RBG-24132, Startup Test Rept,River Bend Unit 1
| ML20205D957 | |
| Person / Time | |
|---|---|
| Site: | River Bend  |
| Issue date: | 07/31/1986 |
| From: | Dagan W, Hicks D, Hieb M GULF STATES UTILITIES CO. |
| To: | Martin R NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| References | |
| RBG-24132, NUDOCS 8608180217 | |
| Download: ML20205D957 (275) | |
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GULF STATES UTILITIES COMPANY
- . RIVER BEND STATION UNIT 1 STARTUP TEST REPORT 1
1 i i l 4 1 b Contributors: i I' ' W. Dagan !- D. Hicks
. M. Hieb l- S. Perris i G. Pratt K. Tageson l V. Tilghman
, C. Townsend l l R. Trowbridge ' L. Zipper i ! l L i i f l July 1986 l O ' 8608180217 860731 PDR ADOCK 05000458 P PDR [ ,g w -w___,m,. - - -,. ,._ r- . __., _ ._______m___
f~b G TABLE OF CONTENTS PAGE
1.0 INTRODUCTION
1.1 Purpose 1-1 1.2 Plant Description 1-1 1.3 Startup Test Program Description 1-1 2.0
SUMMARY
OF INITIAL STARTUP TEST PHASE 2.1 Chronology of Startup Testing 2-1 2.2 Histogram of Power Ascension 2-1 2.3 Simplification / Elimination of 2-2 Startup Tests 2.4 Sequence of Testing 2-3 3.0
SUMMARY
OF TEST RESULTS O k/ 3.1 1-ST-1 Chemical and Radiochemical 3-2 3.2 1-ST-2 Radiation Measurements 3-11 3.3 1-ST-3 Fuel Loading 3-13 3.4 1-ST-4 Shutdown Margin 3-15 3.5 1-ST-5 Control Rod Drive System 3-17 3.6 1-ST-6 SRM Performance 3-24 3.7 1-ST-10 IRM Performance 3-26 3.8 1-ST-11 LPRM Calibration 3-28 3.9 1-ST-12 APRM Calibration 3-31 j 3.10 1-ST-13 Process Ccmputer 3-36 l 3.11 1-ST-14 RCIC System 3-44 3.12 1-ST-16A Vessel Temperatures 3-55 3.13 1-ST-16B Water Level Reference Leg 3-57 l Temperature 3.14 1-ST-17 System Expansion 3-61 l 3.15 OMITTED 3.16 1-ST-19 Core Performance 3-69 3.17 1-ST-20 Steam Production 3-72 3.18 OMITTED 3.19 1-ST-22 Pressure Regulator 3-76 3.20 1-ST-23A Water Level Setpoint, 3-90 Manual Feedwater Flow Change [) s_, t
TABLE OF CONTENTS (Cont'd) PAGE 3.21 1-ST-23B Loss of Feedwater Heating 3-102 3.22 1-ST-23C Feedwater Pump Trip 3-105 3.23 1-ST-23D Maximum Feedwater Runout 3-107 Capability 3.24 1-ST-24 Turbine Valve Surveillance 3-111 3.25 1-ST-25A Main Steam Line Valve Tests 3-115 3.26 1-ST-25B MSIV Full Closure 3-118 3.27 1-ST-25C/D Main Steam Line Flow 3-130 Instrument 3.28 1-ST-26 Safety Relief Valves 3-132 3.29 1-ST-27 Turbine Trip and Generator 3-134 Load Rejection 3.30 1-ST-28 Shutdown From Outside the 3-146 Control Room 3.31 1-ST-29 Recirculation Flow Control 3-149 System 3.32 1-ST-30B Recirc Two Pump Trip 3-165
; 3.33 1-ST-30C Recirculation System 3-167
' Performance 3.34 1-ST-30E Recirculation System 3-171 Cavitation 3.35 1-ST-31 Loss of Offsite Power 3-174 3.36 1-ST-33 Drywell Piping Vibration 3-178 3.37 1-ST-35 Recirculation System Flow 3-186 Calibration 3.38 1-ST-70 Reactor Water Cleanup System 3-192 3.39 1-ST-71 Residual Heat Removal System 3-196 3.40 1-ST-74 Off-Gas System 3-199 3.41 1-ST-94 Loose Parts Monitoring System 3-207 i 3.42 1-ST-95 Emergency Response Information 3-210
- 3.43 1-ST-100 Piping Vibration 3-216 3.44 1-ST-101 BOP Piping Thermal Expancion 3-225 3.45 1-ST-103 Drywell Cooling 3-239
. 3.46 1-ST-104 ESF Area Cooling 3-242 3.47 1-ST-105 Penetration Temperatures Test 3-244 t 4
O s_/
1.0 INTRODUCTION
1.1 Purpose The purposekof this report is to provide a concise summary of t &. initial startup test program conducted on the River .%:nd Nuclear Power Station. This report is intended to satisfy the reporting requirements of the River Bend Technical Specification Sections 6.9.1.2 and 6.9.1.3 concerning the startup report. Included in this report are sections which cover general plant and startup test program descriptions and specific test results with comparison to expected results. 1.2 Plant Description The River Bend Nuclear Power Station, owned by Gulf States Utilities (GSU) and the Cajun Electric Power Cooperative (CEPCO) is located approximately 2 miles east of the Mississippi River and approximately 18 miles north-northwest of Baton Rouge, Louisitna. The River Bend Nuclear Power Station is a direct-cycle boiling water reactor (BWR). The Nuclear Steam Supply System and the Turbine / Generator was furnished by General 7~ Electric Company. V The balance of the unit was designed and constructed by Stone & Webster Engineering Corporation. The rated core thermal power is 2894 Mwt and the net electrical output is approximately 936 MWe. Other principal plant parameters are presented in Table 1-1. 1.3 Startup Test Program Description 1.3.1 Overview of Program The River Bend Station startup and test program was es*ablished to administratively and technically control all testing activities commencing with construction completion and ending with rated power warranty run for the River Bend Station. This test program applies to all structures, systems, and components required to conduct normal commercial operation and is in compliance with the basic intent of Regulatory Guide 1.68 (August 1978), Initial Test Program for Water Cooled Nuclear Power Plants. To facilitate a systematic approach in conducting the startup and test program, the program has been divided into three major phases; preliminary test, (]) preoperational test, and initial startup test. 1-1
1.3.1.1 Preliminary Test Phase lh The preliminary test phase begins as installation and/or construction of the individual structures, systems, and components nears completion. The prime objective of this phase is to verify that construction activities associated with the respective structure, system, or , components have been completed and documented. This phase is not covered in this report. 1.3.1.2 Preoperational Test Phase The preoperational test phase normally commences after preliminary testing on individual components and systems or subsystems is completed. This phase includes the tests required to demonstrate that structures, systems, and components, perform satisfactorily in all modes of operation and that they are ready to support fuel loading and initial startup phase testing. This phase is also not covered in this report. 1.3.1.3 Initial Startup Test Phase The initial startup test phase of the test program commences with the preparation for fuel load and extends through 100 percent rated power and demonstrations. Testing performed during this phase of warranty lll the program ensures that fuel loading is accomplished in a safe manner, confirms the plant design basis, demonstrates that the plant can withstand anticipated transients and postulated accidents, and ensures that the plant can be safely brought to rated power. The initial startup phase of testing is divided into four areas: open vessel, initial heatup, power ascension, and rated power warranty run. The power ascension testing is further subdivided into six Test Conditions. These are shown on the power flow map in Figure 1-1 and defined in Table 1-2. 1.3.2 Criteria For Testing To assist in the evaluation of proper plant performance from the test results obtained, a set of criteria for each test has been developed. These criteria are a result of a combination of factors such as safety analysis assumptions, enginecting expectations and contractual commitments. Safety concerns are considered Level I while other considerations are Level 2 and Level
- 3. Definitions of these Level 1, Level 2 and Level 3 criteria and required actions in the event of a violation are defined as follows:
g 1-2
() 1.3.2.1 Level 1 Criteria If a Level l' test criterion is not satisfied, the plant is placed in a hold condition that is judged to be satisfactory and safe, based upon prior testing. Plant operating or test procedures or the Technical Specifications may guide the decision on the direction taken. Startup tests consistent with this hold condition may be continued. Resolution of the problem is immediately pursued by appropriate equipment adjustments or through engineering support by offsite personnel if needed. Following resolution, the applicable test portion is repeated to verify that the Level 1 requirement is satisfied. 1.3.2.2 Level 2 Criteria If a Level 2 test criterion is not satisfied, plant operating or startup test plans are not necessarily altered. The limits stated in this category are usually associated with expectations of system transient performance, and whose characteristics can be improved by equipment adjustments. An investigation of the related adjustments, as well as the measurement and analysis methods, is initiated. O If all Level 2 requirements in a test are ultimately met, there is no need to document a temporary failure in the test report unless there is an educational benefit involved. Following resolution, the applicable test portion is repeated to verify that the Level 2 requirement is satisfied. If a certain controller-related Level 2 criterion is not satisfied after a reasonable effort, then the control engineers may choose to document that result with an explanation of their recommendation. This report discusses alternatives of action, as well as the concluding recommendation so that it can be evaluated by all related parties. 1.3.2.3 Level 3 Criteria If Level 3 performance is not satisfied, plant operating or startup test plans would not necessarily be altered. The numerical limits stated in this category are associated with expectations of individual component or inner control loop transient performance. Level 3 performance is to be viewed as highly desirable rather than required to be satisfied. If all Level 1 and Level 2 criteria are satisfied, then it is not required to (]} repeat the test to satisfy Level 3 criteria. 1-3
1.3.3 Conduct of Testing dh 1.3.3.1 Facility Review Committee commencing with initial fuel load, the Facility Review Committee (FRC) assumed the responsibility for review and recommended approval of test results. During the initial startup test phase, the FRC was augmented by the Superintendent-Startup and Test and the General Electric Operations Manager. After each power plateau (Test Condition), the FRC reviewed the test results prior to going to the next Test Condition. Based upon this review and recommendation, approval to proceed to the next Test condition was given by the Plant Manager. 1.3.3.2 Test Procedures Startup test procedure preparation, procedure and results approval, procedural changes, conduct and test exceptions were governed by the River Bend Station Startup Manual. Inputs to specific startup test procedures included the General Electric Startup Test Specification, other vendor design specifications and the River Bend Final Safety Analysis Report. 1.3.3.3 Test Exceptions There were numerous Test Exceptions (TEs) generated during the initial startup test phase. Test Exceptions are deficiencies encountered during the conduct of a test. These may be unexpected data, missing data or data outside the acceptance criteria. Procedural difficulties, and repetition or postponement of testing would also be a test exception. Test exceptions require separate review and approval by the FRC and associated engineering evaluations if necessary. 1.3.3.4 Test Data Data used in the evaluation of the individual startup tests were obtained primarily from plant instrumentation (recorders, meters), plant process computer, and the Emergency Response Information System (ERIS). All of these were used to obtain steady state data. The process computer was utilized primarily for evaluation of thermal power and thermal limits whereas the ERIS computer was employed mainly for system performance demonstrations and plant response to transients. O 1-4
( 1.3.3.4 Test Data (Cont'd) Over one thousand analog and digital plant input signals (both permanent and temporary) are fed into the ERIS computers. The system is divided into two parts - Transient Recording and Analysis (TRA) and Real Time Analysis and Display (RTAD or the safety parameter display system). Although the RTAD portion underwent extensive testing during the initial startup test phase, the TRA portion was predominantly used for acquiring startup best data. TRA has the capability to scan plant parameters up to 250 samples per second. It was also used to perform data reduction such as plotting plant parameters as a function of time, statistical analysis, and scram time analysis. i t O 1-5
l l TABLE l-1 h l RIVER BEND NUCLEAR POWER STATION PRINCIPAL PLANT PARAMETERS PARAMETER VALUE NSSS Design BWR 6 Rated Core Thermal Power (MWt) 2894 Rated Core Flow (Mlb/hr) 84.5 Rated Reactor Dome Pressure (psia) 1040 Rated Steam Flow (Mlb/hr) 12.453 Rated Feedwater Flow (Mlb/hr) 12.428 Rated Feedwater Tempera *.:ure (deg. F) 420 Veusel Diameter (inches) 218 gg Number of Control Rods 145 Turbine Control Valve Mode Full arc Number of Turbine Control Valves 4 Turbine Bypass Valve Capacity (% NBR) 10 Number of Bypass Valves 2 Safety Relief Valve (SRV) Capacity (% NBR) 80 Number of SRVs 16 Recirculation Flow Control Mode: 2 speed Recirculation Pump Motor with Variable Flow Control Valve Control Feedwater Flow Control Mode: 3 Motor-driven pumps with 3 Variable Feedwater Regulation Valves with a common header between pumps & valves 1-6
4 l l l l l TABLE 1-2 TEST CONDITION (TC) REGION DEFINITIONS Test Condition (TC) , Power Flow Map Region and Notes 1 Before or after main generator synchronization from 5 to 20 percent thermal power and operating on recirculation pump low frequency power supply. 2 After main generator synchronization from 45 to 75 percent control rod lines, at or below the analytical lower limit of Master Flow Control mode. 3 From 45 to 75 percent control rod lines above 80 percent core flow, and within maximum allowed recirculation control valve position. O 4 On the natural circulation core flow line within +0 to -5 percent of the intersection with the 100 percent power rod line. 5 From the 100 percent loadline to 5 percent below the 100 percent loadline and between minimum flow at rated recirculation pump speed (minimum valve position) to 5 percent above the analytical lower limit of the automatic flow control range. 6 With 0 to -5 percent of rated 100 percent thermal power, and within 0 to -5 percent of rated 100 percent core flow rate. O 1-7
i O O O FIGURE l-1 POWER FLOW OPERATING MAP i 114 >
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- A A A A A A A A A A a e 18 20 20 48 50 00 79 80 SS 100 fle PERCENT CORE FLOW 1-8
2.0
SUMMARY
OF INITIAL STARTUP TEST PHASE 2.1 Chronology of Startup Testing ' Facility Operating License No. NPF-40 was granted for the River Bend Station on August 29, 1985. As of this date, the unit was restricted to five percent of rated power. Fuel load commenced on August 31, 1985 and was completed 22 days later. Initial criticality was achieved on October 31, 1985. On November 20, 1985 Facility Operating License No. NPF-47 was issued allowing the unit to operate to rated thermal power. River Bend Nuclear Power Station reached rated thermal power for the first time on May 11, 1986. On June 16, 1986 the unit was declared to be in Commercial Operation by Gulf States Utilities. A more detailed chronology of the initial startup test phase is presented in Table 2-1. In addition to the startup tests as described in FSAR Section 14.2.12.3 and recommended in Regulatory Guide 5O 1.68, Operating License NPF-47 imposed two additional requirements to be accomplished prior to completion of the initial test program. These involved station electrical distribution voltage testing and evaluations / modifications on battery powered lighting systems. These items have been acccmplished and found acceptable as documented in NRC Inspection Report 86-20. 2.2 Histogram of Power Ascension 2.2.1 Plant Scrams During power ascension testing through the completion of Test Condition 6 testing on June 9, 1986, there were 22 plant scrams. Five as these scrams were planned as a part of specific startup tests. These scrams are listed in Table 2-2. 2.2.2 Plant Outages From the end of the fuel load on September 22, 1985 through the completion of initial startup testing, the station was shutdown on several occasions. A brief description of the major outages follows. Figures 2-1 , are power histograms for the initial startup test phase. 2-1 I
2.2.2 Plant Outages (Cont'd) The break in startup testing from the end of fuel load until initial criticality was due exclusively to the baselining of Mode 2 ,( STARTUP) Surveillance Test Procedures. The first major outage began on December 7, 1985 and lasted for nine days. The outage was taken to complete the baseline data for the Mode 1 (RUN) Surveillance Test Procedures. This task was completed in seven days. However, startup was further delayed due to a problem on RWCU differential flow instrumentation. On January 5, 1986 during a startup after a scram, the limitorque operator came apart from the feedwater Mov 7B. All flow was diverted to the "A" FW line, restricting power to less than five percent. However, a scram on January 7, forced a shutdown to repair FW MOV 7B and perform inspections and retorquing of 24 similar valves. The plant was started up again on January 13, 1986. A commitment to verify the torque on the actuator bolts to 253 safety-related valves was the initial critical path item for a planned outage beginning on February 15, khh 1986. Retorquing verification was completed on February
- 22. However, three more items (repair of main steam valve B21-F098C, replacement of a radiation monitor, and repair of containment airlock seals) caused startup to be delayed until February 27.
The outage of longest duration commenced on March 20, 1986 and ended on April 13, 1986. The critical path items during this outage were modifications to the main condenser and ATWS trip logic on the recirculation pumps. Several main condenser tube leaks were experienced during previous operation due to warping of the tube sheets. Also during previous operation, several recirculation pump trips occurred on inadvertent ATWS signals. The logic was modified to minimize this from taking place. 2.3 Simplification / Elimination of Startup Tests Various changes were made to the initial test program described in the FSAR Section 14.2.12.3. Most of these changes came onder the heading of the Startup Test Simplification / Elimination program. Since this program was not in place prior to receipt of an operating license, the changes were made in accordance with the provisions of 10CFR50.59 persuant to Section 2.C(12) of lll NPF-47. 2-2 '
2.3 Simplification / Elimination of Startup Tests (Cont'd) Most of the test simplifications or eliminations were a result of the General Electric Company's evaluation from extensive amount of data and experience for startup testing conducted at other stations, particularly BWR 6 plants. Most of these changes are briefly described in Table 2-3. The changes listed in Table 2-3 are estimated to have saved 24 1/2 days of testing from the initial schedule. Both the General Electric Company and Gulf States Utilities found no unreviewed safety issues in the implementation of these changes. Furthermore, none of the simplifications or eliminations affected the testing set forth in Regulatory Guide 1.68, Revision 2. However, some of the testing which was eliminated was added back at the end of the test program. The basis for this was that the Nuclear Regulatory Commission had initial concerns with the elimination of these tests for a similar simplification program (Hope Creek). These tests were as follows: O l-ST-30B: Recirculation two pump trip in the Test Condition 3 window Test Condition 4: Natural Circulation testing consisting of 1-ST-19, 1-ST-22 and 1-ST-23A 1-ST-25B: MSIV full closure at 100% power. This test was performed earlier at 62% power and the results extrapolated to 100% power. 2.4 Sequence of Testing Table 2-4 contains a breakdown of the individual startup i tests conducted at each Test Condition. It is a result of the initial scope of the test program plus changes made per the Startup Test Simplification / Elimination program as well as other minor rearrangements of the testing. Further details are presented in the individual startup test summaries of Section 3. Testing listed in Table 2-4 and Section 3 which is not mentioned l in FSAR Sect 2on 14.2.12.3 came about from additional requirements in Regulatory Guide 1.68. [ t 2-3
TABLE 2-1 h CHRONdLOGY OF SIGNIFICANT EVENTS Fuel Loading Commenced 31-Aug-85 Fuel Loading Completed 22-Sep-85 Initial Criticality Achieved 31-Oct-85 Initial Heatup Commenced 31-Oct-85 Rated Pressure Achieved 18-Nov-85 Initial Generator Synchronization 3-Dec-85 Test Condition 1 Completed 31-Jan-86 Test Condition 2 Completed 7-Mar-86 Test Condition 3 Completed 30-Apr-86 ggg Test Condition 5 Completed 5-May-86 Rated Thermal Power Achieved 11-May-86 Warranty Run Completed 15-May-86 Test Condition 4 Commenced / 8-Jun-86 l Completed Test Condition 6 Completed 9-Jun-86 Commercial Operation 16-Jun-86 i l l h 2-4 I t
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l TABLE 2-2
- RIVER BEND STATION SCRANS DURINC POWER ASCENSION TESTING l
SCRAM NO. DATE DESCRIPTION 85-01 11-14-85 Seismic supports not installed on Standby Service Water piping. Tech Spec required shutdown. Manual scram taken for training. 85-02 11-21-85 Low Reactor Vessel Level 3. Feedwater pump tripped probably due to main oil pump trip on overload due l to low temperature. 85-03 11-28-85 IRM upscale trip due to cold FW injection after the tur-
- bine tripped on high vibration (2% power)
. 85-04 12-06-85 1-ST-31 Loss of Offsite Power (12% power) 85-05 12-24-85 Low Reactor Vessel Level 3. FW pump was manually tripped due to oil leak. Discharge valve on standby pump could not be opened. (1% power) I 85-06 12-31-85 High Reactor pressure resulting from generator load re-jection due to lightning on grid (20% power)
- 86-01 01-01-86 Low Reactor Vessel Level 3. Loss of condensate due to FW heater strings isolating and feedwater heater bypass valve failure to open (19% power)
- 86-02 01-07-86 IRM upscale trip due to pressure increase after fire pro-l tection diluge caused a breaker to trip closing the steam j bypass valves (3% power) i 2-5
O O O TABLE 2-2 (Cont'd) RIVER BEND STATION SCRAMS DURING POWER ASCENSION TESTING SCRAM NO. DATE DESCRIPTION 86-03 01-15-86 High reactor water level scram from 17% reactor power while placing "B" Feedwater Regulating Valve (FWRV) in service. High level was caused by erroneous "B" FWRV position indicating closed when the valve was 70% open 86-04 01-31-86 Manual training scram was taken after the purge ex-haust valves failed the leak rate test requiring a plant shutdown per Tech Spec. 3.6.1.9 86-05 02-12-86 Turbine trip caused by high water level in the moisture separator drain tank (34% power) 86-06 02-15-86 1-ST-28 Shutdown From Outside the Control Room (12% power) 86-07 03-01-86 Low reactor water level scram occurred when a transformer disconnect switch failed and power was lost to the FW main lube oil pump causing "B" FW pump to trip. Both standby feed pumps were out of service for maintenance (39% power) 86-08 03-12-85 Spurious pressure transient from valving in jet pump flow transmitters caused high water level half scram (Division II). Half scram was in Division I from on-going Surveillance Test Procedure (42% power) 86-09 03-20-86 1-ST-25B MSIV Full Closure (62% power) 86-10 04-23-86 High reactor water level scram occurred. In single element control, level control failed to shift from manual to auto, resulting in a level transient. The transient could not be controlled within the operating range by manual control. 2-6
O O O TABLE 2-2 (Cont'd) RIVER BEND STATION SCRANS DURING POWER ASCENSION TESTING SCRAM NO. DATE DESCRIPTION 86-11 04-26-86 APRM high flux scram signal spuriously occurred due to a blown fuse in the RPS panel. Another half scram signal was present from an on-going surveillance test. 86-12 05-01-86 APRM thermal upscale trip occurred due to drive flow downscale. A half scram was inserted to allow the "B" reactor recirculation flow transmitter to be dampened. Upon valving out the "B" transmitter, the "A" transmitter (which shares the same sensing line) went downscale. 86-13 05-05-86 High reactor pressure due to turbine trip resulting from stator water cooling system high temperature setpoint being adjusted too low. No actual stator water high temperature occurred (71% power) 86-14 05-19-86 Turbine trip occurred due to indication of 93 bearing high vibration. The indication was due to water accumulation causing a grounding in the vibration sensor. The water accumulation was caused by an inadvertant actuation of the Main Turbine bearing fire deluge system (73% power) 86-15 05-29-86 1-ST-27 Generator Load Rejection (96% power) 86-16 06-08-86 1-ST-25B MSIV Full Closure (99.5% power) 2-7
O O O TABLE 2-3 RIVER BEND STARTUP TEST SIMPLIFICATION / ELIMINATION l TEST NO. DESCRIPTION I l i 5 1. Reduce Rated Pressure Control Rod Drive friction testing from 50% to less than or equal to four. All~ rods undergo friction testing at zero pressure. Only a minimum number of rods (4) need to undergo a retest at rated pressure to check i on the effects of thermal expansion in the core. This is due to the data base of other BWR 6 plants showing no problems in this area. Also, all rods will be scram-timed at rated pressure.
- 2. Scram Timing at Rated Pressure: Rather than being required to conduct this upon reaching rated pressure initially, it could be postponed as long as all
! rods are scram-timed prior to 40% power as required by Technical Specifications.
; 3. Postpone or eliminate gang rod testing: The gang rod feature was removed by a design modification. Therefore, no gang rod testing was necessary.
l 13 Deleted OD-ll testing since River Bend has barrier fuel which does not fall under the PCIOMR guidelines. Portions of OD-ll were later added back into 1-ST-13 and tested. 18 Deleted TIP Uncertainty. TIP hardware was tested during the preoperational phase. Software testing was done in conjunction with 1-ST-13. Actual measurement of TIP uncertainty is not necessary based on the abundance of data from previous startup testing. 21 Deleted Core Power / Void Mode Response Testing: Measurement of local flux oscillations during control rod movement and pressure changes was deleted. This is due to General Electric's extensive testing and analysis of core thermal hydraulic stability. Overall flux changes to control rod movement and pressure changes are observed during power ascension. 2-8
O O O TABLE 2-3 (Cont'd) RIVER BEND STARTUP T%T SIMPLIFICATION / ELIMINATION TEST NO. DESCRIPTION 22 Simplified the pressure regulator testing by eliminating testing in the auto-matic load following mode (See Test No. 29) and some of the pressure regulator failover tests. 23A Scme of the Level 2 response time criteria was slightly expanded based upon previous startup testing. 25A The requirement to do MSIV Stroke testing at every Test Condition was changed to do it only at Test Condition Heatup and Test Condition 2 per Regulatory Guide 1.68. The frequency of MSIV stroke time testing is further dictated by Technical Specifications. 26 Initial requirement to cycle the SRV's twice (at 250 psig and 50% power) was changed to once at 950 psig. Low pressure testing is no longer advised due to the possibility of seat damage. SRV actuations at power can be observed during planned transients. 27 Deleted the Turbine Trip test at Test Condition 3 (75%) : This is not a Regulatory Guide 1.68 test. General Electric had originally required this to obtain more data for transient predictions. However, based of qualification of predictions from numerous previous testing, this test is no longer necessary. Also, the load rejection test at 100% will provide additional checks on the predictions. 29 Simplified the recirculation flow control testing. Deleted the automatic load following feature (removed from system per modification). Also, deleted the requirement to do any step changes less than 5% and relaxed some time response criteria. This is based on previous startup testing. 2-9
O O O TABLE 2-3 (Cont'd) RIVER BEND STARTUP TEST SIMPLIFICATIOM/ ELIMINATION TEST
- NO. DESCRIPTION 30A Deleted recirculation one pump trip testing. This is not needed from a safety standpoint.
30B Deleted recirculation two pumps trip test. This is also not needed from a safety standpoint. Furthermore, River Bend is not permitted to operate in the natural circulation mode. This test, however, was added back at the 1 end of the test program. l l 30D Deleted the recirculation runback test as a separate test. During the
; feedwater pump trip test 1-ST-23C a recirculation flow control valve run-
! back was planned. i 71 Deleted RHR steam condensing mode testing. Operation in the mode is pro-hibited by license. Test Deleted Natural Circulation testing (Test Condition 4). Operation in this Condition mode is not intended. Also, intensive testing in natural circulation at j 4 other BWR's have proved that stability exists in this region. This affected l tests 1-ST-19, 1-ST-22, and 1-ST-23A. This testing, however, was added back ] at the end of the test program. I I l 1 i l 2-10
TABLE 2-4 TESTING SEQUENCE l PROCEDURE l 10 PEN I TEST CONDITION l NUMBER f TITLE fVESSEL HEATUPI TC! l TC2 f TC3 I TC4 l TCS I TC6 l l l CHEMICAL & RADIO lW 3 l 1-ST-1 l CHEMICAL 'h h 1-ST-2 RADIATION MEASUREMENTS h l 1 ST-3 FUEL LOADING l l (FUEL CORE l 1 ST-4 l 3 l lSHUTDOVN MARGIN l. W I l CONTROL ROD l g g g 3 l 1 ST-S W l l DRIVE SYSTEM L T T W 1-ST-6 SRM PERFORMANCE 1 ST-10 IRM PERFORMANCE 1 ST-11 [LPRM CALIBRATION l l 1-ST-12 APRM CALIBRATION 1-ST-13 PROCESS COMPLTER l l 1 57-14 RCIC l IVESSEL l g i l 1 ST-16A lTEMPERAR*RE l w l l WATER LEVEL REFERENCE l g g i 1 ST-168 l LEG TEMPERAR1tE l T T 1 ST 17 SYSTEM EXPANSION . _1 ST 19 CORE PERFORMANCE j l ! ST-20 STIAM PRODUCTION l_1 ST 22 l PRESSURE REGULATOR l_ l IWATER LEVEL SETPOIhT, I l l MANUAL FDVTR FLOW 1.1 ST 23A l CHANGES l f g h $ $ h g I ! LOSS OF TEEDWATER l 1 57 239 QEATING l g 3 l_ W _W_
!1-ST-23C lFEEDVATERPUMPTRIP i l MAXIMUM FEEDWATER i_1 ST 230 lRlNOLT CAPABILITY l
l g T l lR'RBINE i 1572. IVALvt StRVEILLANCE l g l w I 1 ST 25A lMSIV FUNCTIONAL TESTS l1ST2sB lFUtoSouT:0N i IMAIN STEAMLINE FLOW l 0 g e l 1 1 ST 25C/Dl!NSTR'.HENT CALIBRATION l T . _ W 1-57 26 RELIEF VALVES l 2-11
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s Figure 2-1 POWER HISTOGRAM
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() 3.0
SUMMARY
OF TEST RESULTS The individual startup tests which were performed during the initia2 startup test phs c are described in this section. Each test is presented in a separate subsection. The subsections are further broken down into a Description and a Discussion. The Description consists of the pur-pose of the test and the acceptance criteria associated with the test. The Discussion briefly describes the results in comparison with the acceptance criteria and gives a listing of all of the test exceptions which were written while conducting the test. l As mentioned in Section 1.3.3.3, test exceptions do not necessarily constitute a failure to satisfy acceptance criteria. Most of the status of the test exceptions are given as of July 15, 1986. As of this date, there are a number of test exceptions which are not resolved (open). Some of these do involve a failure to satisfy acceptance criteria. However, none of the open test exceptions pertain to Level 1 Criteria failures which is a safety concern. () Resolution of the open test exceptions is ongoing. A supplement to Section 3 of this report is planned to cover these resolutions. O 31
O V CHliDEICAL & RADIOCHEMICAL l-ST-1 3.1 1-ST-1 CHEMICAL AND RADIOCHEMICAL 3.1.1 Description The principal objectives of this test are as follows: 0 To secure information on the chemistry and radiochemistry of the reactor system. O 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. O To use the data obtained to evaluate fuel s' performance, demineralizer operation, filter performance, condenser integrity, steam separator dryer operation and operation of the off-gas system. The acceptance criteria applied to this test are shown in Subsections 3.1.1.1 and 3.1.1.2. 3.1.1.1 Level 1 Criteria
- 1. Chemical factors defined in the Technical Specifications and Fuel Warranty must be maintained within the applicable limits specified.
- 2. The activity of gaseous and liquid effluents must conform to all license limitations.
- 3. Reactor Coolant water quality is within the limits specified by Technical Specifications and the Water Quality Specifications.
3.1.1.2 Level 2 Criteria
- 1. The off-gas prefilter and after-filter assemblies shall comply with the off gas design specification.
(]) 2. The ratio of off-gas Pre-treatment Post-treatment radiation shall be at least 100 to to 1. 3-2
CHEMICAL AND RADIOCHEMICAL 1-ST-1 3.1.2 Discussion Water Chemistry data was taken during Test Conditions open vessel, Heatup, 1,3 and 6. Table 3.1-1 summarizes the significant parameters associated with Reactor Water Chemistry and Radiochemistry. The major deficiency was in the final feedwater metals and oxygen concentrations. These discrepancies were addressed by Test Exceptions
- 9,10 & 17 and have been evaluated and acccepted by General Electric Chemistry.
The Gaseous Chemistry subtest was used to gather chemistry data in order '- determine / calculate the off-gas activity patter., off-gas pre /after filter efficiencies, and off-gas charcoal bed residence times and activity ratio. Table 3.1-2 gives the Test Condition 6 data for 100% power. During TC-6 testing, the off-gas pre-filters failed the level 2 filter efficiency criteria (TE-13), and there was insufficient 3 W off-gas activity to establish Pre and Post treatment monitor response versus release rate tends. TE's 13 and
- 16 are open pending retest at a higher off gas activity
- level.
Condensate Demineralizer performance data was accumulated and the trend in results plotted during the power ascension test program. The results show that the total available resin bed capacity was maintained above the recommended 50%. During Test Condition 6, the Reactor Water No-Cleanup test was performed in order to determine the RWCU i operating characteristics and moisture carryover in the l steam. Table 3.1-3 summarizes the pertinent test
-results. The test was initiated by isolating the RWCU system and then injecting sodium hydroxide upstream of the feedwater pumps. The reactor water conductivity was allowed to exceed 1ps/cm at which time the RWCU system was placed back into service. Conductivity exceeded 1p /cm for a total of three hours. Test Exception 14 l was written against this test because there was no detectable Na-24 carryover to the hot well. The test was repeated with larger sample volumes taken, and the results were acceptable. A summary of the test exceptions follows along with the status as of 15-Jul-86.
