ML20132H002

Rept of Initial Plant Startup,Dec 1984

ML20132H002
Person / Time
Site:	Limerick
Issue date:	09/30/1985
From:	Alden W PECO ENERGY CO., (FORMERLY PHILADELPHIA ELECTRIC
To:	Murley T NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
References
NUDOCS 8510020031
Download: ML20132H002 (124)

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PHILADELPHIA ELECTRIC COMPANY PHILADELPHI A

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LIMERICK GENERATING STATION -

UNIT NO.-I ,

DOCKET NUMBER 50-352 * ,

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, REPORT OF INITIAL PLANT STARTUP '

DECEMBER, 1984 -

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. SUBMITTED TO - t THE UNITED STATES NUCLEAR. REGULATORY COMMISSION PURSUANT TO FACILITY OPERATING LICENSE NO. NPF-39 p s )

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PHILADELPHIA ELECTRIC COMPANY 9

1 LIMERICK GENERATING STATION UNIT NO. 1 DOCKET NUMBER 50-352 l

l REPORT OF INITIAL PLANT STARTUP DECEMBER, 1984 J

d SUBMITTED TO THE UNITED STATES NUCLEAR REGULATORY COMMISSION PURSUANT TO ,

FACILITY OPERATING LICENSE NO. NPF-39

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l Rev. O September 1985 I

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j PHILADELPHIA ELECTRIC COMPANY LIMERICK GENERATING STATION UNIT NO. 1 STARTUP REPORT Preparation Directed by:

G. M. Leitch, Manager Limerick Generating Station

l TABLE OF CONTENTS PAGE l

,1. INTRODUCTION 1-1 s

l 1.1 Report Abstract 1-2 1.2 Limerick Plant Description 1-3 j T;ble 1.2-1 Limerick 1 Plant Parameters 1-4 i

1.3 Initial Test Program 1-5 f Fig. 1.3-1 Operational Power / Flow Map ,

1-7 1.4 Major Startup Test Program Administrative Controls 1-9 i2.

SUMMARY

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2.1 Overall Evaluation 2-2

! TIble 2-1 Limerick 1 Milestones 2-3 Table 2-2 Startup Test Program Chronology 2-5 Table 2-3 Startup Test Performance Dates 2-8

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T;ble 2-4 Scram Summary 2-10

3. STARTUP TEST PROCEDURES 3-1 3.1 Startup Test Procedure Format and Content 3-2 3.2 Acceptance Criteria 3-3

]4. RESULTS 4-1 4.1 STP-1, Chemical and Radiochemical 4-2 1 T;ble 4.1-1 Chemical and Radiochemical Data Sheet 4-4 j 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 4.5 STP-5, Control Rod Drive System 4-19 4.6 STP-6, SRM Performance and Control Rod Sequence 4-23 i

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4.7 STP-9, Water Level Reference Leg i Temperature 4-25 '

4.8 STP-10, IRM Performance 4-27 4.9 STP-11, LPRM Calibration 4-30 4.10 STP-12, APRM Calibration 4-32 ,

4.11 STP-13, Process Computer 4-35 4.12 STP-14, Reactor Core Isolation Cooling System 4-38 '

Tcble 4.12-1 RCIC Test Results Summary 4-42 4.13 STP-15, High Pressure Coolant Injection System 4-43 T.ble 4.13-1 HPCI - Equipment Problems 4-46 T;ble 4.13-2 HPCI Test Results Summary 4-48 4.14 STP-16, Selected Process Temperatures 4-49 4.15 STP-17, System Expansion 4-5.1 4.16 STP-18, TIP Uncertainty 4-56 4.17 STP-19, Core Performance' 4-57 4.18 STP-20, Steam Production 4-59 4.19 STP-21, Core Power - Void Mode Response 4-60 4.20 STP-22, Pressure Regulator 4-61 4.21 STP-23, Feedwater System 4-63 4.22 STP-24, Turbine Valve Surveillance 4-66 4.23 STP-25, Main Steam Isolation Valves 4-67 4.24 STP-26, Relief Valves 4-69 4.25 . STP-27, Main Turbine Trip 4-71 4.26 STP-28, Shutdown From Outside the Control Room 4-73 4.27 STP-29, Recirculation Flow Control System 4-74 4.28 STP-30, Recirculation System 4-75 il i

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4.29 STP -31, Loss of Turbine Generator and offsite Power 4-77 4.30 STP-32, Essential HVAC System Operation and

- Containment Hot Penetration Temperature Verification 4-78 4.31 STP-33, Piping Steady State Vibration 4-82 4.32 STP-34, Of fgas Performance Verification 4-86 4.33 STP-3 5, Recirculation System Flow Calibration 4-88 4.34 STP-36, Piping Dynamic Transients 4-89 4.35 STP-70, Reactor Water Cleanup System 4-91 4.36 STP-71, Residual Heat Removal System 4-93 t

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O e 9 SECTION 1 1

e e INTRODUCTION i

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1.1 REPORT ABSTRACT I

This Startup Report, written to comply with Technical Specifications paragraph 6.9.1.1 thru 6.9.1.3, consists of o summary of the Startup Test Program portion of the l Initial Test Program performed at Unit 1 of the Limerick Generating Station. It includes the events starting with initial fuel loading and ending with the completion of Test ,

Condition 1. Since Limerick Unit I has not completed the t Ctartup Test Program, supplementary reports will be submitted on three month intervals as required by Technical Specification 6.9.1.3.

i The report addresses each of the Startup Tests identified

, in chapter 14 of the FSAR and includes a description of the '

j measured values of the operating conditions or  ;

i characteristics obtained during the test program with a  ;

comparison of these values to the Acceptance Criteria.

Also included is a description of any corrective actions

) required to obtain satisfactory operation. L 1

} This report also provides a brief description of the plant,

, o description of the Startup Test Procedure format and the objectives of each test. t i

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1.2 LIMERICK PLANT DESCRIPTION I

The Limerick Generating Station is a two unit nuclear power p lant . The two units share a common control room, refueling f).oor, turbine operating deck, radwaste system, cnd other auxiliary systeme.

The Limerick Generating Station is located on the east bank cf the Schuylkill River in Limerick Township of Montgomery County, Pennsylvania, approximately 4 river miles downriver from Pottstown, 35 river miles upriver from Philadelphia, cnd 49 river miles above the confluence of the Schuylkill ,

eith the Delaware River. The site contains 595 acres - 423 l ccres in Montgomery County and 172 in Chester County.

Each of the LG8 units employs a General Electric Company boiling water reactor (BWR) desiped to operate at a rated core thermal power of 3293 MWt (100% steam flow) with a correspding gross electrical output of 1092 MWe.

Approximately 37 MWe are used for auxiliary power, resulting in a not 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 ,

clab Which also serves to strengthen the entire system.

The Architect Engineer and Constructor was Bechtel Power Co rporation.

The plant is owned and operated by the Philadelphia Electric Company.

O l-3

TABLE 1.2-1 Limerick 1 Plant Parameters Parameter Value Rated Power (MWt) 3293 Rated Core Flow (M1b/hr) -

100 Re:ctor Dome Pressure (psia) 1020 Rated Feedwater Temperature (Deg. F) 420 Tot 01 Steam Flow (M1b/hr) 14.159 V;0sel Diameter (in) 251 Total Number of Jet Pumps 20 Coro Operating Strategy Control Cell Core Number of Control Rods 185 Nurber of Fuel Bundles 764 Fu;1 Type 8 x 8 (Barrier)

- Coro Active Fuel Length (in) 150'-

Cladding Thickness ('in) 0.032 4

Ch nnel Thickness (in) 0.100 MCP.3. Operating Limit 1.22 Maximum LHGR (KW/f t) 13.4 Turbine Control Valve Mode Full Arc Turbine Bypass Valve Capacity (% NBR) 25 Relief Valve Capacity (t NBR) 87.4 Number of Relief Valves 14 Recirculation Flow Control Mode Variable Speed M/0 Sets 1-4 .

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1.3 INITIAL TEST PROGRAM The Initial Test Program encompasses the scope of events that commences with system / component turnover and terminates with the completion of power ascension testing.

The Initial Test Program is conducted in two separate and sequential subprograms: the Preoperational Test Program Cnd the Star tup 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 coquential phases. ,

Maior Test Phases - Initial Test Program

a. Phase I - Preoperational Testing

b. Phase II - Initial Fuel Loading and Zero Power Testing I

c. Phase III - Low Power Testing

d. Phase IV - Power Ascension Testing Prooperational 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.

Startus 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 Puel 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 cesemblies 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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Power Ascension Test Phase i 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.

l 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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8. MINIMUM RSC8ACULATION PUMP SPEED .

C. ANALYTICAL LOWER LIM 47 0F MASTER POWER PLOW CONTROL

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TC3 TYPICAL STARTUP PATH m -TC2 , MINIMUM power LINE RSet0N ill CAVITATION

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. Operational Power / Flow Map Figure 1.3-1 Sheet i 1-7 e

TEST CONDITION (TC) REGION DEFINITIONS Tnat 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 rynchronization 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 rate ~d value.

4 On the natural circulation core flow line - within +0, -5% of the intersection with the 100% power rod line.

5 Within +0, -5% of the 100% control rod line - within -0, +5% of the analytical lower limit of Master Plow 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

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 - 1004 Rod Line Testing

7. Test Plateau E - Warranty Run

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A Test Plateau Review is performed prior to commencing otartup testing in the next higher plateau. The following items shall be completed prior to the Test Plateau Reviews

a. All Startup Tests scheduled for the current Test Plateau have been implerented or deferred, the analyses have been completed, and the t'e st .

results have been reviewed and approved.

b. All Startup Test Change Notices af fecting tests scheduled for the current Test Plateau have been approved.

c. All Test Exception Reports af fecting 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 procedure 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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Test Exception Reports (TER) were written to document the description and resolution of all test exceptions as well es the subsequent actions required to close out the exception. The processing and approval of Test Exception Reports was independent of test results. All test cxceptions 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 dif ferent from that stated in the FS AR by more than 5% of rated power.

d. Failure to satisfactorily complete the entire initial startup test prgram by the time core burnup equals 120 ef fective 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.

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0 SECTION 2

SUMMARY

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2.1 OVERALL EVALUATION The Limerick Generating Station Unit 1 Startup Test Program has been successful to date. The Startup Test Program commenced with fuel loading on October 26, 1984. Test 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.

TC 1 was successfully completed on August 16, 1985.

All testing identified in Chapter 14 of the FSAR for Test Conditions Open Vessel, Beatup and TC 1 have been performed. Individual test results are described in section 4.

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TABLE 2-1 LIMERICK 1 MILESTONES Jul - 1970 Start Construction, Temporary Permit Jun - 1974 NRC Issue 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 l

l Apr 1, 1985 Commence Test Condition Heatup ratests.

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.

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TABLE 2-1 (cont'd)

LIMERICK 1 MILESTONES Aug 8, 1985 Received Full Power License 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.

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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.

N v 9, 1984 Experienced second "RPS Trip" due to loss of power to RPS channels B and D caused by electrical fault in static inverter.

N:v 13, 1984 Last fuel bundle loaded at 0054.

Nov 2 5, 1984 RPV head installed. Entered Operational Condition 4.

Nov 27, 1984 Commenced operational hydrostatic test.

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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 Open 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.

J2n 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 j and temperature.

Jan 31, 1985 SCRAM #1. While valving in instrument i 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.

Fcb 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) af ter cooldown. Test Condition Heatup Complete.

Apr 1, 1985 Completed Low Power Outage.

Commenced Test Condition, Heatup Ratests.

Apr 11, 1985 Initial Main Turbine Roll Apr 13, 1985 Initial Generator Synchronization

! Apr 17, 1985 Reactor Shutdown at completion of Test Condition Heatup ratests. Commenced

, Outage.

