysis indicated Lower Limit of Detection (LLD).
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Radionctiva rolocca rates of tho six noble grece miasured at the after condenser discharge have all been well under the Technical Specification Limit of 330,000 MC1/sec. For Test Condition 3 total observed value was 37.82 mci /sec and for Test Condition 5 total observed value was 82.44 mci /sec.
The hydrogen content of the offgas effluent downstream of the recombiner has been less than 1% by volume for all test conditions. The total flow rate of dilution steam plus l offgas has continued to exceed the 9555 lbs/hr minimum.
Offgas flow rates were in excess of 200 scfm during test condition H/U (total flow was >l4,000 lbs/hr) but subsequent testing after a condenrer leak was found and l plugged reduced in-leakage to approximately 15-35 scfm.
Several instruments (dew point meters, hydrogen concentration meters and pressure indicators) were not performing satisfactorily during Test Condition H/U but subsequent retests have cleared all of these problems prior to test performance at Test Condition 1. System flow, pressures, temperatures (except recombiner preheater inlet temperature) and dew points were within expected values.
All system major components performed their required functions adequately.
The recombiner preheater inlet temperature controller is set to maintain a temperature of 350 degrees F (380 degrees F design). Maintaining a 380 degrees F setpoint causes high condensate levels in the preheater. Engineering has evaluated this problem and has recommended maintaining preheater temperature at 350 degrees F.
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4.33 STP-35, RECIRCULATION SYSTEM FLOW CALIBRATION OBJECTIVES The objectives of this test are to perform a complete calibration of the recirculation system flow instrumentation, including specific signals to the plant process computer and to adjust the recirculation flow control system to limit maximum core flow to 102.5% of rated core flow.
ACCEPTANCE CRITERIA Level 1 None Level 2 Jet pump flow instrumentation shall be adjusted such that the jet pump total flow recorder will pr9 vide correct core flow indication at rated conditions.
The APRM/RBM flow bias instrumentation shall be adjusted to function properly at rated conditions.
The flow control system shall be adjusted to limit maximum core flow to 102.5% of rated.
RESULTS l STP-35.1, Recirculation System Flow Calibration In Test Condition 3 at 42.7% power and 88% indicated core flow, single tap jet pump, double tap jet pump and recirculation loop data was recorded and a calculation was performed to determine total core flow. Calculated core flow was 100.66%. Core flow was reduced to <100% and the jet pump loop flow summers were adjusted to provide the I
correct loop and total core flows. In addition, the APRM/RBM flow bias instrumentation was adjusted to function
- properly at ' rated core flow conditions.
In Test Condition 3 at 49.5% power and 98% indicated core flow the core flow was again calculated. Calculated core flow was 93.74%. Jet pump loop summers and the APRM/RBM for bias instrumentation were adjusted based upon these results.
For both of these tests in Test Condition 3 all applicable acceptance criteria were satisfied.
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4.34 STP-36, PIPING DYNAMIC TRANSIENTS j OBJECTIVES The objectives of this test are to verify that the following pipe systems are adequately designed and restrained to withstand the following respective transient loading conditions:
Main Steam - Main Turbine Stop Valve / Control Valve closures at approximately 20-25%, 60-80%, and 95-100% of rated thermal power.
Main Steam and Relief Valve Discharge - Main Steam Relief Valve actuation. ;
Recirculation - Recirculation Pump trips and restarts.
i High Pressure Coolant Injection steam supply - High Pressure Coolant Injection turbine trips.
Feedwater - Reactor feed pump trips /coastdowns.
ACCEPTANCE CRITERIA . .
Level 1 Operating Transients: The measured amplitude (peak to peak) of each remotely monitored point shall not exceed the ,
allowable value for that point.
Level 2 ,
Operating Transients: The measured ampl'itude (peak to peak) of each remotely monitored point shall not exceed (?,e /
expected value for that point.
The maximum measured loads, displacements, and/or velocities are less than or equal to the acceptance limits specified.
In the judgment of the qualified test engineers, no signs i of excessive piping response (such as damaged insulation; markings on piping, structural or hanger steel, or walls; damaged pipe supports; etc.) are found during a post- ,
transient walkdown and visual inspection of the piping i tested and associated branch lines. ;
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,y- .+--- . ,.- ,- - --- - - - -
y-- - --t-+ - * -- w-r+--- -- + --i ---w-'-- - e--- - - - -=
RESULTS l STP-36.1, Main Steam Piping Vibration during Main Turbine l Stop Valve and Control Valve Closure This test was performed in conjunction with STP-27.1, Turbine Trip Within Bypass Valve Capacity, in TC 2 and STP-07:3, Turbine Trip at TC 3.