3 -3
CHEMICAL AND RADIOCHEMICAL 1-ST-1 TE TEST DESCRIPTION STATUS CONDITION 1 OV CRD water conductivity and oxygen Closed exceeded acceptance criteria. The criteria were deleted from the test, since they did not apply at Test Condition OV. 2 1 Data required for water chemistry Closed suction was not taken. The test data was retaken. 3 1 Final Feedwater conductivity exceeded Closed criteria. The test data was retaken () successfully after source of contaimina-tion was corrected. 4 1 CRD water conductivity and oxygen ex- Closed ceeded acceptance criteria. CRD supply was from condensate storage tank. The test data was retaken successfully after the lineup was corrected. 5 1 Off-Gas pre-filter readings were in- Closed consistent. Activity levels were too low to evaluate the data, Accepted "as-is". 6 1 Off-gas activity pattern was not closed was not performed. Charcoal bed INFLUENT / EFFLUENT gas activities were not taken. The test data was retaken successfully. 3- 4
CHEMICAL AND RADIOCHEMICAL 1-ST-1 TE TC DESCRIPTION STATUS 7 1 Suppression Pool conductivity and Closed and chloride exceeded acceptance criteria. The suppression pool water was filtered and the values returned to acceptable levels. The data was evaluated by GE chemistry and was acceptable. 8 3 Charcoal adsorber bed pre and post Closed treatment activity ratio failed l criteria . The TE was accepted l "as is" since the activities are at i or near the low detection limit of the a W instrument. The test was repeated during TC-6. ! 9 3 Suppression pool chlorides, feedwater closed copper and oxygen, and reactor water silica failed acceptance criteria. The data was evaluated by GE chemistry and was acceptable. 10 6 Final Feedwater total metals and Closed copper exceeded criteria. The data l was evaluated by GE chemistry and wi.s l acceptable. 11 6 Unable to determine reactor water Closed Beta Gamma activity. Accepted "as is" since no criteria are associated with the data. 12 6 Require 30 day decay for isotopic Closed analysis. Data was taken after 30 day decay period. l 3-5 l_----____.____--
O c==#1 cit a o =^o10C=== cat 1-ST-1 { l TE TC DESCRIPTION STATUS l 13 6 HEPA pre-filter efficiency failed Open i acceptance criteria. A retest will be ' done when radionuclides levels are higher 14 6 Results of RWCU "no clean-up" test Closed did not agree with experience. No NL-24 was detected in Hot Well. A retest was completed successfully with appropriate results. 15 6 Condensate Resin capacity tracking Closed not completed. Data was obtained and (]) the trend was completed. 16 6 Insufficient data to determine off- Open gas Pre and Post treatment monitor response versus release rate. Re-peat when off gas activities are sufficient to establish trending. 17 6 Final feedwater oxygen below Closed acceptance criteria. Forwarded to General Electric Chemistry for evaluation, acceptable as is. O 36
O O O CHEMICAL AND RADIOCHEMICAL 1-ST-1 TABLE 3.1-1 WATER CHEMISTRY PARAMETER OPEN REACTOR WATER LIMIT VESSEL HEATUP TC-1 TC-3 TC-6 Conductivity , (1)
- 0.65 0.2 0.15 0.52 0.3
(//s/cm @ 25#C) pH (s.u. @ JS C) (1)
- 5.74 6.7 6.7 6.8 6.7 Chloride (,79/L) (1)
- 114 88 60 t 20 <_2 0 Turbidity (NTU) (2)
- 1.8 0.58 3.0 0.36 0.2 Iodine 131 (/f'c i/g) 40.2 N/A N/A 2.78 6.25 6.08 E-5 E-5 E-5 I CONDENSATE .
Conductivity # 410.0 N/A 0.077 0.11 0.09 0.09 (p /cm @ 25 C) Chloride Wg/L) (2)* N/A 28 19.8 4 20 420 Insoluable Iron #g/L) (2)
- N/A 46.5 4LLD z 5 25 CONDENSATE DEMINERALIZER EFFLUENT Conductivity # 40.1 N/A 0.060 0.60 0.06 0.06
#s/cm @ 25 C) l Oxygen #g/L) (2)
- N/A 20 10 15 20 i Insoluable Iron gg/L) (2)
- N/A 85.5 4LLD 4.8 45 FINAL FEEDWATER Conductivity #
40.1 N/A 0.063 1.5 0.06 0.06 (/[s/cm @ 25 C) 'I4 ) * (TE-3) Oxygen (gg/L) 20-200 N/A 20 20 10 10 (TE-9) (TE-17) i Total Metals (fg/L) (5j 6)
- N/A 112.9 82.1 22.8 36 a.
(TE-10) Copper (/f'g/ L) (Sj 6)
- N/A 44 4LLD 3.0 7 (TE-9) (TE-10) 37
1 l l CHEMICAL AND RADIOCHEMICAL
~
! 1-ST-1 ! TABLE 3.1-1 (Cont'd) {
- The following limits are referred to by number in Table 3.1-1:
- 1. The following limits are applicable for the following OPERATING CONDITIONS, as defined in the River Bend Station Unit 1 Technical Specifications.
OPERATING CONDUCTIVITY CONDITION (uS/cm) CHLORIDE (ppb) pH (S.U.) 1-Power Operation <p.0 $200 or 5.6 - 8.6 2,3-Startup, Hot Shutdown
<2.0 <100 (p/L) 5.6 - 8.6
() 4,5-Cold Shutdown, Refuel
<10.0 <500 5.3 - 8.6 l
- 2. This data is collected for trend analysis and as future reference is data only, and has no limits associated with it.
- 3. This limit is applicable only during steady state reactor operation at greater than or equal to 1% rated thermal power with a main condenser vacuum established.
- 4. This limit is applicable only when a main condenser vacuum has been established.
- 5. During initial plant testing and startup, the normal limit of metallic impurities may be exceeded for the first 500 hours of effective full power operation.
During such periods, the daily average concentration of metallic impurities shall not exceed 100 ppb at y;50 percent power a..d 50 ppb at;>50 percent power. Short duration spikes exceeding 100 ppb may occur during startup or when operational changes are made. If the spike concentration does not decrease to less than 100 ppb within 30 minutes, corrective action shall be taken to reduce the concentration to less than 100 ppb.
)
- 6. Total Feedwater metals content shall not exceed 15 ppb, with not more than 2 ppb as copper.
3- 8
l CHEMICAL AND RADIOCHEMICAL 1-ST-1 TABLE 3.1-2 GASEOUS CHEMISTRY TC-6 TOTAL OFF-GAS ACTIVITY 239.27 ({7 gases, mci /sec) ACTIVITY PATTERN 92%/8% (Recoil /No-Recoil) OFF-GAS FLOW RATE (SCFM) 95 OFF-GAS FILTER EFFICIENCIES (%) l PRE A/B 90.3/98.82 (TE-13) AFTER A/B NA/NA CHARCOAL BED RESIDENCE TIME (MINIMUM) 1554 Min a PRE / POST TREATMENT RATIO 2920 W O 3- 9
CHEMICAL AND RADIOCHEMICAL
~
1-ST-1 TABLE 3.1-3 REACTOR WATER NO CLEANUP RESULTS RWCU Purification Constant 0.277 hour ~1 Conductivity Input Rate 0.0258 ys/cm/hr Equilibrium Conductivity 0.21ps/cm RW Background Conductivity 0.13 ps/cra Reactor Water Carryover 0.0022% O l l l l I l 1 3-10
n U RADIATION MEASUREMENTS 1-ST-2 3.2 1-ST-2 RADIATION MEASUREMENTS 3.2.1 Description The major objectives of this test are as follows: 0 Determine the background radiation levels in the plant environs prior to operation for use as base data on activity buildup. O Monitor radiation at selected power levels to assure the protection of personnel during plant operation. The acceptance criteria applied to this test are shown in Subsections 3.2.1.1 and 3.2.1.2. 3.2.1.1 Level 1 Criteria () 1. The radiation doses of plant origin and occupancy times of personnel in radiation zones the shall be controlled consistent with the guidelines of the standards for protection against radiation as outlined in 10CFR20, " Standards for Protection Against Radiation", or equivalent. 3.2.1.2 Level 2 Criteria None 3.2.2 Discussion During Condition Open Vessel, a survey of natural radiation throughout the protected area was made prior to and following fuel load. After performing the surveys prior to fuel load, two point descriptions were found not to match the survey point location in the plant or the location map in the procedure. Test Exception il documents this and has been resolved. During heatup, TC-1 (20% power), TC-3 (72% power), and TC-6 (98% power) , surveys were performed in general access areas and potentially high radiation areas: Drywell to Containment Penetrations, all accessible () floor areas within the containment building, and the Reactor Water Cleanup System backwash receiver tank resin transfer piping before, during, and after a resin 3-11
RADIATION MEASUREMENTS
~
1-ST-2 3.2.2 Discussion (Cont ' d) transfer. TE-02 was written during Test Condition 1 to document two DRMS sensors not functioning. There are no criterion associated with this test exception. TE-03 documents four survey points which could not be taken during Test Condition 3. This TE is acceptable "as is" based on other adjacent survey readings. There were no test exceptions in TC-6. During each of the above conditions, radiation surveys were conducted to verify posting requirements. All survey results were satisfactory, and radiation levels were less than the limit of the allowable radiation levels. All test criteria were met. For background information, radiation surveys were also taken during a RWCU resin transfer late in the test program. The following table smnmarizes the test exceptions 9 (TE's) associated with 1-ST-2. All TE's are closed. TE DESCRIPTION STATUS 1 Descriptions for survey points CB-ll5-2 Closed and FB-ll3-3 do not agree with the point locations on survey maps. 2 DRMS points lAA204 and 1AA218 are not in- Closed dicating and are not in consistent units with other points. There is no test criteria associated with this exception. Data retaken using hand held instruments. Both points have been fixed and are in consistent units with other points. 3 Four survey points were not taken due to Closed either identification plates missing or blocked. This was closed based on ad-jacent surveys. gg) 3-12
l FUEL LOADING l l-ST-3 3.3 1-ST-3 FUEL LJADING 3.3.1 Description
- The major objective of this test is to load fuel safely and efficiently to the full core size.
The acceptance criteria applied to this test are shown in Subsections 3.3.1.1 and 3.3.1.2. 3.3.1.1 Level 1 Criteria The partially loaded core must be subcritical by at least 0.38% K/K with the analytically determined strongest rod fully withdrawn. f-) 3.3.1.2 Level 2 Criteria V Not Applicable 3.3.2 Discussion On August 31, 1985, fuel loading commenced with the loading of four fuel assemblies around the central neutron source at location 26-31; then continued cell by cell sequentially so that increasing square blocks were built up in a clockwise direction. Upon completion of loading 144 bundles, a partial shutdown margin demonstration was performed by withdrawing the following Group 3, Sequence A, control rods: 16-37, 16-21, 24-29 and 32-29. After waiting for 5 minutes, subcriticality was verified and the core reactivity (keff) was calculated, after temperature compensation, to be 0.97283. Thus, by verifying that this measured keff exceeded the minimum required value of .97159 (strongest rod out plus 0.0038), it was determined that the Level 1 criteria for this test was met and that it was safe to continue fuel loading to the full core configuration. To ensure continued suberiticality during fuel loading, a plot of the relative inverse count rate (1/M) with all rods in as a function of the number of fuel bundles () loaded was maintained. As an additional check on subcriticaility for the next fuel cell to be loaded, the control rod was withdrawn in the just-loaded cell. 3-13
FUEL LOADING h 1-ST-3 Upon completion of fuel loading, on September 21, 1986 proper bundle location, orientation and seating was visually verified and recorded on video tape as a part of the plant historical record. The following exceptions were written to 1-ST-3 and closed out prior to test approval: TE DESCRIPTION STATUS l 1 Discrepancy in 1/M plots Closed 2 Failure to document Closed g response check. W 3 Use of incorrect C 0 Closed for calculation of 1/M plots, t l l l O 3-14
l SHUTDOWN MARGIN 1-sT-4 3.4 1-ST-4 SHUTDOWN MARGIN 3.4.1 Description The major objective of this test is to demonstrate that the reactor is subcritical throughout the first fuel cycle with any single control rod fully withdrawn. The acceptance criteria applied to this test are shown in Subsections 3.4.1.1 and 3.4.1.2. 3.4.1.1 Level 1 Criteria The Shutdown Margin of the fully loaded, cold (68 degrees F.) Xenon-free core occurring at the most reactive time during the cycle must be at least 0.38% [iK/K with the analytically strongest rod (or its reactivity equivalent) fully withdrawn. If the shutdown O- margin is measured at some time during the cycle other than the most reactive time, compliance with the above criteria is shown by demonstrating that the shutdown margin is
>0.38% fK/K plus an exposure-dependent increment "R"~which adjusts the shutdown margin at that time to the minimum shutdown margin.
3.4.1.2 Level 2 Criteria Criticality should occur within + 1.0% dK/K of the predicted critical. 3.4.2 Discussion The full core shutdown margin was calculated from data taken during the initial criticality on October 31, 1985. The reactor went critical on sequence step 27, Group 3, Gang 2, Rod 44-33, Notch 12 with a period of 151 seconds and a moderator temperature of 102 degrees F. After correcting for the actual vs. predicted rod worth, temperature and period, the shutdown margin was calculated to be 2.593% 8K/K. O 3_15
SHUTDOWN MARGIN @ 1-ST-4 1 3.4.2 Discussion (Cont ' d) , 1 This meets the Level 1 criteria which requires the shutdown margin to be 2y 0.38% K/K. The percentage difference between the actual and predicted rod worth ( /hK/K) was also calculated at criticality. This calculated difference value was -0.49790%dK/K which meets the Level 2 criteria requiring the difference to be within + 1.0% dK/K. No test exceptions were written against thIs test. O O 3 16
O- CONTROL ROD DRIVE SYSTEM 1-ST-5 3.5 1-ST-5 CONTROL ROD DRIVE SYSTEM 3.5.1 Description The major objectives of this test are as follows: 0 To demonstrate that the Control Rod Drive (CRD) system operates properly over the full range of primary coolant temperatures and pressures from ambient to operation. O To determine the initial operating characteristics of the entire CRD system. The acceptance criteria applied to this test are shown in Subsections 3.5.1.1 through 3.5.1.3. n 3.5.1.1 Level 1 Criteria
- 1. Each CRD must have a normal withdraw speed indica *ca by a full 12-foot stroke in greater than o" equal to 40 seconds.
- 2. For vessel pressures between 950 and 1050 psig the maximum scram times of individually fully withdrawn CRD's shall comply with the following table (Note:
Performance rated with charging headers at greater than or equal to 1520 psig.) : The scram insertion time of each control rod from the fully withdrawn position, based on de-energization of the scram pilot valve solenoids as time zero, shall not exceed the following criterion: Maximum Insertion Times From Opening Of Main Scram Contractor To Notch Reactor Pressure Position psig sec ** 43 29 13 () 950 1050 0.31 0.32 0.81 0.86 1.44 1.57 3-17
CONTROL ROD DRIVE SYSTEM l-ST-5 3.5.1.1 Level 1 Criteria (Cont'd)
- 3. If the maximum scram insertion time of one or more control rods exceeds criteria 3.5.1.1.2. then the following criteria are applicable:
NOTE A drive failing 3.5.1.1.3.a is con-sidered to be inoperative.
- a. The individual scram times of a drive exceeding the times of criterion 3.5.1.1.2.
shall not exceed the following table: Maximum Insertion Times From Opening Of Main Scram Contractor To Notch Reactor Pressure Position psig sec ** 43 29 13 950 0.38 1.09 2.09 1050 0.39 1.14 2.22
- b. The total number of drives failing criterion 3.5.1.1.2. but meeting criterion 3.5.1.1.3.a.
shall not exceed 5.
- c. The average scram times of the remaining (i.e., those that meet criterion 3.5.1.1.2) individual control rod drives shall be less than the following table:
Maximum Insertion Times From Opening Of Main Scram l Contractor To Notch ! Reactor Pressurc Position l psig sec ** 950 43 0.30 29 0.78 13 1.40 g 1050 0.31 0.84 1.53 3-18
i CONTROL ROD DRIVE SYSTEM l-ST-5 3.5.1.1 Level 1 Criteria (Cont'd)
- d. A drive failing criteria 3.5.1.1.2. but meeting the criteria under 3.5.1.1.3. shall not occupy an adjacent location in any direction, including the diagonal, with another slow or inoperative rod.
** For intermediate vessel dome pressure, the scram time criteria are determined by linear interpolation at each notch position.
3.5.1.2 Level 2 Criteria
- 1. Each CRD must have a normal insert or withdraw speed, indicated by a full 12-foot stroke in 40 to 60 seconds.
() 2. With tests, respect to the control rod drive friction if the differential pressure variation exceeds 15 psid for a continuous drive in, a settling test must be performed, in which case, the differential settling pressure should not be less than 30 psid nor should it vary more than 10 psid over a full stroke.
- 3. The CRD's total cooling water flow rate shall be between 40.6 and 49.3 gpm.
- 4. For vessel pressures below 950 psig the maximum scram time of individual fully withdrawn CRD's shall comply with the criteria provided in 1-ST-5.
This is the time from the opening of the main scram contractor to notch 11. 3.5.1.3 Level 3 Criteria
- 1. Upon receipt of a simulated (maximum controller error) or actual scram signal, the FCV must close to its minimum position within 10 to 30 seconds.
- 2. The CRD system flow should not change by more than
+ 3.0 gpm as reactor pressure varies from 0 to
() rated pressure, 3-19
I CONTROL ROD DRIVE SYSTEM l-ST-5 l 3.5.1.3 Level 3 Criteria (Cont'd)
- 3. The decay ratio of any controlled variable must be
< 0.25 for any flow set point changes or for system Histurbances caused by the CRD being stroked.
3.5.2 Discussion All 145 control rods were tested for normal insert and withdrawal times, coupling checks and position indication during Test Condition Open Vessel. The testing was performed after all four fuel bundles were placed around the control rod to be tested to insure that no binding between control rod and fuel bundle existed as would be evidenced by abnormal insert and withdrawal times. All 145 control rods were also friction tested during test condition open vessel. The testing was performed after all four fuel bundles were placed around the lll control rod to be tested to further insure that no binding between control rod and fuel bundle existed as would be evidenced by excessive differential pressure across the insert and withdraw sides of the Hydraulic Control Units (HCUs) . The testing was performed by installing a differential pressure (dP) cell across the insert and withdraw sides of the control rods HCU. The dP cell was powered by an external voltage source with the output being sent to the ERIS computer. All control rods satisfactorily passed the continuous insert friction testing criteria therefore no settling friction l tests were required to be performed. l l All 145 control rods were individually scram time tested during test condition open vessel. 140 of the 145 control rods had acceptable scram times of less than 1.0 seconds and greater than or equal to 0.71 seconds. O 3 20
r CONTROL ROD DRIVE SYSTEM l-ST-5 3.5.2 Discussion (Cont'd) Three test exceptions were generated for the remaining 5 control rods. TE-1 resulted from scram times not being obtained for rods 04-25 and 16-09 due to equipment failure. TE-2 resulted from rods 20-29 and 24-17 railing the Level 2 criteria by being 0.01 seconds too fast. TE-3 resulted from rods 28-05, 24-17 and 20-29 falling outside the Reg Guide 1.68 requirement that all rods must fall within two standard deviations of the average scram times of all rods. TE-1 was resolved when equipment problems were resolved. TE-2 was accepted with no retest required per General Electric engineering. TE-3 was resolved by scram timing each of the required rods 2 additional times as recommended by Reg Guide 1.68. During test condition heatup it was demonstrated that O CRD system flow could be maintained at 45 gpm +/-0 gpm within the limits of the Level 3 criteria of 45 +/-3 gpm utilizing flow control valve Cll-F002B. Flow control valve Cll-F002A was failed therefore it was not possible to obtain data for this valve. Due to Cll-F002A being failed it was also impossible to perform the flow controller, Cll-R600, tuneup verification using this valve. TE-4 resulted from Cll-F002A being failed and was resolved during a subsequent power ascension after the affected equipment was repaired. Retesting of TE-4 showed excessive limit cycles existed with Cll-F002A, however, and TE-7 was written to troubleshoot and repair the problem. TE-7 was resolved and retest was performed following repair of Cll-F002A. TE-6 resulted when data obtained for flow controller, Cll-R600, tuneup verification using flow control valve Cll-F002B was not complete. TE-6 was resolved by retesting and no problems were found. The following is a summary of Test Exceptions generated for 1-ST-5. O 3-21
CONTROL ROD DRIVE SYSTEM 1-ST-5 TE DESCRIPTION STATUS 1 CRD's 04-25 and 16-09 were not scrammed due to Closed RCIS problems 2 CRD's 20-29 and 24-17 had scram times 0.01 too Closed fast 3 CRD's 28-05, 24-17 and 20-29 were outside two Closed standard deviations of average scram time 4 CRD System flow and controller testing not Closed performed on loop due to failed FCV A 5 Rated pressure scram times not obtained during Closed due to reactor pressure less than 950 psig 6 Controller testing data missing on FCV B Closed 7 FCV A exhibited excessive limit cycling Closed 8 13 control rods fell outside two standard de- Closed viations of average scram times during rated pressure scram testing O 3-22
O O O - CONTROL ROD DRIVE SYSTEM 1-ST-5 TABLE 3.5-1 SCRAM TIME TO NOTCH POSITION TC-2 TC-3 TC-6 CONTROL (17% POWER,954 psig) (62% POWER,1006 psig) (96% POWER, 1013 psig)
- ROD
, 43 29 13 43 29 13 43 29 13 l
44-09 0.22 0.60 1.10 0.20 0.55 0.99 N/A N/A N/A 24-13 0.20 0.56 0.97 N/A N/A N/A 0.21 0.57 1.06 36-33 0.20 0.56 1.02 N/A N/A N/A N/A N/A N/A 28-49 0.21 0.56 1.00 0.20 0.55 0.99 N/A N/A N/A 24-17 N/A N/A N/A 0.21 0.56 1.01 0.21 0.58 1.06 36-53 N/A N/A N/A 0.21 0.53 1.04 0.21 0.58 1.06 l 2 44-49 N/A N/A N/A N/A N/A N/A 0.20 0.55 1.02 l 4 l 3- 23
SRM PERFORMANCE w 1-ST-6 3.6 1-ST-6 SRM PERFORMANCE 3.6.1 Description The major objectives of this test are as follows: 0 To demonstrate that the operational neutron sources and SRM instrumentation provide adequate information to achieve criticality. O To show IRM instrumentation to have sufficient overlap with SRM instrumentation. 1 The acceptance criteria applied to this test are shown in Subsections 3.6.1.1 and 3.6.1.2. 3.6.1.1 Level 1 Criteria
- 1. There must be a neutron signal count to noise count ratio of at least 2:1 on the required operable SRMs.
- 2. There must be a minimum count rate of 0.7 counts
() per second (cps) on the required operable SRMs.
- 3. Each IRM channel must be on scale before the SRMs exceed their rod block setpoint.
3.6.1.2 Level 2 Criteria
- 1. Each IRM channel must be adjusted so that a half decade overlap with the SRMs is assured.
3.6.2 Discussion Prior to the Initial Criticality being performed, the SRMs were tested for adequate signal to noise ratio (S/N Jt2) and minimum number of counts (at0 .7 cps). All of the SRMs tested satisfactorily with the following results: SRM FULLY FULLY CHANNEL WITHDRAWN INSERTED S/N CPS A <.1 2.7 27 2.7 B <L 1 2.5 25 2.5 C <01 2.5 25 2.5 D <T.1 3.0 30 3.0 3-24
1 SRM PERFORMANCE l-ST-6 3.6.2 Discussion (Cont ' d) l In addition, initially the SRM non-coincident scram l shorting links were removed. Also the SRM scram ang rod block setgoints were set down one decade to 2 X 10 cps and 1 X 10 cps respectively. After the SRMs were verified operable, the mode switch was taken to "Startup" and the approach to criticality was initiated. As control rods were withdrawn, SRM and IRM data was obtained for plotting 1/M graphs. The SRMs provided sufficient information for a safe and efficient reactor startup at low neutron flux levels. Upon criticality, the SRM/IRM overlap of one-half decade was verified for all IRMs, except IRM 'A', which did not show any response to increasing flux. After adequate overlap was verified, the SRM non-coincident scram shorting links were installed. Following installation of the shorting links, each SRM was verified not to saturate until it registered greater than 150% of the normal scram setpoint cps) (2X10 without experiencing detector saturation. After this verification the SRM scram and rodblock setpoints were lll returned to their nominal value. The following is a list of the test exceptions for 1-ST-6 TE DESCRIPTION STATUS TE-1 IRM 'G' was inoperable prior Closed to verifying overlap. This was due to the Surveillance Test procedure being overdue. This surveillance was later performed and this TE was closed TE-2 IRM 'A' could not be verified Closed to meet overlap criteria as it did not come on scale. This was corrected TE-3 IRM 'B' initially increased Closed
'3/125s' vs. '5/125s' required ggg for overlap. At a later time, however, an increase of over
'5/125' was observed.
l 3-25
.\
IRM PERFORMANCE 7- 1-ST-10 \/ ; l 1 3.7 1-ST-10 IRM PERFORMANCE I 3.7.1 Description The major objective of this test is to adjust the i Intermediate Range Monitor (IRM) system to obtain an ! optimum overlap with the Average Power Range Monitor (.A PRM) system. The acceptance criteria applied to this test are shown ) in Subsections 3.7.1.1 and 3.7.1.2. l 3.7.1.1 Level 1 Criteria
- 1. Each APRM must be on scale near the downscale trip !
before the IRM's exceed their rod block setpoint of 108/125 on Range 10.
- 2. The IRM's shall produce a scram at less than or equal to the Technical Specification Trip Setpoint.
3.7.1.2 Level 2 Criteria (]) Each IRM channel must be adjusted so that one decade overlap with the APRM's is assured. 3.7.2 Discussion Surveillance Test Procedures 504-4501 through 504-4508 were utilized to perform trip tests on each IRM channel to verify that each produced a scram signal at <; 120/125 divisions of full scale. IRMs were adjusted so that ranges 6 and 7 correlated exactly even though the standard correlation was to be within 10%. One decade of IRM-APRM overlap was verified by the APRMs responding prior to the IRMs exceeding Range 8. The IRMs were also l shown not to exceed their rod block setpoint of 108/125 on Range 10 prior to the APRMs being on scale. Test Exceptions 1 through 4 were generated to justify and/or reverify the IRM-APRM overlap since the APRM readings were adjusted several times during the IRM-APRM overlap verification per 1-ST-12. TE-4 is the final verification during Test Condition Heatup. l l 1 O 3 26
l l IRM PERFORMANCE l-ST-10 3.7.2 Discussion (Cont'd) After the APRM channels were calibrated per a plant heat balance at a higher power level, the IRM/APRM overlap was reverified during a subsequent startup. Test Exception 5 was written since this test was initiated on 3-Feb-86 and was discontinued. The test exception was closed on 26-Feb-86 when the overlap was completed. l Below is a listing of the Test Exceptions generated during 1-ST-10: r TE DESCRIPTION STATUS O 1 APRM gains changed during Closed 1-ST-12 initial performance l 2 APRM gains changed during Closed j 1-ST-12 initial performance 3 APRM gains changed during Closed 1-ST-12 initial performance 4 APRM gains changed once more Closed during constant heatup rate APRM calibration 5 IRM/APRM overlap testing ini- Closed tiated discontinued due to plant conditions l l l 4B> 3 27
l Pd LPRM CALIBRATION 1-ST-ll l 3.8 1-ST-11 LPRM CALIBRATION 3.8.1 Description The major objectives of this test are follows: 0 To functionally test the Local Power Range Monitoring (LPRM) system by verifying proper response and correct connection of each LPRM. O To calibrate the LPRM's The acceptance criteria applied to this test are shown in subsections 3.8.1.1 and 3.8.1.2 3.8.1.1 Level 1 Criteria
, None I
'u) 3.8.1.2 Level 2 Criteria Each LPRM reading shall be within 10% of its calculated value. 3.8.2 Discussion LPRM functional testing was performed by making localized power changes in the vicinity of an LPRM by movement of a control rod in the vicinity of an LPRM chamber. The D (top), C, B, and A (bottom) detectors within a string are expected to respond to control rod movement between notch positions 0 and 12, 12 and 24, 24 and 36, and 36 and 48 respectively. Testing was performed between 15 and 30 percent core thermal power (CTP) at a time when all operable LPRM's were on scale during the time period 26-DEC-85 to 29-JAN-86. 130 of 132 LPRM chambers satisfactorily responded during the functional testing. The B and C detector in LPRM string 46-23 responded in a manner that indicated their connections were reversed. Test Exception I was written to report this and investigation showed that 'the connection were reversed. This'was corrected and the Test Exception was closed out after retest indicated that the LPRM string responded normally to the insertion ('~} of control rod 48-21 from notch position 48 to 0. 3-28
LPRM CALIBRATION 1-ST-ll 3.8.2 Discussion (Cont'd) Initial LPRM calibration began on 26-Dec-86 with CTP just below 20%. Test Exception 2 was written to allow the calibration to be performed even though the final Traversing Incore Probe (TIP) core top and bottom limits had not been set utilizing the LPRM/ spacer dips as required by the initial conditions. This was done since it was not possible to determine spacer /LPRM dips at this power level. Several iterations were required to complete the calibration of the LPRM's. These recalibrations are documented in Test Exceptions 4, 5 and 6, all of which were cleared upon closing TE-6. Test Exception 7 was the result of two failed LPRM's, SB-14-07 and 1D-22-47, which could not be calibrated and were deferred until the LPRM calibration at Test Condition 6. The LPRM calibration was initially done by using the BUCLE (Backup Core Limits Evaluation) code. g When the process computer program P1 was validated per W 1-ST-13, LPRM calibration was accomplished with the process computer. This was done for Text Exception 6 and the Test Condition 6 calibration. Final LPRM calibration at Test Condition 6 was begun on 22-May-86 with CTP of 96%. Calibration of the LPRM's at Test Condition 6 resulted in 2 LPRM's, IB-30-47 and 2B-22-39, having Gain Adjustment Factors (GAF) greater than the 10% allowed by the criteria. Test Exception 9 was written to document and recalibrate these two LPRM's. Test Exception 9 was cleared upon successful recalibration of the two LPRM's. Test Exception 8 was the result of two failed LPRM's, 6B-38-15 and 2D-38-47, which could not be calibrated and was deferred until the LPRM's were repaired. Test Exception 7, from the initial LPRM calibration was cleared with the successful calibration of LPRM's 5B-14-07 and 1D-22-47 LPRM calibrations will continue to be done periodically using the applicable plant procedures. O 3-29
O V LPRM CALIBRATIOlt 1-ST-11 The table below is a list of all the Test Exceptions for 1-ST-ll,
.a brief description and the status as of 15-Jul-86:
TE DESCRIPTION STATUS 1 Channels B and C of LPM 46-23 reversed Closed 2 Final TIP limits not set using spacer / Closed LPRM dips due to insufficient CTP. 3 NOT USED ------ () 4 All LPRM GAF's not within 10%. Closed 5 All LPRM GAF's not within 10%. Closed 6 All LPRM GAF's not within 10%. Closed 7 LPRM's 5B-14-07 and 1D-22-47 failed / Closed not calibrated. 8 LPRM's 6B-38-15 and 2D-38-47 failed / Open not calibrated. Repair and retest is planned. 9 LPRM's 1B-30-47 and 2B-22-39 GAF's not Closed within 10%. O 3-30
(v) APRM CALIBRATION 1-ST-12 3.9 1-ST-12 APRM CALIBRATION 3.9.1 Description The major objective of this test is to calibrate the Average Power Range Monitor System. The acceptance criteria applied to this test are shown in Subsections 3.9.1.1 and 3.9.1.2. 3.9.1.1 level 1 Criteria
- 1. The APRM channels must be calibrated to read equal to or greater than the actual core thermal power.
- 2. Technical specification and fuel warranty limits on APRM scram and rod block shall not be exceeded.
O (_/ 3. In the startup mode, all APRM channels must produce a scram at less than or equal to 15% of rated thermal power. 3.9.1.2 Level 2 Criteria '
- 1. If the above criteria are satisfied, then the APRM channels will be considered to be reading accurately if they agree with the heat balance or the minimum value required based on peaking factor, CMFLPD, and fraction of rated power to within
(+7,-0)% of rated power. 3.9.2 Discussion During the initial heatup, and APRM calibration was done using a constant heatup rate heat balance at approximately 1% core thermal power. When adequate feedwater flow indication was available, more accurate calibrations were performed using an overall reactor heat balance. Calibrations are performed at each major test condition. During heatup, core thermal power was calculated to be .51%. The APRMs were adjusted to read 3-31
APRM CALIBRATION 1-ST-12 3.9.2 Discussion (Cont'd) 120% of this value, thus meeting the Level 2 criteria. All APRMs produced a scram indication at less than or equal to 15%, and no APRM exceeded its rodblock setpoint upon adjustment of its gain. There were nine test exceptions at this test condition which have all been resolved. They are listed at the end of this section. For test conditions, 1,2,3,5, and 6 a surveillance test procedure, STP-050-3001 Power Distribution Limits Verification, was used to determine the desired APRM readings and the upscale thermal alarm setpoints for each of these plant conditions. The desired reading is calculated by dividing the initial percent of rated thermal power by the ratio (T) which is the Fraction of Rated Thermal Power (FRTP) over the Core Maximum Fraction of the Limiting Power Density (CMFLPD). This is used to take into consideration core peaking and therefore only applied if T is less than 1.0. Once the . desired readings are determined, the APRMs are adjusted to indicate greater than or equal to the desired APRM reading. Table 3.9-1 lists the desired APRM readings and the as-left readings for each APRM at each test condition. I 3-32
l APRM CALIBRATIOtt l-ST-12 { l The following is a list of the nine test exceptions written for the Heatup Condition. All have been closed: i TE DESCRIPTION Status , i l 1 APRM "A" Inoperable due to initial Closed calibration not being current. APRM "A" power supply was replaced, STP-505-4201 performed, and APRM "A" was declared operable. 2 Method of establishing the desired closed APRM readings was not conservative due to a considerable change in rod pattern and thermal power since the s 3) calculations were done. The method was revised to account for estimated changes in thermal power from the time of the constant heatup rate calcula-tion. Retest was conducted using the new method, 3 Error found in the calculation of the closed average reading used to get the desired APRM reading resulting in non-conservative as left APRM readings. Retest was performed to correct the desired reading calculation. 4 Error in the equation to calculate Closed thermal power. This error was correct-ed. Retested to reset APRM gains. O 3 33
I i l APRM CALIBRATION h 1-ST-12 TE DESCRIPTION STATUS 5 Attempted to increase operating Closed margin due to the APRM gains being too conservative by utilizing feedwater flow. This optional section was started, but not completed due to the unavailability of an accurate dP gauge to measure feedwater flow. Accepted as is since this section is optional. 6 The as-left APRM settings met all Closed acceptance criteria, but proved to be too limiting at high reactor pressures (lt600 psig). Reperformed portions of the calibration during a subsequent heat-up. 7 Due to inaccuracies in feedwater in- Closed G dication the attempt at this optional method to show the APRMs are conserva-tive was not successful. Reperformed constant heatup rate heat balance and adjusted the APRM gains to agree with the results of this heat balance per-formed at a higher reactor pressure. 8 APRM g-f.ns were increased to add 20% Closed more conservatism to the adjustments made in TE-07. 9 Error found in the calculation of closed thermal power performed under TE-06 resulting in as-left readings less than thermal power. This error was corrected when TE-07 and TE-08 retest packages were performed. , 1 l l 9 3-34
O O O APRM CALIBRATION 1-ST-/2 i TABLE 3.9-1 1 TC-1 TC-2 TC-3 TC-5 TC-6 , DESIRED AS-LEFT DESIRED AS-LEFT DESIRED AS-LEFT DESIRED AS-LEFT DESIRED AS-LEFT APRM READING READING READING READING READING READING READING READING READING READING A 19.2 24.5 34.5 34.5 46.7 58.0 73.8 74.1 97.3 97.3 ]
- B 19.2 24.5 34.5 35.0 46.7 58.0 73.8 74.0 97.3 97.3 C 19.2 24.5 34.5 34.8 46.7 58.0 73.8 74.0 97.3 97.3 i
D 19.2 24.5 34.5 34.5 46.7 58.0 73.8 74.1 97.3 97.3 E 19.2 24.5 34.5 35.0 46.7 58.0 73.8 74.1 97.3 97.3 F 19.2 24.5 34.5 35.0 46.7 58.0 73.8 74.0 97.3 97.3 G 19.2 24.5 34.5 34.5 46.7 58.0 73.8 74.1 97.3 97.3 H 19.2 14.5 34.5 34.5 46.7 58.0 73.8 74.0 97.3 97.3 3-35
PROCESS COMPUTER l-ST-13 0 3.10.1 Description The purpose of this test is to verify the performance of the Nuclear Ste.m Supply (NSS) and Balance of Plant (BOP) process computer programs under plant operating conditions. The acceptance criteria applied to this test are shown in Subsections 3.10.1.1 and 3.10.1.2. 3.10.1.1 Level 1 Criteria None 3.10.1.2 Level 2 Criteria
- 1. The MCPR calculated by BUCLE and the process computer either:
- a. Are in the same fuel assembly and do not differ in value by more than 2% or g b. For the case in which the MCPR calculated by the
_/ process computer is in a different assembly than that calculated by BUCLE, for each assembly, the MCPR and CPR calculated by the two methods shall agree within 2%.