Jul 31, 1985 Completed Plateau Review of Test

,' Condition Heatup (Phase III - Low Power Testing) .

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! 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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TABLE 2-2 (cont'd)

STARTUP TEST PROGRAM CHRONOLOGY Aug 14,1985 Main Generator Synchronized and loaded. Increased reactor power to 19%.

Aug 16,1985 Complete Test condition 1 Testing.

Decreased Power to <5% as a result of Stay issued by Appeals Court on Full Power License.

Aug 21, 1985 Completed Plateau Review of Test Plateau A (Test Condition 1). Third Circuit Court of Appeals lifts Stay on Full Power License.

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TABLE 2-3 STARTUP TEST PERFORMANCE . DATES Cl of 2)

STP SPIst WARRANTY h VESSEL MEATUP IG1 192 1Cl IGi 191 Ifd RUN Chemical and 10/24/84' 01/11/85 08/15/85 1 Radiochesteal 12/03/84 et/f8/85 08/16/85 - -

10/04/84 01/15/85 2 Radiat ion Measurement s 11/f5/84 08/16/85 - - - -

10/26/84 3 Fuel Leadina 11/13/84 - - - - - - - -

Shutdown Margin 12/21/84 .

4 Demonstrations 12/22/84 - - - - -- - - -

Control Rod '

10/f8/84 01/06/85 5 Drive System 11/18/84 Of/28/85 - - - -

SRM Performance and 12/22/84 6 Control Rod Seouence 12/23/84 - - - - - - - -

Water Level Reference -

09/26/85 08/l5/85 9 Leo Temoerature 01/26/85 08/f6/85 -

12/21/44 12/30/84 08/10/85 10 IRM Per formance 12/22/84 12/30/84 08/10/85 - - - - - -

1 01/16/85 08/14/85

] 11 LPRM Callbration' -

0f/25/85 08/96/85 - - - -

12/31/84 08/16/85 -

12 APRM Calibration -

01/02/85 08/16/85 - .

11/29/84 09/23/85 08/12/85 I

.f3 Process comouter 12/04/85 01/29/85 08/16/85 - - -

01/02/85 08/16/15 14 RCIC Svstem -

03/01/85 08/f6/85 - - - - -

01/04/85 15 HPCI Svstr,s. -

02/26/85 - - - - - -

5 elected lee <.es s 01/27/85

! 16 Temoeratures -

0f/27/85 - - - -

12/13/84 12/30/84 17 System Exoansion 12/f4/84 03/05/85 - - - - -

j 18 TIP Uncertaintv - - - - - - -

08/16/85 19 Core Performance - -

08/f6/85 j 20 Steam Production - - - - - - - -

i Core Power - Vold j 21 Mode Response - - - - - - -

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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.

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i SECTION 3 STARTUP TEST PROCEDURES 3-1

l-l 3.1 STARTUP TEST PROCEDURE FORMAT AND CONTENT Startup Test Procedures are generally written to demonstrate and verify the performance of a system or control rystem, 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 Main 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 cections:

1. Objectives

2. Description

3. Acceptance Criteria

4. Re ferences

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 l

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during the test. A Subtest consists of the following sections:

1. Di scus sion

2. Precautions

3. Test Equipment

4. Prerequisites

5. Initial Conditions

6. Test Instructions j

7. Analysis

8. Appendices (optional)

A Startup Test Procedure contains as many Subtests as. '

required to satisfy all the Acceptance Criteria listed in the Main Body and to ef fectively 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

3.2 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 (FS AR, equipment specification, test specifications, etc.). These criteria state expected values such as flows, temperatures, preasures, 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 which are defined below:

a. A Level .1 criterion normally relates to the value of a process variable assigned in the design of the plant, component, systems or associated equipment . If a Level I criterion were not satisfied,. the plant would be placed in a suitable hold condition, until resolution was obtain ed. Tests compatible with the hold condition would be continued. Following resolution, applicable _ retesting would be reperformed to verify that the requirements of the Level I criterion were satisfied.

b. A Level 2 criterion is associated with expectations relating to the prformance of sys tem s. If a Level 2 criterion were not satisfied, cperating 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

- - ..w----.vy-,,,-,yem,.-,,,,-,mm--,----, - - , ---.~-r , - - - - - - - -- - - -

l l

l l

SECTION 4 l

RESULTS l

1 l

4-1 1

l .

4.1 STP-1, CHEMICAL AND RADIOCHEMICAL OBJECTIVES The principal objectives of this test are a) to secure information on the chemistry and radiochemistry of the reactor . coolant, and b) to determine that the sampling equipment, procedures and analytic techniques are adequate to supply the data required to demonstrate that the chemistry of all parts of the entire reactor system meet specifications and process requirements.

Specific objectives of the test program include evaluation of fuel performance, evaluations of domineralizer operations by direct and indirect methods, measurements of l 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 cpecial chgmical tests.

ACCEPTANCE CRITERIA Level 1 Chemical factors defined in the Technical Specifications cnd Fuel Warranty must be maintained 'w ithin the limits speci fied.

The activity of gaseous and liquid of fluents must conform to licentie limitations. i 1

Water quality must be known at all times and must remain <

within the guidelines of the Water Quality Specifications.

Level 2 1

None 1

1 1.

I 4-2 l

l l

RESULTS STP-1.1, Pre-Fuel Load Data chemical and radiochemical characteristics of reactor water, stored makeup water, standby liquid, closed cooling system water, and floor drain water were measured. Result s showed that all water chemistry values were within applicable limits. Baseline data for stack ef fluents and radiological dose rates were established. All test ,

acceptance criteria were satisfied. Refer to Table 4.1-1 for test results.

4 STP-1.2, Chemistry Data Chemical and radiochemical characteristics of reactor water, control rod drive water, condensate domineralizer influent and ef fluent, fe edwater, stored makeup water and floor drain water were measured. With two test exceptions, results showed that all water chemistry values were within applicable limits. Baseline data for No rth and South stack ef fluents and radiological dose rates were established.

Dif ferential 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 In Test Condition 1 of fgas 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.

I 4-3

Oablo 4.1 Chemical 'and Redischemic21 D:to She:t Shent i Test Crnditisa Opes Vccool Op:n Veccc1 Hsstup 15-25% 45-55% 65-80% 90-100X Pre-Fuel Post-Fuel Power Power Power Power i

' Load Load (5X Power TC-2 TC-3 TC-3 TC-6 Date 18-24-84 12-3-84 t-11-85 l MW Thermal e e 144.9

) MW Electrical e e e STP f.1 1.2 f.2 1.2 1.2 1.2 f.2 Limit or REACTOR WATER Design value  ;

Crnductivity, unho/cm at 25 dog C e.9 0.4 0.2 NOTE (t) j Chlaride, ppt 120 120 120 NOTE (1)

! pH ct 25 deg C 7.5 7.8 6.2(a) NOTE (t)

Gamma Isotopic, uCl/ge -

4 1

I-131 XX XX 11.7 E-5 B.O.D.

I-132 XX XX S2.8 E-7 B.O.D.

I-133 XX XX 12.1 E-6 B.O.D.

I-134 XX XX $2.4 E-7 .

B.O.D.

I-135 XX XX 11.9 E-6 B.O.D.

! Dzzo Equivalent I-131, uCl/gm XX XX $2.1 E-5 10.2 i

l .Teerbidity, NTU fe.61 10.61 10.61 B.O.D.

Silica, ppb 10 20 194 B.O.D.

I i Baren, ppb $50 150 150 B.D.D.

I B.O.D. : Baseline Operation Data

) (a) = Uncorrected for CO2 absorption

+

] 4-$

1

?

~ ~ ~ ' _ __ _ , _ _ _ . .

Tablo 4.1 Chemicht and Redischeele:I Date Sheet 5hent 2 Test condition Open Wessel Open Vessel Heatup 15-25% 45-55X 65-88X 90-188X

', Pre-Fuel Post-Fuel 15X Power Power Power Power Power Load Load TC-2 TC-5 TC-3 TC-6

) 'Date 18-24-84 12-3-84 1-11-85 '

~

MW Thermal e e 144.9

i MW Electrical e e e i

i STP 1.1 1.2 1.2 1.2 1.2 1.2 1.2 Limit or

)

REACTOR WATER (CONTINUED) Design Value Grass Activity:

i Filtrate, cpm /ml, 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> XX XX 374 B.O.D.

Crud, cpm /mg Fe, 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> XX XX 1.2 E5 B.O.D.

4 Filtrate, cpm /m1, 7 day XX XX 17 B.O.D.

Crud, cpm /mg Fe, 7 day XX XX 4.5 E4 B.O.D.

l CHEMICAL ANALYSIS OF FILTRATE Iron, ppb XX XX XX XX XX XX B.O.D.

Copper, ppb XX XX XX XX XX XX B.O.D.

Nickel, ppb X X- XX XX XX XX XX B.O.D.

l . Chromium, ppb XX XX XX XX XX XX B.0.D.

CHEMICAL ANALYSIS'0F CRUD 1

Iron, ppb XX XX XX XX XX XX B.O.D.

f Copper, ppb XX XX XX XX XX XX B.O.D.

I Hickel, ppb XX XX XX XX XX XX B.O.D.

l Chromium, ppb XX XX XX XX XX XX B.O.D.

Spsetral Analysis of Major .

Nuclides at 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />s:

Filtrate XX XX XX B.O.D.

Crud XX XX XX B.O.D.

i B.O.D. : Baseline Operating Data 4-5

Tablo 4.1 Chemical anal Redischemisc1 Dato She:t Sheet 3 Tcat Candittsa Open Vessel Open Vessel Heatup 15-25X 45-554 65-802 90-100X Pre-Fuel Post-Fuel 154 Power Power Power Power' Pouer Lead Load TC-2 TC-3 TC-3 TC-6 Date 15-24-84 12-3-84 1-11-85 MW Thermal 0 0 144.9 pel Electrical e e 0 STP 1.1 1.2 1.2 1.2 f.2 1.2 1.2 Limit or Design CONTROL ROD DRIVE WATER Value Crnductivity, unho/cm at 25 dog C XX XX 9.07 10.1 Dierolved Oxygen, ppb '

XX XX 80# f50 FUEL AND EQUIPMENT STORAGE POOLS Canductlvity, unho/cm at 25 deg. C 0.7 XX XX XX XX XX XX 13.0 Chlerlde, ppb 120 XX XX XX XX XX XX 1500 4

pH ct 25 deg. C 7.2 XX XX XX XX XX XX 5.3-7.5 H2 vy Elements (Fe, Cu, NI), ppt 67 XX XX XX XX XX 'X X 1100 Tatc1 Insolubles, ppm 0.025 XX XX XX XX XX XX 11.0 Turbidity, MTU St.61 XX XX XX XX XX XX B.O.D.

CONDENSATE D'EMIN. INFLUENT Crnductivity, umho/cm at 25 deg C XX XX 9.2 B.O.D.

Chlerlde, ppb XX XX 120 B.O.D.

pH ct 25 deg C XX XX 7.0 B.O.D.

Iren, insoluble, ppb XX XX 28 8.0.D.

Silica, ppt XX XX 12 B.O.D.

B. O. D. = Baseline Operating Data * = Test Exception 4-6

Tablo 4.1 Chemient and Radiochemicci Dato She:t Short 4 Te t condition Open Vecco! Open Vaccci Hr.t up 15-25% 45-35% 65-80E 90-1943 Pre-Fuel Post-Fuel ISE Power Power Power Power Power Load Load TC-2 TC-3 TC-3 TC-6 -

i Date 1e-24-84 12-3-84 t-11-85 Ist Thermal e e 144.9 PSI Electrical e a 0 STP 1.1 f.2 1.2 f.2 f.2 1.2 f.2 Limit or Design l

CONDENSATE DEMIN EFFLtlENT Value Cinductivity, unho/cm at 25 deg. C XX XX 8.88 10.1 l

l 2

Chloride, ppb . XX XX 128 B.0.17.

i pH, at 25 deg. C XX XX 6.3 fa) B.O.D.