I Data wLs recorded on the Emergency Response Facilities Data System (ERFDS) from remotely mounted sensors. Recorded data was processed as applicable, and compared with the applicable accepts.tce criteria values. '
l NCSE Sconoi Trensient vibration data was recorded during both Main Turbine Trips performed in TC2 and 3 for Main Steam piping ir.sido th( drywell. Remotely mounted sensors, 24 lanyard pe,tentiometers in total, were installed and monitored on i
each Main Steam Line. All transient vibration results obtained satisfied the applicable Level 1 and 2 acceptance 4
I criteria for both truts.
$ BOP Scopt J T!e results of the testing, thus far, show that the dynamic vibratocy reatensi of the main steam supply piping, outside the Drywall, during main turbine stop and control valve cloivre was within acceptable design limits.
) Problecs encountered during the performance of the tests i were mir.cr in nature and include the following:
- 1. At Test Condit!cn 2, Icad sensing clevis pin CL.YA.13 exceeded allevab?.e values. Further analysis revealed that the majority of the loading was the thermal pre-load on the strut in which the pin waL installed. The test data was i reanalyzad to conservatively determine the
' dynamic component of the total recorded load.
f Based on this analyais, the dynamic loading was 1 avaluated as accept:ble.
It wa7 also determined that pressure transducer DP.NF. 02 was inoperative. The remaining instruments illustrated an acceptable piping response and no damage was noted during a visual l fnspection of the piping system.
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criterion values.
The test results were forwarded to Bechtel ,
Engineering for further evaluation. Based on i their analysis of the provided test data, they deemed the results acceptable. No further action was required.
STP-36.2, Main Steam and Relief Valve Discharge Piping Vibration during SRV Operation This test was performed in conjunction with STP-26.2, Relief Valve Rated Pressure Test in TC 2.
Data was recorded on the Emergency Respouse Facilities Data System (ERFDS) from remotely mounted sensors. Recorded data was processed as applicable, and compared with the I applicable acceptance criteria values.
l NSSS Scope:
As each Relief Valve was cycled at rated reactor pressure, transient vibration was recorded for Main Steam piping inside the Drywell. Remotely mounted sensors, 24 lanyard potentiometers in total, were installed and monitored on each Main Steam Line. All transient vibration results obtained satisfied the applicable level 1 and 2 acceptance criteria.
l BOP Scope This test was performed for the cycling of Relief Valve J with the reactor at rated pressure.
The results of this test showed that the dynamic vibratory response of the main steam relief valve piping during a steam relief valve opening was within acceptable design limits.
Problems encountered during the performance of the test were minor in nature and include the following:
- l. Load sensing clevis pin, DL.YR.05 was determined to be inoperative. The remaining instruments illustrated an acceptable piping response and no damage was 1oted during a visual inspection of the piping system. Bechtel Engineering concluded that no further action was required.
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- 2. Lord sGncing clCvis pin DL.YR.04 cxcOcdcd allowable values. Further analysis revealed that the majority of the loading was the thermal pre-load on the strut in which the pin was installed.
The test data was re-analyzed to conservatively determine the dynamic component of the total recorded load. Based on this analysis, the dynamic loading was evaluated as acceptable.
STP-36.3, Recirculation Piping Vibration during Selected Transients This test, performed in Test Condition 3, provided the means for collecting vibration data cor the recirculation piping during recire pump trip (double and single) and single pump restart transients. Data collection was accomplished using the Emergency Response Facilities Data System (ERFDS) and remote monitoring instrumentation (24 lanyard potentiometers and 3 resistance temperature devices). For all tests, vibration acceptance criteria were satisfied.
STP-36.4, HPCI Steam Supply Piping Vibration During HPCI Turbine Stop Valve Closure The results of this test showed that the dynamic vibratory response of the HPCI steam supply piping during a stop valve closure was within acceptable design limits.
Data was recorded on ERFDS (Emergency Response Facility Data System) from remotely mounted vibration sensors.
Recorded data was processed as applicable, and compared with design limits.
The test was performed with the HPCI turbine running on nuclear steam at a nominal throttle pressure of 920 psig and the HPCI pump discharging at rated head and flow. Pump suction was from, and discharge was to, the condensate storage tank. The HPCI turbine stop valve was tripped remotely.
No piping dynamic vibratory response problems were encountered during the test.
Test data was provided to Bechtel Engineering in the forms of loads and acceleration power spectral density plots.
Based on their analysis of the provided test data, they deemed that the acceptance criteria had been met.