- 2. The maximum LHGR calculated by BUCLE and the process computer either:
- a. Are in the same fuel assembly and do not differ in value by more than 2%, or i
- b. For the case in which the maximum LHGR calculated by the process computer is in a difterent assembly than that calculated by BUCLE, for each assembly, the maximum LHGR and LHGR calculated by the two methods shall agree within 2%.
- 3. The MAPLHGR calculated by BUCLE and the process computer either:
- a. Are in the same fuel assembly and do not differ in value by more than 2%, or
() 3-36
PROCESS C(N6PUTER 1-ST-13 0 3.10.1.2 Level 2 Criteria (con't)
- b. For the case in which the MAFLHGR calculated by the process computer is in a different assembly than that calculated by BUCLE, for each assembly, the MAPLHGR and APLHGR calculated by the two methods shall agree within 2%.
- 4. The LPRM calibration factors calculated by BUCLE and the process computer agree within 2%.
3.10.2 Discussion
- 1. Test Condition Open Vessel At Test Condition Open Vessel the Static System Test Case (SSTC) was performed using simulated static data overlayed onto the system software to perform a preliminary verification of OD-1 (Whole Core LPRM Calibration and Base Distribution). The test verified the following:
- 1. The process computer recognizes OD-1 related g errors. W
- 2. OD-1 outputs the appropriate errors, warnings, messages and edits to simulated and real input data.
- 3. The process computer and Traversing Incore Probe (TIP) machine interface is functional.
- 4. A complete OD-1 can be successfully performed by obtaining successful traverses of all required TIP channels.
TE-01 resulted from the inability to obtain a successful traverse from TIP Machine C Channel 9 due to hardware problems. TE-02 was the result of the failure to obtain an expected error message when a particular error was generated. After the completion of testing new software was installed in the process computer and hardware was changed in the TIP machines. TE-03 was generated to retest applicable portions of the SSTC that might be affected by the changes. TE-01 was resolved in conjunction with TE-03 after the hardware problems were , resolved. TE-02 was resolved when it was determined that the software revision O 3-37
PROCESS COMPUTER
-~
1-ST-13 4 3.10.2 Discussion (Cont'd)
- 1. Test Condition Open Vessel (Cont ' d) delivered to River Bend would not generate the originally expected error message.
- 2. Test Condition One During Test Condition One, at rated reactor pressure and temperature, the TIP System core top and bottom limits were reset. This was accomplished by manually cranking the TIPS individually into each of their respective channels to determine actual top of the TIP chamber and calculating the new limits. The core limits are reset after the reactor is at operating temperature to account for system expansion to prevent inserting the TIP probes into the top of the TIP chamber and damaging it. A two inch margin is allowed between the actual top of the TIP chamber and the programmed top. The bottom limit is then programmed such that the TIP machine will send the proper number of pulses
() to the process computer to obtain a successful traverse edit. These newly calculated limits are then verified / reset based upon performing actual traverses and observing dips in the TIP traces resulting from spacers and LPRM chamber at known elevations within the core. This verification was not able to be performed at Test condition One since the power level was too low. TE-04 was generated to perform this portion at a power level sufficiently high to distinguish the dips in the traverse caused by the spacers and LPRM chambers. In the processing of retesting TE-04 it was found that even near 100% power some spacer dips were still not distinguishable. TE-13 was written to note this discrepancy and resolved with no retest requirements. TE-04, however, remains open.
- 3. Dynamic Systems Test Case Beginning at a core thermal power level of approximately 20%, the Dynamic System Test Case (DSTC) was performed to verify the NSS programs were functional. The testing included:
- 1. Verification of the Computer Outage Recovery Monitor (CORM) to initial'ize necessary variables and exposure arrays as part of initial plant 3-38
PROCESS COMPUTER l-ST-13 3.10.2 Discussion (Cont'd) computer startup and to allow for controlled set of data in further system testing.
- 2. Verify all required plant sensors for NSS programs are being properly scanned.
- 3. Verification of the heat balance subroutine used by OD-3 and P1 by comparing it with a manually calculated heat balance.
- 4. Performing an LPRM calibration to verify the operation of OD-1 prior to the verification of thermal limit calculations.
- 5. Verification of thermal limits calculations and core power distribution.
ggg
- 6. Verification of the exposure updating programs P4 (10 Minute Core Energy Increment), P1 (Periodic Core Evaluation), P2 (Daily Core Performance Summary) and P3 (Monthly Core Performance Summary).
- 7. Verifying key variable memory locations and performing manual calculations to verify the remaining NSS software at steady state operation and symmetric rod pattern.
Thermal limit and LPRM calibration factor calculations were verified in conjunction with the DSTC. The verification was performed by taking the same data that is input to the P1 program, for its calculation, and inputting it into an approved offline computer program (Backup Core Limits Evaluation (BUCLE), which also performs the P1 calculations. The resulting thermal limits and LPRM calibration factors were verified against the criteria. In all instances the results were in the same fuel assembly and the results are as follows: O 3-39
PROCESS COMPUTER 1-ST-13 I~h v; 3.10.2 Discussion (Cont'd) PARAMETER LOCATION P1 RESULTS BUCLE RESULTS % ERROR Max LHGR 21-50-11 3.07 3.06 0.33 Max MAPLHGR 21-08-11 2.77 2.76 0.36 Min CPR 21-50 3.915 3.917 0.05 P1 RESULT - BUCLE RESULT
% ERROR =
- 100%
P1 RESULT
- 4. BOP Program It was not possible to perform the verification of the BOP Performance Calculations (BPC) prior to the end of Test condition 6. A late software delivery and an incomplete software acceptance test were the reasons.
() generated to test the BPC programs after the completion of the preliminary site software acceptance TE-12 was test and resolution of potential problems noted in the delivery.
- 5. OD-11 After originally being deleted from the test program, because River Bend was using barrier fuel, some portions OD-11 were added and tested. None of these programs are required for plant operation but reactor engineering requested that programs involving envelope updating and pin powers be tested. The programs are useful for core management at high power. No dynamic testing involving control rod movement and automatic initiation of P1 was performed. OD-11 testing was not performed for alarms, automatic initiation or ramping. These portions should not be considered available for use.
O 3 40
PROCESS COMPUTER l-ST-13 0 3.10.2 Discussion (con't)
- 6. Remaining NSS Programs The verification of the remaining NSS programs was performed at various power and flow conditions starting in Test Condition 1 and extending through Test Condition 6.
Several test exceptions were generated during the testing. These are documented in the following. TE-05 was due to the TIP plotter being out of adjustment and therefore impossible to verify the OD-1 edits against a set of TIP traces during the testing sequence. After the TIP plotter was calibrated this exception was resolved by obtaining a set of TIP traces in conjunction with an OD-1 and verifying the OD-1 output edits. During verification of P4 (feedwater temperature compensation), it was found that P4 was not functioning properly and this was documented by TE-07. Several data base values were found to be in error and were modified. The applicable steps were retested and the exception resolved. g During the testing of P1 it was not possible to verify the validity of P1 edits and the as yet untested P2 and P3 due to reveral P1's being demanded outside the test. TE-08 was written to resolve this by reinitializing the system and exposure arrays, and resuming the system testing. TE-08 was completed and closed. An apparent discrepancy in the output of the failed sensor edits of OD-3 and OD-10 Option 40 was recorded in TE-09. Closer examination revealed this not to be an actual problem but merely the different manner in which the two outputs were generated. O 3_41
PROCES3 COMPUTE 2 1-ST-13 3.10.2 Discussion (con't) A change in the allocation of TIP channels was found not to be incorporated into the software during testing. TE-10 was written and the proposed disposition to resolve this error was to reperform the thermal limits verification. The retest was satisfactorily performed and the TE was closed. The drive flow (WDC), and core flow (WTC) relationship used by OD-3 to verify the measured value of core flow could not be completed, by the end of Test Condition 6, due to the recirc system calibration performed by 1-ST-35 not being corapleted. TE-11 was written to document this. This TE was resolved upon satisfactory completion of 1-ST-35. All of the test exceptions for 1-ST-13 are listed below i along with the status as of 15-July-86. () l l l 3-42 i
- . . - , _ ~ . _ . , _ . . - _ _ _ . . _ . , , , _ . - . . . _ _ _ _ - . - _ - . . _ - . . . _ , , . , _ _ _ , _ _ _ _ . _ _ - _ _ _ _ - _ _ - . . -_ _ _ - _ _ . . , . - _ , , - _ . . _ . , _ . _ . . _ .
PROCESS COMPUTER 1-ST-13 O TE DESCRIPTION STATUS 1 Unable to obtain a successful traverse of TIP Closed Machine C Channel 9. 2 Unable to obtain expected error message. Closed 3 New software installation on process computer Closed and new hardware installed in TIP machines. 4 Spacer /LPRM dips not distinguishable at low Open power level. A retest of this is planned. 5 TIP plotter out of adjustment prevents verification Closed of OD-1 output. 6 NOT USED ------ 7 Improper feedwater temperature compensation. Closed 8 Uanable to initially perform P1 edits verification. Closed 9 Failed sensor list descrepancy. Closed 10 Incorrect assignment of TIP channels to LPRMs. Closed 11 WDC/WTC correlation not obtained since recirc Closed calibration was not completed. 12 BOP calcs not verified due to late software Open delivery and incomplete software acceptance test. This verification is planned. 13 Some spacer dips still indistinguishable at 100% Closed power. O 3-43
O . Rc1c S1Sr - 1-ST-14 1 l 3.11 1-ST-14 RCIC SYSTEM 3.11.1 Description The purposes 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. i The acceptance criteria applied to this test are shown in Subsections 3.11.1.1 and 3.11.1.2. 3.11.1.1 Level 1 Criteria NOTE O If any Level 1 criteria are not met, the reactor will only be allowed to operate up to a restricted power level until the problem is resolved. Plant Technical Specifications take precedence over any power restriction consideration.
- 1. The average pump discharge flow must be equal to or greater than the 100% rated value after 30 seconds have elapsed from automatic initiation or manual initiation push button start at any reactor pressure between 150 psig and rated.
- 2. The RCIC turbine shall not trip or isolate during auto or manual start tests.
3.11.1.2 Level 2 Criteria
- 1. In order to provide an overspeed and isolation trip avoidance margin, the transient start first and subsequent speed peaks shall not exceed 5% above the rated RCIC turbine speed (105% of rated turbine speed = 4777.5 rpm).
O 3-44
RCIC SYSTEN 1-ST-14 3.11.1.2 Level 2 Criteria (Cont'd)
- 2. The speed and flow control loops shall be adjusted to that the decay ratio of any RCIC system related variable is not greater than 0.25.
- 3. The turbine gland seal system shall be capable of preventing steam leakage to the atmosphere.
- 4. 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 (300%).
3.11.2 Discussion RCIC testing was accomplished in three phases. First, the system was verified to operate properly while injecting into the condensate storage tank in its test mode of operation. Second the system was verified to meet its design objective of injecting rated flow into the vessel within 30 seconds of initiation. Third, the system was operated to the CST in its test mode after the final tuning was completed in order to establish surveillance baseline data. A complete sequence of testing is outlined in Table 3.11-1. The results of the RCIC testing are summarized in Table 3.11-2 for the 6 quick starts conducted. The final hcIC control settings are summarized in Table 3.11-3. At 150 psig a manual start of the RCIC system was performed in CST to CST mode. The system satisfied the necessary criteria of not tripping the RCIC turbine and the gland seal system satisfactorily prevented steam leakage. Three (3) minor test exceptions were generated. TE-1 was written since the RCIC controller, 1E51-R600, settings were not available at the time of the test. These were added before any setting changes were made to the controller. TE-2 and TE-3 involved minor problems with ERIS signals for'the governor valve and the turbine trip signals. O 3-45
RCIC SYSTEM l-ST-14 3.11.2 Discussion (Cont'd) At 920 psig RCIC was manually initiated in CST to CST mode. Significant problems were encountered with the RHR/RCIC steam flow transmitter 1E31-N084A. This transmitter saw pressure spikes during system initiation and step changes causing the system to isolate. Also, the transmitter drifted negative as RCIC was operated over a period of time. This resulted in TE-4 being written to reperform portions of the test after the lE31-N084A transmitter trip setpoints were lowered,due , to the negative drift observed. The transmitter damping was also adjusted. TE-4 was completed resulting in the generation of TE-5, TE-6, TE-7, TE-15, and TE-18. TE-5 was written because turbine speed limitations would only allow a 30 gpm and l not a 60 gpm increase in flow. TE-6 was written when the pressure setpoint was restored to 950 psig and not ({} 920 psig as per the procedure. TE-7 was written since } the ERIS turbine trip data was not available to verify that the RCIC turbine did not trip. TE-15 was written ! since the EGM output failed the Level 2 criteria ! concerning decay ratio. The disposition was to accept the current data since tuning would be performed when injecting to the vessel and since no other RCIC variables exceed the criteria. TE-18 was written since RCIC steam flow isolation data failed to be recorded on the ERIS tape. This data was taken during a subsequent running of RCIC. l TE-8 through TE-14 were written to defer certain testing to a later test condition. At 920 psig RCIC was manually initiated and tuned to the vessel. All decay ratios were less than .25 except for the EGM output which had a decay ratio of .44. TE-19 was written against this and evaluated as acceptable by i General Electric Engineering. After tuning a Quick Start was performed. The time to rated flow was 15 seconds. All Level 1 criteria were satisfied. TE-17
- was written because RCIC Steam line dP data for l 1E31-N083A was not taken. TE-16 was written since the l position of the turbine trip throttle valve was not recorded, t
3-46 i i
RCIC SYSTEM 1-ST-14 3.11.2 Discussion (Cont'd) On 6-Dec-85 the RCIC ist Cold Quick Start - Injection into Reactor Vessel, was performed. 600 gpm flow (rated) was achieved in 22.6 seconds and all Level 1 and Level 2 criteria were satisfied. TE-20 was written against this section to document changing the ramp rate setting for the quick start from 12 seconds to 18 seconds. RCIC Vessel Injection and tuning at 150 psig, was not completed due to a concern over the RCIC flow dropping below 600 gpm one minute after the initiation of a quick start. TE-21 was written to document this concern and a retest was conducted after it was determined that Level I criteria was not affected by the momentary dip in RCIC flow. On the two subsequent quick starts, 600 gpm flow was achieved in 8 seconds and 9 seconds, respectively. All of the tuning steps were satisfactory, with the only lll criteria failure being that the EGM controller output failed to meet the Level 2 criteria of exhibiting a quarter-damped decay ratio. Exception TE-24 was written on the EGM Level 2 failure. The 2nd Cold Quick Start to the vessel, was performed on 21-Dec-85 with a time to rated flow of 23 seconds. All criteria were satisfied. RCIC Operating from the Remote Shutdown Panel (RSP) was initially performed on 21-Dec-85, but the section was unable to be completed because the procedure was incorrect in assuming that a quick start could be performed from the RSP. A manual RCIC start from RSP was performed under TE-22 with all Level I criteria satisfied. There was one Level 2 criteria failure as the EGM Controller output decay ratio was greater than 0.25 during the stability demonstration. This was evaluated by General Electric Engineering as acceptable. O 3~47
RCIC SYSTIEM l-ST-14 3.11.2 Discussion (Cont'd) on 31-Dec-85 the RCIC Quick Start to the CST at Rated Pressure for Surveillance Baseline Data, was initiated. After the RCIC Quick Start, it was discovered that the CST Throttle Return Valve was set incorrectly, resulting in an incorrect simulated vessel pressure. TE-26 was written and the associated retest was performed with all
- criteria satisfied.
The system Technical Specification High Steamline Flow Isolation setpoints were also determined after reviewing all of the data for the Quick Starts. The E31-N083 A and B transmitter isolation setpoints (RCIC Steam Line Flow) were calculated to be 127 inches of H2O versus 222 inches as the preliminary Technical Specification setpoint. This was based on 300 percent of steady-state system flow at rated conditions. The E31-N084 A and B () transmitter preliminary isolation setpoints (RHR/RCIC Steam Line Flow) were found adequate primarily based on the condition that the steam condensing mode of RHR was prohibited. The Technical Specifications have provisions to change the preliminary setpoints. TE-27 has been written to track this change and remains open. A summary of all the test exceptions follows along with the status as of 15-Jul-86. 3-48
i l RCIC SYSTEM 1-ST-14 TE DESCRIPTION STATUS 1 Control settings not recorded prior to test Closed 2 ERIS Governor Valve Position Signal failed Closed 3 ERIS Turbine Trip Signal failed Closed 4 RCIC System Isolation Due to Second High closed Steamline Flow 5 Used 30 GPM Step changes instead of 60 GPM Closed llh specified 6 Pressure Setpoint not lowered as specified Closed in procedure 7 ERIS Turbine Trip Signal failed Closed 8 Defer testing Section 5.1.5 Closed 9 Defer testing Section 5.1.6 Closed 10 Defer testing Section 5.1.7 Closed 11 Defer testing Section 5.1.8 Closed 12 Defer testing Section 5.1.9 Closed 13 Defer testing Section 5.1.10 Closed 14 Defer testing Section 5.1.11 Closed 15 Failed Level 2 criteria for EGM Decay Ratio Closed 16 ERIS Trip Throttle valve Signal failed Closed O 3 49
- _ _ . . a
O V RCIC SYSTE36 1 1-ST-14 l TE DESCRIPTION STATUS 17 Data for setting high steam line Isolation Closed trip not obtained 18 Data for setting high steamline Isolation Closed trip not obtained 19 Failed Level 2 criteria for EGM Decay Ratio Closed 20 Changed RCIC Controllers Pump Rate Closed 21 Flow Dipped slightly below 600 GPM on Quick Closed Start 22 RCIC failed to Quick Start from the Remote Closed () shutdown panel 23 ERIS EGM controller Output Signal failed Closed 24 Failed Level 2 criteria for EGM Decay Ratio Closed 25 ERIS Governor Signal failed Closed 26 Set CST return valve to wrong setting for Closed Quick Start 27 Track Technical Specification change for Open high steamline flow isolation setpoint. This change is in process. l O 3-50 b
-- ---s---__, --.-., +y,_-#_---,._,,,-,_.,,,,,y ,,%7- m. -,-,.------- ., , ,-- , ~ . - - - - - - - - - , , . , - _ , , . - - - -
O O O l 1 BCIC SYSTEM , 1-ST-14 1 j TABLE 3.11-1 I j Sequence Of RCTC Testing i i I ACTION CONDITIONS i
- 1 Condensate storage tank injection first Demonstration of operability at l phase manual start, low pressure 150 psig reactor pressure i
2 Condensate storage tank injection first Rated reactor pressure, RCIC dis-j ; phase manual start charge 100 psi above RPV , 3 Condensate storage tank changes in flow RCIC discharge to condensate l storage tank, manual and automatic modes l l 4 Condensate storage tank, extended oper- In conjunction with 3 ! ation demonstration 1 l l 5 Reactor vessel injection manual start Rated reactor pressure, manual and changes in flow automatic modes l l 6 Reactor vessel injection hot quick start Rated reactor pressure, automatic ! mode ) 3-51 l
t O O O i 1 BCIC SYSTEM
. 1-ST-14 I
4 j 1 TABLE 3.11-1 (Cont'd) 1 Sequence Of RCIC Testing I l l
! ACTION CONDITIONS l
! 7 Reactor vessel injection hot or cold quick 150 psig reactor pressure, manual start followed by stability demonstration modes i and hot quick start i j 8 Confirmatory reactor vessel injection, Rated reactor pressure at final ' j cold quick start controller settings I i j 9 Second consecutive confirmatory reactor Rated reactor pressure at final vessel injection, cold quick start controller settings 10 Condensate storage tank injection for Rated reactor pressure, final surveillance test base data, cold quick controller settings, RCIC dis-j start charge i 1 l 11 Condensate storage tank injection for 150 psig reactor pressure, final i surveillance test base data, cold quick controller settings, RCIC discharge test approx. 100 psi above reactor , pressure ! t 12 Reactor vessel manual start from the Rc- Rated reactor pressure at final ' l mote Shutdown Panel controller settings i j 3-52
- e. -
, yr
--r-y- -
O O O
~
l RCIC SYSTEN 4
! 1-ST-14 1
I TABLE 3.11-2 I l RESULTS OF RCIC TESTING INJECTION HOT /COIE* PRESSURE FIAN TINE TO PtBIP DISCHARGE NAXIMUN TURBINE TO QUICK START (PSIG) (GPM) RATED FLON PRESSUP.E (PSIG) SPEED (RPM) (SECONDS) RPV HOT 925 599 15 988 4397 I RPV HOT 150 600 9 210 2540 RPV COLD 954 600 22.6 1015 4418 RPV COLD 982 600 23 1045 4303 CST COLD 955 600 23 1140 4571 l; CST COLD 161 646 15 345 2731 i I
- A Cold quick start is defined as a start of the RCIC system after 72 hours of no RCIC system operation.
i 3-53 l
i
)
RCIC SYSTEM 1-ST-14 FINAL RCIC CONTROLLER SETTINGS TABLE 3.11-3 RCIC FLOW CONTROLLER Proportional Gain 0.11%/% Integral Gain 48 Recets/ Minute Ramp Time 18 seconds WOODWARD EGM TURBINE CONTROLLER () Gain 5.0 Stability 5.0 EGR Needle Valve 1/2 turn CCW Valve Setting O 3-54
O sELECTEo rRoCEss TE ERATUres (VESSEL TE PERATUREs) 1-sT-16A l 3.12 1-ST-16A SELECTED PROCESS TEMPERATURES 3.12.1 Description The major objective of this test is to determine if an administrative limitation is needed on the flow control valve minimum position when the recirculation pumps are on slow speed to prevent coolant temperature stratification in the bottom head region. The acceptance criteria applied to this test are shown in subsections 3.12.1.1 and 3.12.1.2. 3.12.1.1 Level 1 Criteria
- 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 100 degrees F.
- 2. The recirculation pump in an idle loop must not be started, active loop flow must not be raised, and power must not be increased unless the idle loop suction temperature is within 50 degrees F of the active loop suction temperature and the active loop I flow rate is less than or equal to 50% of rated l loop flow. If two pumps are idle, the loop suction l
temperature must be within 50 degrees F of the steam dome temperature before pump startup. 3.12.1.2 Level 2 Criteria
- 1. Recalibrate bottom head flow indicator against RWCU flow indicator if the deviation is greater than 25 gpm.
3.12.2 Discussion On November 24, 1985 the recirculation flow control valves were closed simultaneously to determine if an administrative valve position limitation is needed when () 1 1 3-55
. _ . _ . =_ ._
l l I l SELECTED PROCESS TEMPERATURES
, (VESSEL TEMPERATURES) 1-ST-16A 3.12.2 Discussion (Cont'd) the recirculation pumps are on slow speed to prevent temperature stratification in the bottom head region.
The differential temperature between the steam dome and bottom head drain must be within 100 degrees F. The l l flow control valves were closed to approximately 2% open l resulting in a calculated differential temperature of 96 1 degrees F. The plot of temperature versus flow control valve position indicated that stratification would occur at valve positions less than 2% open so an administrative limit was implemented to limit the valve closures to 2% open while on slow speed. The Level 2 criterion concerning bottom head drain flow indication was satisfied by Special Situation Test 5 (1-SST-05) Reactor Bottom Head Drain Flow Calibration. During the hot recirculation preoperational 1-PT-53, the bottom head drain flow indicator was test llh calibrated against the RWCU flow indication with reactor moderator temperature greater than 430 degrees F. A maximum deviation of 15 gpm was observed. An additional Level 2 criterion dealt with a temperature differential measurement at rated recirculation flow. This measurement was transferred to 1-ST-35 since rated conditions were not achieved during 1-ST-16A. Test Exception 1 documents this and is summarized below. TE DESCRIPTION STATUS 1 Since the plant was not at rate- Closed ed core flow, Level 2 criteria could not be verified. This criteria was removed from 1-ST-16A and transferred to 1-ST-35 where appropriate conditions exists to obtain the data. O 3-56
WATER LEVEL REFERENCE LEG TEMPERATURE 1-ST-16B 3.13.1 Description The major objective of this tent is to verify that the containment and drywell temperatures in the vicinity of the Reactor Level Reference Legs are within the limits that would result in less than a one percent of full scale error due to temperature compensation. The acceptance criteria applied to this test are shown in Subsections 3.13.1.1 and 3.13.1.2. 3.13.1.1 Level 1 Criteria None 3.13.1.2 Level 2 Criteria
- 1. The
() difference Reference Leg between the Temperatures sensing determined line containment and drywell temperature measurements and and from the values assumed during initial calibration shall be less than that amount which will result in a scale end point erroI of 1% of the instrument span for each range. 3.13.2 Discussion This test was performed during steady state operation with constant drywell temperatures during Test Condition Heatup (less than 5% power) and again at Test Condition 6 (94% power) . In both conditions, drywell and containment temperatures were taken in the vicinity of the sensing and reference leg lines. The densities at these temperatures were used to determine the error introduced by the actual temperatures from those assumed in the calibration. The results are summarized in Table 3.13-1. O 3 57
i WATER LEVEL REFERENCE LEG TEMPERATURE 1-ST-16B l 3.13.2 Discussion (con' t) During Test Condition Heatup, the maximum calculated narrow range level error was -0.678 compared to a criteria of less than 0.6 inches. This is documented in Test Exception 7. This violation was mainly a result of the reference leg condensing chambers located at a higher elevation than recommended. This coupled with the lower drywell temperatures produced an error of this magnitude. This was accepted by General Electric Engineering based on the small magnitude of the error and the expected higher drywell temperatures at higher powers. This was seen at the 100% power condition. Another Test Exception (TE-06) was documented due to a possible error in the initial calibration. A computer program RXWTR01 is utilized for calibration of initial level instrumentation. The program used specific volumes at saturated conditions instead of 950 psig. General Electric Engineering was aware of this end stated that the error induced in this simplification was very small (less than 0.2 inches) . During this test, all narrow range and wide range instruments were compared to each other. The recommended duration from the average is + 1.5 inches and + 6 inches for narrow and wide range instrumentation respectively. For the Heatup testing, 2 narrow range instruments exceeded this recommendation by 0.5 inches while 2 wide range instruments varied by more than one inch from recommended (TE-3). During the higher power measurement, however, 4 of the wide range instruments varied between 9 and 17 inches from the average. This is documented as TE-9 and remains open pending investigation. The following summarizes the test exceptions for 1-ST-16B along with the status as of 15 July 86. hII 3-58 l
i 1 WATER LEVEL REFERENCE LEG TEMPERATURE l-ST-16B ' TEST TE CONDITION DESCRIPTION STATUS 1 HU ERIS Reference Leg Temperatures not avail- Closed able. Drywell temperatures in the vicinity were used. 2 HU Recirc. temperature on ERIS not available Closed and total core flow signal was downscale. Used B33-R614 for substitute recirc. temp-erature data. ERIS core plate dP used to obtain total core flow. 3 HU Narrow range instruments IC33-R606C and Closed 1B21-LIS-N095B were +.5 inches from the analysis criteria. Wide range instruments ('~' 1B21-LIS-N681A and 1B21-LIS-N673G were 1 inch above the analysis criteria. No acceptance criteria is associated with this. 4 HU Voltage values were not used due to a re- Closed sultant excessive time leg between read-ings. Recorded values in inches. 5 HU The calculated narrow range error for two Clused of the loops exceeds the acceptance criteria. Problem is tracked by TE-6 and TE-7. 6 HU Specific volume used for Drywell and Con- Closed tainment temperature correction was at saturated conditions instead of 950 psig. 7 HU The narrow range error calculated for loops Closed A and C exceeded the acceptance criteria. Re-evaluated during TC-6. 8 6 ERIS Reference Leg Temperatures not avail- Closed able. Used Drywell temperatures for water level calculations. 9 6 Wide Range instrtments 1B21-R623A, R623B, Closed O LIS-N699E, and 1RHS-R119 readings are greater than 6 inches from the average. An investigation is underway and this problem is being tracked by a Condition Report. 3-59
O O O WATER LEVEL REFERENCE LEG TEMPERATURE 1-ST-16B TABLE 3.I3-1 CALCULATED MAXIMUM WATER LEVEL ERRORS i TEST CONTAINMENT DRYWELL NARROW RANGE WIDE RANGE CONDITION TEMP TEMP MAX ERROR CRITERIA MAX ERROR CRITERIA (F{ (F) (in) (in) (in) (in) { HU 76-80 107-110 0.678 10.6 0.836 42.1 j 6 76-81 125-130 0.184 [0.6 0.162 < 2.1 1 i 4 1 3-60
SYSTEM EXPANSION 1-ST-17 3.14 1-ST-17 SYSTEM EXPANSION 3.14.1 Description The purpose of the thermal expansion test is to verify the following: 0 The amount of thermal expansion is within limits to prevent overstressing of the recirculation and main steam piping systems. O There are no obstructions to constrain free pipe thermal movement. O The pipe suspension (i.e., hangers, snubbers and spring cans) are working as designed. O Satisfy Snubber Pre-service Inspection Requirements. The acceptance criteria applied to this test are shown in Subsections 3.14.1.1 and 3.14.1.2. 3.14.1.1 Level 1 Criteria A. The piping response to thermal expansion shall be considered acceptable if any of the following conditions are met:
- 1. Pipe motion is within Level 1 limits specified per Table 3.14-1.
- 2. General Electric Piping Design reviews the test results and determines that the piping responded consistently with the predictions of the stress report, or;
- 3. Observed piping stresses are within ASME Code limits as determined by General Electric Piping Design.
3.14.1.2 Level 2 Criteria
- 1. The piping response to thermal expansion shall be considered acceptable if pipe motions are within Level 2 limits specified in Table 3.14-1.
O 3-61
SYSTEM EXPANSION h 1-ST-17 3.14.2 Discussion During the hot recirculation preoperational test (1-PT-053) and the first nuclesr heatup cycle, the recirculation and main steam piping were walked down. The maximum pre-op temperatures reached during testing was 470 deg. F on the Recirculation lines and about 430 deg. F on the main steamlines. This walkdown verified that there were no restraints to thermal expension and that all hangers and snubbers were operating as nominally expected at ambient, 300 deg. 1 50 deg. F, maximum preoperation temperature or normal operating temperature, and at return-to-ambient. In addition to the walkdowns, remote displacement readings of the piping were recorded by 35 lanyard potentiometers connected through the ERIS computer system. Readings were taken at 50 deg. 110 deg. F intervals during the hot recirculation preoperational test and three subcequent nuclear heatup cycles. ggg The expansion taken during the third heatup cycle is summarized in Table 3.14-1. Also included is -a summary of the test exceptions written during the test. l 1 3-62
l O srsr== =xra=S1o= 1-ST-17 TEST l TE CONDITION DESCRIPTION STATUS 1 OV Thermal expansion data at rated Closed conditions was not taken since rated conditions were never achieved. Closed because test will be repeated during nuclear heattp. 2 OV SA6-MX, SA7-MY, and SD6-MX failed Closed Level l criteria. GE Piping Design evaluated the data and determined it was acceptable since the piping had not reached rated temperature. 3 OV Recirc: 11 points failed to reach Closed Level 2 limits, Main Steam:' 15 O points failed to reach Level 2 limits. See TE-4 4 OV Travel stops were not removed Closed from constant support hangers GE Piping Design evaluated the data'for TEs 3 and 4 and determined that the data was acceptable and that no over-load conditions had occurred. 5 OV Potential interferences to thermal Closed expansion were not resolved. Walkdowns prior to heatup showed that the interferences had cleared. 6 HU Numerous potential interferences Closed to thermal expansion were observed during ambient walkdown. Interferences were monitored during heatup and return-to-ambient. Insulation was notched as required to assure no actual interferences occurred. O 3-63
SYSTEM EXPANSION , 1-ST-17 { TEST l TE CONDITION DESCRIPT10N STATUS l l 7 HU SA6-MZ failed Level 1 at inter- Closed mediate temperature. SA6-MX l and SA6-MZ were reversed in the pipe expension data base. The error was corrected with no impact on the remainder of the i heatup cycle. 8 HU Twenty points failed Level 2 Closed criteria at rated during first heatup cycle. GE Piping Design reviewed the test results and found them acceptable. 9 HU A pipe expansion report was not Closed taken at 300 deg. F during g second heatup cycle. Accepted W "as-is". 10 HU Twenty-two points failed Level 2 Closed limits during second heatup cycle. GE Piping Design reviewed the test results and found them acceptable. 11 HU Forty-six piping supports failed Closed to meet Level 2 criteria for rated and/or return-to-ambient movement. GE Piping Design reviewed the test results and found them acceptable. 12 HU Initial walkdown data was Closed recorded or measured in-correctly for 5 piping supports. The data was retaken during the next heat up cycle and the results were acceptable with one hanger not meeting ambient / return to ambient Level 2 criteria.