Iron, insoluble, ppb XX XX (f B.O.D.

1 I j Dissolved oxygen, pp5 XX XX at B.O.D.

i j - Silica, ppb XX XX IIS B.O.D.

] FEEDWATER Conductivity, unho/cm at 25 deg. C XX XX 9.08 13.1 Chloride, ppb XX XX S20 B.O.D.

pH at 25 deg. C XX XX 6.7 6.5-7.5 4

Iron, soluble, ppb XX XX XX XX $15 Insoluble, ppb XX XX

• Total Copper, soluble, ppb XX XX #

$2 insoluble, ppb XX XX # Total Hickel, soluble, ppb XX XX XX XX 115'

] insoluble, ppb XX XX XX XX Total Chromium, sol'uble, pp5 XX XX XX XX SIS

] insoluble, pp5 XX XX XX XX Total l

i B. O. D. : Baseline Operating Data e a Test Exception d-v fa) = lincorrected for CO2 Absorhtlon

Tablo 4.1 Cheels:1 and Radicchestect Dato Sheet She:t 5 j -

Test Conditlen Open Vessel Open Vessel Heatup 15-25X 45-55X 65-30X 90-legX Pre-Fuel Fest-Fuel <5X.Peuer Feuer Feuer Peuer Peuer Lead Lead TC-2 TC-3 TC-3 TC-6 1 Date 18-24-84 12-3-84 1-11-85 W Thereal e e 144.9 j W Electrical e e e l STP 1.1 1.2 1.2 1.2 1.2 1.2 1.2 ,

5 Llult er Design FEEDWATER (CONTINUED) Value Total Soluble Metals (ppb)

Fe, Cu, MI, Cr ,. , XX XX XX XX 115

{ t Total Filtrate Metals (ppb) l

- Fe, Cu, MI, Cr XX XX XX XX 115

~

Metallic Impurities, pp5 (Filtrate and Solids) XX XX e 115 DEMINERALIZED WATER STORAGE TANK  ;

l.

Conductivity, umho/cm at 25 deg. C 0.7 0.6 0.6 11.s i

Chloride, ppb .128 120 120 150 pH at 25 deg. C _6 . 4 6.4 7.3 6.0-a.0 Baron, pp5 ISO $50 150, flee I i j Silica, ppb XX fit 10 B.O.D.

CONDENSATE STORAGE TANK Conductivity, unho/cm at 25 deg. C 0.9 0.54 8.6 11.0 i

j Chloride, ppb $2e 120 f20 150 l I

pH at 25 dog. C 7.1 6.5 6.6 6.e-8.0 f .

l Boron, ppb 150 XX XX XX XX XX XX 1103 i

l Silica, pp5 XX 18 fl0 B.O.D.

I i a-a a = T..+ Fw,..ntion n n n - . . is non sino n+

l,

Sheet 6 Tect Condition Open Vanect Open Vacccl Heatup 15-25X 45-55X 65-Set te-leet

Prc-Puel Pcet-Puel (5X Power Power Feuer Power- Power 1

1 tsad Lead . TC-2 TC-3 TC-3 TC-6 Data 10-24-84 12-3-84 1-11-85 l Pti Thermal e e 144.9 tel Electrical e e e j STP 1.1 f.2 1.2 1.2 1.2 1.2 1.2 i

Limit er IIERNAIfR (CONTINUED)

Design Value PLOOR DRAIN SAMPLE TANK NO. 2 i <8.5 E-8 11.4 E-7

) Liquid Effluent Activity XX

d. NOTE f3 j LAUNDRY DRAIN SAMPLE TANK No Liquid No Liquid 1 Liquid Effluent Activity XX ~

NOTE (2 l SUPPRESSION POOL i

Conductivity, unho/cm at 25 dog C 2.2 e.te 1.12 a.O.D.

l Chloride,* ppb 12e 38 128 1500 l .

)

pH at 25 deg C 7.2 6.8 6.8 s.0.p.

Silica, ppt 78 YX XX XX XX XX XX 3.0.D.

l Turbidity, NTU St.61 XX XX XX XX XX XX B.0.3.

I i STANDBY LIQUID CONTROL SYSTEM j Pentaborate, weight X 13.8 YY XX XX XX XX XX B.O.D.

l Density of Solution, ge/cc 1.068 XX XX XX XX XX XX B.O.D.

j Solution volume in tank, get 4668.7 XX XX XX XX XX XX B.O.D.

Weight of sodium pentahorate, !bs _5727 YX XX XX XX XX XX 559 emir j REACTOR ENCLOSURE COOLING MATER j Corrosion Inhibitor, ppm See XX XX XX XX XX XX 500-30E l PH at 25 deg. C 9.2 XX XX XX XX XX XX 9.e-9.1

! Chloride, ppb 128 XX XX XX XX XX XX 110,001 l B. O. D. = Baseline Operating Data l

I

Tablo 4.1 Chemical and Radt chemical Paramettes Data She t sheet 7 1

2 Test Conditlen Open Vesset Open Vessel Heatup 15-25X 45-55E 65-302. ge-Iset

. . Pre-Fuel Post-Fuel <5x Power Feuer Feuer Feuer Feuer Lead Lead TC-2 TC-3 TC-3 Tc-6 1 . Date . 1e-24-84 s2-3-84 1-11-a5

. ISI Thermat 0 0 144.9 1

ISI Electrical e e e j STP '

1.1 1.2 f.2 f.2 f.2 f.2 s.2

. Limit on TURBINE ENCLOSURE CgGLING WATER -

$ue" i Corrosion Inhiblior, ppm 586 YY YY YY YY- YY YY 500-3000 pil at 25 deg. C 9.e YY YY YY YY YY YY g.e-g.7 Chlorlde, ppb 500 XX XX XX XX 'X X XX 110,000 MAKEUP WATER EFFLUENT j .. Conductivity, unho/cm at 25 deg. C e.04 _

YY YY YY YY YY YY B.O.D.

j Chloride, ppb -

420 XX XX XX XX XX XX B.O.D.

j Silica, ppb fle XX XX XX XX XX XX B.O.D.

j

. pil at 25 deg. C 7.1 YY 'T Y YY YY YY YY B.O.D.

Boro'n, ppt 150 XX~ XX XX XX XX XX 3.0.D.

i jl 3.0.9. = Besettne Operating Data l

I

4-18 ,

1 i .

l .

j 3

T.ablo 4.1 Chemical and Radlechanisci Dato Sheet Sheet 8 Tc:t C nditica Open V:s::t open Voce.cl Heatup 15-25X 45-55X 1 65-80% we-less 4 Prc-Fst Post-Fm:1 (52 Power Power Power -Power Power Load Lead TC-2 TC-3 TC-3 TC-6

,' Date 18-24-84 12-3-84 1-11-85 ISI Thermal e a 144.9 ISI Electrical e e e

]

I STP , t.I 1.2 l- 1.2 f.2 1.2 1.2 1.2 Limit'or i GASE0US EFFLUENTS -

} Off-Sas Activity, uct/sec ( 6)

• XX XX - XX 1333,g00 i

i H-13, uCl/sec YY YY YY B.O.D.

i

Off-Gas flow Rat't, cfm YY YY YY B.O.D.

1 Activity Pattern j Recoll, X YY YY YY B.O.B.

). Diffusion, X YY YY YY 3.0.D.

I Equilibrium, X YY YY YY B.O.D.

i Off-Gas System Effluent

, (Post-Treatment) uCl/sec YY YY YY ~

B.O.D.

. Pre-Treatment Monitor .

Ast

! Reading, ar/hr YY No Callb. 5:0 B.O.D.

t North Stack Monitor Reading i Particulate uCl/cc XX <3.5 E-12 11.8 E-12 B.O.D.

Iodine uCl/cc - c XX (1.7 E-12 <2.3 E-12 B.0.D.

l Hoble Gas uCl/cc XX (1.4 E-7 13.4 E-7 B.O.D.

t

Flow Rate, scfm XX 1.0 E5 f.8 E5 S.0.0.

, South Stack Monitor Reading Particulate uCl/cc XX <3.5 E-12 11.8 E-12 B.O.D.

! Iodine uCl/cc XX (4.7 E-13 11.8 E-12 B.O.D.

, Noble Gas uCl/cc XX (1.2 E-7 11.6 E-6 B.0.D.

Flow Rate, scfm XX 1.0 E5 2.5 ES B.O.D.

Noble Gas body dose rate, mres/yr XX gl.8 E II.8 E-3 1500 l Noble Gas skin dose. rate, ares /yr .X X 11.0 E-3 41.8 E-3 13000

. Particulate, lodine and tritium XX 11.0 E-3 I 1.0 E-3 11500 dose rate, mres/yr '

Sheet 9 Tcble 4.1-1 Notes for Chemical and Radiochemical Data Sheets NOTE (1) Conductivity Chloride pH at 25 usho/cm at 25 ppb Degrees C Degrees C Pre-Fuel Load Limits <3.0 <500 5.3-7.5 Limits for Power Operation <1.0 <200 5.6-8.6 Licits for Startup <2.0 <100 5.6-8.6 cr Hot Shutdown Limits applicable at -<10.0 <500 5.3-8.6 c11 other times NOTE (2)

C:ncentrations of radioactive material released in liquid offluents to unrestricted areas are limited to levels specified in 10CFR Part 20 Appendix B, Table II, Column 2 for nuclides other Ehan dissolved or entrained noble gases.

Surmary of Test Exceptions and Recommendations:

a. Control Rod Drive ~ water (Condensate Domineralizer Ef fluent) dissolved oxygen was 80 ppb, 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 hold a  ;

filter and ion exchange paper for crud and filtrate metals l analysis, has been installed. Samples will be taken in l subsequent test conditions. l l

l l

l 4-12 - i o

l I

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 End b) monitor radiation at selected power levels to assure the protection of personnel during plant operation.

ACCEPTANCE CRITERIA s

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 A survey of radiation levels in the plant environs was taken prior to fuel load, after fuel load before achieving the first reactor critical, and with the reactor critical at rated temperature and pres sure ( <5% CTP) .

Approximately 380 Radiation Base Point (RBP) locations were curveyed. In addition, radiation dose rates were measured in transit from one RBP to the next. All gamma and neutron radiation dose rates were measured to be ,less than or equal to minimum detectable (0.2 mR/hr gamma and 0.5 mR/hr neutron) and, as such, were below all applicable limits.

i 1

s 1

4-13

1 4.3 STP-3, FUEL IDADING OBJECTIVE The objective of this test is to load fuel safely and sf ficiently to the full core size.

ACCEPTANCE CRITERIA Level 1 The partially loaded core gust 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 I 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 per. formed to show that all . fuel assemblies were - 5 properly loaded, oriented, and seated in the core. The Level 1 Acceptance Criterion was satisfied.