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4.35 STP-70, REACTOR WATER CLEANUP SYSTEM OBJECTIVES The objective of this test is to demonstrate specific aspects of the mechanical operability of the Reactor Water Cleanup (RWCU) System.
ACCEPTANCE CRITERIA Level 1 None Level 2 The temperature at the tube side outlet of the non-regenerative heat exchangers shall not exceed 130 Deg F in the blowdown mode and shall not exceed 120 Deg. F in the normal mode.
The pump available NPSH shall be 13 feet or greater during the Hot Shutdown mode as defined in the process diagram.
The cooling water supplied to the non-regenerative heat exchangers shall be less than 6% above the flow corresponding to the heat exchanger capacity (as determined from the process diagram) and the existing temperature differential across the heat exchangers. The outlet temperature shall not exceed 180 Deg. F.
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 J
measured on the coupling end.
RESULTS STP-70.1, Blowdown Mode Performance Verification The RWCU System was tested during Test Condition Heatup at rated temperature and pressure in the Blowdown Mode with one RWCU pump running, and one RWCU NRHX group in service.
The RWCU System was aligned to divert all flow to the main condenser and the system flow was then increased until 148 gpm was obtained. The steady state RWCU NRHX cutlet '
temperature was less than 130 Deg. F and the steady state i NRHX RECW outlet temperature was less than 180 Deg. F when I the system flow reached 148 gpm. It was then discovered '
that the RECW throttle valve was 6-1/2 turns open instead of the required 3-1/2 turns. The valve was adjusted to 3- i 1/3 turns open and the data was retaken. The other NRHX 1
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l was placed into service and testing repeated with similar !
results. All applictble acceptance criteria was satisfied.
STP-70.2, Hot Shutdown Mode Performance Verification The RWCU System was tested during Test Condition Heatup at rated temperature and pressure in the Hot Shutdown Mode with two RWCU pumps running and two F/D's in service. A bottom head drain flow of 120 gpm was first established and then, while maintaining balanced F/D flows, the F/D flows were adjusted to obtain a RWCU System flow of 354 gpm. The applicable Level 2 Acceptance Criterion was satisfied since the available NPSH for the RWCU pump with the lowest t, suction pressure (RWCU pump A) was greater than 13 feet.
STP-70.3, Normal Mode Performance Verification The RWCU System was tested in the Normal Mode with two RWCU pumps running, two filter /demineralizers (F/D's) in service, and one NRHX group in service. While maintaining balanced F/D flow, F/D flow was adjusted until RWCU System flow reached 354 gpm. The steady state RWCU NRHX outlet temperature was less than 120 Deg. F and the steady state NRHX RECW outlet temperature was less than 150 Deg. F when RWCU System flow reached 354 gpm.
The other NRHX group was placed in service and testing repeated with similar results. Vibration measurements were then taken on each RWCU pump pump bearing housing vibration in the horizontal, vertical, and axial directions and shaft vibration on the coupling end.
All applicable acceptance criteria were satisfied.
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4.36 STP-71, RESIDUAL HEAT REMOVAL SYSTEM OBJECTIVES The objectives of this test are 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.
Additionally, this test will demonstrate the ability of the RHR System to remove heat from the suppression pool.
Level 1 The RHR System shall be capable of operating in the Suppression Pool Cooling Mode at the heat exchanger capacity specified.
The RER System shall be capable of operating in the Shutdown Cooling Mode at the heat exchanger capacity specified.
Level 2 None RESULTS STP-71.1, Suppression Pool Cooling Mode The Residual, Heat Removal (RHR) System was demonstrated for heat exchanger performance capacity in the suppression pool cooling mode at Test Condition Heatup. Inlet and outlet temperatures were recorded from the RHR system and RHR Service Water System streams every five minutes during a twenty minute duration test. Heat exchanger capacities for RHR loops A and B successfully met the Level 1 acceptance criteria.
As shown in the table below, the average heat removal rate and the average logarithmic mean temperature difference for both heat exchangers were higher than the process diagram values. As'a result, the actual performance of the heat exchangers is greater than the design performance.
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Avarrq7 RHR Hent Exchanq7r P2rform'.nc7 P.Grrmtr< rs A Heat B Heat Process Exchanger Exchanger Diagram RHR System Heat Removal Rate (MBhu/hr) 69.0 62.3 26.0 RHR Service Water System Heat Removal Rate (MBtu/hr) 49.9 69.0 26.0 Log Mean Temperature Difference (Deg F) 27.1 29.5 19.5 LMTD_(actual)
LMtS (design) 1.34 1.51 1.0 e
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