~
This exception was included with TE-ll. O 3-64
O S1STE =xe==SIO= 1-ST-17 TEST TE CONDITION DESCRIPTION STATUS 13 HU The third cycle heat up data was Closed not taken during test condition heatup. The data was taken during test condition one with 21 test points failing Level 2 criteria. GE Piping Design reviewed the test results and found them acceptable. O O 3-65
I O O O SYSTEM EXPANSION 1-ST-17 i THERMAL EXPANSION ACCEPTANCE CRITERIA /RESULTS
! TABLE 3.14-1
! MAIN STEAM LANYARD POTS (inches) } i Level 1 i j 8
. Level 2 ,
i 8 1 I I I i , ! I I l TEST POINT l l MEASURED
- l 1 CRITERIA **
, i DISPLACEMENT , EVALUATION l
' i e i SA2-MX -2.561 -2.035 -1.806 -1.679 -1.153 Y SA6-MX -2.525 -2.100 -1.730 -1.843 -1.417 L II SA6-MY 0.786 0.665 0.271 0.279 0.159 L II SA6-MZ 1.488 1.030 1.188 0.799 0.341 L II l SA7-MY 2.312 2.142 1.905 1.954 1.784 L II SA8-MY 3.310 1.145 0.845 0.888 -1.277 L II SA9-MX -3.683 -1.906 -1.710 -1.613 0.164 Y SB2-MX -3.440 -2.046 -1.915 -1.646 -0.252 Y SB6-MX -3.077 -2.301 -2.472 -2.085 -1.310 L II SB6-MY 1.679 1.058 0.346 0.673 0.052 L II SB6-MZ -2.866 -1.722 -1.151 -1.423 -0.279 L II SC2-MX -3.440 -2.046 -1.830 -1.646 -0.252 Y SC6-MX -3.077 -2.301 -2.356 -2.085 -1.310 L II SC6-MY 1.679 1.058 0.338 0.673 0.052 L II SC6-MZ 2.866 1.722 0.975 1.423 0.279 L II SD2-MX -2.391 -2.035 -1.814 -1.679 -1.323 Y SD6-MX -2.264 -2.089 -2.009 -1.832 -1.657 Y j SD6-MY 0.957 0.666 0.401 0.281 -0.010 Y SD6-MZ -1.479 -1.041 -0.784 -0.810 -0.372 L II 4
3-66
l O O O 1 i i ! SYSTEM EXPANSION 1-ST-17 ! THERMAL EXPANSION ACCEPTANCE CRITERIA /RESULTS I TABLE 3.14-1 (Cont'd) l l REACTOR RECIRCUALTION } NOTE The listed limits are for Loop A; the X and Z signs must be changed to obtain Loop B, X and Z limits. l RAl-MY/RB1-MY 0.703 0.417 0.282/0.256 0.230 -0.056 Y/Y RA2-MZ/RB2-MZ 1.954 0.877 0.709/ .645 0.630 -0.446 Y/Y RA3-MX/RB3-MX 3.262 0.509 0.258/ .358 0.322 -2.431 L II/Y RA3-MZ/RB3-MZ 3.171 0.556 0.498/ .294 0.309 -2.306 Y/L II RAS-MX/RB5-MX 4.000 0.306 .266/0.163 -0.556 -4.000 L II/L II RA5-MY/RB5-MZ 4.000 -1.454 -1.315/-1.268 -1.858 -4.000 L II/L II RAS-MZ/RBS-MZ 1.267 0.008 0.046/0.029 -0.314 -1.573 L II/Y RA6-MZ/RB6-MZ 1.761 -1.006 .767/0.697 -0.818 -0.063 L II/L II IIEAT CYCLE NO. 3, 520 DEGREES F. l ** Y = Yes, all criteria satisfied LII = Level 2 Criteric violation 1 3-67
f l O 3.15 O OMITTED r O 3-68
._. _ , . - _ - - - - - - - - - - - - - - - - - - ~ ~ - - - - ' - - ' ~ ~ ' ^ ' ~ " ' ~ ~ ~ ' ~ ' ' ~ ~ ~ ~ ~ ~ ' ~~
O coR= >=RroRMAMc= 1-ST-19 3.16 1-ST-19 CORE PERFORMANCE 3.16.1 Description The major objectives of this test are as follows: 0 To evaluate the core thermal power and flow 0 To evaluate whether the following core performance parameters are within limits:
- a. Maximum linear heat generation rate (MLHGR)
- b. Minimum critical power ratio (MCPR)
- c. Maximum average planar linear heat generation rate (MAPLHGR)
O The acceptance criteria applied to this test are shown in subsections 3.16.1.1 and 3.16.1.2. 3.16.1.1 Level 1 Criteria
- 1. The maximum linear heat generation rate (MLHGR) of any fuel rod during steady-state conditions shall not exceed the limit specified by the RBS Technical Specifications.
- 2. The steady-state minimum critical power ratio (MCPR) shall not exceed the minimum limit specified by the RBS technical specifications.
- 3. The maximum average planar linear heat generation rate (MAPLHGR) shall not exceed the limits specified by the RBS technical specifications.
- 4. Steady-state reactor thermal power shall be limited to the rated core thermal power and values on or below the design flow control line (100 percent rod line).
3.16.1.2 Level 2 Criteria None 3-69
CORE PERFORMANCE l-ST-19 3.16.2 Discussion 1-ST-19, Core Performance was performed at each d:ajor test condition to verify that core thermal limits were within Technical Specification limits and that eore thermal power and core flow were below their maximuus values. The plant process computer was used as the method of verification following its validation per 1-ST-13. During each test condition, the core thermal power and core flow were below their maximum values. Each of the core performance parameters (MLHGR, MCPR, and MAPLHGR) was verified to be within the acceptance criteria. No test exceptions were generated during the performance of this test. Table 3.16-1 shows the data for each test condition. O O 3-70
t O CORE PERFORMANCE 1-ST-19 TABLE 3.16.-1
% Power,% Flow, THERMAL LIMITING TECH SPEC TC ROD LINE LIMIT VALVE LIMIT 19.2% MLHGR 3.07 KW/FT < 13.4 KW/FT 1 22.8% MCPR 3.915 3 1.710 30% MAPLHGR 2.77 KW/FT -}l2.10KW/FT 34% MLHGR 4.25 KW/FT 5;13.4 KW/FT 2 30.6% MCPR 2.689 ;> 1.71 64% MAPLHGR 3.66 KW/FT [g11.8 KW/FT
( 45.3% MLHGR 7.30 KW/FT s;13.4 KW/FT 3 83.0% MCPR 2.683 2 1.519 57% MAPLHGR 6.61 KW/FT i;12.10 KW/FT 39.3% MLHGR 5.57 -<r13.4 KW/FT 4 26.0% MCPR 2.057 ;. 1.710 79% MAPLHGR 4.95 [;12.11 KW/FT l 74.4% MLHGR 8.47 KW/FT <;13.4 KW/FT 5 68.4% MCPR 1.742 2 1.317 97% MAPLHGR 6.92 KW/FT 5p10.82KW/FT 99% MLHGR 12.61 KW/FT g;13.4 KW/FT 6 98% MCPR 1.376 > 1.18 100% MAPLHGR 10.24 KW/FT 2;10.75 KW/FT I (1) 3-71
STEAM PRODUCTION 1-ST-20 3.17 STEAM PRODUCTION 3.17.1 Description The purpose of the Steam Production Startup Test, 1-ST-20, is to demonstrate that the nuclear steam supply system is providing steam sufficient to satisfy all appropriate warranties as defined in the contract. The acceptance criteria are shown in subsections 3.17.1.1 and 3.17.1.2. 3.17.1.1 Level 1 Criteria
- 1. The NSSS parameters ac determined by using normal operating procedures shall be within the appropriate license restrictions.
() 2. The NSSS will be capable of supplying amount steam in an and quality corresponding to the final feedwater temperature and other conditions shown on the Rated Steam Output Curve in the NSSS Technical Description. The Rated Steam Output Curve provides the warrantable reactor vessel steam output as a function of feedwater temperature, as well as warrantable steam conditions at the outboard main steam isolation valves. Thermodynamic parameters are consistent with the 1967 ASME Steam Tables. Correction techniques for conditions that differ from the preceding will be mutually agreed to prior to the performance of the test. 3.17.1.2 Level 2 Criteria None 3.17.2 Discussion Steam Production (1-ST-20), also referred to as the Warranty Run, was performed between 10 May and 15 May, 1986 at River Bend 1 under the. following plant conditions: (]) 100% Core Thermal Power 1014 MWE Gross Generator Output 12.4 M1bm/hr Feedwater Flow 3-72
STEAM PRODUCTION h 1-ST-20 3.17.2 Discussion (con't) 12.4 Mlbm/hr Steam Flow 1014 PSIG Reactor Pressure With the plant operating at these "near-rated" conditions for 100 continuous hours, various plant parameters were recorded both hourly and every ten minutes during two test runs of four hours each. The reactor power level and nuclear steam supply system output were computed from measurements of:
- 1. Feedwater temperature and pressure
- 2. Feedwater flow rate
- 3. Recirculation pump power
- 4. Cleanup system flow and temperature
- 5. CRD system flow and temperature 6.
7. Water carry over (per 1-ST-1) Steam pressure near outboard MSIV (using g a temporary installed pressure transmitter)
- 8. Reactor Steam dome pressure A heat balance was calculated using the following inputs:
Value Used
- 1. Feedwater Power 1441.55 MW
- 2. Steam Power 4331.4 MW
- 3. CRD Power 0.63 MW
- 4. Recirculation Pump Power 6.04 MW
- 5. Cleanup System Power 3.57 MW
- 6. Fixed Power Losses 1.1 MW The significant results of 1-ST-20 are:
- 1. Reactor Power 2887.8 MWT
- 2. Reactor steam exit moisture carry over 0.0022%
- 3. Downstream of MSIV's steam moisture carryover 0.4%
- 4. Steam flow rate 12.404 Mlbm/hr All test acceptance criteria were satisfied and the Warranty Run was completed successfully. Below is a list of all 1-ST-20 test exceptions (TE's).
3-73
r STEAM PRODUCTION 1-ST-20 TE DESCRIPTION STATUS 1 CRD cooling water temperature was Closed not taken. A condensate tempera-ture was used. 2 Several "P-l's" were not taken dur- Closed ing the warranty run. Accepted, sufficient data was obtained. 3 The steam carryover measurement was Closed repeated per 1-ST-1, generating the need for recalculations. () 4 The temporary outboard MSIV pressure transmitters required a post cali-Closed bration. This has been performed. O 3-74
pa - A - O 3.18 O OMITTED l t i O 3-75
PRESSURE REGULATOR 1-ST-22 3.19 l-ST-22 PRESSURE REGULATOR 3.19.1 Description The purposes of this test are: 0 To determine the optimum settings for the pressure control loop by analysis of the transients induced in the reactor pressure control system by means of the pressure regulators, O To demonstrate the backup capability of the pressure regulators via simulated failure of the controlling pressure regulator, O To demonstrate smooth pressure control transition between the turbine control valves ( and bypass valves when the reactor steam generation exceeds the steam flow used by the turbine, and 0 To demonstrate that other affected parameters are within acceptable limits during pressure regulator induced transient maneuvers. The acceptance criteria applied to this test are shown in Subsections 3.19.1.1, 3.19.1.2 and 3.19.1.3. 3.19.1.1 Level 1 Criteria
- 1. The transient response of any pressure control system related variable to any test input must not diverge.
3.19.1.2 Level 2 Criteria
- 1. Pressure control system related variables may contain oscillatory modes of response. In these cases, the decay ratio for each controlled mode of response must be less than or equal to 0.25. (This criterion does not apply to. tests involving simulated failure of one regulator with the backup regulator taking over.)
3-76 l
~
l l l PRESSURE REGULATOR g 1-ST-22 3.19.1.2 Level 2 Criteria (Cont'd)
- 2. The pressure response time from initiation of pressure setpoint change to the turbine inlet pressure peak shall be 110 seconds.
- 3. For all pressure regulator transients the peak neutron flux and/or peak vessel pressure shall remain below the scram settings by 7.5% and 10 psi respectively.
4 Pressure control system deadband, delay, etc., shall be small enough that steady state limit cycles (if any) shall produce steam flow variations no larger than 1 0.5 percent of rated steam flow.
- 5. The variation in incremental regulation (ratio of the maximum to the minimum value of the quantity,
" incremental change in pressure control signal /
incremental change in steam flow", for each flow range) shall meet the following:
% of Steam Flow Obtained With Valves Wide Open Variation 0 to 85% $4:1 85% to 97% 3C2:1 85% to 99% sg5:1 3.19.1.3 Level 3 Criteria
- 1. Control or bypass valve motion must respond to pressure inputs with deadband (insensitivity) no greater than 1 0.1 psi.
l O 3-77 i
PRESSURE REGULATOR l-ST-22 3.19.2 Discussion The Turbine Control System is supplied by General Electric and consists of 4 full arc Control Valves and two bypass valves, each 5% capacity for a total 10S bypass capacity. Testing was conducted on the Pressure Regulator system at all test conditions. Testing was conducted in three modes: A. With the system operating normally, load limit not limiting, controlling pressure with the control valves, B. The system operating with the load limit limiting, with the Bypass valves open and controlling pressure and C. The system operating just below the load limit such ( that an upward pressure transient would cause the system to transfer pressure control from the control valves to the Bypass Valves, as the load limit becomes limiting, (TC-3 only). i ' Testing consists of inputting a 7.5 psi step change via a step generator into the controlling regulator, and analyzing the response of the system. Also, the regulators are simulated to fail so that the other regulator will take control. Control System Linearity data is taken, the system response evaluated and regulator settings optimized. Final Control System settings are summarized in Table 3.19-1. The pressure response to step changes for all conditions are summarized in Table 3.19-2 and discussed in the following.
- 1. Test Condition 1 On 12/5/85, in Test Condition 1 at 5% power, Pressure Regulator Testing while controlling on the Bypass Valves was initially conducted.
This testing had to be reperformed under TE-1 because the ERIS system did not record all of the data required for analysis. O 3-78
PRESSURE REGILATOR h 1-ST-22 3.19.2 Discussion (Cont'd) Pressure Regulator Step changes of 7.5 psi were input, resulting in a 959 psig peak pressure with a negligible rise in APRMs. All of the applicable decay ratios were within the quarter damped criteria and the maximum delay time from the pressure setpoint change to peak turbine inlet pressure was 5 seconds, well within the specified time ot 10 seconds. The Pressure Regulator Failovers were not completed successfully as there was an offset of 2-3 psig between the A& B regulator channels. TE-2 was written on the failure to test the Pressure Regulator Failovers. The TE-2 retest was conducted after the procedure was changed to null out the offset between the pressure regulators during testing. However, the data on ERIS was overwritten prior to analysis ggg being performed. Testing was reperformed per TE-3 and consisted of simulating a Pressure Regulator Failure by inputting 20 psi steps into the channel to be failed. The maximum pressure rise seen was 10 psig and the APRM flux rise was again negligible. TE-4 was written since the retest was l done at 950 psig and thus the peak pressures could l not be compared directly. The 920 psig data was i extrapolated to 950 psig to effect a direct comparison and complete the Level 2 criteria. Pressure Regulator Testing with the control valves controlling pressure was initiated at 23% power, with the generator on line at 185 MWE. Step Levels of 8.75 psi were input for the Pressure Regulator Step changes and Step levels of 20 psi were utilized for the Pressure Regulator Failures. The maximum pressure reached was 970 psig with a peak APRM rise of 3%, both well within the acceptance criteria. The maximum response time from l 3-79 l _
O ra=ssua= == cut ^ rom 1-ST-22 3.19.2 Discussion (Cont'd) the setpoint changes to the peak turbine inlet pressure was 7 seconds vs. 10 seconds allowed. The maximum decay ratio was 0.13, on the Bypass Valve Position, which satisfactorily meets Level 2 criteria.
- 2. Test Condition 2 Pressure Regulator testing at Test Condition 2 was conducted at a power level of 32% for both Bypass Valves and Control Valves controlling pressure.
The peak pressure of 968 psig was noted during a simulated pressure regulator failure while controlling with the Bypass valves. The peak APRM flux rise of 7.5% was observed during a simulated
'N pressure regulator failure while controlling on the control valves. All of the response times for the
! step changes were less than the 10-second Level 2 criteria. Several difficulties were encountered during performance of this testing, ERIS data was not complete for the failover from B to A Regulator Upscale. TE-7 was written to retest this transient. Another difficulty was that only one of the control valve failover tests out of four was performed successfully. For the unsuccessful tests, a 20 psi step was input, but the regulator failure circuitry never detected a fault. This was due to the extremely rapid response of the control valves, which brought the pressure under control more quickly than the bypass valves and did not create a large enough deviation or error for the fault-sensing circuitry to detect. TE-6 was written for this problem. General Electric Engineering approved the performed failover test stating that this test was adequate to demonstrate operability of the failure detection logic. O 1 l l 3-80
PRESSURE REGULATOR l-ST-22 1 llI 3.19.2 Discussion (Cont'd) Pressure Regulator Testing for Test Condition 3 was conducted at 70% Reactor Power. Test results from the control valve steps showed a stable response with no measurable decay ratios. The maximum time from the input of the step to the maximum turbine throttle prassure was 5.6 seconds, well within the Level 2 criteria of 10 seconds. The maximum pressure reachod was 990 psig, with only a 2 psi overshoot on the upward step. The peak Neutron Flux rise was 2%. The test results for the Bypass Valve Incipient mode also showed a stable response with no measurable decay ratios. The longest time response measured was 9.2 seconds. The maximum pressure reached was 993 psig, with a 3 psi overshoot and a peak APRM rise of 3.5%. Exception TE-9 was written since the Pressure Regulator Testing with the Recirculation System in llh Flux Control could not be accomplished. At present 1-ST-29 Flux Controller Tuning has not been completed.
- 4. Test Condition 5 Pressure Regulator Testing for Test Condition 5 was conducted at 60% 3eactor Poder.
Test results from the control valve steps showed a stable response with no measurable decay ratios. The maximum time from the input of the step to the maximum turbine throttle pressure was 6.4 seconds. The maximum pressure reached was 983 psig, with only a three (3) psi overshoot on the upward step. The peak Neutron Flux rise was 3%. O 3-81
O rarsso== ==ou'^'on 1-ST-22 3.19.2 Discussion (Cont'd) The test results for the Bypass Valves also showed a stable response with no measurable decay ratios. The longest time response measured was 7.6 seconds. The maximum pressure reached was 984.5 psig, with a 3 psi overshoot and a peak APRM rise of 3.0%.
- 5. Test Condition 6 Pressure Regulator Testing for Test Condition 6 was conducted at 93% Reactor Power.
Test results from the Control Valve Steps showed a stable response to all steps with no measurable decay ratios. The longest time from the input of the step to the maximum turbine throttle pressure was 12.8 seconds. Test Exception 15 was written as ! ^ this time exceeds Level 2 criteria of 10 seconds. This test exception has been evaluated and accepted by General Electric Engineering. The maximum pressure reached was 1023 psig with only a 2 psi overshoot on the upward step. The peak neutron flux rise was 3%. Generator load changed by approximately 10 MWE during each step change. Text Exception 15 was written due to the loss of ERIS data for the "A" regulator step up. The test results for the Bypass Valve Steps also showed a stable response with no measurable decay ration. The longest time response measured was 6.0 seconds. The maximum pressure reached was 1024 psig, with a two (2) psi overshoot and peak APRM l rise of 4%. Test results for the Bypass Valve Regulator Failures showed that the automatic backup feature of the pressure regulator was satisfactorily demonstrated. Test Exception 12 was written because only the downward failures were performed, as the margin to scram at 93% power was judged to I be inadequate for the upward failures. Both the "A" and "B" regulators, when failed, switched over w 3-82
PRESSURE REGULATOR h 1-ST-22 l 3.19.2 Discussion (Cont'd) after a delay of 2.5 seconds, causing a 7 psi
. reactor pressure decrease. Peak neutron flux rise was 4%.
- 6. Test condition 4 Pressure Regulator Testing for Test Condition 4 was conducted at 40% Reactor Power on natural circulation.
Test results from the control valve steps showed a stable response to all steps with only small decay l ratios during the transients. The maximum time from the step input to the maximum turbine throttle pressure was 6.3 seconds which satisfied the 10 second criteria. The maximum pressure reached was j 967 psig with a peak neutron flux rise of 3.6%. lll Test results for the bypass valves steps also l showed a stable response. One step (a downward l step with the 'A' pressure regulator in control) resulted in a pressure response time of 10.1 seconds. This exceeded the Level 2 criteria of 10 seconds. Test Exception 19 was written to document this. The maximum pressure peak was 967 psig and the maximum neutron flux rise was 4%. The results of the bypass valves presssure l regulator failures was unexpected in that the "B" pressure regulator did not transfer to the "A" pressure regulator during the upscale simulated failure. This discrepancy is. documented by Test Exception 14 The failover testing from the "A" to "B" regulator and the "B" to "A" regulator downscale was successful. O l l 3-83 I
PRESSURE REGULATOR 1-ST-22 0 3.19.2 Discussion (Cont'd)
- 7. Power Ascension Testing In the power ascension portion of 1-ST-22 data was collected from 5% to 100% power in order to verify the linearity of the control system over the entire control range and verify that the system deadband delay is such that the steady state steam flow variation is within acceptable limits. When analyzed, the data collected yielded a maximum variation of 1.12% for 0-60% power and 1.28% for 60-100% power. Both numbers exceeded the Level 2 criteria of + 0.5% of rated steam flow. These deviations are~ documented in Test Exceptions 8 and 18 respectively.
The linearity of the system is determined by the variation in incremental regulation, and was , excellent up to 60% power. The measured value of incremental regulation (the ratio of the maximum to the minimum value of the quantity " incremental (]) change in pressure control demand / incremental change in steam flow") for the 0-85% steam flow region was 3.5 to 1 which meets the Level 2 criteria of less than 4 to 1. A distinct non-linearity is seen beginning at 60% power as the Turbine Steam flow drops off as Steamflow Demand increases, relative to the linearity displayed at lower Turbine Steam Flows. Test Exception 17 was written as the Incremental Regulation Level 2 criteria for the 85-97 steamflow regions could not be evaluated due to insufficient data and the MSR's being out of service. Test Exception 20 was written due to the linearity data being taken at power levels greater than indicated due to incorrect Feedflow calibration. TE-13 was written as the pressure regulator testing with the recirculation system in flux control could not be accomplished. 1-ST-29 flux controller tuning has not been completed. The following is a summary of the Test Exceptions for 1-ST-22 along with the status as of 15-Jul-86. C O 3-84
PRESSURE REGULATOR h 1-ST-22 TEST TE CONDITION DESCRIPTION STATUS i 1 1 ERIS test data lost for TC-1 testing Closed 2 1 Could not perform pressure regulator Closed failures 3 1 ERIS test data for TE-2 retest not Closed complete 4 1 TE-2 retest performed at 920 psig in- Closed
, stead of 950 psig 5 1 Transfer data from Rev. O to Rev. 1 Closed 6 2 h Could not perform pressure regulator Closed l failures on control valves 1
7 2 ERIS test data not obtained for "B" to Closed "A" to failure upscale 8 PA Exceeded Level 2 criteria of Steamflow Open variation for 0-60% Steamflow. General Electric Engineering evaluating 9 3 Pressure regulator testing for Test Open Condition 3 was not performed with the recirculation system in the flux control mode. Flux testing is under consideration 10 5 ERIS test data not obtained during TC-5 Closed testing 11 5 Insufficient ERIS test data to determine Closed decay ratios during TC-5 testing 12 6 Cannot perform upscale pressure closed regulator failures during TC-6 testing l' 13 6 Pressure regulator testing for test Condition 6 was not performed with the Open g recirculation system in the flux control 3-85
PRESSURE REGULATOR 1-ST-22 TEST TE CONDITION DESCRIPTION STATUS 14 4 Could not perform pressure regulator Open failure during TC-4. General Electric Engineering is evaluating 15 6 Missing ERIS data for pressure Open regulator "A" CV stepup. General Electric Engineering is evaluating 16 6 Upward step on "B" pressure regulator Closed control valves failed Level 2 criteria on pressure response. 17 PA Could not determine Incremental Open C_/) regulation for regions of 85-97% and 85-99% steamflow to satisfy Level 2 criteria. Open pending retest. 18 PA Exceeded Level 2 criteria of steam Open flow variation for 60-100% steamflow. General Electric Engineering is evaluating 19 4 Downward step on "A" pressure regula- Closed tor, bypass valves, failed Level 2 criteria on pressure response 20 PA Linearity data taken was incorrect due Closed to the feedwater flow being calibrated incorrectly l I i O i 3-86 I _ _ . _ _ _ _ _ . _ _ _ _ _ . _ . . _ . . . ._ . _ _ _ _ _ __ J
~
PRESSURE REGULATOR h 1-ST-22 TABLE 3.19-1 SYSTEM ADJUSTMENT SETTINGS Regulator Component Dynamic Settings "A" "B" Pressure Regulator Proportional Gain 3.25 3.22 Pressure Regulator Lead TC 2.7 1.8 Pressure Regulator Lag TC 5.5 5.5 ( Steam Line Compensator Z1/Z2 8.0 9.0 Steam Line Compensator Z2 6.0 6.0 1 Steam Line Compensator T3 8.0 4.0 Steam Line Compensator To 6.0 6.0 g Load Demand Rate Limiter Local Bias 3.47 3.02 Load Demand Rate Limiter Local Step 3.0 4.09 Load Demand Rate Limiter Load Rate 9.99 9.82 l O 3-87 l t
O O O Shn6t 1 of 2 PRESSURE REGULATOR 1-ST-22 Table 3.19-2 l Pressure Regulator 'A' Response to Setpoint Changes, Dome Pressure Control Test Valve Step Time To Peak Vessel Peak Neutron Decay Condition in ' PSI) Peak Pressure Flux (%) Ratio Control Reactor (psig) Pressure (SEC) . 1 BPV* 7.5 4.5 956 5 .08
-7.5 5.0 - -
- g. 2 5 j BPV 7.5 4.0 958 25 0 i -7.5 7.0 - -
0 i 2 BPV 7.5 6.0 959 32 4.25
-7.5 8.0 - -
<<.25 CV 7.5 5.0 958 34 g g. 25
-7.5 5.0 - -
(<.25 3 BPV Incipient 7.5 3.6 991 73.5 0
-7.5 5.6 - -
0 CV 7.5 3.2 992 74
-7.5 5.6
<<.25
(<.25 4 BPV 7.5 6.6 967 44 .06
-7.5 10.5 - -
.11 CV 7.5 5.4 967 43.6 0 l -7.5 6.3 - -
0 5 BPV 7.5 985
-7.5 5.2 7.6 63 (<.25
(<.250
- CV 7.5 5.2 983 62
-7.5 6.4 - -
0 ! 6 BPV 7.5 5.4 1024 96 (4'. 2 5
-7.5 5.1 4 4 25 l -
CV 7.5 7.0 1022 95.6 0
-7.5 TE-15 - -
TE-15 i
- Generator Not on Line
- 3-88
O O O Sheet 2 of 2 PRESSURE REGULATOR 1-ST-3.19-2 ll 4 Table 3.19-2 i Pressure Regulator 'B' Response to Setpoint Changes, Dome Pressure Control ? ! Test Valve Step Time To Peak Vessel Peak Neutron Decay Condition in (PSI) Peak Pressure Flux (%) Ratio control Reactor (psig) Pressure (SEC) . I
! 1 BPV* 7.5 4.4 959 5.8 .12
-7.5 5.0 i
BPV 7.5 5.0 958 25 ft.25.13
-7.5 6.0 - -
0 j 2 BPV 7.5 5.0 959 34
-7.5 7.0 -
44.25 4.<. 25 l CV 7.5 6.0 959 32
! -7.5 6.0 44.25 ] 3 BPV Incipient 7.5 9.2 992 74 (4 25 0
j -7.5 8.4 - - 0 { CV 7.5 4.0 993 74 g.25
-7.5 5.6 - -
g.25 4 BPV 7.5 5.1 966 44 .08
-7.5 6.9 - -
.11 l'
CV 7.5 5.4 966 44 0
-7.5 6.0 - -
0
. 5 BPV 7.5 5.6 985 62' g. 25
-7.5 7.2 -
(<.25 j CV 7.5 5.6 983 62 g.25
- -7.5 6.0 -
6 BPV 7.5 5.1 1024 (<.25 97 (K.25 j -7.5 6.0 - - q.25 CV 7.5 12.8 1023 96 0
-7.5 9.2 - -
0 i l
- Generator Not on Line 3-89
i j l f'T U WATER LEVEL SETPOINT, MANUAL FEEDWATER FLOW CHANGES 1-ST-23A . l l i 3.20 1-ST-23A WATER LEVEL SETPOINT, MANUAL FEEDWATER FLOW CHANGES l 3.20.1 Description The major objectives of this test are to demonstrate and document that the feedwater control system has been properly adjusted to provide acceptable reactor water level control. The following will be demonstrated: 0 The startup level control system, including the startup level controller and the startup level flow control valve, will be tuned for optimum response. O The individual level control valves will be dynamically tested by injecting steps into the () individual flow control loops. O The master level control system will be dynamically tuned to provide adequate reactor water level control over the spectrum of power operating conditions. l The acceptance criteria applied to this test are shown } in Subsections 3.20.1.1, 3.20.1.2 and 3.20.1.3. 3.20.1.1 Level 1 Criteria The transient response of any level control I system-related variable to any test input must not l diverge. 3.20.1.2 Level 2 Criteria Level control system-related variables may contain oscillatory modes of response. In these cases, the decay ratio for each controlled mode of zesponse must be less than or equal to 0.25. O 3-90 l _ _ - - _ _ -__ - - - - - - - - - - - - - - - - -
WATER LEVEL SETPOINT, MANUAL FEEDWATER FLOW CHANGES
^
h 1-ST-23A 3.20.2.1 Level 2 Criteria (Cont ' d) The open loop dynamic valve position response of each feedwater flow control valve to small (410 %) step disturbances shall be: -
- 1. Maximum time to 10% of a step f 1.2 seconds disturbance 2.
Maximum time from 10% to 90% of f 2.1 seconds a step disturbance
- 3. Peak Overshoot (% of step f15%
disturbance)
- 4. Settling time 100% +5% of step 14.0 seconds disturbance The maximum rate of response of the feedwater flow actuators to large (>20% of pump flow) step disturbances (g) shall be between 3.3% and 8.3% nuclear boiler rated (NBR) flow /second.
At steady state generation for the 3/1 element systems, the input scaling to the mismatch gain should be adjusted such that level error due to biased mismatch gain output should be within + or - ) inch. 3.20.1.3 Level 3 Criteria Initial settings of the function generators should give a straight line. The function generators must be adjusted so that the change in slope (actual fluid flow change divided by demand change for small dist'Jrbances) shall not exceed a factor of 2 to 1 (maxim am slope versus minimum slope) over the entire 20% to 100% feed flow range. Also the function generators should be used to minimize the differences between feedwater actuators (valves). O 3-91
WATER LEVEL SETPOINT, MANUAL FEEDWATER FLOW CHANGES 1-ST-23A 3.20.2 Discussion Dynamic testing of the feedwater flow control system was accomplished in Test Conditions Heatup and 2 through 6. , Data .was collected throughout power ascension for function generator calibration. Level setpoint changes of + 3 and + 6 inches were scheduled for single and three element control in Test Conditions 2 through 6 with + 3 inch steps only performed in Test Condition Heatup. In TC-6, + 20% valve position steps were injected into the individual valve control loops; + 10% individual valve and the mismatch gain verifications were performed during TC-3 and 6. Summary of each Test Condition follows. An overview of the test exceptions is given at the end of the subsection.
- 1. Tast Condition Heatup O During Test Condition Heatup, initial startup controller tuning was performed. Reactor level showed a decay ratio of 0.28. This was larger than the level 2 criteria of 4 0.25 and TE-3 was written for this with the disposTtion being that is was acceptable due to a very stable response. All other related variables show a negligible decay ratio. TE-2 and TE-7 were written since the ERIS signal for IC33-LVD002 failed after a scram damaged the end device. This signal is not actually analyzed but used for troubleshooting. Therefore it was accepted "as is". TE-5 was written since changes had been made after final tuneup settings were tested. TE-6 was written in order to perform system tuning as a result of unsatisfactory system response (decay ratio 4 .25), discovered while performing testing to cloie out TE-5.
O 3-92
WATER LEVEL SETPOINT, MANUAL FEEDWATER FLOW CHANGES h 1-ST-23A 3.20.2 Discussion (Cont'd)
- 2. Test Condition 2 During TC-2, setpoint level steps were introduced, to observe the dynamic response of the master level control system, by quickly changing the thumbwheel tape set on the master level controller by an amount equal to the desired step. TE-9 was written to repeat testing since the valve configuration was altered before testing was completed. TE-10 was taken to increase the margin from a feed pump trip on low suction pressure during level steps. Here,
+/-5 inches step changes were injected in the three element mode instead of the +/-6 inches steps.
This does not affect any level criteria and this TE was closed. TE-11 was taken since there was a Level 2 violation on decay ratio. The highest decay ratio for ggg feedwater flow is 0.55 while the decay ratio for the feedwater reg. valve is 0.52. The criteria calls for a maximum decay ratio of $ 0.25. For the given configuration the feedwater control system demonstrated adequate response to control water level. The TE is closed since response was adequate and was further optimized in Test Condition 3.
- 3. Test condition 3 There were 3 portions of the TC-3 testing. The first portion involved data collection of the mismatch data (the difference between feedwater flow and steam flow) and verification that a mismatch of less than 1 inch met the level 2 criteria. No adjustment was necessary to meet the Level 2 criteria. The second portion consisted of injecting + 10% step changes into the individual feedwater valve dynamic loops with a step change generator to verify open loop response. In the third portion, the total loop was evaluated by observing the response of the level control system to level setpoint step changes.