The loadedLevel core1 must acceptance be subcritical criterionbystated that0.38%

at least the partiallydelta k /k with Ohe 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) we're withdrawn one notch at a time while observing the nuclear inst rumentation. The nuclear instrumentation did not indicate a continuous positive period thus demonstrating suberiticality.

i Prior to the start of fuel loading, four fuel loading chambers were assembled, placed in the core, and connected j to the permanent SRM preamplifiers. The rod block setpoint wrs set one decade lower at lx10**4 CPS and the scram cstpoint at 2x10**4 CPS due to Ehe 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

-. _ .- ,_,m. . , __ . , _ _ _ _ - . . ...,,-,..~.-_--.-.,-m.___ - - . . - _ +  %- _ .

m_~...--_ _, . . , - - - - ,

The average 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.

i The entire core complement of fuel assemblies was prepared, l inventoried, and stored in Ehe fuel pool prior to the start )

of fuel loading. Fuel was loaded into the core from the l center out in a roughly spiral pattern of increasing size. l Before fuel was loaded, each control rod was tested for position Ladication, 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 i Transfer Authorization Sheet (CCTAS) as the guiding document. Starting near the center of the core, four fuel I 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 l square core.

A plot of . inverse count rate (1/M) was taken during fuel load to verify suberiticality 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 Ehe 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 ef fects encountered when less than four fuel cells are loaded and the strong ef fects as fuel is loaded adjacent to the neutron sources. The interpretation of the geometry af fected 1/M plots allow disregarding one or more 1/M intercepts because the obvious geometric ef fect invalidates the theoretical basis for the 1/M plots.

Several minor 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). Ete bundle was inspected and found to have some scratches on the channel but was determined to be ccceptable. Another bundle (LY8076 at coordinate SS-23 in SFSP) required repeated application of force by lifting the l 4-15 l

- _ - - - . _ _ - . _ - . . - _ _ - _ - . - _ . , ....- _.---_.-_. . ~ , _ _ . - _ _ _ _ . - , - . -

grapple until it was freed. This bundle was also inspected and found acceptable. The SFSP locations were inspected 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 point during the loading, SRM D was declared inoperable. Since fuel was being loaded in that quadrant, FLC A had to be respositioned to core location 09-20 to allow continuation in accordance with LGS Technical of fuelfications Speci loading (SRM monitoring required in the quadrant of core alterations and one adjacent quadrant).

4-16

4.4 STP -4, SHUTDOWN MARGIN DEMONSTRATION OBJECTIVES __

The purpose of this test is to demonstrate that the reactor  !

will be sufficiently suberitical throughout the first fuel )

cycle with any single control rod fully withdrawn. 1 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 ct 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 delta M/K. The measured shutdown margin of 2.3% delta K/K sasily meets the level 1 criterion of having a shutdown margin of greater than 0.38% delta K/K. The critical rod l

position (K-ef f=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-ef f=0.9902) and 2326 notches withdrawn (K-cf f=1.0100) . These notch totals represent +1.0% delta K/K of the predicted critical rod pattern. Criticality occurred approxi'mately 0.51% delta M/K from predicted.

- These results satisfy the level 2 criterion.

This test was performed by bringing the reactor critical end 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 i

I

- --. --w. - , - - , . , - - , , ,,-,.,-m . . - ,- - - , , _ . . - , , - - - . . , - , - . . , .mann,-, - -,-- - - - - - . .-e-:,--~er

1 was measured to be 2.3% delta M/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.

9 4

9 9

9 4

4-18 9

--w. p+- ,,,,..---,____,_.-.,,.,ym,- -

.,r~- -.-,,-.-,,,,,,-y,. ,y..w,n3,,, - -,,,--,y, ,,-.m. , , . %,~--y--.e r. . . - . - -

I 4.5 STP-5, CONTROL ROD DRIVE SYSTEM OBJECTIVES I l

The objectives of this test are to demonstrate that the Control Rod Drive (CRD) System operates properly over the ,

full range of primary coolant operating temperatures and '

pressures, and to determine the initial operating characteristics of the CRD system. ,

ACCEPTANCE CRITERIA t

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 l

Level 2 Each CRD aust have normal insert and withdrawn speeds of 3.0 + 0.6 inches per second, indicated by a full 12 foot ctroEe in 40 to 60 seconds.

With respect to the control rod drive friction tests, if  !

the dif forential pressure (dp) variation exceeds 15 psid for a continuous drive in, a settling test must be pe r formed, in which case the dif ferential settling pressure .

4-19

)

should 'not be less than 30 psid nor should it vary by more than 10 paid 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 Feater 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 o.n retest.

STP-5. 2, Zero Reactor Pressure Friction Testing Following the completion of fuel load'ing 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 perforNance 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 l

Following completion of friction testing, each CRD was ceram tested. All applicable Level 1 Acceptance Criteria were satisfied since the average scram times to position l

45, 39, 25 and 05 for all operable control rods were less l Chan 0.4,3, 0.86,-1.93 and 3.49 seconds, respectively, and

j. the mean scram times of the three fastest rods in every '2 x l 4-20 l

1 4

0 c- +,, ---,,~.w. . , , - . - - , , - - . - , - + - . ,

,--v.---m-,,n--,-.,,,.,,-.w.w.,m,,-m_,,.,----,----v.--,,,-.---.-.:.--c,,.,

2 array to position 45, 39, 25 and 05 were less than 0.45, O.92, 2.05 and 3.70 seconds, respectively. The mean scram time of all operable CRDs and associated criteria are listed below:

Position Inserted to Mean Scram Time Level 1 Criteria From Fully Withdrawn (Seconds) (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 celected 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 pres sure with normal accumulator pres sure; 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 cettling tests and each of these satisfied the applicable Level 2 Acceptance Criterion.

STP-5.6, Rated Reactor Pressure Scram Testing At rated temperature 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:

l l

l 4-21

,,.m__..y-,rw e ~~ w' w- - - - - -- *-+ "-

• Average Maximum Allowable Elapsed Scram Ave: age 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 l 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 Acceptan' c e 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 l

l I

I l 4-22 l

4.6 STP-6, SRM PERFORMANCE AND CONTROL ROD SEQUENCE

. OBJECT 1VES The objective of this test is co 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 ef ficient 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 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 acram mode.

In addition, the SRM rod block and scram setpoints were conservatively adjusted one decade less than their normal values (set to 1x10**4 and 2xlO**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 identif fed in the following table.

j 4-23 1

4 .

- , ~- - - , - ,-+------,,gn.,,,,n.en- , . , ,,---a,ne.,_ w. ,.m..mma,,,mw , - , , . , nm.,,m_,,._,,,.,-w, ,w--_.,,-- . --, n---

l 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 acrams, SRM detectors were partially withdrawn, as required, to maintain the -

observed count rate greater than 100 CPS and less than lx10**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 chorting 1 inks 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.

4 4

4 4-24 i

i

.,--.4..--,,,-.-.._ . . . , - _.,,.,--._ ,,, ,.,. i.,, __ ,_ ,,- n.__ , , , . , , , - _ _ - _ _ , . , , _,-,_n._,n-

i 4.7 STP-9, WATER LEVEL REFERENCE LEG TEMPERATURE OBJECTIVES i

The objectives of this test are to measure the level j instrumentation reference leg temperature, recalibrate the water level instruments if the measured temperature is i significantly dif ferent 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 dif ference between dhe actual reference leg temperature (s) and the value(s) assumed during initial calibration shall be less than that amount which will re sult in a scale end point error of 1% of the inst rument gpan for each range.

RESULTS STP-9.1, Reference Leg Temperature Comparison With Ehe 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 dif ference 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.It of the measured instrument span for each range, thereby satisfying the i

ccceptance criterion.

STP-9.1 was performed in TC-1 to determine whether changes in plant conditions had af fected reactor water level end f

point calculations. The principal variables are reference leg temperature and reactor building temperature. There were small changes in the two sets of temperatures from TC-H/U to TC-1. Consequently, and point calculations were made only for those instruments on the reference leg with the largest temperature change (Ref. Leg "B") . The end 4-25

1 I

point error was still well within the required 1% of inst rument span.

4-26

i 1

4.8 STP-10, IRM PERFOhtMANCE OBJECTIVES The objectives of this test are to adjust the Intermediate Range Monitoring (IRM) System to obtair. an optimum overlap with the SRM and APRM systems.  !

ACCEPTANCE CRITERIA l

Level 1 Each IRM channel must be on scale before the SRM's exceed 4 their rod block setpoint. I 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. Once overlap was satisfactorily demonstrated, RPS was taken out of the noncoincident scram mode by the installation of the shorting links.

4-27 1

The following indications were recorded after SRM count

rates were stabilized

Normalized Range 1 Reading) Reading SRM (CPS IRM (0-40 scale)

A 3.24x10**4 A 3.5 B 4.39xlO**4 B 3.0 C 1.35x10**4 C 4.0 D 2.07x10**4 D 2.5 E 3.6 F 3.5 G 5.0 H 4.5 All IRM readings were above the downscale value of 5/125 (1.6 on 0-40' scale).

The applicable Level I criterion was satisfied when each

~~

IRM channel was on scale before the SRM's exceeded the

, normal rod block setpoint of 1x10**5 CPS (normalized reading).

The applicable Level 2 criterion was verified when the IRM downscale lights cleared and .all SRM's indicated less that 5xlO**4 CPS (half decade from rod block setpoint).

I 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 +5%, 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 +5% ,

cf the corresponding range 6 reading. Each high frequency amplifier for IRM ranges 7 through 10 had to be adjusted to catisfy the +5% test objective. IRM B was satisfactorily cdjusted durTng a subsequent startup.

4 4-29 I

Following adjustment of all IRM channels, the as left 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 STP-10.3, IRM/APRM Overiap 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 overlap. Each IRM high frequency amplifier gain had to be cdjusted 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. IRM C will be tested in a subsequent Test Condition.

D 4

4-29

(

4.9 STP-11, LPRM CALIBRATION OBJECTIVES The objectives of this test are to calibrate the Local Power Range Monitoring (LPRM) System and to verify LPRM Flux Response.

ACCEPTANCE CRITERIA l Level 1 None

! Level 2 Each LPRM reading will be within 10% of it's calculated talue.

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 j . 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 cquipment. 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 ratested

{ ct a higher power level in Test Condition 1 (see STP-ll.4).

'!here are no acceptance criteria associated with this test.

l 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 of f line computer program, Backup, Core Limits Evaluation. Of the 172 LPRM's, twelve detectors were I

4-30 i

bypassed and declared inoperable. 108 of the remaining detectors had final GAF's > 0.9 and < l.1, thus satisfying the applicable acceptance criteria. ' 52 of the detectors had final GAF's outside of the acceptance criteria limits.

Immediately following the completion of Test Condition 1, at approximately 23% CTP, an additional LPRM calibration was performed utilizing the Process Computer. These

~

results were satisfactory with only three operable LPRM's with GAF's outside of the 0.9 and 1.10 limits. These three LPRM's and the bypassed detectors will be addressed by subsequent calibrations.

STP-ll.4, LPRM Operational 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% CTF 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.

o l

8 .

4-31 l

1 1

4.10 STP-12, APRM CALIBRATION OBJECTIVES The objective of this test is to calibrate the Average l Power Range Monitor ( APRM) System. '

ACCEPTANCE CRITERIA Level 1 -

The APRM channels must be calibrated to read equal to or I greater than the actual core thermal power. l 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 Ute APRM channels will be considered to be reading accurately if they agree with the heat balance or the minimum value required based en 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 Gain 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 satisf~ied.

The first part of this test involved taking plant data cvery 10 minutes during a reactor heatup. The heatup was catablished 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 I hour period, a core thermal power was calculated. Using this CTP, an APPM gain cdjustment factor ( AGAF) ware calculated for each APRM, for cach data set. These AGAFs ware averaged providing an

• 4-32

average AGAF for each APRM. While these 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 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 O.324 2.9 0.94 1.00 B 0.246 3.0 0.74 1.05 C 0.263 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, resoectively. 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 C 11 14 D 11.5 14 i

E 12 15 F 12 15 l

l 4-33 J

\

i I

)

,n------.--,n - ., - -,w ,-.,-- - -..r,.w, aw,-_,,,,-,-.,-----.,_--_ ,-,--,----,.-r.,m

STP-12.2 Low Power APRM Calibration This test was performed at Test Condition 1 at approximately 20% CTP. The purpose of the test was to calibrate the APRM channels against core thermal power.