O 3-93
l l O WATER LEVEL SETPOINT, MANUAL FEEDWATER FLOW CHANGES 1-ST-23A 3.20.2 Discussion (Cont'd) During dynamic testing in TC-3, only the "B" and "C" feedwater regulating valves were in service. ' TE-15 was written to test FWRV "A" at a later date. A stro generator was utilized to inject + 10% valve position steps into the valve being tested in an open loop configuration. The valve (s) not being tested remained in Auto control and compensated for the injected step. Valves "B" and "C" met Level 1 Criteria for f.ndividual steps. The "B" FWRV met all level 2 criteria except overshoot. It exceeded the allowed 15% criteria with a 56% value resulting in TE-17. For "C" FWRV the ERIS valve position signal was not available for data acquisition. TE-16 documented this condition. TE's 15, 16 and 17 were cleared due to retesting performed per TE-18. TE-18 resulted since the feedwater flow control valves dynamic characteristics were altered
'N by replacing discontinued AP532 Bailey positioners
('d with AP932 units. Theses units were determined to be slower by the vendor. Subsequently, additional tuning was required. For the master level control steps, all Level 1 and 2 Criteria were met on the + 3 and + 6 inch level setpoint steps into the master leveI controller. A quick adjustment of the thumbwheel tape set was the method used to provide the step function. A 2-3 inch limit cycle was observed and was further tuned in Test Conditions 5 and 6.
- 4. Test Condition 4 TC-4 testing was performed chronologically after TC-6 testing. Therefore, basically only demonstration tests were performed. Level 1 and 3 critoria were met. However, the level 2 criteria of a decay ratio was exceeded in three element with a 0.47 for the negative steps. Also the single element decay ratio could not be evaluated due to the very large steady-state limit cycle (3-4 inches) which was a result of the slower AP932 Baily positioners. TE-31 documented the dacay ratio problems and is being evaluated by General n)
\m Electic Engineering. 3-94
t WATER LEVEL SETPOINT, MANUAL FEEDWATER FLOW CHANGES h 1-ST-23A 3.20.2 Discussion (Cont'd)
- 5. Test Condition 5 TC-5 testing consisted only of + 3 and 6 inch setpcint level steps. Only "B" and "C" FWRV were used since mechanical problems with the "A" FWRV precluded its use. The largest decay ratio observed was 0.175 (feedwater flow) which met the level 2 criteria. No test exceptions were generated in TC-5.
v
- 6. Test Condition 6 There were three (3) sections of 1-ST-23A performed under Test Condition 6. They were:
i
~
- 1. Individual Feedwater Control Demonstration Test
- 2. Master control One and Three Element Demonstration Test
- 3. Mismatch Gain Output Verification The Individual Feedwater Control Demonstration Tests were performed by inserting positive and negative 10% and 20% step changes into each feedwater regulating valve (FRV) individually.
Data was collected by the ERIS computer, analyzed, and compared to the acceptance criteria. TE-20 was written because the response times of the FRV's did not satisfy the criteria of less than 2.1 seconds. . The response times ranged from 2.2 seconds to 9.9 seconds. IED 3-95 m r-
O WATER LEVEL SETPOINT, MANUAL FEEDWATER FLOW CHANGES U 1-ST-23A 3.20.2 Discussion (Cont'd) TE-21 address the "B" FWRV settling time of 15.05 seconds. The criteria calls for a settling time of 414 seconds. TE-22 was written to document that the maximum rate of response of total feedwater flow to large step disturbances exceeded the criteria of 3.3% to 8.3%. The maximum rate of response was 52.6%. TE's 20, 21, and 22 are open and are being evaluated by General Electric Engineering. TE-23 was written because the total steam flow signal was not available to analyze for decay ratio. Because the Reactor water level and feedwater flows were not oscillating or diverging, it was clear that total steam flow satisfied the criteria. This test exception has been closed. Otherwise there were no other test related ( parameters that displayed decay ratios greater than 0.25. All three (3) FWRV's satisfied the 1.2 second delay time criteria, and no overshoot was observed. The Master Control One and Three Element Demonstration Test was performed by using the Master Level Controller in both one and three element control. In each control configuration,
- positive and negative three inch and six inch level steps were manually introduced. Although, there was no divergent behavior, there was a large i steady-state oscillation for all three FWRV's when testing in one element control. This was a result of the insensitivity of the valves to small demand signal changes resulting in a larger time constant than could be compensated for electronically.
i O 3-96
WATER LEVEL SETPOINT, MANUAL FEEDWATER FLOW CHANGES h 1-ST-23A 3.20.2 Discussion (Cont ' d) This made analyzing for decay ratios impractical. Test exception 24 was written because of the inability to analyze the data for Level 2 decay ratio criteria. Level 1 and Level 3 criteria were satisfied. The Mismatch Gain Output Verification was performed by taking sets of data every 5% power along the 100% rod line. The purpose of the test was to verify that the Steam Flow / Feed Flow Output card does not result in a level error of greater than one inch (output between 0.903 to 1.09v). This criteria was satisfied.
- 7. Overview The final feedwater dynamic response verification was not performed. This consists of one and three element testing to be performed throughout the entire operable range of feedwater. Prior to Test Condition 6, the testing was performed with the system gain set for one, llg and then two valves in service. Performing this verification ensures that the gain settings determined for three valves in service at 100% power are sufficient for one valve in service at low power level. Test Exception 30 documents this exception.
The data from the individual feedwater control demonstration showed that there was no divergent behavior and all decay ratios were less than 0.25. The maximum delay time was specified to be 1.2 seconds. It was actually 2.35 seconds. The maximum response time was specified to be 2.1 seconds. The actual maximum response time was 14.6 seconds. The maximum settling time was specified to be 14 seconds. The actual maximum settling time was 75.4 seconds. Finally, the peak overshoot allowed was 15%. The maximum was 61%. These critoria violations were documented by test exceptions 25, 26, 28 and 27 respectively. O 3-97 1
O =Ar== t=v=t S=reo1=r, =A= oat r==o AT== roo= c=A=a S 1-ST-23A 3.20.2 Discussion (Cont'd) A test condition power ascension test, Function Generator Calibration, was specified to be performed as part of TE-19 of 1-ST-23A because the flow transmitters were recalibrated. Since that time, a number of modifications have been made affecting all three feed regulating valves including replacement of the Bhiley positioners (formerly AP 532) with AP 932 positioners. TE-19 remains open. It is a level 3 criteria concern. Although there are numerous Level 2 Criteria concerns, the Level control system is stable and responds well to transients, particularly large transients, on the system. The final setting (as of 15-Jul-86) on the startup and master level controllers end the 3 element dynamic compensator are as follows: Master Level Controller (C33-R600-1) DIAL ACTUAL Gain 2. 5 (x1) 2.8 i Reset R/M 0.7 (0.07 x 10) .55 Startup Level Controller (C33-R602) Gain 5.0 (x1) 4.1 Reset R/M 1.0 (.1 x 10) 1.2 3 Element Dynamic Compensator Lead (T-1) Sec 2.6 2.25 Lag (T-2) Sec 8.0 7.97 Gain .95 (9.5 x .1) 1.0 The test exceptions for 1-ST-23A are summarized as l follows along with the status as of 15-Jul-86. () 3-98 l
- - - . . . , , . , - - - - - - - - - - - - - - - .- - - - - - . - , - - - -, m . - - - - , - - - - - - - - - - - - -
WATER LEVEL SETPOINT, MANUAL FEEDWATER FLOW CHANGES 1-ST-23A TEST TE CONDITION DESCRIPTION STATUS 1 HU Contoller Dial Calibration not completed Closed 2 HU ERIS signal for C33-F002 startup level Closed control valve 3 HU Decay ratio for RX water level exceeded Closed 0.25 (0.28) 4 HU Dynamic response of each Level 1 flow Closed sensor is not available 5 HU Startup level controller changed after Closed completion of testing lll 6 HU Following changes to C33-R602-1 TE-5 was Closed performed without tuning of startup level control system 7 HU ERIS signal for C33-F002 is inoperable - Closed cannot evaluate level 2 criteria 8 2 Dial calibrations not completed Closed 9 2 Feedwater FCV configuration changed Closed during testing 10 2 + 6 inch setpoint level steps were not closed performed in 3 element since feed pump low suction pass alarm actuated 11 2 In 3 element control, decay ratio was closed exceeded O 3-99 i
( ) WATER LEVEL SETPOINT, MANUAL FEEDWATER FLOW CHANGE 3 1-ST-23A TEST TE CONDITION DESCRIPTION STATUS 12 PA/3 Did not take linearization data over Closed entire range 13 3 RX power and core flow were not con- Closed sistent with TC-3 14 3 Testing was performed outside the TC-3 Closed window 15 3 A FWRV was not operable to perform testing Closed 16 3 ERIS data for "C" FWRV is not operable Closed O k/ 17 3 "B" FWRV exceeded 15% overshoot criteria closed with 56% 18 3 Characteristics of FWRV's changed necessary Closed to reperform testing 19 6 Flow transmitters were recalibrated. Re- Open taking the function generator linearization data is under consideration. 20 6 Response times of FWRV's exceeded 2.1 secs. Open This is under evaluation by General Electric Engineering. 21 6 "B" FWRV exceeded settling time criteria Open of f 14 seconds (15.05s). This is under evaluation by General Electric engineering. 22 6 Feedwater flow response exceeded 3.3% - Open 8.3% with a value of 52.6%. This is under evaluation by General Elect..c engineering. 23 6 Total steam flow data not available for Closed analysis O 3-100
l WATER LEVEL SETPOINT, MANUAL FEEDWATER FIM CHANGES h l l-ST-23A ' TEST TE CONDITION DESCRIPTION STATUS 24 6 Decay ratios cannot be determined due to Closed excessive limit cycles 25 3 Delay time of "A" FWRV exceeded 1.2 secs Open (2.35 seconds). This is under evaluation by General Electric engineering. 26 3 Response time of a FWRV exceeded 2.1 Open seconds (14.6 seconds). This is under evaluation by General Electric engineering. 27 3 Peak overshoot of a FWRV was 61%. This is under evaluation by General Electric Open lll engineering. 28 3 A FWRV settling time of 75.4 seconds ex- Open ceeded criteria of 414 seconds. This is
~
under evaluation by General Electric engineering. 29 3 Portions of single element testing was Open not performed , 30 6 Final feedwater dynamic response verifica- Open tion was not performed. Dapending on the outcome of General Electric's evaluation, retesting may be performed. 31 4 Single element limit cycles make determina- Open tion of decay ratio impractical. This is under evaluation by General Electric engineering. l 32 6 Recorded data on incorrect revision sheets closed l l 3-101
h LOSS OF FEEDWATER HEATING l-ST-23B 3.21 1-ST-23B LOSS OF FEEDWATER HEATING 3.21.1 Description The major objective of this test is to demonstrate adequate plant response to a feedwater temperature loss. The acceptance criteria applied to this test are shown in subsections 3.21.1.1 and 3.21.1.2 3.21.1.1 Level 1 Criteria
- 1. The maximum feedwater temperature decrease due to a single failure case must be less than or equal to 100 degrees F. The resultant MCPR must be greater than the fuel thermal safety limit.
- 2. The increase in simulated heat flux cannot exceed the predicted Level 2 value by more than 2%. The ggg predicted value will be based on the actual test values of feedwater temperature change and initial power level.
3.21.1.2 Level 2 Criteria The increase in simulated heat flux cannot exceed the predicted value referenced to the actual feedwater temperature change and initial power level. 3.21.2 Discussion A loss of feedwater heating can be initiated in a number of ways. Stone and Webster Engineering performed a parametric study to determine the single failure scenario which would result in the largest drop in feedwater temperature. This analysis showed that if 1-CNM-AOV119, the bypass valve around the condensate demineralizers and low pressure heaters, was opened at power, the loss of flow through the low pressure heaters and subsequent drop in feedwater temperature would be the worst case single failure accident. The predicted drop in feedwater temperature at 100% reactor power was 35 degrees F. O 3-102 _ _-.. . . =
LOSS OF FEEDWATER HEATING l-ST-23B 3.21.2 Discussion (con't) This procedure was performed during Test Condition Power Ascension at 49% power, and Test Condition 6 at 94% power. The actual loss of feedwater heating was initiated by opening 1-CNM-AOV119 by means of a temporary test switch. The results are summarized in Table 3.21-1. During the test at 49% power, feedwater temperature stayed constant for approximately four minutes after 1-CNM-AOV119 was opened and then decreased 35 degrees F over the next four minutes. The final feedwater temperature was 315 degrees F, giving a total drop of 42 degrees F. While this was greater than the predicted temperature drop at 100% power, it was not expected that the 100 degrees F limit would be approached when the test would be performed in Test Condition 6. The results from Test Condition 6 are also summarized in llh Table 3.21-1. Feedwater temperature stayed constant for approximately eighty seconds after 1-CNM-AOV119 was opened and then decreased over the next nine minutes. The final feedwater temperature was 367 degrees F, giving a total average drop of 42.5 degrees F. This is only slightly greater than the temperature drop at lower power, and is well below the level one criteria of 100 degrees F. All criteria for both test conditions were met. One test exception was written against the test at 49% power due to a failure of the ERIS computer. This exception did not affect the results of the test since all of the necessary data was obtained from the plant process computer. This test exception is summarized below. TE DESCRIPTION STATUS 1 ERIS Failure - could not obtain Closed data from the ERIS computer. Plant process computer provided sufficient information. lll 3-103 l
LOSS OF FEEDWATER HEATING 1-ST-23B TABLE 3.21-1 TEST RESULTS TCPA TC-6 PARAMETER PRIOR AFTER PRIOR AFTER Reactor Power (%) 49.2 51.7 86.8 93.6 Reactor Pressure psig 951 951 1006 1008 Total Feedflow lb/hr 5.6 5.6 10.7 10.8 Core Flow lb/hr 55.7 55.8 74.5 74.65 Final FW Temp (F) 357 315 409 367 Limiting MCPR 2.371 2.265 1.566 1.492 Location of Minimum MCPR 7-22 7-22 29-18 27-18 O. MCPR Limit 1.503 1.493 1.227 1.203 1 'O 3-104
O >====^r== ro=> 2r1> l-ST-23C 3.22 1-ST-23C FEEDWATER PUMP TRIP 3.22 Description The major objective of this test is to demonstrate the capability of the automatic core flow runback feature to prevent low water level scram following the trip of one feedwater pump. The acceptance criteria applied to this test are shown in Subsections 3.22.1.1 and 3.22.1.2. 3.22.1.1 Level 1 Criteria None 3.22.1.2 Level 2 Criteria
- 1. The reactor shall avoid low water level scram by
{s'>) three inches margin from an initial water level halfway between the high and low level alarm setpoints. 3.22.2 Discussion On 5/25/86 Feedwater Pump "A" was tripped from 95% core thermal power. Reactor water level dropped to 31.5 inches and stabilized at 33 inches. The feedwater regulating valves went full open and the Feedpumps "B" and "C" current went to 310 Amps, just below the alarm point of 340 amps. The "A" feedpump was restarted ar soon as conditions stabilized (3 minutes) to avoid high motor temperatures on the *B" and "C" feedpumps. Tripping Feedpump "A" renulted in a margin to scram of 1 21.8 inches. The criteria was a margin of > 3 inches.
- The criteria was met, however, the purpose of the procedure was to demonstrate the capability of the flow control runback circuit to drop power sufficiently to prevent a scram. Level did not drop enough to cause a
! 3-105
FEEDWATER PUMP TRIP 1-ST-23C 3.22.2 Discussion (Cont'd) runback therefore this could not be demonstrated. On at least three (3) previous occasions the recire runback function operated as designed as documented in the Shift Test Logs. Since the runback circuit was not necessary to maintain the margin to scram due to the feedpump capacity, the feedpump trip transient becomes a milder transient and the runback function becomes a backup for this event.
"A" feedpump was chosen to be tripped as it has less capacity than the other two (2) feedpumps. "A" feedpump was previously modified and is scheduled to be reworked such that it has the same dP vs. flow characteristics as the other feedpumps.
The test exceptions generated for 1-ST-23C are listed below: TE DESCRIPTION STATUS 1 Could not demaDJ rest test Process Computer Closed Edits due to the urgency to restart "A". Power levels were recorded on ERIS data. 2 1-ST-23D (Maximum Feedwater Runout Capability) Closed was listed as a prerequisite to performance of 1-ST-23C and was not performed until after 1-ST-23C. Test results are acceptable. O 3-106
MAXIMUM FEEDWATER RUNOUT CAPABILITY l-ST-23D 3.23 1-ST-23D MAXIMUM FEEDWATER RUNOUT CAPABILITY 3.23.1 Description The major objective of this test is to provide a limitation on the maximum feedwater flow control valve position, if necessary, to ensure that the maximum feedwater runout capability is compatible with the licensing assumptions. The acceptance criteria applied to this test are shown in subsections 3.23.1.1 and 3.23.1.2. 3.23.1.1 Level 1 Criteria Maximum valve positions attained shall not exceed the positions which will give the following flows with the normal complement of pumps operating. () a. 130% NBR Flow at 1080 PSIA
- b. 130+0.2(1080-P rated)% NBR at P rated PSIA or 138% NBR Flow at 1040 PSIA 3.23.1.2 Level 2 Criteria The maximum valve positions must be greater than or equal to the calculated positions required to supply:
- a. With rated complement of pumps-115% NBR at 1080 PSIA l
- b. One feedwater pump tripped condition-80% NBR at 1042 PSIA 3.23.2 Discussion Data for 1-ST-23D, Maximum Feedwater Runout Capability was taken during Test Condition Power Ascension. '
Various plant process parameters were recorded by the () 3-107
MAXIMUM FEEDWATER FUNOUT CAPABILITY l-ST-23D 3.23.2 Discussion (Cont'd) ERIS and process computers at reactor powers between 55 and 100 percent with a full condensate and feedwater pump lineup (3 feedpumps, 3 feedwater regulating valves, 3 condensate pumps and two heater drain pumps on-line). ~ This data was utilized to produce characteristic curves for the individual components of the Condensate and Feedwater systems. The Condensate system was broken down into the Condensate Pumps, the Demineralizers, and the Low Pressure Heaters. The Feedwater system was broken down into the Heater Drain Pumps, the Second Point Heaters, the Feed Pumps, the Feed Regulating Valves, and the First Point Heaters. For each of these components, a differential pressure versus flow curve was generated. From these curves, plant performance under the conditions specified by the acceptance criteria was predicted. In two instances, data from other startup tests was used 9 to generate these characteristic curves, as it was not possible to obtain this data during steady-state conditions. It was planned to obtain each Feedwater Regulating Valves's dP vs. Flow Curve individually, however, this proved to be not practical operationally. Instead, this data was obtained in the actual plant conditions specified by the test, valves wide open, using the feedwater transient after the MSIV Full Isolation (1-ST-25B). Also, the dP vs. flow relationship for the condensate bypass line when valve CNM-AOV119 opened was obtained from the Loss of Feedwater Heating test, when the valve was opened to bypass the Low Pressure Heaters. The Level 1 acceptance criteria are written in terms of placing a limit on feed regulating valve positions, if necessary, to prevent excessive feedwater flow during a control system failure. The analytical approach for , 9 3-108
MAXIMUM FEEDWATER RUNOUT CAPABILITY l-ST-23D 3.23.2 Discussion (Cont ' d) this criteria was to demonstrate that the feed flow with the regulating valves full open meets the criteria, and no position limits are therefore required. Analysis predicted that the feedwater flow at 1080 PSIA would be 113.8% of rated feedwater flow with the feed regulating valves (FRV) fully open. This meets the criteria of less than 130%. The predicted feedwater flow at 1040 PSIA is 116% of rated with fully open FRV's. This meets the criteria of less than 138%. The Level 2 criteria are control system requirements to ensure that adequate feedwater flow is available during transients. They are also written in terms of limiting FRV position, but since no position limiting is required, they were analyzed for the FRV full open p/ . condition. With one feedpump tripped, the analysis s- predicts 92.1% NBR feedwater flow at 1042 PSIA. This is well above the criterion of greater than 80%. The criterion of 115% NBR at 1080 PSIA was evaluated in two conditions. Condensate valve 1-CNM-AOV119 bypasses the Condensate system demineralizer and low pressure heaters in the event of a turbine trip from high power in order to provide more feedwater flow and protect the condensate demineralizer beds from damage in this condition. The analysis was performed assuming the bypass valve does not open, and heater drain pumped forward flow is normal. It was also performed assuming the bypass valve opens and the heater drain flow stops. In the case of 1-CNM-AOV119 opening, the analysis predicts 116.5% NBR. This meets the criterion of greater than 115%. In the case of the bypass valve not opening, the predict feedwater flow is 113.8%, which does not meet the criterion. Test Exception 3 was written against this deficiency and is being evaluated by General Electric Engineering. i l l (S) l l 1 1 3-109 l
MAXIMUM FEEDWATER RUNOUT CAPABILITY h 1-ST-23D 3.23.2 Discussion (Cont ' d) Test Exception 1 was written against the initial method of determining the characteristic curves for the feed regulating valves and for 1-CNM-AOV119. The methodology for 1-CNM-AOV119 and the feed regulating valves was revised. Test Exception 2 was written against the method of analysis for the two feed pump condition. A curve was generated for feed pump head versus flow taking data with all three feed pumps in service. A curve for the two feed pump condition was also derived from the same data. The "A" feed pump, however, has a head curve significantly different than the other two feed pumps due to an impeller modification. The assumption that the three pumps are identical was therefore invalid. In order to disposition this exception, analysis was performed using field data on the "A" feed pump and preoperational test data and vendor data on the "B" and "C" pumps. The "B" pump was selected as the most conservative of the two to be lll paired with the "A" pump to develop a new two pump curve. This curve was then used to perform the two pump analysis. The Test Exceptions (TE's) are listed below along with the status as of 15-Jul-86. TE DESCRIPTION STATUS 1 Analysis Methodology closed was changed 2 "A" feed pump head Closed differing from "B" and "C" pump curves 3 Level 2 Criteria exceeded Open in the 3 pump /3 valve configuration with CNM-AOV119 failing to.open Data will be transmitted to General Electric Engineering g for dispositioning W 3-110
() TURBINE VALVE SURVEILLANCE 1-ST-24 3.24 1-ST-24 TURBINE VALVE SURVEILLANCE 3.24.1 Description The major objective of this test is to determine the maximum recommended power levels for the turbine valve surveillances that will allow testing without producing a reactor scram. The acceptance criteria applied to this test are shown in Subsections 3.24.1.1 and 3.24.1.2. 3.24.1.1 Level 1 Criteria None 3.24.1.2 Level 2 Criteria () When Turbine Valve Cycling is performed at the maximum recommended power level:
- 1. Peak neutron flux will remain at least 7.5%
below the scram trip setting.
- 2. Peak vessel pressure will remain at least 10 psi below the high pressure scram setting.
- 3. Peak heat flux will remain at least 5% below its scram trip point.
- 4. Peak steam flow in each steam line will remain at least 10% below the high flow, isolation trip setting.
3.24.2 Discussion The control valves, stop valves and bypass valves were cycled at 45 to 65 percent power and again at 75 to 90 percent power during which neutron flux, heat flux, reactor pressure and steam flow are monitored. This data is extrapolated to determine a new maximum power level for this testing. Turbine valve cycling will be performed at this maximum power level to determine the margin to scram. {]) 3-111 1
i l i TURBINE VALVE SURVEILLANCE h' l-ST-24 3.24.2 Discussion (Cont'd) The turbine control, stop and bypass valves were cycled at 62% power in TC-3 and again at 74.6% power in TC-5. Neutron flux, heat flux, reactor pressure, and steam flow were monitored to determine margins to a tripped i condition. From the analysis, the test data was found to be insufficient for extrapolation to determine the I maximum power level to conduct this test. Test Exception 1 was written, and the test was reperformed at 80.5% power. These test results indicated the maximum power level for turbine valve surveillance testing is 100%. However, additional verification is needed by performing a test between 85% and 95% power. TE-03 was written, to cover this. This was not performed during TC-6 testing due to inoperable moisture separator / reheaters. Table 3.24-1 lists the results for testing performed. The following is a summary of the Test Exceptions along O with the status as of 15-Jul-86. 1 I l 3-112
O Gl TURBINE VALVE SURVEILLANCE l-ST-24 TE Description Status 1 Reperform test at 75-90% power Closed as the test data is not sufficient for extrapolation to determine the operation limit on Turbine Valve Surveillance. 2 The Bypass Valve #2 position ERIS point Closed was not functional as the fast open position of the valve can not be determined from the time history plot. The opening / closing time for BPV
#2 was determined by the total valve position point.
3 Turbine valve surveillance at high power Open level was not performed due to inoperable moisture separator / reheaters. Consideration of a retest is underway. O 3-113
O O O TURBINE VALVE SURVEILLANCE 1-ST-24 TABLE 3.24-1 1-ST-24 STOP VALVES CONTROL VALVES BYPASS VALVES. Power (%) 62 75 81 62 75 81 62 75 81 Peak Flux (%) 64 77 83 69 79 85 65 76 82 Peak Pressure 981 995 1015 999 1000 1020 984 991 1010 (psig) MARGIN TO SCRAM Pressure (psi) 84 70 50 66 65 45 81 74 55 Neutron Flux (%) 54 41 35 49 39 33 53 42 36 Heat Flux (%) 17 15 15 15 15 15 15 15 16 ' Steam Flow (%) 49 41 25 47 40 34 51 43 39 3-114
O =^1= s'=== L'"= va'v= '==' l-ST-25A 3.25 1-ST-25A MAIN STEAM L*..E VALVE TESTS 3.25.1 Description 0 The purpose of this test is to functionally check each Main Steam Isolation valve (MSIV) and Main Steam Branch Valve for proper operation and to determine the valve closure time for each MSIV. O The closure time for each MSIV was measured at test condition (TC) Heatup and TC-2. O The closure time for each Main Steam Branch Valve was measured during TC Heatup and TC-2 according to STP-109-0301. 3.25.1.1 Level 1 Criteria
- 1. The MSIV stroke time (ts) shall be no faster than 3.0 seconds (average of the fastest valve in each steam line), and for any individual valve 2.5 seconds < ts <c 5 seconds. Total effective closure time for any individual MSIV shall be tsol plus the maximum instrumentation delay time as determined in preoperational test 1-PT-58, Nuclear Steam Supply Shutoff System, and shall be <f 5.5 seconds.
I 3.25.1.2 Level 2 Criteria
- 1. Main Steam Valve Stroke time must satisfy the requirements of Reference 2.9, STP-109-0301.
3.25.2 Discussion Main Steam Line Valve Tests, 1-ST-25A, were performed at 3% power during Test Condition Heatup (TC-HU) on 25 Nov. 85 and again at 30% power in TC-2 on 7-Feb. 86. O 3-115
MAIN STEAM LINE VALVE TESTS h 1-ST-25A During this test the MSIV's and Main Steam Branch Valves were individually tested for operability and were individually timed. The MSIV stroke and closure times were determined by monitoring the 90% and 10% open limit switches en the ERIS computer. The stroke time was then calculated by extrapolating the measured valve movement over the measured time to the 100% valve movement and full stroke time. The valve closure time is the time from when the valve solenoid is deenergized to when the valve is fully closed. The stroke and valve closure times were determined using extrapolation from the actual limit switch positions. The instrument delay time was determined from preoperational test data (1-FT-058) to be 0.28 seconds. The results of the MSIV testing are shown in Table 3.25.2.1. Each MSIV satisfied the Level 1 criteria for both stroke time and effective closure time. All of the Branch valves satisfied the requirements of STP-109-0301 which satisfied the Level 2 criteria. lll The process computer On Demand program OD-1 (Heat Balance) was not available for this test resulting in test exception (TE) 1. This did not affect the results of the test and was dispositioned accordingly. This test exception is listed below. All applicable criteria were satisfied. TE DESCRIPTION STATUS i 1 Process Computer Edit 00-1 not available Closed as requested by the procedure O 3-116
O A1= sr a t1== vArv= ==== 1-ST-25A Table 3.25.1 MSIV STROKE TIME EFFECTIVE ID (Sec) Closure Time (Sec) H/U TC-2 . H/U TC-2 B21-F022A 3.62 3.45 3.91 3.71 B21-F022B 3.49 3.04 3.77 3.42 B21-F022C 3.29 3.11 3.61 3.39 B21-F022D 3.46 3.46 3.80 3.75 B21-F028A 3.30 3.23 3.57 3.52 B21-F028B 3.38 3.32 3.69 3.69 O B21-F028C 3.67 3.67 3.91 3.69 B21-F028D 3.33 3.33 3.62 3.62
- Average 3.33 3.18
- The average stroke time is calculated by averaging the time of the fastest MSIV in each of the four main steam lines.
i !O l l 3-117 l . - _ . - . _ .. - - - _ _ - . .- - .-.. -. - - - .- - . - _ . - . - _ . . - - . - -
MSIV FULL CLOSURE 1-ST-25B O 3.26 1-ST-25B MSIV FULL CLOSURE 3.26.1 Description The purpose of this test is to determine the reactor j transient behavior that results from simultaneous full closure of all Main Steam Isolation Valves (MSIV's). The acceptance criteria are listed in Subsections 3.26.1.1 and 3.26.1.2. 3.26.1.1 Level 1 Criteria
- 1. The positive change in vessel dome pressure occurring within 30 seconds after closure of all MSIVs shall not exceed the Level 2 criteria by more than 25 psi. The positive change in simulated (APRM) heat flux shall not exceed the Level 2 criteria by more than 24 of rated value.
- 2. Feedwater system settings must prevent flooding of the steam lines.
() 3. The reactor must scram to limit the severity of the neutron flux and fuel surface heat flux transient.
- 4. The recorded MSIV closure times must meet previously stated timing specifications (Ref. 2.6).
, (These requirement are The MSIV stroke time (ts) i shall be no faster than 3.0 seconds (average of the fastest valve in each steam line), and for any individual valve 2.5 seconds f ts (5 seconds. Total effective closure time for any individual MSIV shall be tsol (valve closure time) plus the maximum instrumentation delay time as determined in preoperational test (1-PT-058) and shall be g 5.5 seconds).
- 5. If any safety / relief valves open, no more than one l valve shall reopen after the first blowdown.
i O 3-118
MSIV FULL CLOSURE l-ST-25B O 3.26.1.2 Level 2 Criteria
- 1. 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.
- 2. The positive change in vessel dome pressure and simulated heat flux signals occurring within the first 30 seconds after the closure of all MSIVs must not exceed the predicted values. Predicted values will be referenced to actual test conditions of initial power level and dome pressure and will use beginning of life nuclear data.
- 3. Initial action of RCIC and HPCS shall be automatic if low water level (L2) is reached, and system performance shall be within specification.
- 4. Recirculation pumps will trip if low water level (L2) is reached. Recirculation pump power will transfer to the Low Frequency Motor Generators if low water level (L3) is reached. llg
- 5. The total number of safety / relief valve opening cycles of the " low-low" set valve after initial blowdown shall not exceed three times during the initial five minutes following isolation.
i
- 6. If the low-low set pressure relief logic functions, the open/close actions of the SRV's shall occur within +/-15 psi of their design netpoints.
3.26.2 Discussion The MSIV Full Closure test was performed at 62% power during Test Condition (TC) 3 on 20-Mar-86 and at 99% power during TC-6 on 8-Jun-86. The simultaneous full closure of all MSIVs was initiated by placing two " low condenser vacuum" channels in the trip condition. O 3-119
MSIV FULL CLOSURE 1-ST-25B O V 3.26.2 Discussion (Cont'd)
- 1. Test Condition 3 In TC-3, the MSIVs closed with an average valve stroke time of 3.25 seconds. The reactor scram occurred .48 seconds after the MSIVs received a signal to isolate.
Reactor power did not rise during the transient and the maximum reactor pressure rise was 82 psi which occurred approximately 3 seconds after receiving the isolation signal. The maximum level during the transient was 73 inches while the minimum level was - 22 inches. The level 3 alarm came at 4.5 seconds into the transient transferring recirc pumps to slow speed. The Level 2 setpoint was never achieved but Level 8 trip initiated approximately 3 minutes into the transient. RCIC and HPCS systems did not initiate since Level 2 was never reached. Safety Relief Valve (SRV) F015D opened on pressure relief while F051C opened on low low set pressure relief just prior to achieving the maximum reactor pressure rise. Based on SRV Tailpipe temperature and Main Steam Line "C" it was clear that SRV F041C opened for (]) flow, approximately three seconds. Test Exception (TE) 3 was written to document these SRV's lifting. General Electric Engineering concluded that these SRV's lifting did not effect the pressure rise because they lifted very close to the peak pressure. This resolved TE-3. A brief sequence of events is shown in Table 3.26-1. A comparison of the results with the acceptance criteria is given in Table 3.26-2. All acceptance criteria have been met. I For the TC-3 testing there were portions of feedwater system testing (1-ST-23A) and pressure regulator testing (1-ST-22) that were listed as prerequisites, but were not completed. Test Exception 1 documented this concern and it was resolved when 1-ST-25B was performed at near rated conditions. Also, initial core flow was lower than required. Test Exception 4 was written regarding this and was dispositioned since core flow is of minor effect for this transient. Initially, analysis was done
- for test conditions at 70% power. However, due to an error found in the feedwater flow calibratior., the data was reevaluated for 62% initial. power. This was documented by Test Exception 6.
O 3-120
MSIV FULL CLOSURE 1-ST-25B O 3.26.2 Discussion (Cont'd) There were two (2) other Test Exceptions written due to problems associated with ERIS signals. Test Exception 2 concerns failure to obtain the inboard MSIV solenoid deenergization signal. Since MSIV stroke time measurements are taken periodically per Tech Specs and by previous testing (1-ST-25A), failure to obtain the times during this test was acceptable. Test Exception 5 was written since the scram delay could not be obtained for analysis. In this case, there was no computer signal for the RPS limit switches on the MSIVs. Since the scram delay has a very small affect on the analysis, this was accepted accordingly.
- 2. Test Condition 6 The MSIV full closure at TC-6 was initiated at rated reactor power and steam dome pressure. The MSIVs closed with an average valve stroke time of 3.8 seconds. The reactor scrammed 0.5 seconds after the isolation signal.
The reactor pressure peaked at 1091 psig approximately 27 seconds into the transient. SRV F051D actuated on g pressure relief at 1087 psig while F051C lifted on the low low set pressure relief logic. The low low pressure relief logic was further demonstrated in that F051D opened two additional times at about 6 minutes and 10 1/2 minutes into the transient. Three additional SRVs may have lifted off their seats briefly as evidenced by increased tailpipe temperatures. This is documented in TE-12. I The water level reached a minimum of -45 inches approximately 6 seconds after the isolation signal. Both RCIC and !!PCS properly initiated on Level 2. The recirculation pumps transferred to LFMG sets at Level 3 l but did not trip on a Level 2 signal. TE-9 documents this. The ATWS logic and setpoints have been satisfactorily checked and TE-09 dispositioned. Water Level indicated a high of 71 inches when the MSIVs were reopened about six minutes after the isolation. Prior to that the highest water level was 56 inches seen 5 minutes after isolation, tripping all three FW pumps and closing the !!PCS injection valve. The RCIC flow had been previously diverted to the test return line when water .tevel climbed back to about 30 inches. A brief sequence of events is listed in Table 3.26-3. ggg 3-121
MSIV FULL CIASURE 1-ST-258 O 3.26.2 Discussion (Cont'd) The dome pressure rise for normal conditions was predicted to be 121.4 psi from the Transient Safety Analyses Design Report (TSADR) . This number was adjusted based upon the actual conditions of the test and sensitivity analyses also given in the TSADR. No correction was needed for the initial power and dome pressure since these parameters were essentially at rated. However, adjustments for scram speed, MSIV closure time and SRV setpoints were made. An adjustment j for scram delay was not made since this cannot be done from the ERIS data. This is listed as TE-13. Since any adjustments for scram delay would be extremely small, TE-13 was dispositioned to be accepted as is. With the appropriate adjustments made, the predicted pressure rise during the actual test conditions was originally calculated to be 98 psi. However, due to the probability that 3 additional SRVs may have opened, General Electric Engineering p( formed another analysis based on actual plant data and calculated a peak pressure rise criteria of 77 psi. Since the actual O pressure rise was only 61 psi, the Level 1 and Level 2 criteria were satisfied. The criteria for heat flux rise was also met with an actual rise of 0.27% compared with the requirement of 1 css than 0.4%. A complete comparison of acceptance criteria and test results is shown in Table 3.26-2. Following is a summary of the Test Exceptions written for 1-ST-25B along with the status as of 15-Jul-86. s O 3-122
MSIV FULL CLOSURE 1-ST-25B O TEST TE CONDITION DESCRIPTION STATUS 1 3 Applicable portions of the startup tests closed for the feedwater control system (1-ST-23A) and the pressure regulating sys-tem (1-ST-22) were not completed prior to conducting this test. 2 3 Inboard MSIV solenoid deenergization time Closed was not obtained. 3 3 SRV-F041C apparently opened during the closed pressure increase against its spring, but at a pressure below its spring setpoint. 4 3 The test was conducted with core flow less closed than 95% as required by prerequisites. 5 3 Scram delay could not be obtained for Closed analysis. 6 3 The feedwater flow transmitters were im- Closed O properly calibrated during the TC-3 test, resulting in the process computer indicat-ing a higher than actual reactor power.
- 7 6 Some SRV tailpipe temperatures returned to Closed l
l a value which was less than 10 degrees F of the initial tailpipe temperature. 8 6 The ERIS signal for recording the HPCS Closed initiation was not operable. 9 6 A recirculation pump ATWS trip did not Closed occur although RCIC and HPCS received an initiation signal from reactor water Level 2. l l O 3-123
1 1 MSIV FULL CLOSURE , 1-ST-25B O TEST TE CONDITION DESCRIPTION STATUS 10 6 Initial discrepancy between HPCS actual Closed flow and Technical Specifications. 11 6 In low-low set logic, SRV, F051D opened Closed and closed at pressures not within + 15 psi of the respective setpoints. 12 6 SRVs F047A, F0478, and F041B appeared to Closed open against their springs during the pressure transient at pressures signifi-cantly less than the spring setpoint. 13 6 ERIS recorded the scram signal as occurring closed before the MSIVs reached their 90% open position. O O 3-124
MSIVC FULL CLOSURE 1-ST-258 TABLE 3.26-1 Sequence Of' Events For MSIV Full Closure TC-3 TIME (Seconds) EVENT ' cannot be determined from ERIS Initiation by Simulating Signals low condenser vacuum 0.00 Reactor Scram 4.6 Recirculation Pump Trip Occurs on Reactor Water Level 3 5.2 Minimum water level - 22 inches 6.63 SRV F051D opens 6.63 SRV F051C opens 4 7.2 Peak pressure of 1073 psig attained 35.15 SRV F051C closes i l 39.65 SRV F051D closes i 185.2 Feed pumps trip on ' j reactor water level 8 577.5 SRV F051D opens on low-low set 628.5 SRV F051D closes on low-low set j
- O i
p 3-125
O O O 3 MSIV FULL CIASURE l-ST-258 l TABLE 3.26-2 LJ7EL 1 ACCEPTANCE CRITERIA TC-3 RESULTS TC-6 RESULTS l j 1. Peak Pressure rise less than 87 psi (TC-3) 83 psi 1 , Peak Pressure rise less than 77 psi (Tc-6) 61 psi I I ) 2. Heat flux rise less than 2.4% None Observed 0.274 1 I
- 3. Maximum allowed vessel water level is 72 Inches 71 Inches 101.68 + 2.2 inches i
- 4. Reactor must scram Scram Occurs Scram Occurs
- 5. Average of fastest MSIV in each line must 3.25 seconds 3.83 Seconds
- be no less than 3.0 seconds I
4 6. MSIV stroke times shall be 3 seconds f stroke time f.5 seconds F022A 3.51 3.50
- F022B 3.20 3.30 F022C 3.20 3.17 l
F022D 3.49 3.46 $ F028A 3.26 3.23 F028B 3.42 3.32 F028C 3.67 3.67
- F028D 3.35 3.33 3-126 1
O O O I l NSIV FULL NYWRE i , 1-ST-255 j TABLE 3.26-2 (Cont'd) t l LEVEL 1 ACCEPTANCE CRITERIA TC-3 RESULTS TC-6 RESULTS i
- 7. MSIV stroke time and delay time shall be less than 5.5 seconds F022A TE-2 4.13 I
F022B TE-2 3.88 l F022C TE-2 3.75 F022D TE-2 3.99 j F028A 3.85 3.8 l F028B 4.00 3.86 l F028C 4.19 4.14 a F028D 3.96 3.89 1 4 1 j 8. No more than one SRV shall reopen after Only F051D Reopened Only F051D reopened 1 first blowdown In Low-Low set logic In Low-Low set logic i l l I b I l 3-127 i
O O O MSIV FULL CLOSURE 3 1-ST-255 TABLE 3.26-2 (Cont'd) 't i LEVEL 2 ACCEPTanarT CRITERT4 TC-3 RESULTS TC-6 RESULTS I l 1. SRV tailpipe temperatures must return to Maximum positive tem- TE-7 l within 10 degrees F of the pretest tem- perature difference 5 perature degrees F. Same pro-blem as explaned in l l TE-7 on the negative side
- 2. Predicted pressure rise less than 61 psi pressure in-77 psi (TC-6) 83 psi pressure in- crease measured 87 psi (TC-3) crease measured
- 3. Predicted heat flux rise will be less than None Observed 0.27%
i 0.4% 'l
- 4. RCIC and HPCS will automatically initiate Level 2 not reached Both auto initiated
- reactor water level 2 is reached SEE TE-10
- 5. RPT shall occur if reactor water level 3 is RPT occurs RPT occurs reached
- 6. ATWS recirculation pump trip to off will Level 2 not reached TE-9 occur if Level 2 is reached
- 7. No more than 3 SRV actuation shall occur in None occured in first None occurred in low-low set logic in first 5 minutes after 5 minutes after first 5 minutes the initial blowdown initial blowdown after initial blowdown
- 8. In low-low set logic, SRV's will open and close TE-3 TE-Il within + 15 psi of the set point 3-128
IISIV FUI4 CIASURE 1-ST-258 O . Ta t= 3.2S-3 Sequence Of Events For MSIV Full Closure For TC-6 TIME (Seconds) EVENT Cannot be determined from ERIS Initiation by simulating Signals low condensers vacuum 0.00 Reactor Scram 3.64 Recirculation Pump Trip occurs on Reactor Water Level 3 3.97 SRV F051D opens 3.99 SRV F051C opens 4.24 RCIC initiates. (HPCS initiated at approximately the same time) O 4.9 Minimum reactor water level - 45 inches 5.0 Peak pressure of 1091 psig attained 30.75 SRV F051C closes 32.69 SRV F051D closes 171 sec Feed pumps trip on reactor water level 8 350 SRV F051D opens on low-low set 422 SRV F051D closes on low-low set 634 SRV F051D opens on low-low set 698 SRV F051D closes on low-low set O 3-129
MAIN STEAM LINE FL0tt INSTRUMENT CALIBRATION 7s 1-ST-25C/D (_) 3.27.1 Description The major objective of this test is to investigate the performance of and calibrate the main steam flow venturis and elbow taps at selected power levels over the entire steam flow range. The final calibration will take place with the data accumulated along the 100% rod line. The acceptance criteria applied to this test are shown in Subsections 3.27.1.1 and 3.27.1.2. 3.27.1.1 Level 1 Criteria None. 3.27.1.2 Level 2 Criteria
- 1. The flow venturi dp shall be equal to or greater than 79.3 psig at rated steam flow, and greater than or equal to 178 paid at 140% rated steam flow.
/~N 2. The accuracy of the elbow tap kJ relative to the calibrated feedwater flow shall be at least +5 percent of rated flow at flow rates between 40 and TOO percent of rated. The repeatability / noise shall be within +1.5 percent of rated flow.
3.27.2 Discussion Beginning at approximately 40% core thermal power and a fixed full load turbine inlet pressure of between 950 tc 955 psia, data was taken on the Main Steam venturis and elbow taps using digital voltmeters and the ERIS computer. This data was taken at selected power levels along the 75% rod line and again along the 100% rod line to verify the associated instrumentation calibration. For both the venturis and the elbow taps, plots were made of the calculated steam flow versus the delta P. In TC-3, the venturi data was insufficient for extrapolation to 140% steam flow resulting in TE-01 which was resolved by continuing data collection along the 100% rod line. TE-06 was written due to extensive noise on the elbow taps. Similar observations were made at Test Condition 6. (~h (_) 3-130
MAI] STEAM LINE FLOW INSTRUMENT CALIBRATION 1-ST-25C/D g 3.27.2 Discussion (Cont'd) The initial power ascension data along the 100% rod line was not completed due to the erroneous feedwater flow calibration. TE-02 documents this and dictated retaking the data. The second power ascension data set along the 100% rod line was successfully completed. Test Exceptions 4, 5 and 6 resulted from the failure to meet the Level 2 criteria associated with this test. These along with a status as of 15 July 86 are summarized as follows: TEST TE CONDITION DESCRIPTION STATUS 1 3 Insufficient data tc extrapolate Closed flow to 140% rated steam flow. Continue data accumulation along 100% rod line. 2 6 Incorrect feedwater flow calibration caused all data to be invalidt closed g additional data was taken. 3 6 The elbow tap flow versus delta P Open curves are not within +5% of the design curves. Largest deviation is 32%. Evaluated and accepted by GE Engineering for operation. Investi-gation is continuing to determine cause. 4 6 The repeatability / noise of the Main closed i Steam elbow tap signals is greater than 1.5% criteria. Maximum value is 2.31%. Evaluated and accepted by GE Engineering. 5 6 The flow venturi delta P as extrapolated Open to 140% rated steam flow is 157 psid violating Level 2 criteria of 178 psid. The design documents are undergoing appropriate changes. This will also force a change in the Plant Technical Specifi-
- cations for the high steam flow isolation.
6 3 Elbow tap repeatability /ncise signal Closed g failed Level 2 Criteria. T. valuated and W l accepted by GE Engineerin3 3-131
O - =1- - 1-ST-26 9, 3.28 1-ST-26 SAFETY RELIEF VALVES 3.28.1 Description
- The purpose of the Safety Relief Valve test is to 3 verify
j 0 That the relief valves can be opened and closed 1 manually j 0 That the relief valves reseat properly after operation O That there are no major blockages in the relief valve discharge piping. l Subsection 3.28.1.1 and 3.28.1.2 list the applicable
; acceptance criteria.
4 i 3.28.1.1 Level 1 Criteria
- 1. There shall be positive indication of steam
(]) discharge during the manual actuation of each valve
, 3.28.1.2 Level 2 Criteria l! 1. Pressure control system related variables may
{ contain oscillatory modes of response. In these 4 cases, the decay ratio for each controlled mode of . response must be less than or equal to 0.25.
- 2. The temperature measured by thermocouples on the discharge side of the valves shall return to within i 10 deg. F of the ten.perature recorded before the valve was opened.
l i 1 3. The change in bypass valve position for each SRV i opening shall not be less than 90% of the average ! change in bypass valve position. 3.28.2 Discussion l . Safety Relief Valves test, 1-ST-26, was initiated on 5 ! December 1985 at River Bend 1 during Test Condition 1. j Reactor power was 8%, and total bypass valve position I was 79% (to control the pressure transient). Due to ! instabilities in the pressure regulator control system, ' it was necessary to perform pressure regulator tuning prior to continuing safety relief valve testing, generating Test Exception 1. 3-132 l
SAFETY RELIEF VALVE l-ST-26 3.28.2 Discussion (con't) Safety Relief Valve testing began again on 06 December 1985 per Test Exception 1. The maximum decay ratio measured was 0.4 for bypass valve position during the F051C relief valve activation. The Level 2 criteria requires decay ratios of less than 0.25. Test Exception 2 documents this exception. Since the reactor pressure responded acceptably, this test exception was closed. i The discharge temperatures of six (6) safety relief I valves did not return to within 10 deg. F of the initial readings, which is a Level 2 criteria violation. The maximum temperature difference was 16 deg. F and is documented in Test Exception 3. This test exception was dispositioned as acceptable. l All other applicable criteria were satisfied. A summary ! of all test exceptions is shown below. TE DESCRIPTION STATUS l 1 Pressure regulator tuning needed Closed to be performed to increase system stability. 2 BPV decay ratio of 0.4. Reactor Closed l pressure was stable. 3 6 SRV discharge temperatures did closed not return to within 10 deg. F of their initial temperature. 4 Tabular Trends were not utilized. Closed Equivalent ERIS data was obtained. l 9 3-133
l l i TURBINE TRIP AND GENERATOR LOAD REJECTION 1-ST-27 - 3.29 1-ST-27 TURBINE TRIP AND GENERATOR LOAD REJECTION 3.29.1 Description The major objectives of this test are as follows: Turbine Trip Within Bypass Capacity - At TC-1, within the capacity of the Bypass Valves,the turbine will be tripped. The Bypass Valves will open, routing the steam directly to the condenser. The reactor will not scram in this transient. Bypass Valve Capacity Determination - At TC-2, with the Turbine-Generator synched to the grid, the bypass valves will be opened and the reduction of Generated Electrical Power will be used to determine bypass valve capacity. p/ s-Generator-Load Rejection at High Power generator load rejection at Test Condition 6 will A be initiated by tripping a generator differential relay. This will open both generator output breakers and cause a fast closure of the turbine control-valves, inducing a reactor scram and the opening of the bypass valves. System responses will be analyzed and compared to expected responses. The acceptance criteria applied to this test are shown in subsections 3.29.1.1 and 3.29.1.2. 3.29.1.1 Level 1 Criteria
- 1. For Turbine and Generator trips at power levels greater than 50% NBR, there should be a delay of less than 0.1 seconds following the beginning of control or stop valve closure before the beginning O
3-134
TURBINE TRIP AND GENERATOR I4AD REJECTION 1-ST-27 3.29.1.1 Level I criteria (Cont'd) of bypass valve opening. The bypass valves should be opened to a point corresponding to greater than or equal to 80 percent of their capacity within 0.3 seconds from the beginning of control or stop valve closure motion. 2 Feedwater system settings must prevent flooding of the steam lines following these transients.
- 3. The two pump drive flow coastdown transient during the first five seconds must be bounded by the limiting curves.
- 4. The positive change in vessel dome pressure occurring within 30 seconds after either generator or turbine trip must not exceed the Level 2 criteria by more that 25 psi. lll S. The positive change in simulated heat flux shall not exceed the Level 2 criteria by more than 2% of rated value.
- 6. If any safety / relief valves open, no more than one valve shall reopen after the first blowdown.
- 7. The total time delay from start of turbine stop valve motion or from start of turbine control valve motion to the complete suppression of electrical arc between the fully open contacts of RPT circuit breakers shall be less than 140 milliseconds.
3.29.1.2 Level 2 Criteria
- 1. There shall be no MSIV closure during the first three minutes of the transient and operator action O
3-135
O roR=1== ra1r >=o =====^ro= toao ==3=crzo= l-ST-27 3.29.1.2 Level 2 Criteria (Cont'd) shall not be required during that period to avoid the MSIV trip. (The operator may take action as he desires after the first three minutes, including switching out of run mode. The operator may also switch out of run mode in the first three minutes if he confirms from measured data that this action did not prevent MSIV closure).
- 2. The positive change in vessel dome pressure and in simulated heat flux which occur within the first 30 seconds after the initiation of either generator or turbine trip must not exceed the predicted values.
- 3. For the Turbine trip within the bypass valves capacity, the reactor shall not scram for initial thermal power values within that bypass valve
(~' capacity and below the power level at which the scram is inhibited.
- 4. The measured bypass capability (in percent of rated power) shall be equal or greater than that used for
- the FSAR analysis.
- 5. Low water level recirculation pump trip, HPCS and RCIC shall not be initiated.
- 6. Recirculation low frequency MG sets shall take over l after the initial Recircualtion Pump trips and adequate vessel temperature difference shall be maintained.
- 7. Feedwater level control shall avoid loss of feedwater due to high level (L8) trip during the event.
O 3-136
l 1 TURBINE TRIP AND GENERATOR LOAD REJECTION h J 1-ST-27 l l 3.29.1.2 Level 2 Criteria (Cont'd)
- 8. If the low-low set pressure relief logic functions, the open/close actions of the SRVs shall occur within + 13 psi and + 20 psi of their design setpoints; respectively.
- 9. 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.
3.29.2 Discussion Turbine Trip within Bypass Valve Capacity On 23-Dec-85, with the reactor power at 8% indicated on the APRMs, and the main generator carrying 70 MWe the main turbine was tripped by depressing the main turbine trip push buttons in the main control room. The two lll bypass valves responded correctly to the transient by opening to pass reactor steam to the main condenser. Reactor pressure increaEed by 20 psi immediately after the turbine trip before returning to its initial valve. As a reactor scram did not occur all acceptance criteria were satisfied. There were no test exceptions associated with this portion of the startup test. Bypass Valve Capacity Determination With reactor power at 32%, both aypass valves were fully opened using the bypass ,ulves jack. Main generator output decreased from 239.1 MWe to l 3-137
th TURBINE TRIP AND GENERATOR LOAD REJECTION 1-ST-27 3.29.2 Discussion (Cont'd) 128.4 MWe. Main steam flow rate was determined by summing the values of feedwater flow and CRD flow obtained from a process computer OD-3 edit. The initial calculated value of bypass valve capacity was incorrect because the feedwater flow venturis were not calibrated correctly. Feedwater flow indication was 93% of actual flow during the test. After the venturis were recalibrated, a correction factor was applied to the previously measured feedwater flow rate. This is documented in Test Exception 1. A total bypass valve capacity was calculated as 11.13% using the corrected feedwater flow rate. The total bypass valve capacity exceeded the required value of 10%, satisfying all acceptance criteria. hN Generator Load Rejection at High Power l On 29-May-86, the generator load rejection was initiated l by manually actuating the main generator differential relay from initial conditions of 96% core thermal power l and 96% of rated core flow. General Electric l Engineering evaluated actual plant conditions and predicted a maximum allowable pressure increase of 104 psi. Actual pressure increase was 82 psi on the transient. The initial dome pressure was 1024 psig. The maximum heat flux rise was 0.15% which was less than 0.3% as required. A sequence of events for the transient is listed in Table 3.29-1. l () 1 3-138 l
l l TURBINE TRIP AND GENERATOR IDAD REJECTION 1-ST-27 l l Table 3.29-1 Sequence of Events During Generator Load Rejection, TC-6 Time (Seconds) Event 0.00 Beginning of Bypass Valves Opening (First transient action seen by ERIS)
.055 Recirculation Pumps A&B trip (time determined from preoperational test data) .116 Turbine Control Valves begin to close .128 Bypass Valves 80% open .151 Reactor Scram Signal occurs .161 Bypass Valves fully open .241 Turbine Control Valves fully closed .925 SRV F051D Open l .952 SRV F051C Open 1.40 SRVs F047A,B,C,D,F and F0519,G Open 1.56 Maximum Reactor Pressure reached (1106.9 psig) 6.28 SRV F047F Closed 6.30 SRVs F047A,B,C,D and F051B, G Closed 6.44 Mode Switch taken to Shutdown 15.65 SRV F051C Closed O
3-139
TURBINE TRIP AND GENERATOR LOAD REJECTION
' TABLE 3.29-1 (Cont' d)
Time (Seconds) Event 16.6 Recirc Pump "A" shift to LFMG complete 16.9 Recirc Pump "B" shift to LFMG complete 26.2 Minimum Reactor Water level reached (+7") 36.2 SRV F051D Closed 37.2 Minimum Reactor Pressure reached (908 psig) 70.4 Reactor Feed Pumps "A,B,C" trip on Level 8 180 Maximum water level reached (73 inches) Level 1 and Level 2 criteria requirements and the test results are listed in Table 3.29-2. O O 3-140 - _ . . - . - - _ _ _ _ _ . .__ ._-_~_ - ....-- - - . _ .
TURBINE TRIP AND GENERATOR LOAD REJECTION h 1-ST-27 Table 3.29-2 A. LEVEL 1 REQUIREMENT RESULT
- 1. Less than 0.1 delay following Bypass valves began turbine stop or control valve opening before closure before bypass valves control valve motion.
begin opening.
- 2. Less than 0.3 seconds from 0.045 seconds beginning of control or stop valve motion until bypass valves are at least 80% open.
- 3. Reactor water level does not Highest Level 73" G reach or exceed +104 inches on the upset range.
- 4. Recirculation loop flow coast- (TE-3) down bounded by curves.
- 5. Reactor peak pressure must not 82 psi positive exceed 129 psi greater than change initial pressure.
- 6. Positive heat flv;'x change must 0.15%
not exceed 2.3%. positive heat flux rise. O 3-141
TURBINE TRIP AND GENERATOR LOAD REJECTION 1-ST-27 A. LEVEL 1 (Cont'd) REQUIREMENT RESULT
- 7. No more than one relief valve None reopened shall reopen following the initial relief valves opening.
- 8. Total RPT delay from control valve Preoperational tests motion start to electrical arc sup- measured 55 ms, pression must be less than 140 ms.
B. LEVEL 2
- 1. No MSIV closure within 3 minutes of Although the reactor transient mode switch was immediately taken to shutdown following scram reactor pressure remained
(' greater than 849 psia for the first 3 minutes. MSIV's did not close.
- 2. Positive reactor pressure change 82 psig positive will be less than 104 psig. pressure change was observed.
- 3. Positive heat flux change will be 0.15% positive less than 0.3%. heat flux change was observed.
- 4. Level 2 in reactor water level will Level 2 was not not be reached. HPCS & RCIC reached initiation and Recirc pumps trip to off shall not occur.
- 5. Recirc pumps transfer to LFMG sets Transferred at occurs satisfactorily. Level 3
- 6. Level 8 feed pump trip following (TE-05) l transient shall not occur.
- 7. In low / low set logic, safety relief Acceptable'perfor-valves open within 13 psi and close mance observed
- Os within 20 psi of their design set l points.
3-142
l TURBINE TRIP AND GENERATOR LOAD REJECTION h 1-ST-27 REQUIREMENT RESULT
- 8. Safety Relieve Valve discharge (TE-02) thermocouples must return to within 10 degrees F of the initial temp.
prior to the transient. l Several test exceptions were written for 1-ST-27. The i following summarizes these Test Exceptions along with the status as of 15-Jul-86. l 1 l 9 l i I i l l 9 3-143 f
TURBINE TRIP AND GENERATOR LOAD REJECTION 1-ST-27 TE DESCRIPTION STATUS 1 Bypass valve capacity was deter- Closed mined using an erroneous feed-water flow rate. After the feed-water flow venturi were recalibrated, the calculations were performed again using a correction factor applied to the measured feedwater flow rate during the original test. 2 Final transient temperatures for some Closed relief valve tailpipes were lower than the initial temperatures by more than 10 degrees F due to reactor cooldown. 3 Loop A recirculation loop coastdown flow closed was outside the upper limit boundary
\
curve for approximately 0.5 seconds. All relevant data has been forwarded to General Electric Engineering which has performed an engineering analysis and found the pump coastdown to be acceptable. 4 AOV-119, the condensate Closed demineralizer bypass valve, did not open following the main turbine trip. The problem was identified and corrected. 5 A reactor water level 8 feedpump trip Closed occurred approximately one and one-half minutes after the transient started. l System response was adequate to prevent steam line flooding. 6 Safety relief valves F041D and F041F Closed apparently lifted against their springs during the peak pressure spike, based upon an increase in their tailpipe l temperatures. General Electric Engineer-() ing has evaluated this for impact upon the I plant's expected transient behavior. There l was no additional impact since the pre-l dictions were made with the actual test l conditions. 3-144
I TURBINE TRIP AND GENERATOR LOAD REJECTION h 1-ST-27 TE DESCRIPTION STATUS 7 Safety relief valves F051B, F051G, and Closed F047F did not meet the 20 psi close criteria. These calculated values were based on a reclose setpoint of 946 psig, the LLS setpoint. It is apparent from the actual closing pressure that the 1113 psig LLS trip units did not activate so the closing setpoint was 1013, and the actual closing pressures were within 20 psia of 1013. O 9 3-145
O s=oroo O oors1D= r== Co raos l 1-sT-28 3.30 1-ST-28 SHUTDOWN FROM OUTSIDE THE CONTROL ROOM 3.30.1 Description The major objective of this is as follows:
- 1. To demonstrate that the reactor can be brought from a normal initial steady-state power level to the point where cooldown is initiated and under control with the reactor vessel pressure and water level controlled from outside the main control room.
The acceptance criteria applied to this test are shown in Subsections 3.30.1.1 and 3.30.1.2. 3.30.1.1 Level 1 Criteria None (]) 3.30.1.2 Level 2 Criteria
- 1. During a simulated control room evacuation, the reactor must be brought to the point where cooldown is initiated and under control, and the reactor vessel pressure and water are controlled using equipment and controls outside the control room.
3.30.2 Discussion Reactor shutdown and the requirement to maintain stable control in hot standby was demonstrated in TC-2. Reactor cooldown using the RHR system in Shutdown Cooling mode was demonstrated in TC-6. At Test Condition 2 the reactor was scrammed from the outside the control room by simulating a low condenser vacuum causing a main steam isolation valve (MSIV) isolation and a reactor scram. The initial reactor and plant condition were as follows: INITIAL FINAL Reactor Power---------344 Mwt (11.9%) 0% O' Reactor Level--------- 36 inches 51 inches Reactor Pressure------955 psig 743 psig 3-146
SHUTDOWN FROM OUTSIDE THE CONTROL ROOM 1-ST-28 3.30.2 Discussion (Cont'd) During the test the maximum and minimum reactor water levels were 54 and 13 inches respectively. Maximum reactor pressure was 1020 psig. From the Division 1 Remote Shutdown Panel (RSP) Reactor Core Isolation Cooling (RCIC) was operated in the CST to CST mode, Loop A of the Residual Heat Removal (RHR) system was operated in suppression pool cooling mode and safety relief valve (SRV) RVF051C was manually cycled. Reg Guide 1.68 provides the following guidelines concerning the performance of this test:
- 1. The reactor be at an initial power level of 10% - 25% with the turbine generator on-line.
- 2. The test be performed with a minimum shift crew (defined Specifications).
in the Technical lll
- 3. The plant be maintained in a stable hot standby condition for at least thirty minutes.
- 4. Only equipment for which credit would be taken in performing an actual remote shutdown should be used.
These recommendations were all followed and addressed specifically in the procedure: TE-3 resulted from a procedural problem with this test. Initial suppression pool level could not be recorded at the RSP prior to transfer from the main control room. The TE was resolved by recording the suppression pool level after transfer to the RSP. O 3-147
(] SHUTDOWN FROM OUTSIDE THE CONTROL ROOM 1-ST-28 3.30.2 Discussion (Cont ' d) At test condition 6 cooldown was initiated and controlled from the RSP utilizing the RHR system in th Shutdown Cooling mode. The initial reactor conditions were: Reactor Pressure------120 psig Reactor Temperature---350 degrees F. Reg Guide 1.08 provides the following guidelines concerning the performance of this test:
- 1. A heat transfer path to the ultimate heat sink can be established.
- 2. Reactor coolant temperature can be reduced approximately 50 deg F. using the shutdown r~s cooling system at a rate of less than 100 deg
(_) F. in any one hour period. These recommendations were all followed and addressed specifically in the procedure. A cooldown rate of 86 deg F/hr was achieved over a period of 37 minutes which satisfies the Reg Guide 1.68 recommendations and Technical Specifications. All acceptance criteria was met. The test exception for 1-ST-28 is summarized below. I TE DESCRIPTION STATUS 1 1 Unable to record initial suppression Closed pool level at the RSP prior to trans-fer from main control room. O . 3-148 1 l
d(x RECIRCULATION FLOW CONTROL SYSTEM l 1-ST-29 l 1 3.31 1-ST-29 RECIRCULATION FLOW CONTROL SYSTEM 3.31.1 Description The purpose of the recirculation flow control system test is to: 0 Demonstrate the recirculation systems capability to control core flow over the entire range of the power / flow operating map. O Demonstrate the recirculation flow control system's capability in each control mode, including the position command, flow command, and flux command modes of operation. O Determine the settings of all electrical (]) compensators and controllers for the desired system performance and stability. The acceptance criteria applied to this test are shown in subsections 3.31.1.1, 3.31.1.2 and 3.31.1.3. 3.31.1.1 Level I Criteria The transient response of any recirculation system-related variable to any test inputs must not diverge. The flux loop response to test inputs shall not diverge. 3.31.1.2 Level 2 Criteria A. Valve Position Loop
- 1. Recirculation system related variables may contain oscillatory modes of response. In these cases, the decay ratio for each controlled mode of response must be less than or equal to 0.25.
- 2. Maximum rate of change of valve position shall be 10 +/- 1% per sec.
O a 3-149
RECIRCULATION FLOW CONTROL SYSTEM l-ST-29 l 3.31.1.2 Level 2 Criteria (Con t ' d)
- 3. During TC-3 and TC-6 while operating Recirc Pumps on the high speed gains and limiters shall be set to obtain the following response:
- a. Delay time for position demand step shall be:
For step inputs of 5% f 0.2 sec.
- b. Response time for position demand step shall be:
For step inputs of 5% f 0.5 sec.
- c. Overshoot after a small position demand input (St} step shall be less than 10% of magnitude of input. (gg i
l B. Flow Loop
- 1. The decay ratio of the flow loop response to any test inputs shull be 0.25.
- 2. Flow loops are for the purpose of maintaining steady-state flow equal in the two loops. Flow loop gains should be set to correct a flow imbalance in less than 25 sec.
- 3. The delay time for flow demand step (f 5%) shall be 0.5 seconds or less.
- 4. The response time for flow demand shall be 1.2 seconds or less.
step (f 5%)
- 5. The maximum allowable flow overshoot for step demand of f 5% of rated shall 6% of the demand step.
- 6. The flow demand step settling time shall be f 6 sec.
3-150
. _ _ _ _ _ _ _ _ _ _ _ _ 1
~'s (V RECIRCULATION FLOW CONTROL SYSTEM 1-ST-29 3.31.1.2 Level 2 Criteria (Cont'd)
C. Flux Loop
- 1. Flux overshoot to a flux demand step shall not exceed 2% of rated for a step demand of f 20% of rated.
- 2. The delay time for flux response to a flux demand step shall be f 0.9 sec.
- 3. The response time for flux demand step shall be j;2.6 sec.
- 4. The flux settling time shall be (15 sec. for a flux demand step f 20% of rated.-
,_ D. Scram Avoidance and General V For any one of the above loops' test maneuvers, the trip avoidance margins raust be at least the following:
- 1. For APRM & 7.5%.
- 2. For simulated heat flux h 5.0%.
E. Flux Estimator Test
- 1. Switching between estimated and actual flux should not exceed 5 times in 5 minutes at steady state.
l 2. During a flux step transient there should be no i switching to actual flux or if switching does occur, it should switch back to estimated flux within 20 seconds of the start of the transient. O 3-151
RECIRCULATION FLON CONTROL SYSTEM h 1-ST-29 3.31.1.2 Level 2 Criteria (Cont'd) 4 F. Flow Control Valve Duty Test
- 1. The flow control valve duty cycle in any operating mode shall not exceed 0.2% Hz. Flow control valve duty cycle is defined as:
Integrated Valve Movement in Percent (%Hz) 2 x Time Span in Seconds 3.31.1.3 Level 3 Criteria A. Valve Position Loop
- 1. Gains shall be set to give as fast a response as possible for small position demand input within the overshoot criterion and without additional valve duty cycle.
lll
- 2. Position loop deadband shall be f4' .2% of full valve stroke.
B. Flow Loop
- 1. Incremental gain from function generator for valve position demand input to sensed drive flow shall not vary by more than 2 to 1 over the entire flow range.
l 2. Flow controller upper limit should be checked for proper setting. 3.31.2 Discussion
- 1. Test Condition Open Vessel In Test Condition (TC) Open Vessel, position loop testing was performed at cold conditions. This was accomplished by inserting a number of small and large flow control valve (FCV) position steps over a range of FCV positions.