This test was conducted by performing a heat balance using appropriate process computer points and instrument readings. Core thermal power was calculated to be 698.82 MWt.

All APRMs were calibrated to read greater than actual core thermal power as shown below:

Final Reading APRM (% rated CTP)

A 21.5 B 22.0 C 22.0 D 22.5 E 23.0 F 22.5 In addition, the flow biased scram and rod block setpoints were verified to be less than the allowable values given in Technical Specifications. All applicable acceptance criteria were satisfied.

, 4-34 i

I j

1

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 eithers 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 dif forent assembly than that calculated ,

by BUCLE, for each assembly, the MCPR and the CPR l calculated by the two methods shall agree within 24. I The maximum LHGR calculated by BUCLE and the Process {

Computer either:

l are in the same fuel assembly and do not dif fer in value by more than 24, or for the case in which the maximum LHGR calculated by the Process Computer is in a dif ferent assembly than that calculated by BUCLE, for each assembly, the maximum LHGR and the LHGR calculated by the two methods shall ~ agree within 21.

The MAPLHGR calculated by BUCLE and the Process Computer cither

• 1 1

are in the same fuel assembly and do not differ in value I by more than 24, or for the case in which the MAPLHGR calculated by the l Process Computer is in a dif forent assembly than that calculated by BUCLE, for each assembly, the MAPLHGR and APLHGR calculated by the two methods shall agree within l 21.

e l '

! 4-35 4

i

-.------,ww-.,.,, - - -_ ..,-w,---vyyry---+yr,m ._ _ ,m------,-ne-rwu-,-------- - y--

The LPRM gain adjustment factors calculated by BUCLE and

! the Process Computer agree to within 2%.

RESULTS STP-13.1, St'atic System Test Case The Static System Test Case associated with Process Computer /TIP machine interface was ratisfactorily pe rfo rmed. Proper OD-1 operation, ' including interface with the TIP machines, agreement between computer and TIP

'; . machine indez settings, and generation of CRT and typer nes sages, was demonstrated. There are no acceptance 4

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 I

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

! cs 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

olmulated 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 i

The TIP Alignment test at Test Condition Heatup was I

. performed with the reactor operating at rated temperature l end pres sure. There were no acceptance criteria, but the l purpose of this test war to determine if the core top (NCCT) and core botton (NCCB) limits or .the x-y plotter span required adjustments. Each of the TIP guide tubes was probed, and the full-in index position (NCPI) at hot conditions was verified to'be greater than or equal to the value at cold conditions. No limit adjustments were required, but several TIP channels required plotter Qdjustments. 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.

4-36

(.

! . . - . _ _ _ _ _ _ , _ - . _ _ . _ _ . . _ . _ _ _ _ . , _ . _ . - - ~ _ _ _ _ . . .-_ . _ _ _ , ~ . . _ . _ _ _ _

STP-13.3, Program Testing at Test Condition 1 Program Testing was performed during Test Condition 1 at 19.5% of rated core thermal power. During this test the TIP core limits were checked against the limits set in STP-13.2, TIP Alignment at Rated Reactor Pressure, pe r formed during Test Condition Heatup. The average dif ference 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 LPi:M Calibration and BASE distribution was performed confirming correct TIP-Computer interface. The operettion of OD-18, LPRM Alarm Trip Recalibration could not be performed due to a power reduction and will be performed in a later Test Condition.

There were no acceptance criteria for this test.

• 1 l

4-37

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 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 avoidance margin, the transient start first and subsequent cpeed peaks shall not exceed 5% above Ehe, rated RCIC -

turbine speed.

The speed and flow control loops shall be adjusted so that the decay ratio of any RCIC system related variable is not greater than 0.25.

The tarbine gland seal condenser rystem shall be capable of preventing steam leakage to the atmosphere.

The delta P 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 3004).

The RCIC system must have the capability to deliver cpecified flow against normal rated reactor pressure without dhe normal AC site power supply. i RESULTS STP-14.1, RCIC Functional Demonstration CST to CST at 150 psig 4-38 f 4

0

- - y,-.., _ _ _ , , _.,___r,_., _ ,,r, . - - , _ ,__.-,_____,,,_-_.,3 ., , _,v-c_g,- -, ,, .m,,,_____,, . , .. - , - , , , , - - - , . _ _ . , _ , _ _ _ . . . , , , _ , , ,

i STP-14.2, Functional Demonstration and Controller Optimization at Rated Pressure CST to CST 2

STP-14.3, Stability Check CST to CST at 150 psig STP-14.4, Controller Optimization During RPV Injection at Rated Pressure STP-14.5, Stability Check CST to RPV at 150 psig STP-14.6, RCIC Cold Quick Start at Rated Pressure - CST to RPV i STP-14.7, Surveillance Tests CST to CST STP-14.8, RCIC Endurance Run 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 with the exception of minor steam leakage around the turbine shaft on the governor end.

The initial RCIC subtest, STP-14.1, was a RCIC run at a reactor pressure of 150 psig from condensate Storage Tank (CST) to CST. The test consisted of a manual. start, flow oteps in manual and automatic, and a quick start. All acceptance criteria were satisfied. -

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 rystem tuning, flow steps in manual and automatic, and a quick start. A Level 2 acceptance criteria was not met due to a small

, oteam leak at the RCIC turbine governor bearing end.

The following RCIC subtest, STP-14.3, was a RCIC run at 150

. psig reactor pressure from CST to CST. The subtest l consisted of 'a quick start followed by automatic and manual j flow step changes to check RCIC stability after tuning in -

STP-14.2. There were Level 2 test exceptions with

! oscillatory behavior observed in flow, control valve

i. position, and EGM output signals during the automatic flow decrease step. These parameters were evaluated and considered acceptable. Another problem noted during the subtest was the flow controller demanding full flow due to turbine control valve binding, which was subsequently resolved.

The next RCIC subtest, STP-14.4, was a vessel injection at 920 psig reactor pressure. During the manual RCIC start >

4-39 e

e- ,- --,e.,n +n. - ----m,nr,., ...,.~,.,..,...,,.m,m-_. ,gv....,--m-,-...,,n~_-.-,,v.,.,,-c._---,,_mn,m--...,-_-~,., e

divergent oscillations were seen When the flow controller was placed in automatic. A turbine trip then occurred on low suction pressure Which did not satisfy the Level I criteria. The RCIC system was retuned and the required

. quick start successfully 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 start was successfully completed. There was a Level 2 test exception due to transient start first speed peak (5000 RPM) being greater Chan the limit of 4725 RPM. An ovaluation was made of the data and a second cold quick Otart was successfully conducted 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 cvaluated as acceptable.

On the 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 cat conservatively.

The last RCIC subtest ,in Test Condition Heatup was STP- -

14.7, the RCIC surveillance from CST to CST at 150 psig.

The subtest was conducted with all acceptance criteria

, satisfied.

) e STP-14.7 was performed again in Test Condition 1 with the reactor at rated pressure. All level 1 and level 2 h criteria were satisfied except for the speed peak limit l' of 4725 rpm was exceeded. The speed peak on this run was

5301 rpm. A test exception was written and two hot quick l charts were performed to the vessel. Speed peaks of 4813 i rpm and 4537 rpm _were obtained. A third hot quick start l was performed to the CST. The resulting speed peak was

! 5034 rpm. Since RCIC was still operable per plant l technical specifications, testing continued. Fur ther investigation of the gpeed peaks is being conducted.

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 4-40

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 1 supplied to RCIC components, including the room cooler . l 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 required system modification, consisted of ~ binding of the RCIC turbine control valve and turbine governor end gland seal leakage. 'Ihe 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 control valve linkage.. The steam leakage from the turbine governor end is a minor problem and a resolution continues to be investigated.

A 'RCIC test results summary is provided in Tr.ble 4.12-1.

8 4 l

e 4-41 e

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TABLE 4.12-1 RCIC TEST RESULTS 54N9tARY Level i LEVEL 2 TEST DATE T.C. PRES 5URE TIME TO TRIP SPEED OSCILLATIONS SEAL 5 PSIS DELTA P RATED FLOW PEAK LEAKAGE SMITCH 130 sec. 14725 SETTINGS 14.1 t/03/a5 NU 150 11.5 NG 2555 NOME NOME N/A 14.2 t/ft/85 HU RATED 17.5 NO 4400 NOME YES N/A I 2 14.3 2/18/a5 NU 150 21.7 YES 2357 AffEPTABLE MONE N/A 5

14.4 2/27/85 NU RATED 18.6 YES 4211 NOME YES N/A 14.5 3/01/85 NH 150 5.6 NO 2422 "a"f YES N/A 14.5 t/03/85 HU 158 6.8 NO 2298 NOME MONE N/A 4 4 4 14.6 4/06/85 HU RATED 18.8 YES 4462 NOME NOME N/A 5

14.6 4/09/85 NU RATED 18.7 MS 5000 NONE NOME N/A 14.6 4/12/85 NU RATED 18.6 NO 4200 NONE YES OK 14.7 4/97/85 NU 158 7.1 NO 2423 NONE NDHE N/A 6 7 14.7 8/15/85 .1 _ RATED 17.4 NG 5301 N/A N/A N/A anual turbine trip on less of annual control due to control valve binding.

2 Minor limit cycles observed on step change. Accepted as is.

3 Following manual start, when controller placed in auto, divergent escl11ations occurred resulting successfully.

in a low suction pressure turbine trip. Centrol system rotuned and test completed

4. Turbine trip on low suctlen pressure during cold quick start. Listed results are for a successful Mt quick start which followed.

5. High speed peak evaluated as acceptable with adequata mergin to overspeed trip maintained.

6. 5Tr-14.8 and 14.9 performed concurrently.

7. Speed peak to be resolved at a later date.

4-42 .

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4 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)

System over its expected operating pressure and flow ranges, and to demonstrate reliability in automatic '

ctarting from cold standby when ethe reactor is at rated pressure conditions.

ACCEPTANCE CRITERIA Level 1 The average pump discharge flow must be equal to or greater than 100% rated value after 25 seconds have elapsed from Eutomatic initiation at any reactor pressure between 200 peig and rated.

The HPCI turbine shall not trip or isolate during auto or autnual 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 3004).

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 4-43

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I 4

STP-15.3, Stability Check CST - CST at 200 psig STP-15.7, HPCI Endurance Run The results of HPCI testing during Test Condition Heatup were satisfactory. All problems n'oted during the tests were resolved with the exception of minor steam leakage at the stop valve stem and control valve lifting rod bushing. I Resolution of these minor steam leaks continues to be investigated.

1 An outage was commenced after the initial phase of Test i 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 oteps 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 cwap overs and a Level 2 criteria was not met due to gland coal steam leakage. Al1 other applicable acceptance criteria were sat.isfied.

The next HPCI subtest, STP-15.2, was a HPCI run at 920 psig rcactor pressure from CST to CST. This test consisted of a manual start, inner and outer loop tuning, flow steps in anual and automatic, and a quick start. This subtest cnccuntered 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, cc outlined in Table 4.13-1, were resolved as a result of a bypass 'line modification that bypassed Auxiliary Oil Pump Oil around the EGR 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 cf a quick start followed by flow step changes in automatic End manual to check HPCI stability at low reactor pressure after control system tuning. The test initially did not meet the Level I criteria of time to rated flow but was 4

4-44

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i l

cuccessfully 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 cnd 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.

A discussion of problems encountered during HPCI 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 expected. This discovery, combined with the water found in the discharge line, was evidence that the  !

vacuum pump had been pumping water which could have l

caused the overload condition. Subsequent operation of the HPCI system was performed without any further tripping of the Barometric Condenser Vacuum Pump.

2) Balance Chamber Adjustment - It was suspected that the balance chamber pressure adjustment of 165 psig was low enough to allow the observed spiking open of the HPCI turbine stop valve on system startup. The stop j valve was observed to spike fully open and then settle j 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 54) was completed. The bypass modification made the l balance chamber pressure less limiting and improved performance was observed with a final pressure 1

adjustment of 108 psig in the balance chamber at a reactor pressure of 900 psig.

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 l the hyGaulic 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.

4-46

TABLE 4.13-1

- HPCI Equipment Problems (Cont.)

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 dif forential 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'1evel transmitters .

susceptible to the ef fects. of the HPCI starting flow surge, and necessitated the use of the time delay.

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 HV55-IF008 (Test Loop Shutof f) valve. This allowed HPCI flow only after a back pressure was developed and lessened the severity of the starting flow surge. In i

addition, the hydraulic bypass modification limited

! the acceleration of the HPCI turbine. This also had the of fact of limiting the starting flow surge and eliminated the HPCI turbine low suction pressure trip i grob1em.

I 4-47 W

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1 1

4 i

TA5LE 4. 83-2 HPCI TEST RESULTS

SUMMARY

evel I LEVEL 2 TEST DATE T.C. PRESSURE TIllE TO TRIP SPEED PEAK OSCILLATION 5 5 PSIS SEAL RATED FLON IMITIAL/5055E4. LEAKAGE

] 125 sec. (4609 (4399 8

15.1 1/a4/a5 NU 280 18.5 YES 2

1480 */ 3853 NONE YES 15.2 2/26/85 NU RATED 28.1 No 4240

3

/ 4337 NONE YES 1 15.2 4/05/85 NU RATED 19.8 NO 1356

• / 4356 NONE YES 4

15.3 2/19/85 NU 200 26.8 N0 1615 / *3000 N/A NO j 15.3 2/20/85 NU 249 19.7 NO 1477 i .

/ 3184 NONE YES 15.7 1/17/85 NU RATED N/A No N/A 1

N/A N/A l ne manual and one automatic trip (Iow suction pressure) on CST to SP suction swap during a i

startup. One manual trip when CST return valve (Fell) failedtoopen(SPsuctioninterlock5 stem on j

startup. Successfully completed subsequent startup with results as shown.

i 2.

i Results shown are for the last performance of 5TP-85.2 prior to the hydraulic bypass modification.

i j 3. Post hydraulic modification results.

! 4.

Stop valve went shut for a short. 't ime on a momentary low suct ion pressure trip signal resulting in excessive time to rated flow. STP-85.3 repeated on 2/20/85.

2 k

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P 4.14 STP-16, SELECTED PROCESS TEMPERATURES OBJECTIVES The objectives of this test are (1) to assure that the measured bottom head drain temperature corresponds to bottom 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 ctratification 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 loop suction temperature end 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 cteam done 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 deorees F of the recirculation loop temperatures.

RESULTS STP-16.1, Minimum Recirculation Pump Speed Determination The Selected Process Temperatures test at Test Condition Heatup was performed with the reactor operating at rated temperature and pressure at approximately 51 power. There were no acceptance criteria, but the existing scoop tube positioner low speed stop settings were shown to prevent cxceeding the Technical Specification limit on the bottom head to steam done temperature difference (145 Deg. F) 4-49

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during norm 1 plant operation with the recirculation pumps operating.

The reactor. steam done pressure was constant at 930 psig throughout the test resulting in a constant steam dome saturation temperature of 536 Deg. F. The temperature dif forence 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 181, control rod drive flow varied from 60 gym to 40 gpa, and reactor water cleanup flow varied from 78 gym to 139 gpa.

The variations in recirculation, control rod drive and reactor water cleanup flows had a negligible impact on the steam done to bottom drain temperature dif ference, and the Technical Specification limit of 145 Dog. 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.

J 4-50

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i 4.15 STP-17, SYSTEM EXPANSION OBJECTIVES ,

l This test verifies that safety related piping systems and i l

other piping systems as identified in the FSAR expand in an ccceptable 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) cnd Reactor Recirculation piping systems.

Tlie 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.

Pwsidual displacements measured following system return to cubient temperature do not exceed the greater of + 1 in.

cr + 25tof the maximum displacements measured durTng/16 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 4-51

. _ ._m . _ _ _ _ _ _ _ _ . _ _ _ _ _ _ _ _ _ - . _ _ . = _ _ . . . _ . _ . _ , . _ _ _ _ _ . _ - _ _ . ._

Startup Test Program, per FSAR Table 3.9.7, was free 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 otructural reference points, prior to reactor heatup in order to estabish baseline data.

f 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 pres sure. ,

System expansion testing for High Pressure Coolant Injection and Reactor Core Isolation Cooling was performed at reactor moderator temperatures of 350 degrees F, 450 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.

4-52 4

e

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i Residual displacements for all tested system were determined subsequent to the cooldown from the initial reactor heatup.

Problems encountered during the performance of this test 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 af fact on the involved piping by Bechtel Engineering. Following this review they were deemed acceptable and required no further action.

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 noszles 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 3

retest was performed during a subsequent heatup and the results were satisfactory.

4. The RRR head spray line initial displacements were outside of the stated tolerances. Bechtel Engineering reviewed the actual displacements and found the i

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 ratested 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.

4-53

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_.,,,,,.,_,.,,.,,.,.m--,-1 w-

STP-17.2, Measured Pipe Displacements (Feedwater and RNCU Systems)

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. To date, the only measurements taken were at Test Condition Open Vessel to obtain baseline data.

STP-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) cnd Reactor Recirculation piping under specific conditions.

Data Response collection Facilities was accomplished Data System using)the Emergency (ERFDS and the specific cystem remote monitoring instrumentation (Lanyard Potentiometers and Resistance Temperature Devices, RTD's) installed on each Main Steam line and Recirculation loop.

Thermal expansion data collection was taken at Open Vessel and Test Condition Heatup 275 + 25 DEG F, 425 + 25 DEG F, -

cnd normal operating temperature.

Remotely monitored instrumentation are in two ' locations on cach steam line .and four locations on each react.or 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 met at 275 Dog F. At 425 Dog 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 I criteria for SB-LZ. Permission was granted '

to continue testing and heatup to rated conditions.- For I 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 i 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 cceeptable by GE Plant Piping Design.

4-54 9

r- 6 ,,-n,-,,-,-,-, - - , , - - - .-,--,,m--. wav ,-,-,-w,,, --e--,---- ,,n,,-r- .--,-,,,-en,,,,,,vm.-,w.,,,,,-,-mm- ,,w, -

J 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 Cf obstructions to normal system expansion. No cables were found stretched, no position indicators were out of their travel range, and no hangers were bottomed out.

J Visual inspections were performed during Heatup at 275 Deg F, at Rated Temperature, and shutdown after 'two heatup cycles were complete. Of the 110 piping restraints associated with this test, a total of seven Main Steam and Recirculation hangers were found to be outside of their hot Ond cold design settings. This data was evaluated by GE Plant Piping Design and was determined to be acceptable.

All snubbers were within their normal operating range. 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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4.16 STP-18, TIP UNCERTAINTY OBJECTIVES The objective of this test is to determine the reproducibility of the Traversing Incore Probe system readings.

ACCEPTANCE CRITERIA Level 1 None 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 ~ 64.

RESULTS 4

STP-18 has not been performed at this time. Results will be discussed in a supplement to this report.

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i 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) Evalute whether the following core performance para.w:ers are within limits:

Maximum Linear Heat Generation Rate (MLHGR),

Minimum Critical Power Ratio (MCPR),

- Maximum Average Planar Linear Heat Generation Rate (MAPLHGR).

ACCEPTANCE 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 Cxceed the minimum limit specified by the Plant Technical Speci fications. .

4 The Maximum Average Linear Heat G4neration 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 cower (3293 MWt) .

Core flow shall not exceed its rated value (100 Mlb/hr).

Level 2 None RESULTS l STP-19.1, Core Performance - BUCLE Calculation In Test Condition 1, the of f-line computer program, Backup Core Limits Evaluation (BUCLE), was used to calculate the c8re thermal limit. parameters MLHGR, MCPR, and MAPLHGR. A manual heat balance was also performed to calculate the e

4 .57 ,

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i reactor core thermal power. All acceptance criteria were

, catisfied.

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 I criterion limits of 3293 MWt and 100 Mlb/hr.

The values of MFLPD, MFI4PR, and MAPRAT were calculated to be 0.262, 0.307, and 0.242, respectively, using the of f-line computer program BUCLE. Since all of these thermal limit parameter ratios were less than 1.0, the Level 1 acceptance criteria were satisfied.

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4.18 STP-20, STEAM PRODUCTION OBJECTIVES The objectives of this test is to demonstrate that the N clear 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 i procedures shall be within the appropriate license i

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 cf 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.

4 9

4-59 4

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4.19 STP-21, CORE POWER-VOID MODE RESPONSE i

OlkTECTIVES -

The objectiva of this test is to measure the stability of the core power-void dynamic response and to deronstrate that its behavior is within specified limits.

ACCEPTANC2 CRITERIA Level 1 The de'.:ay 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 i

STP-21 has not been performed at this time. Results will be discussed in a supplement to this report.

e 4-60 e .-,-,,.,n- - - , , - , , . ----r.vwn -,,w---w -,w,-n-- -g,-----v- - - - - . - - - , - - . - -----, ,,r-, ,r--,-,----, ---,,mrr-,.-,-nn.- --

4.20 STP-22, PRESSURE REGULA'IOR 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 setpoints at an cppropriate 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 respo'nse of any pressure control system related variable to any test input must not diverge.

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 cetpoint change to the turbine inlet pressure peak shall be i fl0 seconds. l

Pressure control system deadband, delay, etc., shall be j l small enough that steady state limit cycles (if any) shall produce steam flow variations no larger than +0.5 percent cf rated steam flow. -

The peak neutron flux and/or peak vessel pressure shall rcmain below the scram settings by 7.5 percent and 10 psi 4-61

+

}

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, "incr emental change in pressure control signal / incremental change in oteam flow", for each flow range) shall meet the following:

% of Steam Flow Obtained With Valves Wide Open Variation

. O to 854 j4:1 854 to 97% J2:1 854 to 99% j,5:1 RESULTS STP-22.3, Pressure Regulator Response-Bypass Valve Operation This test was performed during Test Condition 1 and met all Level 1 and Level 2 criteria. The transient response to test input did not diverge Ehus satisfying the Level I criterion. With respect to the three Level 2 criteria cpplicable to this subtest 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 3.33 seconds which is below the required 10 second criterion.

3) The pressure control system did not exhibit steady state limit cycles hence meeting the criterion that steam flow variation be less than +5% of rated steam flow.

4-62

1 i

4.21 STP-23, FEEDWATER SYSTEM OBJECTIVES l

The objectives of this test ares l To demonstrate that the feedwater system has been adjusted to provide acceptable reactor water level ventrol.

To demonstrate an adequate response to a feedwater temperature reduction.

To demonstrate

• the capability of the automatic core flow runbacic 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 aust be greater than the Tuel thermal safety limit.