O 3-152
I ($) i RECIRCULATION FLOW CONTROL SYSTEH 1-ST-29 3.31.2 Discussion (Cont'd) i 1-ST-29 at open vessel verified that large step inputs to the position and velocity controllers will result in valve stroke rates of 9 to 11%/sec. The system deadband was verified to be less than .2% of valve position. The damping ratio of the system response to 5% steps was verified to be less than
.25. Test Exception (TE) I was written when analysis showed the system response was slower than the criteria required at higher test conditions.
This required further tuning of the system prior to TC-1. The TE was completed successfully.
- 2. Test Condition 1
() In Test Condition 1, position loop testing was performed while operating with the Low Frequency Motor Generators (LFMG's) powering the recirculation pump motors. Before actually inserting transients into the system, position and flow controller tuning was performed. Once tuned, +5 percent steps were inserted into each flow control valve (FCV) individually at the minimum position, 75 percent flow position, and 95 percent flow position. The only criteria applicable at TC-1 were to verify no divergent behavior s.id that no control system related parameters experience a decay ratio greater than 0.25. These criteria were satisfied. TE-02 was written during TC-1 when the data for the step changes at 75% flow was lost during the ERIS computer archive process. The exception was resolved by retesting the missing steps. t 3-153
RECIRCULATION FLOW CONTROL SYSTEM 1-ST-29 3.31.2 Discussion (Cont'd)
- 3. Test Condition 3 Testing in Test Condition 3 included four (4) test sections. These sections were Function Generator Linearization, Position and Flow Loop Testing, Flux Loop Testing, and Duty Cycle Testing. A summary of results is listed in Table 3.31-1.
Function Generator Linearization testing was performed by taking recirculation system data approximately every 5 percent core flow. Then graphs were made for both recirculation loops of Valve Position vs. Drive Flow, Function Generator Input vs. Function Generator Output, and Function Generator Input vs. Drive Flow. The graphs were measured to show that the maximum incremental gain did not vary by more than 2:1. The actual maximum variance was 1.3:1. lll The major portion of testing during Test condition 3 involved position and flow demand steps at various flow control valve positions. This test was conducted by inserting positive and negative five percent step changes to individual flow control valve position, individual flow loops, and both flow loops simultaneously. The steps were conducted at minimum flow, 75 percent flow, and 95 percent flow all using fast speed recirculation pumps along the 75% rod line. The first effort was interrupted by a plant shut-down. The discontinuity in the procedure was documented as TE-03. TE-05 resulted from missing data at the 95% flow condition due to a computer problem. These steps were repeated, clearing the test exceptions. 3-154
I (\ Q RECIRCULATION FLOW CONTROL SYSTEM l-sT-29 3.31.2 Discussion (Cont'd) The position control loop was further tuned during Test Condition 3. In this case, the controller was set as fast as possible without sacrificing stability. However, the response slightly exceeded the Level 2 criteria concerning delay and response times in some conditions. This is documented as , TE-06. TE-06 has been accepted by General Electric Engineering. Tuneup of the flow control loop was also accomplished during Test condition 3. No flow loop response Level 2 criteria could be evaluated due to the noise in the flow signal seen by the computer. Despite the noise, however, it could be seen that the flow response did not diverge. Therefore, Level 1 Criteria was satisfied. TE-07 documents the ({} unanalyzed Level 2 concerns. General Electric Engineering evaluated this and accepted TE-07 primarily due to the inner position control loop (the major contributor to the response) exhibiting acceptable response. During the positive five percent step change with both flow loops in auto at 95% flow, the extrapolated margin to the high neutron flux scram (118%) was 1% versus a Level 2 criteria of 7.5%. This was documented as TE-08 and was resolved by changing the method of testing for later conditions. A 2-3% step with both controllers in auto was recommended and followed for Test Condition 6 testing. The high drive flow limitation of 102.5% was to be set per 1-ST-30C and checked by 1-ST-29. However, adequate data for setting this limiter was not available prior to completing 1-ST-29 at TC-3. TE-09 was written to track this open item and was later resolved when 1-ST-30C was satisfactorily completed. 1 () 3-155
RECIRCULATION FLOtt CONTROL SYSTEM h 1-ST-29 3.31.2 Discussion (Cont'd) Flux loop testing was not performed in order to expedite testing. The Level 1 and Level 2 criteria cannot be satisfied without performing this testing. The Recirculation Flow Control System will not be operated in the Flux Auto mode until this testing has been completed. Test Exception 4 was written to document that this testing was not performed and to create a test package. This test exception remains open. Duty cycle testing was also performed in Test condition 3. Duty cycle testing was accomplished by obtaining steady state flow control valve data with the HPU's locked, the HPU's unlocked and flow controllers in manual, and the HPU's unlocked with the flow controllers in automatic. The duty cycle of both control valves exceeded the Level 2 criteria g of 0.2% Hz. "A" was 1.4% Hz and "B" was 2.6% Hz. This was documented by TE-10 and sent to General Electric Engineering for dispositioning. GE has indicated a need for retesting.
- 4. Test Condition 6 Recirculation Flow Control System test 1-ST-29 was performed in Test Condition 6 between 20 May and 22 May 1986. The results are summarized in Table 3.31-1. Similar testing as Test condition 3 was performed at Test Condition 6 along the 95-100% rod line.
9 3-156
1 l O ==c1=cutar1o= roo co===ot srsr== 1-ST-29 l 3.31.2 Discussion (Cont'd) Position and flow loop testing on 100% rod line was performed for three different flow conditions. Minimum flow on fast speed recirculation pumps, 75% total core flow, and 95% total core flow. The control system settings were not changed from those optimized in TC-3. These recirculation controller dial settings are shown in Table 3.31-2. For the position loop tests, neither flow control valves (FCV) satisfied the response time criteria and FCV A exceeded the delay time criteria as documented in Test Exceptions (TEs) 12 and 13. General Electric Engineering has evaluated these minor violations and has accepted them. At each flow condition, the flow loops were tested by inserting negative and positive flow demand (flow testing) steps. At minimum flow and 75% flow, + 5% T'T steps were performed At 95% flow, + 2.5% steps were
~
k/ used where it was determined necessary in order to provide sufficient margin to a reactor scram. The flow steps were inserted into each loop individually and then both loops simultaneously. The collected data was then analyzed for time response, flow response, and margins to APRM and flow biased scrams. Because the flow transmitters were dampened to quiet the noise in the signals, the measured responses were changed. Therefore, TE-15 was written requesting General Electric Engineering to evaluate the data. TE-15 was dispositioned as acceptable. It also appears that during B loop testing there was a significant overshoot. It was difficult to quantify the overshoot because of the steady state flow oscillations in the B loop. TE-16 was written to document the overshoot problem and has been closed based on General Electric observations. In Test Condition 6, flow loop balancing time testing was to be performed at minimum flow, but was not. This testing was performed previously and it was acceptable net to test again in Test Condition
- 6. TE-14 documents this exception.
O 3-157 l
RECIRCULATION FLOW CONTROL SYSTEM g 1-ST-29 3.31.2 Discussion (Cont ' d) Flux loop tests on the 100% rod line were not performed in Test Condition 6. TE-17 was written to document this. Administrative controls are in place to ensure that reactor recirculation is not operated in the Master Manual Mode of recirculation flow control until after flux loop testing is properly performed. Duty Cycle and Flux estimator tests on the 100% line were not performed. The flux estimator portion was deleted and was included in TE-17 along with flux loop testing. The Duty Cycle testing was omitted which generated TE-18. Duty Cycle testing is planned to be reperformed. Function generator linearization data was also collected during power ascension to Test Condition 6 a per 1-ST-29. The graphs of valve position versus W drive flow, function generator input versus function generator output, and function generator input versus drive flow show that the maximum incremental gain did not vary by more than 1.67 over the range of data collection. The criteria was for not more than a 2 to 1 gain variance. This satisfied the criteria. r O 3-158
I RECIItCUIATION FLON CONTROL SYSTEM 1-ST-29 O I l 1 The test exceptions for 1-ST-29 are reiterated as follows. The status as of 15 July 86 is also listed. TEST TE CONDITION DESCRIPTION STATUS I 1 OV This TE was resolved in TC open vessel Closed ! when system tuning was performed to I correct slow valve position response. ) 1 2 1 ERIS archiving problem: Failure to Closed record the 95% flow tests. Repeated testing. 3 3 Initial testing was interrupted. TC-3 Closed testing reperformed. 4 3 Flux Loop and Flux Estimator testing Open (s) was not conducted in order that test-ing could be expedited. This test exception remains open. Flux loop testing is under consideration. 5 3 This TE was resolved by performing Closed position and flow loop testing at 95% flow after a computer archiving problem had lost the previous test data. 6 3 The delay and response times from the Closed position loop testing did not satisfy the criteria. 7 3 A noisy drive flow signal problem made closed flow loop testing analysis inaccurate. I O 3-159
RECIRCULATION FLOW CONTROL SYSTEM l-ST-29 O TEST TE CONDITION DESCRIPTION STATUS 8 3 The extrapolated neutron margin to Closed scram was 1% exceeding a Level 2 cri-teria of 7.5% for a +5% step change with both loops in auto at 95% flow. 9 3 This TE was resolved when the flow Closed limiter was properly set per 1-ST-30C. 10 3 The duty cycles for FCV "A" and "B" Open did not satisfy the Level 2 criteria of 0.2% Hz. A retest is needed. 11 DELETED DELETED 12 6 The response times for FCV "A" and "B" Closed exceed the criteria. 13 6 The delay time for FCV "A" exceeded the criteria. Closed ll) 14 6 Balancing time testing was not per- Closed formed in TC-6. 15 6 The flow response times can not be closed accurately determined due to trans-mitter dampening. 16 6 Flow loop "B" has an overshoot that Closed exceeds the criteria. 17 6 Flux Loop and Flux Estimator testing Open was not performed. Flux loop testing is under consideration. 18 6 Duty Cycle testing for both FCV's was Open not performed. Retest is needed. 19 6 This TE was resolved by setting the Closed Flow Control upper limit per 1-ST-30C. O 3-160
O O O TABLE 3.31-1 1-ST-29
SUMMARY
ACCEPTANCE CRITERIA EVALUATION ACCEPTANCE CRITERIA REQUIRED MEASUstED TC 3 'IC 6 Level 1
- 1. The Transient response of any Decay Ratio f 1.0 Maximum Decay Ratio =
recirculation system-related variable to any test input must f 1.0 f 1.0 not diverge. Level 2
- 1. The decay ratio for each controlled Position and Velocity Maximum Decay Ratio =
mode of response must be less than Decay Ration f 0.25 f 0.25 < 0.25 or equal to 0.25.
- 2. For position demand step inputs Delay Time f 0.2 Maximum Delay Time =
of,1% to 5% the delay time shall f 0.27 sec Se@ f 0.3 be f 0.2 sec. (TE-6) (TE-13)
- 3. For position demand step inputs of Response Time f 0.5 sec Ma:timum Response Time =
1% to 5% the reponse time shall be 0.59 sec 0.62 Se@ f 0.5 sec. (TE-6) (TE-12)
- 4. Overshoot after a small position Overshoot (_ 10% of step Maximum Overshoot =
demand input (1% to 5%) shall be 10% 0 f 10% of magnitude of input. 3-161
O O O TABLE 3.31-1 (Cont'd) 1-ST-29
SUMMARY
ACCEPTANCE CRITERIA EVALUATION (Cont'd) ACCEPTANCE CRITERIA REQUIRED NEASURED l K3 K6
- 5. The Decay ratio of the flow loop Decay Ratio { 0.25 Maximum Decay Ratio =
j response to any test input shall (TE-7) 0.25 be g 0.25. .
- 6. Flow loop gains should be set to Balancing Time f 25 sec. Maximum Balancing Time =
j correct a flow imbalance in less 24 sec TE-14 than 25 sec.
- 7. The delay time for flow demand step Delay Time f 0.5 sec. Maximum Delay Time =
(f 5%) shall be 0.5 seconds or less. TE-7 0.72 sec, (TE-15) l
- 8. The response time for flow demand Response Time f 1.2 sec. Maximum Response Time =
step (f 5%) shall be 1.2 seconds or TE-7 1.25 sec: less. (TE-15)
- 9. The maximum allowable flow overshoot Overshoot f 6% of step Maximum Overshoot =
for step demand of f 5% of rated shall TE-7 16.8% be 6% of the demand step. (TE-16) i 3-162
O O O TABLE 3.31-1 (Cont'd) i 1-ST-29
SUMMARY
ACCEPTANCE CRITERIA EVALUATION (Cont'd) ACCEPTANCE CRITERIA REQUIRED MEASURED TC 3 TC 6
- 10. The flow demand step settling time Settling Time f 6 sec. Maximum settling Time =
shall be f.6 sec. TE 7 Not Performed
- 11. The trip avoidance margin must be APRM Neutron > 7.5% Minimum APRM Scram
, > 7.5% for APRM margin to scram Avoidance Margin = 1% 17.6% (TE-8)
- 12. The trip avoidance margin must be Simulated Heat Flux Minimum Heat Flux
> 5.0% for simulated heat flux 2 5.0% margin to scram Scram Avoidance Margin =
1 8.5% 9.45% 1 3-163 I a _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _______
r'% V RECIRCULATION FLOW CONTROL SYSTEM 1-ST-29 TABLE 3.31-2 Recirculation Controller Dial Settings 1 Loop "A" Loop "B" Velocity Controller Gain Settings: K697 e Proportional Gain 1.1 1.1 e Derivative Gain 0.0 0.0 e Integral Gain 3.0 3.0 Position Controller Gain Settings: K695 e Proportional Gain 2.0 1.5 e Derivative Gain 6.0 7.0 (] e Bias 5.0 5.0 Plow Controller Gain Settings: K642 e Integral Gain 0.1 0.13 0 3-164
p RECIRC TWO PUMP TRIP G l-sT-30s 3.32 1-ST-30B RECIRC TWO PUMP TRIP 3.32.1 Description The major objective of this test is to record and verify acceptable performance of a recirculation two-pump trip and drive flow coastdown transient. The acceptance criteria applied to this test are shown in subsections 3.32.1.1 and 3.32.1.2. 3.32.1.1 Level 1 Criteria
- 1. The two-pump drive flow coastdown transient during the first 5 seconds must be bounded by the limiting Curves.
3.32.1.2 Level 2 Criteria b-s NONE 3.32.2 Discussion This test was conducted on 7-June-86 as part of Test Condition Power Ascension. The test was initiated by transferring the Recirculation Pumps from high to low speed simultaneously. The ERIS computer was utilized to gather recirculation drive flow data during the time in which the pumps coasted down. The test was initiated from a reactor power of 80% and 100% total core flow. The bounding curves for flow coastdown are derived from tables given in the River Bend Power Station Transient Safety Analysis Design Report. Points to develop the curvec were obtained by interpolating between points in the appropriate tables, based on measured plant recirculation drive flow loop transmitter time constants. O 3-165
~ , RECIRC TWO PUMP TRIP h 1-ST-30B 3.32.2 Discussion (Cont'd) Time zero was determined by taking into account the time delay due to the length of the drive flow transmitter instrument lines. This delay was applied to the time of the high speed breaker opening to establish time zero. Recirculation Pump "B" data failed to fall within the upper (4 second pump inertia time constant) bounding curve at 0.25 seconds. Test Exception 1 was generated to document the failure. The test data was subsequently evaluated by General Electric Engineering, and it was determined that the coastdown characteristic was satisfactory. Data at 0.25 seconds and earlier has low reliability and is not important for transient evaluations. No other test exceptions were generated for this test. The test exception is summarized below. O TE DESCRIPTION STATUS 1 Pump"B" Coastdown Criteria Violation Closed 3-166
RECIRCULATION SYSTEM PERFORMANCE (Q_/ l-sT-30c 3.33 1-ST-30C RECIRCULATION SYSTEM PERFORMANCE 3.33.1 Description A series of recirculation system operating data were recorded during power ascension along constant rod lines (75% and 100%). This data was used as a baseline for key system operating relationships for drive flow versus core flow, drive flow versus; flow control valve position, and core flow versus flow control valve position. This information was used to determine core flow shortfall, drive flow shortfall, core plate differential pressure, recirculation pump efficiency, and to set the maximum drive flow limiter. The acceptance criteria applied to this test are shown in Subsections 3.33.1.1 and 3.33.1.2. 3.33.1.1 Level 1 Criteria None 3.33.1.2 Level 2 Criteria
- 1. The core flow shortfall shall not exceed 65% at rated power. (Use core flow of 84.5 x 10 lbm/hr at 79% flow control valve position, 3037 gpm/ psi flow control valve Cv).
- 2. The measured core P shall not be 0.6 psi above prediction, using BOL values at rated power and rated core flow. (22.61 psid)
- 3. The drive flow shortfall shall not exceed 5% at rated power. (Evaluate using a pump flow of 30879 gpm or 11.67 x 10 6 lbm/hr (95%) for a flow control valve position of 79%).
3-167
RECIRCULATION SYSTEM PERFCRMANCE 1-ST-30C 3.33.1.2 Level 2 Criteria (Cont'd)
- 4. The measured recirculation pump efticiency shall not be more than 8% points below the vendor tested efficiency at rated power and rated flow.
- 5. The flow control system shall be adjusted to limit the maximum core flow to 102.5% of rated.
l 3.33.2 Discussion l l Recirculation system performance data was retrieved with l the reactor operating near the 75% rod line between ( 15-Apr-86 and 29-Apr-86. This was accomplished by i taking a minimum of six data sets over a range of flow control valve positions correlating to 60% - 100% core flow. The only applicable criteria to these conditions was llh l that the maximum flow limiter be set at 102.5%. I However, the data could not be accurately extrapolated to 102.5% flo'w due to a flow control valve position mismatch problem. Test Exception (TE) I was written to reperform the data collection along the 100% rod line after 1-ST-35, Reactor Recirculation System Calibration, had been performed. The maximum flow limiter was set to 102.5% as accurately as possible by averaging the drive flows: Testing to clear TE-1 was performed between 25 May and 2 June 86 along the 100% rod line. At these power and flow conditions all of the acceptance criteria apply. The following results were obtained:
- 1. The core flow shortfall was 3.2%, within the
. 5% criteria. l l l l 3-168
l RECIRCULATION SYSTEM PERFORMANCE !m1
~
1-ST-30C l 1 l 3.33.2 Discussion (Cont'd)
- 2. The drive flow was 4.7%25 design also within the 5% criteria.
- 3. The measured core pressure drop was 21.51 psi, below the criteria of 23.21 psi.
- 4. The recirculation pump efficiency had to be not less than 8% from the vendor tested efficiency of 89% per pump. "A" was 86.3%
efficient and "B" was 85% efficient.
- 5. As with the 75% rod line performance of 1-ST-30C, the maximum flow limiter was not set based on the 100% rod line data because the system calibration had not been completed.
TE-2 was written to document this problem and TE-4 was written to retake data along the 100% (]) rod line for extrapolation to 102.5% core flow. TE-4 was performed on 21 June 1986. The maximum flow limiter was set based on the TE-4 data. TE-2 and TE-4 were resolved accordingly. The only other test exception written against 1-ST-30C was to document the flow control valve mismatch that the recirculation system experiences when the jet pump loop flows are matched. This test exception (TE-3) is being evaluated by General Electric Engineering. O 3-169
RECIRCULATION SYSTEM PERFORMANCE 1-ST-30C l l A list of the test exceptions for 1-ST-30C along with the status l as of 15-Jul-86 follows: l l TE ROD LINE DESCRIPTION STATUS l 1 75% Data collection repreformed because reactor Closed recirculation system calibration was reper-formed, i 2 100% The maximum flow limiter was not set be- Closed i cause 1-ST-35 was not complete. TE-2 is resolved. l 3 100% Flow control valve mismatch exists. Core Open l flow and drive flow shortfall exist when considering individual flow control valve llh l I positions. This TE is under evaluation by GE. 4 100% Data collection was required to resolve Closed TE-2. This TE provided the means to collect data. TE-4 is resolved. 1 i l l O 3-170
O ==c'aco'^o" S'S'=" c^v^o" l-ST-30E 3.34 1-ST-30E RECIRCULATION SYSTEM CAVITATION 3.34.1 Description The purpose of this test is to verify that recirculation system cavitation runback features are adequate to prevent cavitation in the operable range of the power / flow map. Both the jet pumps and the recirculation pumps will cavitate at conditions of high flow and low reactor power where Net Positive Suction Head (NPSH) demands are high and little feedwater subcooling occurs. The recirculation system Flow Control Valves (FCV) will cavitate at conditions of high differential pressure and low reactor power (low feedwater subcooling). ( In both of the above cases, flow runback is accomplished by a transfer of the power supply to the recirculation motors from normal power (60Hz) to the low frequency motor generators (15Hz) . The acceptance criteria applied to this test are shown in Subsections 3.34.1.1 and 3.34.1.2. 3.34.1.1 Level 1 Criteria l None 3.34.1.2 Level 2 Criteria Runback logic shall have settings adequate to prevent operation in areas of potential cavitation. 3.34.2 Discussion In Test Condition (TC) 2, the flow control valve (FCV) t cavitation interlock was tested to verify that setpoints were adequate to prevent cavitation of the FCV's. The
- control rods were inserted until ERIS signals indicated that the recirculation pumps transferred to slow speed.
. The actual pump transfers were bypassed. This allowed Os verification that the transfer would occur before any cavitation without actually transferring the pumps, l
3-171
RECIRCULATION SYSTEN CAVITATION g 1-ST-30E 3.34.2 Discussion (Cont'd) This test was initiated at 35% power with FCV's at the minimum position and the recirculation pumps in fast speed. The interlock came in at 3.14 Mlb/hr feed flow. This was later found to be approximately 7% lower than actual as documented in TE-3. Since this is in the conservative direction, acceptance criterion was satisfied. A test exception (TE-1) was written to remove temporary ERIS signals for this test. These sensors have been removed and TE-1 of TC-2 is resolved. TC-3 testing was initiated at about 50% power and 98% core flow. This test was performed to demonstrate that the recirculation system cavitation interlock features are adequate in the operating portion of the power / flow map. No cavitation occurred and no trip actuated upon reaching the lower operating limit allowed by the power / flow map. This adequately completed the test. TE-1 of TC-3 was written to document procedure steps a which could not be performed since no cavitation W interlock was actuated. This TE is closed. TE-2 of TC-3 was written to document the removal of the temporary ERIS signals. These have been removed and TE-2 is closed. TE-3 .was written against 1-ST-30E because a feedwater flow transmitter calibration error was discovered which could have adversely effected these test results. The j error was 7% power lower than actual which turns out to be a conservative adjustment, placing the interlock even , farther below the operating region of the power / flow l map. I ! Since the interlock never actually initiated, actual values were not measured. The interlocks nominal setpoints are 8.6 degrees F difference between the steam dome and recirculation pump suction temperatures or a low feedwater flow of 3.1 Mlbm/hr. Again, the only acceptance criteria was that the runback logic shall have adequate settings to prevent operating in areas of potential cavitation and this was satisfied in TC-2 and TC-3. Below is a list of test exceptions generated during 1-ST-30E O l 3-172
RECIRCULATICII SYSTEM CAVITATICII 1-ST-30E TEST TE CONDITION DESCRIPTION STATUS 1 2 Temporary ERIS signals were Closed removed to resolve this TE. 1* 3 The pump transfer never closed occurred, but no cavitation was noted in the operating band of the power / flow map. This TE is resolved. l 2 3 Temporary ERIS signals were Closed removed to resolve this TE. O 3 2,3 FW Flow was found to be in- Closed dicating 7% higher than actual.
- TE-1 for TC-3 was incorrectly identified.
O 3-173
O . ma== a a =1r= a=== 1-ST-31 3.35 1-ST-31 LOSS OF OFFSITE POWER 3.35.1 Description This test verified the proper performance of plant emergency electrical supplies and the proper reactor transient response during a loss of offsite power incident. Subsections 3.35.1.1 and 3.35.1.2 list the applicable acceptance criteria. 3.35.1.1 Level 1 Criteria
- 1. The Reactor Protection System, the diesel-generators, and HPCS must function properly without manual assistance, and HPCS and/or RCIC system action, if necessary, shall keep the reactor water- level above the initiation level of Low O Pressure Core Spray, LPCI, and Automatic Depressurization.
- 2. If any safety / relief valves open, no more than one valve shall reopen after the first blowdown.
- 3. Reactor pressure is maintained below the set point of the first safety valve, during the transient following the loss of the main generator and all offsite power.
3.35.1.2 Level 2 Criteria
- 1. Proper instrument display to the reactor operator shall be demonstrated, including power monitors, pressure, water level, control rod position, suppression pool temperature, and reactor cooling
! system status. Displays shall not be dependent on l instrumentation specially installed for this test. l . O i 3-174 l
LOSS OF OFFSITE POtfER 1-ST-31 3.35.1.2 Level 2 Criteria (Cont'd)
- 2. If the low-low set pressure relief logic functions, the open/close actions of the SRV's shall occur within i 15 psi and i 20 psi of their design setpoints, respectively.
- 3. 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.
- 4. Reactor cooling systems are able to maintain adequate suppression pool temperature and maintain adequate drywell cooling to prevent actuation of high drywell pressure signal to the ADS system.
- 5. The maximum Reactor Pressure is more below the first safety valve setpoint.
than 40 psi lll 3.35.2 Discussion 1-ST-31 was initiated in Test Condition 1 on 6-Dec-85. The reactor was in the Startup mode at 12% power with the turbine generator on line. A loss of offsite power was initiated by tripping the turbine generator with house loads supplied off the normal service transformers with the preferred transformers locked out to prevent auto transfer. The reactor scrammed within one second from high APRM flux (15% in Startup mode) caused by the resultant pressure transient. Pressure rose from 950 psig initial to 1020 psig, approximately seven and one-half minutes into the transient. The minimum (narrow range) water level was 10 inches, occurring approximately 30 seconds after the scram. The level 1 and 2 criteria concerning SRV's and HPCS/RCIC were therefore satisfied. Only one abnormality was observed during the transient which resulted in a level one failure. O 3-175
LOSS OF OFFSITE POWER l-ST-31 3.35.2 Discussion (Cont'd) TE-01 was written to document the problem. A 3 second time difference in the standby diesels energizing their busses resulted in one control building chiller (HVK*P1A) not starting. This caused the DIV I diesel to fail the criteria to have all of its sequenced loads cycle onto its bus. Extensive troubleshooting and analysis determined that both diesels functioned as designed and that starting time differences can be accounted for due to inherent differences with the two machines and associated support systems. (e.g. starting air pressure). Determination of the conditions for which two chiller operation would be required has been made. Results indicated that one division of control building chilled water is acceptable for at least the first 20 minutes of operation after which operator action may be required. Safe shutdown of the plant on loss of offsite power was not compromised. TE-01 is O' resolved and is summarized below. All applicable criteria were satisfied. l i O 3-176
LOSS OF OFFSITE POWER 1-ST-31 TE DESCRIPTION STATUS 1 The division i diesel failed to Closed properly sequence one of its loads (HVK*P1A) onto the bus. The failure to start was due to the system logic and the 3 second time differences between the divisions. Chill water flow (due to
!!VK* PIB) had already come up above the low flow setpoint before the "A" division chiller was reenergized. Thus, HVK*P1A did not start because the low flow signal was never seen. This was determined safe for 20 minutes which is adequate time for operator action.
g h 9 3-177
DRYWELL PIPING VIBRATION 1-ST-33 i 3.36 1-ST-33 DRYWELL PIPING VIBRATION 1 3.36.1 Description The purpose of this test is to verity that the General Electric supplied piping (Recirculation, portions of Main Steam and Reactor Core Isolation Cooling (RCIC) steam piping) steady state vibration is within acceptable limits and to verify that, during operating l transient loads, pipe stresses are within code limits. Vibration testing on other piping is covered under 1-ST-100. The acceptance criteria applied to this test are shown l in Subsections 3.36.1.1 and 3.36.1.2 3.36.1.1 Level 1 Criteria () Level steady 1 limits on piping displacements and strains for state and transient vibration testing are contained in Table 3.36-1 and 3.36-2 respectively. 3.36.1.2 Level 2 Criteria Level 2 limits on piping displacements and strains for steady state and transient vibration testing are contained in Table 3.36-1 and 3.36-2 respectively. Main Steam, Reactor Recirculation, RHR and RCIC piping were monitored for vibration using lanyard potentiometers and strain gages during steady state and transient plant conditions throughout the testing program. The ERIS computer system was used to statistically analyze the displacement and strain data and calculate peak to peak displacement and strain values for each lanyard potentiometer and strain gage. O 3-178
DRYWELL PIPING VIBRATION 1-ST-33 3.36.2 Discussion Recirculation piping was monitored for steady state vibration at minimum, intermediate and maximum stable preoperational flows during the hot recirculation preop 1-PT-53. During power ascension testing, recirculation piping was monitored at minimum flow, 50% of rated, 75% of rated, and 100% of rated flow. RHR piping was to be monitored during the Shutdown Cooling mode of operation. But the data was not obtained due to a ERIS computer failure. This is documented in Test Exception 18. Main Steam piping steady state vibration was monitored at 25%, 50%, 75%, and 100% of rated steam flow. RCIC steady state vibration was checked during the performance of 1-ST-14, RCIC system testing, at maximum flow conditions. Transient vibration for the recirculation piping was monitored during pump transfer to high speed and pump trip to LFMG and during 1-ST-27, Generator Load lll Rejection. l Transient vibration for Main Steam piping was monitored l during Main Turbine trip at 8.5% power (Test Condition l One), Generator Load Rejection (1-ST-27), and Relief Valve Testing (1-ST-26). Table 3.36-3 summarizes the data taken for steady state vibration at 100% power, transient vibration during the Generator Load Rejection at 100% power, and individual relief valve operation. During the performance of this test, there was a number of criteria violations and test exceptions encountered. I A summary of the test exceptions written during 1-ST-33 follows. All test exceptions have been resolved. The criteria violations were evaluated and found acceptable by General Electric Engineering. 9 l 3-179 1
O DRYWELL PIPING VIBRATION Q 1-ST-33 TE TEST CONDITION DESCRIPTION STATUS 1 OV Constant support hanger pins closed on recirc pumps w..re not removed I prior to test. Accepted as is. GE Piping Design evaluated the data and found it acceptable. 2 OV Strain gage FA10-S failed. Closed GE Piping Design found the TE acceptable since data could be obtained from remaining strain gages. l 3 OV Strain gages RA7-S & RA8-S Closed () failed Level 2 criteria. GE Piping Design evaluated the data and found it acceptable. 4 OV Minor errors in recorded Closed plant conditions. Accepted "as-is" since the data was not used for criteria evaluation. 5 OV Test data sheet has "N/A" Closed for all data dealing with Recirc Loop A (B) since the test was measuring loop B (.A ) performance. l Accepted "as-is". 6 OV Recirc Pump B transfer from Closed low to high speed was substituted for Pump B start. GE Piping Design evaluated the changes and found it and the data acceptable. 7 HU Strain gage RA8-S failed Closed during Recirc Pump at minimum flow testing. Strain gage was repaired and retest results were acceptable. 3-100
DRYWELL PIPING VIBRATION h 1-ST-33 TE TEST CONDITION DESCRIPTION STATUS 8 HU Strain gage SA12-S failed Closed and strain gage SA3-S failed Level 2 criteria during RCIC testing at maximum flow. On subsequent retest SA3-S passed criteria and SA12-S failed again. GE Piping Design evaluated the test data and accepted the test results. 9 HU Strain gage SA12-S failed Closed and SA3-S, SA4-S, SB3-S failed Level 2 criteria during Main Turbine Trip (TC-1) at 8.5% power. On subsequent retest SA3-S and SA4-S failed Level 2 criteria lll and sal 2-S failed again. GE Piping Design evaluated the test data and accepted the test result. 10 HU Safety Relief Valve vibration Closed data was not taken at the correct frequency. On subsequent retest of SRVs, eight test points failed Level 2 criteria. GE Piping Design reviewed and approved the test results. 11 TC-2 Strain gages SA3-S and SA4-S Closed failed Level 2 criteria and SAll-S and SA12-S were not operable during 25% power steady state testing. SAll-S and SA12-S were repaired and retested. The retest results were acceptable. 12 TC-2 Strain gage RA9-S failed during Closed Recirc Pump transfer'to high speed vibration testing. GE Piping Design reviewed and accepted the test results. g 3-181
DRYWELL PIPING VIBRATIOlt 1-ST-33 TE TEST COIEDITION DESCRIPTIOtt STATUS 13 TC-2 Strain gages RA7-S, RA8-S, and Closed RA10-S tailed Level 2 criteria during Recirc Pump transfer to high speed. GE Piping Design has reviewed and approved the test results. 14 TC-5 Strain gage SC3-S failed during closed 75% power steady state testing. GE Piping reviewed and approved the test data. 15 TC-6 Strain gage Sc3-S and lanyard closed (~) potentiometers SC6-DZ, SD6-DX, (_/ SD6-DY, and SD6-DZ failed during 1004 power steady state vibration testing. GL Piping Design reviewed and accepted the test data for this TE. 16 TC-6 Strain gages SA12-S, SC3-S, and closed SD3-S failed during Generator Load Rejection transient testing. GE Piping Design reviewed and l approved the test results for this TE. 17 TC-6 Nineteen test points failed Closed Level 2 criteria during Generator Load Rejection transient testing. GE Piping Design reviewed and approved the test data. 18 TC-6 RHR vibration data, during Closed Shutdown Cooling, was lost due to a failed ERIS panel. GE Piping Design responded that monitoring Recirc Piping was not required during RHR Shutdown O Cooling. 3-182
l I TABLE 3.36-1 hl STEADY STATE VIBRATION LIMITS (Peak to Peak) MAIN STEAM REACTOR RECIRCULATION STRAIN GAGES (in/in x 10-6) STAIN GAGES (in/in x 10-6) TEST POINT Level 2 Level 1 TEST POINT Level 2 Level 1 SA3-5 l 82 l 164 RA7-5 163 l l l 326 SA4-5 l 82 l 164 l RA8 S 163 l l 326 SAll-S l 47 l 95 l RA9-5 l 163 l 326 SA12-5 l 47 l 95 l RA10-S 163 l l 326 , SB3-S/SC3-5 l 81 l 162 l l l 584-S/SC4-S l 81 l 162 l l l SD3-5 l 82 l 164 l l l l SD4-5 l 82 l 164 l l l l 1 l l l l l LANYARD POTS (inches) LANYARD POTS (inches) I l SA6-DX 1 050 1 100 SA6-DY l l l RA3-DX/R33-DY l 1 032 l 3 065 t l 1 040 l 1 080 l RA3-DZ/R33-DZ l 1 033 l 1 065 l SA6-DZ 1 050 1 100 SA8-DY l l l RA5-DX/RBS-DX l 1 030 l 1 060 t l 1 070 l 1 140 l RAS-DY/RBS-DY l 1 039 l t.078 i SA9-DX 1 020 1 040 SB6-DX/SC6DXl l l l RAS-DZ/RBS-DZ l 1 044 l 1 088 i 1 065 l 1 130 l l l SB6-DY/SC6DYl 1 063 l 1 125 l SB6-DZ/SC6DZl !.018 l 1 180 l SD6-DX l 1 033 l 1 065 l SD6-DY l 1 028 l 1 055 l SD6-DZ l 1 020 l 1 040 l l l l \ l e 3-183
p,' TABLE 3.36-2
'v TRANSIENT VIBRATICII LIMITS (Peak to Peak)
MAIN SIT.AN REACTOR RECIRCULATION STRAIN GAGES (in/in x 10-6) STAIN GAGES (in/in x 10-6) TEST POINT Level 2 Level 1 TEST POIFT Level 2 Level 1 SA3 5 l 101 l 903 i RA7-S l 14 l 889 SA4-5 l 101 l 903 l RA8-S l 14 l 889 SA11-5 l 25 l 1122 RA9-5 l l 23 l 1116 SA12-5 l 25 l 1122 RA10-S l l 23 l 1116 SB3-5/SC3-5 l 101 l 935 l l l SB4-5/SC4-5 l 101 l 935 l l l SD3 5 l 104 l 933 l l l SD-4-5 l 104 l 933 l l l l l l l l LANYARD POTS (inches) LANYARD POTS (inches) SA6 DX l 1 033 l 1 961 l RA3 DX/RB3-DX l 1 030 l 1 476 SA6 DY l +.032 l +.848 l RA3 DZ/RB3-DZ l +.030 l +.406 SA6 DZ l I.030 l I.848 l RA5-DX/RBS-DX l I.030 l I.240 SA8 DY l 3057 l 31.871 l RA5-DY/RB5-DY l 3030 l 5348 SA9 DX l 1 030 l 11.116 l RA5 DZ-RB5-DZ l 1 030 l 1 296 SB6 DX/SC6DXl 1 041 l 12.048 l l l SB6-DY/SC6DYl 1 036 l 11.736 l l l SB6 DZ/SC6DZl 3 044 l 12.071 l l l SD6-DX l !.037 l 11.017 l l l SD6 DY l 1 034 l t.889 l l l SD6-DZ l 1 031 l 1 889 l l l l l l l l O 3-184
DRYWELL PIPING VIBRATION h 1-ST-33 TABLE 3.36-3 PIPING VIBRATION RESULTS SUBG4ARY GENERATOR RELIEF TEST 1004 LOAD VALVE POINT STEADY STATE REJECTION OPERATION SA3-S 18.72 166.3 (17) 152.3 (10) SA4-S 21.40 76.4 75.19 SA6-DX .006 .037 (17) 0.0325 SA6-DY .006 .044 (17) 0.0358 (10) SA6-DZ .021 .050 (17) 0.0445 (10) SA8-DY .009 .053 N/A SA9-DX .005 .025 N/A SAll-S 1.949 21.2 N/A SA12-S 2.307 1360.0 (16) N/A SB3-S 22.81 71.2 89.51 SB4-S 10.57 155.0 (17) 138.1 (10) SB6-DX .008 .1055 (17) 0.086 (10) SB6-DY .007 .087 (17) 0.045 (10) SB6-DZ SC3-S 0
.004 (15) 0
.086 (17)
(16) 0.039 82.32 g SC4-S 3.472 50.6 2.728 SC6-DX .007 .056 (17) 0.010 SC6-DY .010 .077 (17) 0.003 SC6-DZ 1.506 (15) .059 (17) 0.001 SD3-S 11.57 954.6 (16) 128.3 (10) SD4-S 18.38 136.6 (17) 68.92 SD6-DX 1.376 (15) .048 (17) 0.029 SD6-DY 1.643 (15) .048 (17) 0.034 SD6-DZ 2.189 (15) .067 (17) 0.064 (10) RB3-DX .002 .024 RB3-DZ .009 .020 RA3-DX .006 .016 RA3-DZ .007 .013 RAS-Dx .001 .009 RA5-DY .002 .001 RA5-DZ .002 .002 RBS-DX .002 .012 RA7-S 10.82 44.24 (17) RA8-S 9.178 43.23 (17) RA9-S 21.15 59.96 (17) RA10-S 21.52 53.80 (17) RBS-DY .003 .003 RB5-DZ .002 .010 (Number) indicates test exception number h 3-185 j
/D RECIRCULATIOtt SYSTEll FLOW CALIBRATION V
1-ST-35 ) 3.37 1-ST-35 RECIRCULATION SYSTEM FLOW CALIBRATION 3.37.1 Description This test is performed for a complete calibration of the installed reactor recirculation system flow instrumentation. Flow indication was adjusted based on jet pump flow. After the relationship between drive flow and core flow was established, the flow biased APRM system was adjusted to be consistent with this relationship. The acceptance criteria applied to this test are shown i in Subsections 3.37.1.1 and 3.37.1.2. gs 3.37.1.1 Level 1 Criteria
\_)
None 3.37.1.2 Level 2 Criteria i l 1. Jet pump flow instrumentation shall be adjusted ) such that the jet pump total flow recorder will provide a correct flow indication at rated conditions.