The increase in simulated heat flux cannot exceed the predicted Level 2 value by more than 24. The predicted value will be based on the actual test values of feedwater temperature changes and initial power level.

l Maximum speed attained shall not exceed the speeds which will give the following flows with the normal complement of l pumps operating.

a. 135% NBR at 1075 psia

b. 146% NBR at 1020 paia Level 2 Level control system-related variables may contain oscillatory modes of response. In these cases, the decay ratio for each controlled mode of resoonse must be less than or equal to 0.25.

l 4-63

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The open loop dynamic flow response of each feedwater actuator (turbine) to small-(<10%) step disturbances shall be

a. Maximum time to 10% of a step disturbance fl.1 see

b. Maximum time for 10% to 90% of a step disturbance fl.9 sec

c. Peak overshoot (% of step disturbance) f15%

d. Settling time, 1004 154 214 see The average rate of response of the feedwater actuator to large (>20% of pump flow) step disturbances shall be between 10 percent and 25 percent rated feedwater 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 11 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

-inches margin from an initial water level halfway between the high and low level alarm setpoints.

The maximum speed must be greater than the calculated cpeeds 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 STP-23.1 was successfully performed during TC-1. The level control system did not diverge as a result of any test input, and therefore, complied with the single Level I 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 4-64

l written to accept the 0.33 decay ratio as it did not significantly af fect system operation.. A controller step input of +5 inches displayed the required decay ratio.

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4.22 STP-24, TURBINE VALVE SURVEILLANCE OBJECTIVES i 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 retting.

Peak steam flow in each line must remain 10% below the high flow isolation trip setting.

RESULTS STP-24 has not been performed at this time. Results will be ' discussed in a supplement to this report.

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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 Ehe reactor transient behavior that results from Ehe simultaneous full closure of all MSIV's at a high power level.

ACCEPTANCE CRITERIA Level 1 MSIV stroke time shall be no faster Ehan 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 settingc must prevent flooding of the steam lines. '

Reactor must scram to limit the severity of the neutron 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 dhe 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 en the discharge cide 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 occur. ring within the first 30 seconds after the 4-67 O

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 This test was performed during Test Condition Heatup and Test Condition One to functionally check all of the Main Steam' Isolation Valves (MSIV's) in addition to measuring their closure times. The closure time of each MSIV and the transient response of certain reactor variables were recorded by the Emergency Response Facilities Data System (ERFDS). All applicable Acceptance Criteria were catisfied. However, during the initial run of this STP at TC-1, one valve did not meet the Level I criterion for minimum stroke time. The F022A Stroke Time was ~2.84 seconds and the Closure Time was 3.48 seconds. Subsequent adjustment and retest recorded these ' times as 3.73 seconds and 4.39 seconds respectively, satisfying the criteria. _

Each MSIV was stroked, one valve at a time, using ihs

. control switch and the response of various reactor parameters recorded by ERFDS.

Each MSIV had a stroke time greater than 3.0 seconds and a closure time of less than 5.0 seconds, thus satisfying the Level 1 Acceptance Criterion.

The reactor did not scram. The peak APRM reading remained

- 7.5% below the scram setpoint (The scram,setpoint for TC- l H/U was 154, and for TC-1 was either 61% or 69.21. The l former (61%) for the initial test of all valves, the latter ]

(69.2%) for retest of valve F022A. ) . The peak vessel 1 pressure remained less than 1027 psig (10 psig below the l high pressure scram setpoint) thus satisfying the )

cpplicable Level 2 Acceptance Criterion. '

. The reactor did not isolate and the peak steam flow on each line remained less than 128% (10% below the high steam flow isolation trip setpoint) thus satisfying the applicable Level 2 Acceptance Criterion.

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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 vailves shall return to within 10 DEG F of the temperature recorded before the valve was opened.

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 vtarage Relief Valve steam flow.

During the rated pressure functional Je : t. p a steam flow through each Relief Valve, as measureC Sy,S r..irator Gross lete, shall not be lower than the average valve response by more than 0.5% of rated Pete.

RESULTS STP-26.1, Relief Valve Low Pressure Test During Test Condition Heatup with reactor pressure at 300 peig, each Relief Valve was manually cycled to verify proper operation. Each valve was maintained open for

. Epproximately 10 seconds to allow system variable to ctabilize.- -

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l Positive indication of Relief Valve discharge was verified

-by review of transient plots . of Bypass Valve position. The cteam 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 lift, with reactor pressure c.t 375 peig, Bypass Valves went fully shut. The Relief valve was immediately shut. Reactor pressure was then reduced to 300 psig, additional Bypes Valve capacity was obtained, and the test was successfully completed.

All applicable -acceptance criteria were satisfied with the j 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 of this exception will be determined following the performance of STP-26.2, Relief Valve Rated Pressure Test, in a subsequent Test Condition.

4-70

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I 4.25 STP-27, MAIN TURBINE TRIP OBJECTIVES The objectives of this test are to demonstrate the response of the Reactor and its control systems to protective trips cf the Main Turbine and to evaluate the response of the l bypass and safety / relief valves.

l ACCEPTANCE CRITERIA Level 1 -

For Turbine and Generator Trips at power levels greater than 50% Nuclear Boiler 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 1 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 I or Stop Valve closure motion. I Feedwater System settings inust prevent flooding of the oteam lines following these transients.

The positive change in vessel done pressure occurring within 30 seconds after either Generator or Turbine Trip must not exceed the Level 2 criteria by more than 25 psi. l

'the poisitive 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 are 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 clinutes of the transient and operator a'ction 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 positive change in simulated Heat Flux occurring within the first 30 seconds after the initiation of either Generator or Turbine Trip must not exceed predicted values.

Feedwater level control shall avoid loss of feedwater flow due to a high (L8) water level trip during the event.

Low (L2) water level recirculation pump trip, HPCI and RCIC shall not be initiated. l The temperature measured by thermocouple.s on the discharge aide of the Relief Valves must return to within 10 Degree F cf the temperature recorded before the valve was opened.

For the Turbine Trip within the Bypass Valves capacity, the Reactor shall not scram.

The measured Bypass Valve capability shall be equal to or greater than that used in the FSAR analysis (25% of Nuclear Boiler Rated Steam Flow).

RESULTS STP-27 has not been performed at this time. Results will be discussed in a supplement to this report.

l 4-72 l

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4.26 STP-28, SHUTDOWN FROM OUTSIDE THE CONTROL ROOM l

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 cddition, it will provide an op portu nity 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 end under. control, and Reactor vessel pressure and water i

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 tho' 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 0 heat transfer 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 l

a rate which does not exceed the Technical Specification Limit.

RESULTS STP-28 has not been performed at this time. Results will be discussed in a supplement to this report.

4-73 1

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4.27 STP-29, RECIRCULATION FIDW 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 controllers are set for the desired system performance and otability.

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 seineuvers. The APRM neutron flux trip avoidance margin shall be >7.5% when the power maneuver of facts are extrapolated to those that would occur along the 100% rated rod line.

The decay ratio of any oscillatory controlled variable must be <0.2 5.

Steady-state limit cycles (if any) shall not produce turbine steam flow variations greater than _+0.5% of rated i cteam flow.

The speed demand meter must agree with the speed meter within 6% of rated generator speed.

! RESULTS STP-29 has not been performed at this time. Results will  !

be discussed in a supplement to this report.

D 4-74 i

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4.28 STP-30, RECIRCULATION SYSTEM OBJECTIVES i The objectives of this test are to:

Obtain recirculation system performanca data during steady-ctate 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.

l ACCEPTANCE CRITERIA l

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 f_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 pmaps are tripped.

Level 2 The reactor-water level margin to avoid a high level trip Whall be 13.0 inches during the one pump trip.

The APRM margin to avoid a scram shall be~17.5% during the pump trip recovery.

The core flow shortfall shall not exceed 5% at rated power.

The measured core delta P shall not be >O.6 PSI above prediction.

l l The calculated jet pump M ratio shall not be <0.2 points l below prediction.

4-75

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1 The drive flow shortfall shall not exceed 5% at rated '

- power.

The measured recirculation pump of ficiency shall not be >8%

points below the vendor tested efficiency.

The nozzle and riser plugging criteria shall not be cxceeded.

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 STP-30 has not been performed at this time. Results will be discussed in a supplement to this report.

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4-76

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l 4.29 STP-31, IDSS OF TURBINE GENERATOR AND OFFSITE POWER OBJECTIVES  !

This test determines electrical equipment and reactor cystem transient performance during a loss of maint turbine-generator coincident with loss of all sources of offaite 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 cetion, i f neces sary, shall keep the reactor water level above the initiating level of Low Pressure Core Spray, LPCI, Automatic Depressurization 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 -

instrumentat. ion. .

Reactor pressure shall not exceed 1250 psig.

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.

l Normal cooling systems shall be capable of maintaining cdequate drywell cooling and adequate suppression pool water temperature. .

RBSULTS STP-31 has not been performed at this time. Results will be discussed in a supplement to this report.

4-77 1

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i 4.30 STP-32, ESS!!NTIAL HVAC SYSTEM OPERATION AND CONTAINMENT HOF PENETRATION TEMPERATURE VERIFICATION OILTECTIVES 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 i

temperatures and relative humidity within the following areas: -

I i

c) Primary Containment (drywell and suppression chamber) b) Reactor Enclosure and Main Steam Tunnel l

c) Control Room d) Control Enclosure o) Radwaste Enclosure In addition, this test shall verify that the concrete 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 i The drywell area and suppression chamber are maintained i between 65 degrees F and 150 degrees F.

The reactor pressure vessel (RPV) support skirt surrounding air temperature is mair.tained 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 tre 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 l

cnd 78 degrees F and relative humidity between 45% R.H. and 55% R.H. .

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The Control Room is maintained at a temperature between 74 degrees F and 78 degrees F and relative humidity between 454 R.H. and 55% R.H. l 2 l 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, 506B, 506C, 506D, i 507, 508, 509, 511, 519, 601, 602, 605, 612, and 618.

The following areas of the Reactor Tnclosure 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

For Test Condition Heatup at rated temperature and I

!~

pressure, while initially operating the Drywell Ventilation i System in a normal configuration of one Chilled Water (CW) '

loop and one fan per unit cooler, area temperatures and overage temperatures were high. A second Chilled Water loop was placed in service with one set of unit cooler fans and the following results were obtained:

Level I criteria was met with a volumetric average temperature calculated at 127.2 degrees F, highest drywell temperature of 146 degrees F, and lowest'drywell temperature of 90 degrees F. The Level 2 criteria was exceeded in the suppression chamber with a maximum air temperature of -155 degrees F. RPV skirt surrounding air temperature was maintained above the established minimum of 70 degrees F.

During a subsequent plant outage, all external surfaces of the unit. cooler cooling coils were cleaned, internal cooler surfaces inspected and Chilled Water System performance reevaluated. Following this outage, the plant was returned to operating conditions (rated temperature. and pressure) .

4-79 O

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and additional data was collected on the Drywell ventilation System in a normal (single loop) configuration.

System performance was much improved with no temperatures exceeding 150 degrees F and the volumetric average temperature stabilized at approximately 132 degrees F.

Additional testing will be performed in subsequent Test Conditions to evaluate system performance.

STP-32.2, Hot Penetration Concrete Temperature For Test Condition Heatup at rated temperature and pressure, concrete temperatures remained well under the 200 degree limit with the maximum recorded temperature of 148 degrees F on r.ain steam line "A" (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, test data was declared invalid due to system malfunctions including loss of relative humidity control and instrument calibration problems.

Ratest 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%

relative humidity. Retest of the system ("A" CW loop) will take place in Test Condition 2.

STP-32.4, Control Room Temperature and Relative Humidity 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 criteria minimum temperature of 74 degrees F and maximum relative humidity of 55% were not met for several rooms and creas. These test exceptions were resolved through an Engineering safety evaluation, expanding the allowable temperature band to 65 to 78 degrees F and humidity band to i

4-80 4

I e

30% to 90% relative humidity. Additional testing will be perfomed in subsequent Test Conditions.

STP-32.5, Reactor Enclosure and Main Steam Tunnel Temperature For Test Condition Heatup all recorded room temperatures were within acceptance criteria but test data was declared 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 exceptions relating to excessive delta temperatures in the Main Steam Pipe Chase Area and the Reactor Water Cleanup Pump Area. These test exceptions are presently being cvaluated.

STP-32.6, Radwaste Enclosure Temperature For Test Condition Heatup 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. This test exception was reviewed and evaluated and found acceptable.

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4.31 STP-33, PIPING STEADY STATE VIBRATION OBJECTIVE The objective of this test is to verify that the steady ctate vibration of Main Steam, Reactor Recirculation and selected BOP piping systems is within acceptable limits.

ACCEPTANCE CRITERIA Level 1 Operating Vibration: The measured amplitude (peak to peak) of each remotely sonitored point shall not exceed the ellowable value for that point.

Level 2 Operating Vibration: The measured amplitude (peak to peak) '

of each remotely monitored point shall not exceed the cxpected 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 cvaluated as determined necessary by BPC Project Engineering.

The vibration measured by a remote accelerometer is cceeptable if the acceleration frequency spectrum falls in the negligible region of the acceptance chart for that cecelerometer.. If the acceleration frequency spectrum crosses the negligible region boundary, the test results

- shall be evaluated by BPC Project Engineering.

RESULTS STP-33.4, HPCI Steam Piping Steady State Vibration The results of the testing showed that steady state vibratory response for the HPCI Steam Piping was within cceeptable design limits.

t

, 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. i j

The test was performed in Test Condition Heatup with the HPCI turbine running on nuclear steam at a nominal throttle pressure of 920 peig and the HPCI pump discharging at rated l

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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 neceptance 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 j ceceptable design limits.

Data was recorded on ERFDS (Emergency Response Facility Data Systsat) from remotely mounted vibration sensors.

Recorded data was processed as applicable, and compared with design limits.

The test was performed with the RCIC turbine running on nuclear steam at a nominal throttle pressure of 920 psig end the RCIC pump discharging at rated head and flow. Pump suction was from, and discharged into, the condensate ctorage tank.

Co piping steady state vibratory response problems were cncountered 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 cceeptance 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 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 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 which bottom head drain line flow is maximized at 4

4-83 e

opproximately 120 gpa and the normal mode in which suction flow from the recirculation line is maximized at appresimately 290 gpa. Two of three RNCU pumps operate during these . modes. ,

1 No piping steady state vibratory response problems were i encountered during the test. The test results were forwarded to Bechtel Engineering for review. Based on i their analysis of the test data, they deemed that the i

ceceptance criteria had been met.

1HF-005, RHR Iow Pressure Coolant Injection Steady State Vibration Test The results of the testing showed that steady state vibratory response for the RRR Low Pressure Coolant .

Injection Piping was within acceptable design limits.

Steady state vibrations were evaluated by qualified test ongineers using visual and tactile judgement and hand held vibration' monitors. These engineers were qualified to j Otandards set by Bechtel Project Engineering.

The object of this test was to verify, by means of visual czamination 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 RRR Loops A and D with pumps LAP 202 and IDP202, respectively, discharging to the reactor vessel at rated flow of approximately 10,000 gym.

No piping steady state vibratory response problems were cncountered during the test.

1HF-006, Core Spray Piping Steady State, Vibration Test The results of the testing showed that steady state vibratory response for the Core Spray Piping was within ecceptable 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.

l 4-84 l

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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.

The test was conducted, prior to fuel load, when both core

, cpray pumps, IAP206 and ICP206, were in operation and discharging to the reactor vessel at a minimum combined

. razed flow of 6350 gym.

No piping steady state vibratory response problems were

cncountered during the test.

1HF-017, ' Head Spray Piping Steady State Vibration Test The results of the testing showed that steady state vibratory response for the RER Head Spray Piping was within cceeptable design limits.

Steady state vibrations were evaluated by qualified test ongineers using visual and tactile judgement and hand held vibration monitors. These engineers were qualified to Otandards set by Bechtel Project Engineering.

The objective of this test was to verify, by means of

. visual examination by qualified test engineers, that the 1 tcsted piping met the steady state vibration limits.

The procedure was implemented, in Test Condition Open i Vessel, during operation of RER loop A running in the shutdown cooling mode and head spray flow at approximately 1,000 gym.

No piping steady state vibratory response problems were cncountered 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 Of fgas 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 cix noble gasee measured at the after condenser discharge shall not be exceeded.

The hydrogen content of the of fgas of fluent downsteam of the recombiner shall be equal to or less than 4% by volume.

The total flow rate of dilution steam plus of fgas when the ctean jet air ejectors are in operation shall exceed 9555 lbm/hr.

Level 2 --

System flows, pressures, temperatures and dowpoint shall be within expected performance values.

The preheater," catalytic recombiner, af ter condenser, Hydrogen Analyzers, cooler condenser, activated charcoal beds and the REPA filter shall be performing their required functions adequately. The automatic drain systems function cdequately.

TEST RESULTS -

STP-34.1, Of fgas Performance Verification This test was performed in Test Condition Heatup and Test Condition 1.

Dose and dose rates from releases of radioactive gaseous and particulate effluents at the site boundary were less than minimum detectable activity (MDA) .

Radioactive release rates of the six noble gases measured at the after condenser discharge were less than MDA.

4-86

The hydrogen content of . the of fgas of fluent downstream of the recombiner was less than it by volume for both test conditions. The total flow rate of dilution steam plus of fgas was >12,600 lba/hr (TC-1) . Of fgas flow rates were in excess of 200 scfm during test condition H/U (total flow was >14,000 lbs/hr) but subsequent testing after a condenser leak was found and plugged reduced in-leakage to cyproximately 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, pres sur es, temperatures and dew points were within expected values. All system major components performed their required functions adequately.

9 8

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4.33 STP-35, RECIRCULATION SYSTEM FIDW CALIBRATION O&7ECTIVES 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 provide 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 STP-35 has not been performed at this time. Results will be discussed in a supplement to this report.

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l 4.34 STP-36, PIPING DYNAMIC TRANSIENTS O&7ECTIVES l 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 '

i ct approximately 20-25%, 60-80%, and 95-100% of rated thermal power.

Main Steam and Relief Valve Discharge - Main Steam Relief i Valve actuation.

Recirculation - Recirculation Pump trips and restarts.

High Pressure Coolant Injection steam supply - High Pressure Coolant Injection turbine trips.

Feedwater - Reactor feed pump trips /coastdowns.

3 i ACCEPTANCE CRITERIA

, Level 1 i

j Operating Transients: The measured amplitude (peak to peak) of each remotely monitored point shall not exceed theJ cllowable value for that point.

Level 2 Operating Transients: The measured amplitude (peak to

peak) of each remotely monitored point shall not exceed the j expected value for that point.

The maximum measured loads, displacements, and/or

volocities are less than or equal to the acceptance limits speci fied. - .

In the judgment of the qualified test engineers, no signs

{ cf excessive piping response (such as damaged insulationt

, markings on piping, structural or hanger steel, or wallar 4

dtmaged pipe supportst etc. ) are found during a post-

, transient walkdown and visual inspection of the piping tested and associated branch liness i

0 4-89 I

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I RESULTS 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 peig cnd the HPCI pump discharging at rated head and flow. Pump suction was from, and discharge was to, the condensate chorage tank. The HPCI turbine stop valve was tripped remotely.

No piping dynamic vibratory response problems were encountered during the test.

Tcat 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 d0emed 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 espects 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 Dog F in the blowdown mode and shall not exceed 120 Dog. F in the normal mode.

The pump available NPSR 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 cxchangers shall be less than 6% above the flow corresponding to the heat exchanger capacity (as determined from the process diagr'an) 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 shaf t vibration as measured on the coupling end.

RESULTS STP-70.1, Blowdown Mode Performance Verification i

The IOfcU System was tested during Test Co'ndition Heatup at rated temperature and pressure in the Blowdown Mode with

! Cne IOfCU pump running, and one IDfCU NRHX group in service.

'!he RNCU Syste.m was aligned to divert all flow to the main a

condenser and the system flow was then increased until 148 j gym was obtained. The steady state RNCU NRHX outlet temperature was less than 130 Deg. F and the steady state NRNX RECW outlet temperature was less than 180 Dog. F When the system flow reached 148 gym. It was then discovered that the RECW throttle valve was 6-1/2 turns open instead

! cf the required 3-1/2 turns. The valve was adjusted to 3-1/3 turns open and the data was retaken. The other NRHX 4-91

i was placed into service and testing repeated with similar result s. All applicable acceptance criteria was satisfied.

STP-70.2, Hot Shutdown Mode Performance Verification J

1Run RNCU System was tested during Test Condition Heatup at l rated temperature and pressure in the Hot Shutdown Mode i with two RWCU pumps running and two F/D's in service. A l

^

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 RNCU System flow of 354 gpm. The j cpplicable Level 2 Acceptance Criterion was satisfied since i the available NPSH for the RWCU pump with the lowest 1 suction pressure (RWCU pump A) was greater than 13 feet.

j-4 STP-70.3, Normal Mode Performance Verification 1

The RNCU System was tested in the Normal Mode with two RWCU pumps running, two filter /demineralizers (F/D's) in

! Ce rvice, 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 RNCU 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.

I The other NRHX group was placed in service and testing repeated with similar results. Vibration measurements were

. then taken on each RNCU pump - pump bearing housing I vibration f a the horizontal, vertical, and axial directions

, and shaf t viurati;n on the coupling end.

All applicable acceptance criteria were satisfied.

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.i 4.36 STP-71, RESIDUAL HEAT REMOVAL SYSTEM l OBJECTIVES i

The objectives of this test are to demonstrate the ability Cf the Residual Heat Removal-(RER) 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 .

RER System to remove heat from the suppression pool.

Level 1 The RRR System shall be capable of operating in the Suppression Pool Cooling Mode at the heat exchanger i capacity specified.

The RER System shall be ekpable of operating in the Shutdown Cooling Mode at the heat exchanger capacity j speci fled.

1 i Level 2 None

) RESULTS

! STP-71.1, Suppression Pool Cooling Mode i . .

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 RER Service Water System streams every five minutes during a

] twenty minute duration test. Heat exchanger capacities for RER loops A and B successfully met the Level 1 acceptance i criteria.

i As shown in the table below, the average heat removal rate

} cnd the average logarithmic mean temperature dif forence 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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i Average RHR Heat Exchanger Performance Parameters A Heat B Heat Process Exchanger Exchanger Diagram RHR System Heat Removal Rate (MBtu/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 IMrD (actual)

IMfS (design) 1.34 1.51 1.0 9

9 8

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PHILADELPHIA ELECTRIC COMPANY 2301 MARKET STREET P.O. BOX 8699 PHILADELPHIA PA.191o1 (215)841-4000 September 23, 1985 Docket No. 50-352 Dr. Thomas E. Murley, Administrator

. Region I U. S. Nuclear Regulatory Commission 631 Park Avenue King of Prussia, PA 19406

SUBJECT:

Report of Initial Plant Startup - December, 1984 Limerick Generating Station, Unit No. 1

Dear Dr. Murley:

Enclosed are two copies of the Initial Plant Startup Report for Limerick Generating Station Unit No. 1 - December, 1984.

{

This report is being submitted in compliance with the Technical Specifications 6.9.1.1, 6.9.1.2, and 6.9.1.3 for Operating License NPF-39.

Very truly yours, I, '

k Engineer-In-Charge Licensing Section Nuclear Generation Division cc: E. M. Kelly, Senior Site Inspector Director, Office of Inspection & Enforcement, NRC ,

• 4e, ,

_..