- 2. The APRM flow-biased instrumentation shall be adjusted to function properly at rated conditions.
- 3. The calculated jet pump M-Ratio shall not be <; 0.2 points below prediction. ( Predicted is 2.618)
O o 3-186
RECIRCULATION SYSTEM FLON CALIBRATION h 1-ST-35
- 4. The nozzle and riser plugging Criteria shall not be exceeded;
- a. Riser Criterion 0.1 10 p 0.5 (dP3 + dPk )
i=1 _ , {0.1 10 p 0.1 i=1
- b. Nozzle Criterion de3 - dPy T0.12 0.5 (dP 3 + dPk I where8P a the jet pumps ok nd the dPkam=ePressure riser, anddrop Pi =inPressure drop in jet pump i on the same loop as jet pumps j and k.
- 5. During two pump operation at rated core flow, the bottom head drain temperature as measured by the bottom head drain line thermocouple should be within 30 degrees F of the recirculation loop temperatures.
O 3-187
RECIRCULATION SYSTEM FLOW CALIBRATION 1-ST-35 3.37.2 Discussion Recirculation System Flow Calibration, 1-ST-35, was performed in Test Conditions, TC-3 and TC-6 at River Bend Station. In TC-3, this test was performed at 70% power and 100% core flow with recirculation system drive flows matched. The TC-6 testing was conducted at 97% power and 98% core flow with jet pump loop flows matched. The TC-6 configuration with jet pump loop flows matched was a better configuration. The flow instrumentation indicate that with drive flows matched, the jet pump loop flows are mismatched. It is preferred to match jet pump loop flows as dictated by plant Technical Specifications. The flow mismatch situation is currently under investigation by General Electric Engineering (Refer to Section 3.33). The purpose of 1-ST-35 was to completely calibrate the recirculation system flow instrumentation. O This accomplished by collecting recirculation system data at near rated conditions and processing that data through was the offline Mark III computer program JRPump. JKpump is a computer program that accesses a plant specific data file to calculate recirculation system parameters using additional input data supplied by this test. The program consists of two sub programs JPump and RPump. JPump bases its calculations on jet pump flow and elbow tap flow, while RPump utilizes head curves. The results of the JRPump calculations were compared to acceptance criteria and used to adjust the APRM flow unit gains, jet pump loop flow summer gains, and the recirculation flow control system drive flow signal inputs. Calculations were also performed to determine nozzle and riser plugging criteria, bottom head drain to recirculation loop temperature differences, and process computer accuracy. The results are shown in Table 3.37-1. O 3-188
RECIRCULATION SYSTEM FLOW CALIBRATION h 1-ST-35 Notice that the APRM flow bias gain adjustment factor (GAF) criteria was changed for TC-6. (The GAF is basically a ratio of indicated flow to actual (JRPUMP) flow and is applied to the signal output) . That was done because the method being employed left the process computer (and flow bias input values for core flow), slightly higher than actual core flow. The desired as left condition was to have the indicated flow slightly less than or equal to actual flow. This results in a more conservative thermal limit evaluation and flow biased trip setpoint. In any case, the maximum deviation was less than or equal to 2%. Table 3.37-1 is the result of three interations of running 1-ST-35 in both TC-3 and TC-6. The test was performed this way to verify that the GAF's were applied to the APRM flow units and jet pump summer properly. After the TC-3 testing was completed, jet pump 19 was ggg recalibrated resulting in Test Exception (TE) 1. TE-2 was written before TC-6 testing began because the drive flow transmitters were adjusted to dampen the noise in the signals. There were three TE's written against the TC-6 results package. The GAF for APRM flow unit D was calculated to be 0.99 which was below the minimum required of 1.00 resulting in TE-3. Based on this the gain was adjusted slightly, but a new GAF has not been calculated. TE-4 was written to document that the process computer core flow reads 2.09% less than the JRPump calculated core flow. The desired condition is to be within 2.0%. This TE is acceptable since the error is conservative and the TE has been closed. TE-5 was written because a procedural step, requiring the recirculation flow control system drive signal inputs to be adjusted, was not performed at the time that the test was performed. This TE has cince been resolved by adjusting the signals. Similar core flow calibrations checks will be done periodically using the appropriate plant procedures, a The following is a listing of the Test Exceptions W generated during 1-ST-35 and their status as of July 21, 1986. 3-189
I g RECIRCULATION SYSTEM FLOW CALIBRATION U 1-ST-35 1 l TEST TE CONDITION DESCRIPTION STATUS 1 3 This TE was resolved by testing Closed in TC-6. Jet pump 19 was re-calibrated 2 6 This TE was resolved by retest- Closed ing in TC-6 after the recircula-tion drive flow transmitters were adjusted to dampen the noise in the drive flow signals. 3 6 APRM Flow unit GAF "D" was left Closed (]) outside the criteria without re-testing. It was adjusted properly since the test. 4 6 The process computer core flow Closed reads 2.09% less than the JRPump calculated values only 2% is de-sired. Accept as is. Error is in the conservative direction. 5 6 This TE was resolved when the Closed ' H638 I/V cards inputting to the recire flow control system were adjusted to indicate rated drive flow at rated core flow. I O ( 3-190
l O O RECIRCULATION SYSTEN FLON CALIERATION O 1-ST-35 TABLE 3.37-1 l REQUIRED CRITERIA (Level 2) TC-3 (23 April 86) TC-6 (27 MAY 86) 1 0.98 f Jet Pump Loop Flow f 1.00 Loop A=1.00 Loop B=1.00 Loop A=0.98 Loop B=0.98 GAF . 0.98 < APRM Flow Bias GAF g 1.00 _ A=1.00 E=0.99 N/A B=1.00 F=1.00 C=1.00 G=1.00 l D=0.98 H=1.00 1.00 f APRM Plow Bias GAF f 1.02 N/A A=1.00 E=1.01 B=1.01 F=1.01
. C=1.01 G=1.02 D=0. 9 9 (TE-3 ) H=1.01 M-Ratio 2 2.418 Loop A=2.549 Loop B=2.423 Loop A-2.646 Loop B=2.518 Nozzle dP f 0.12 Highest dP=0.103 Highest dP=0.049 Riser dP f 0.1 Highest dP=0.065 Highest dP=0.051 Recirc Loop T-BHD T f 30 Deg. F. Loop A=2.1 Loop B=1.15 Loop A=2.6 Loop B=1.6 Deg. F. Deg. F. Deg. F. Deg. F.
I J Pump and R Pump Values Core Flow =0.12% Core Flow =0.095% Agree Within 2% Jet Pump Loop Flow A=0.16% Jet Pump Loop Flow A=0.109% Jet Pump Loop Flow B=0.08% Jet Pump Loop Flow B=0.07% 0.0% f,J Pump - Process Computer (2.0% 0.4% 2. 09 % (TE-4) Core Flow Core Flow 3-191
] REACTOR WATER CLEANUP SYSTEM l-ST-70 3.38 1-ST-70 REACTOR WATER CLEANUP SYSTEM s 3.38.1 Description This test verifies the mechanical operability of the Reactor Water Cleanup System (RWCU) in two modes of operation at normal operating reactor temperature and pressure. The reactor water Non-Regenerative Heat Exchanger (NRHX) outlet temperature was monitored during normal and blowdown operation to assure adequate Reactor Planu Component Cooling Water (RPCCW) cooling to prevent resin damage. Subsections 3.38.1.1 and 3.38.1.2 list the applicable acceptance criteria. 3.38.1.1 Level 1 Criteria None 3.38.1.2 Level 2 Criteria
- 1. The temperature at the tube side outlet of the NRHX's shall not exceed 130 degrees F in the blowdown mode and shall not exceed 120 degrees F in the normal mode.
3.38.2 Discussion The Reactor Water Cleanup System test was performed at 4% power starting 24-Nov-85 at River Bend 1. The Reactor Water Cleanup System (RWCU) test has two sections: (1) Normal Operation and (2) Blowdown Operation. The normal operation section of the test was used to establish the relationship between maximum RWCU
. flow through the Regenerative Heat Exchangers (RHX's) and maintaining NRHX outlet temperature to less than 120 degrees F. The blowdown section was used to establish the maximum obtainable blowdown flow without exceeding !
130 degrees F at the NRHX's outlet temperature. , i Q 3-192
-_..r._- . . .
REACTOR WATER CLEANUP SYSTEM h 1-ST-70 3.38.2 Discussion (Cont'd) The normal operation section was performed by throttling open the RWCU outlet to the RHX's (Valve F042) while maintaining the NRHX's outlet temperature below 120 degrees F by throttling open the reactor plant closed cooling water to the NRHX's. This was continued until either the F042 valve was fully open or the RWCU flow exceeded 329 gpm. The results are shown in Table 3.38-1. The blowdown operation section was performed by throttling the blowdown flow until one of the following condi tions was met:
- 1. Flow controller wide open
- 2. RWCU NRHX's outlet temperature exceeds 130 degrees F. g
- 3. RPCCW outlet temperature from the NRHX's reaches 180 degrees F.
The results of the blowdown testing are shown in Table 3.38-1. Test Exception 1 (TE) was written to document the level 2 criteria concern that the NRHX outlet temperature exceeded 130 degrees F during the blowdown portion of this test. However, the NRHX outlet temperature was observed to be less than 130 degrees F at a RWCU flow of 130 gpm. So, by restricting blowdown operation to below 130 gpm the NRHX outlet temperature is assured of staying below 130 degrees F. This TE is summarized below and has been resolved. 9 1 3-193
( REACTOR WATER CLEANUP SYSTEM 1-ST-70 TE DESCRIPTION STATUS 1 The NRHX outlet temperature exceeded Closed 130 degrees F during the blowdown mode with a flow rate of 180 gpm. However, with a flow rate of 130 gpm the 130 degrees F temperature limitation could be met. O o V 3-194
REACTOR WATER CLEANUP SYSTEM g 1-ST-70 TABLE 3.38-1 NRHX (F) RWCU OUTLET TEMP FLOW GPM TE's ACTUAL CRITERIA Normal Operation 111 120 360 None Blowdown 140 130 180 TE-01 Operation 130 130 130 None 9 l O 3-195
l I (s >) RESIDUAL HEAT REMOVAL SYSTEM l-ST-71 1
)
3.39 1-ST-71 RESIDUAL HEAT REMOVAL SYSTEM 3.39.1 Description The major objective of this test is to demonstrate that the RHR system is capable of removing residual and decay heat from the reactor at the design capacity derived from the information on the process diagram. l l The acceptance criteria applied to this test are shown in Subsections 3.39.1.1 and 3.39.1.2. 3.39.1.1 Level 1 Criteria None 3.39.1.2 Level 2 Criteria
- 1. The RHR system shall be capable of operating in the 0 shutdown cooling modes (with both one and two heat exchangers) at the heat exchanger capacity determined by the flow rates and temperature differentials indicated on the process diagram.
3.39.2 Discussion The Shutdown Cooling (SDC) mode of the RHR system was demonstrated following a plant scram for the "A" and "B" RHR loops at Test Condition 6 on May 30, 1986. Temperatures and flows were recorded using ERIS. This data was used to calculate the RHR heat exchanger capacities (see Table 3.39-1) which met the acceptance criteria of at least 116.5 MBTU/HR~per loop with two loops operating. 3-196
RESIDUAL HEAT REMOVAL SYSTEM g 1-ST-71 The following test exceptions were written to this test: TE DESCRIPTION STATUS 1 RHR flow could not be stabilized at 5050 Closed gpm and maintain a stable cooldown rate less than 100 degrees F. per hour. Flow had to be lowered to a condition other than that required per the process diagram. 2 SW outlet temperature for RHR A heat ex- Closed changer is not correct. Calculated a sub-stitute outlet temperature using a heat balance across the "A" heat exchanger. O i i O 3-197
RESIDUAL HEAT REMOVAL SYSTEM, 1-ST-71 TABLE 3.39-1 RHR - A LOOP RHR - B LOOP ACCEPTANCE MBTU/HR MBTU/HR CRITERIA MBTU/HR RHR SIDE 621 677 116.5 SW SIDE 623 745 116.5 O O 3-198 : l
- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - ~ - - - ~ - ~ ~ ~
I () OFF-GAS SYSTEM l-ST-74 3.40 1-ST-74 OFF-GAS SYSTEM 3.40.1 Description The purpose of this test is to verify the proper operation of the Off-Gas System over its expected parameters. The acceptance criteria applied to this test are shown in Subsections 3.40.1.1 and 3.40.1.2. 3.40.1.1 Level 1 Criteria Flow of dilution steam to the non condensing stage must not fall below 92% of the specified normal value when the steam jet air ejectors are operating. 3.40.1.2 Level 2 Criteria N The system flow, pressure, temperature, and dew point shall comply with the design specification and design specification data sheet supplied to the site. The catalytic recombiner, the hydrogen analyzer, and the desiccant dryers shall comply with the design specification. 3.40.2 Discussion 1-ST-74 testing was conducted while at steady-state conditions during heatup and at Test condition 2 and 6. All applicable Level I criteria were satisfied at each testing level. Because several parameters were outside the system design specifications, not all of the applicable Level 2 criteria were met. The off-gas system parameter results are listed in Table 3.40-1. The overall conclusion is that the off-gas system is capable of performing it's design function. Throughout the test program, excessive off-gas flow (greater than 60 SCFM - twice the design flow rate of 30 SCFM) resulted from excessive main condenser inleakage. In addition, equipment problems prevented testing of several system components, such as the "B/D" Dryer Train O 3-199
OFF-GAS SYSTEM l-ST-74 3.40.2 Discussion (Cont'd) and the Hydrogen Analysers. In the Heatup Test Condition, on 11/22/85, the off gas system was initially placed in service. Test data (Startup flow) was taken at this time and compared against limits given in the Design Specification Data Sheets. This data showed that the majority of system parameters were within the limits specified. Test Exception TE-01 was written against these parameters (six) which fell outside the Level 2 limits. On 11/24/85, with the off-gas system in service and the reactor at rated pressure and temperature, data was taken on off-gas system parameters. TE-02 was written due to the off-gas system having higher flow than specified in the prerequisites (170 SCFM vs. 30 SCFM). ggg TE-03_was written because the "B" Hydrogen Analyzer was inoperable. However, proper operation of the "A" Hydrogen Analyzer was demonstrated and the hydrogen content of the process stream was measured to be 0.1%. Desiccant Dryer data was taken for 72 hours on the "B" dryer. However, TE-04 was written due to the fact that two (2) dryers were on line during the entire data collection due to the high off-gas flow. The normal system line-up calls for only one dryer in service. TE-05 was written against the eight (8) parameters which failed to meet the Level 2 limits. During Test Condition 2, Off-gas System parameters were checked with the Reactor operating at 10-55% power. System flow had decreased from 170 SCFM, as measured in the Heatup Test Condition, to 105 SCFM. The majority of system parameters were again within their design values. TE-07 was written due to several parameters in addition to the system flow being outside of the specified limits. O 3-200
h OFF-GAS SYSTEM 1-ST-74 3.40.2 Discussion (Cont'd) Hydrogen Analyzer performance data was taken after the initial system parameter data was taken. During the interval between the two data collections, power was increased to 13%, which was outside of the specified initial condition of 10% (+/-l%) power. TE-08 was written to document this discrepancy and was subsequently closed out as having negligible effect on the Hydrogen Analyzer Data. Desiccant Dryer Performance Data was taken for Off-gas Dryer "C". TE-06 was written against the failure to satisfactorily test Dryer "C". Test Exception 9 was written as Test Condition 3. Off-gas testing was not conducted, due to the high off-gas flow. O During Test Condition 6, Off-gas system parameters were chocked with the reactor operating at 96% power. Due to the problem with excessive system flow (TE-10), a steam leak on B SJAE (TE-12), H2 Analyzer "A" inoperable (TE-13), desiccant dryer skid "A" in manual operation (TE-ll), and dryer skid "B" shutdown for maintenance, only testing on dryer bed "C" and Hydrogen Analyzer "B" was completed. The Dryer Bed "C" was put in service for 72 hours and the exit gas dew point was maintained below -110 degrees F for the duration of the test. The recombiner "A" performance was validated as the Hydrogen concentration in the recombiner effluent was 0%, which is less the 0.1% acceptance criteria. Hydrogen Analyzer "B" performance was verified during its calibration cycle. The following list summarizes the test exceptions for 1-ST-74 along with the status as of 15-Jul-86. O 3-201
OFF-GAS SYSTEM h 1-ST-74 TEST TE CONDITION DESCRIPTION STATUS
- 1 HU Off-gas parameters outside Level 2 limits Open for startup system 2 HU Off-gas system flow is greater than Closed specified in prerequisite 3 HU "B" Hydrogen Analyzer Inoperable Closed 4 HU Two dryers, instead of one as specified, Open were on-line during off-gas testing 5 HU Off-gas parameters outside Level 2 limits Open 6 2 "C" dryer only completed 48 hours of its Closed 72 hour run 7 2 Off-gas parameters outside Level 2 limits Open 8 2 Power was not constant during Hydrogen Closed Analyzer Data Collection 9 3 Did not conduct Test Condition 3 testing Open due to high flow 10 6 Off-gas system flow is greater than Open l specified in prerequisite 11 6 "A" dryer in Manual Control Open 12 6 off-gas parameters outside Level 2 limits Open 13 6 "A" Hydrogen Analyzer Inoperable Open
- All open Test Exceptions remain open pending resolution of
~
high condenser in leakage. O l 3-202 i )
O O O OFF-GAS SYSTEM 1-ST-74 OFF-GAS SYSTEM DESIGN PARAMETERS AND RESULTS TABLE 3.40-1 NORMAL RESULTS FOR TEST OPERATIOW DESIGN CONDITION PARAMETER RANGE LIMITS HU 2 6 Power (%) Dilution Steam 7.6-7.98 7.0-8.7 7.85 7.8 7.9 (lbm/hr) Preheater Inlet 1.0-5.0 1.0-6.7 2.2 1.1 1.7 Pressure (psig) 1 Recombiner Inlet 325-375 300-410 375 380 380 , Temperature ,( Note 1) l Degrees F. l l Recombiner 8 - 28 8 - 40 DNSC 7 40 7 40 Differential (Note 2) i Pressure (inches of water) l I Recombiner Outlet 1.0-5.0 1.0-6.1 3.7 2.6 3.7 l Pressure (psig) i i Operating Recombiner Temperature ('F) l Bottom 375-380 300-900 375 377 UP Scale Middle 375-830 300-900 376 409 605 Top 375-830 300-900 375 406 605 (Note 3) 3-203
O O O OFF-GAS SYSTEN 1-ST-74 OFF-GAS SYSTEN DESIGN PARANETERS AND RESULTS j TABLE 3.40-1 (Cont'd) 4 NORNAL RESULTS FOR TEST OPERATION DESIGN CONDITION PARANETER RANGE LIMITS BU 2 6 I I Standby Recombiner Temperature (#F) Bottom 325-375 250-400 390 362 600 Middle 325-375 250-400 390 357 600 Top 325-375 250-400 385 367 600 i Off-Gas Condenser (Note 3)
! Condenser Temperature 41.35 4135 92 220 130 F.
Off-Gas Condenser Outlet Temperature ( 154 (154 125 125 140
*F.
i i H2 Analyzer 0-0.1* Recorder (%) 0-1.0** 0-4% (.1 0.2 0.1 (Note 4) i Glycol Pump 15-50 15-60 20 36 15 Discharge Pressure (psig) 3-204
O O O 1 OFF-GAS SYSTM 1-ST-74 OFF-GAS SYSTEM DESIGN PARAMETERS AND RESULTS TABLE 3.40-1 (Cont'd) NORMAL RESULTS FOR TEST OPERATION DESIGN CONDITION PARAMETER RANGE LIMITS HU 2 6 Glycol Tank 32.5-35.45 32.5-40 35 35.5 36 Outlet Temperature (Note 5) (* F. ) Moisture Separator 36-45 33-45 42 44 53
- Outlet Temperature (Note 6)
(* F . ) ! Pre-Filter Differential Z1 g8 0.9 0.6 0.9 Pressure (Inches Water) l l Desiccant Dryer 70-90 70-100 70 72 100 l Outlet Temperature (Note 7) ) (* F. ) Dryer Outlet (-110) - (-85) (-100) (-75) -105 -101 4:-110 Dewpoint (* F. ) Absorber Differential 0.5-3 0-4 1.2 0.7 0.8 Pressure (psid) Absorber Vault (-5 ) - (+5 ) (-4 0 ) - (+4 0 ) 0 0 0 Temperature (*F.) Absorber Vessel (-5 ) - (+5 ) -4 0- (+4 0) (-10 ) - ( 2 ) (-4 ) - (1. 5 ) (-8 ) - (+6) m rature 3-205 ' * '
O O O i l l l OFF-GAS SYSTEM l-ST-74 OFF-GAS SYSTEM DESIGN PARAMETERS AND RESULTS l l TABLE 3.40-1 (Cont'd) ! NORMAL RESULTS.FOR TEST PARAMETER OPERATION DESIGN CONDITION PARAMETER RANGE LIMITS BU 2 6 l After Filter 1 0-5 1.1 .9 0.6 Differential Pressure (Inches Water) Off-Gas System 6-30 SCFM 0-300 SCFM 170 105 60 Plow (Note 9) Limit applicable at 0-50% power < ** Limit applicable at 50-100% power I NOTES:
, 1. High Inlet Temperatures are within Design Limits j 2. Instrument Reading is faulty
- 3. Thermostat Control Problem
- 4. Obtained via Grab Sample
- 5. High Temperature within design limit
! 6. Open item on Test Exception 12
- 7. High Temperature within design limit
- 8. PT-17 Reads low
- 9. High Condenser Leakage 3-206
] LOOSE PARTS MONITORING SYSTEM 1-ST-94 3.41.1 Description The purpose of this test is to obtain normal operating back-ground data for integration with the Loose Parts Monitoring System preoperation test data in establishing the overall system sensitivity. There are no Level 1 or Level 2 criteria associated with this test.
3.41.2 Discussion The Loose Parts Monitoring System test, 1-ST-94, was per-formed at four different test conditions at River Bend 1. Test Condition (TC) Open Vessel, TC Heatup, TC-3, and TC-6. At each condition, data was collected by accessing the inter-face module of the Loose Parts Monitor panel. Here, each sensor was selected and a copy of each drawing display was plotted with the measured RMS value recorded on it. This process was repeated for each of the eight sensors. TC Open Vessel was performed on 1 Oct 85 with a moderator Os temperature of 100 Deg. F. This subtest was used as a verification of the initial high level alarm settings with the plant at its minimum noise level. the results were satisfactory. The RMS values are shown in Table 3.41-1. The TC Heatup section of 1-ST-94 was performed at 3% power on 23 Nov 85 and recorded operational noise levels in the reactor at minimum operating conditions: reactor recirc-ulation pumps were in slow speed and reactor water cleanup was in operation. Channel 2 was inoperativt and changes were made to the Automatic Gain Control. This generated TE-01. The RMS values are shown in Table 3.41-1. 1-ST-94 was performed again at TC-3 with 85% core flow and at 65% power on 22 April 86. channel 2 still had a defective connection so it was not recorded. All other data was recorded successfully. The RMS values are shown in Table 3.41-1. The TC-6 data was recorded at 100% core flow with reactor power at 98% on 8 May 86. Channel 2 was still inoperable at that time. The RMS values are shown on Table 3.41-1. Because the Channel 2 remained inoperative through TC6, TE-02 ) was written and incorporated TE-01. TE-02 has been performed () for TC Open Vessel and Heatup, but is still open for TC-3 and TC-6. I i 3-207
LOOSE PARTS MONITORING SYSTEM g 1-ST-94 A list of the TE's and their status, as of 15 July 86, are shown in the following: TEST TE CONDITION DESCRIPTION STATUS 1 HU LPM Channel 2 was inoperable. Closed 2 ALL LPM Channel 2 was inoperable. Open Retake data for LPM Channel 2 at each test condition. 3 ALL LPM printer is inoperable during Open retest per TE-2. Repair is planned. O O 3-208
LOOSE PARTS MONITORING SYSTEM 1-ST-94 TABLE 3.41-1 RMS Values Sensor ID TC-OV TC-HU TC-03 TC-06 LPM-1 0.004 0.002 0.024 0.031 LPM-2 0.004 0.071 TE-02 TE-02 LPM-3 0.002 0.001 0.207 0.240 LPM-4 0.005 0.029 0.139 0.167 LPM-5 0.003 0.032 0.052 0.127 LPM-6 0.006 0.023 0.088 0.106 LPM-7 0.002 0.049 0.104 0.270 LPM-8 0.002 0.047 0.103 0.225 O 3-209
EMERGENCY RESPONSE INFORMATION SYSTEM 1-ST-95 (h wJ 3.42 1-ST-95 EMERGENCY RESPONSE INFORMATION SYSTEM (ERIS) 3.42.1 Description The major objective of this test is as follows: 0 To verify that the Basic ERIS and scram timing soft- ware, data bases, and hardware have been correctly installed, set up and calibrated (Basic ERIS is defined as the Emergency Procedure Guideline (EPG) required displays. Basic ERIS does not include scram timing, core flow calibration, sentinel, or sequence of events functions). O To ensure that certain data needed from plant operation is incorporated into the plant specific data bases. O To verify that the system as a whole, is capable of meeting the design requirements for the Basic ERIS and scram timing functions. The acceptance criteria applied to this test are shown in Subsections 3.42.1.1 and 3.42.1.2. 3.42.1.1 Level 1 Criteria None l 3.42.1.2 Level 2 Criteria
- 1. All ERIS validated data will agree with actual plant data within +3% (of rated) .
- 2. All ERIS validated data on the various Basic ERIS displays (taken as near simultaneously as possible) will agree with each other within two (2) standard deviations.
BASIC
- 3. Selected ERIS event targets (safety relief valve, MSIV, scram) shall agree with actual plant status.
l l l 3-210
EMERGENCY RESPONSE INFORMATION SYSTEM 1-ST-95 3.42.1.2 Level 2 Criteria (Cont'd) 1 4. The control rod scram timing function shall properly indicate selected control rod status.
- 5. The control rod scram timing function shall. indicate scram times of selected rods to the appropriate notch positions to within +0.01 seconds of an independent measurement.
- 6. The composed point data base will be verified.
l
- 7. The plant specific constant data base will be
( verified. 3.42.2 Discussion Beginning at Test Condition Open Vessel the data bases g required for Basic ERIS and scram timing analysis were W verified. This included the following:
- 1. The composed points required for Basic ERIS are verified to be properly composed.
l 2. The engineering units used for the Basic ERIS measured analog signals are verified to be l consistent with the composed point / software requirements.
- 3. The constants required for Basic ERIS are verified to be consistent with the ERIS design specifications and River Bend design documents.
! 4. The Control Rod Drive (CRD) data bases required for technical specification scram timing verification were verified. i l 3-211 l L
EMERGENCY RESPONSE INFORMATION SYSTEM
^
1-ST-95 v) 3.42.2 Discussion (Cont'd) Certain constants required for Basic ERIS were originally supplied as "best estimates." These constants were recalculated / redefined at various plant conditions them based on plant specific values. The classes of constants recalculated were:
- 1. Reactor Vessel Temperature Constants
- 2. Reactor Level Constants
- 3. Reactor Power Constants
- 4. Core Flow Constants The core flow constants could not be recalculated due to 1-ST-35 not being completed. TE-05 was written to perform this recalculation when 1-ST-35 is satisfactorily completed and required plant conditions are met.
O Basic ERIS Event Indicators were verified at various times throughout the test program. Testing was originally satisfied using controlled simulated inputs to verify the respective event indicators. Each of the event indicators was then shown to function properly during actual plant events. The Basic ERIS event indicators tested were: EVENT INDICATOR EVENT Diesel Generator (DG) Not Operating Command Operating Safety Relief Valve (SRV) Shut Open Stuck open Scram No scram Rods out Command All rods in Main Steam Isolation Valve (MSIV) Open Command l Shut O 3-212 l
EMERGENCY RESPONSE INFORMATION SYSTEM 1-ST-95 3.42.2 Discussion (Cont ' d) All Basic ERIS validated parameters were verified throughout the test program at various plant conditions. Final verification for those affected by constant recalculation was not completed until these values were determined. A particular validated parameter is determined using the following routine:
- 1. All measured analog signals for a particular parameter that are within the prescribed operating limits are averaged.
- 2. Only those measured analog signals within two standard deviations of the average are then again averaged.
- 3. If the number of measured analog signals within two standard deviations of the original average is more than a prescribed minimum required, (generally two) then the second average is considered a validated average, otherwise, the second average is a not-validated average.
The Basic ERIS validated parameters tested were:
- 1. Reactor Pressure
- 2. Reactor Level
- 3. Reactor Power
- 4. RPV Temperature
- 5. Drywell Pressure
- 6. Drywell Temperature
- 7. Containment Pressure O
3-213
/~N EMERGENCY RESPONSE INFORMATION SYSTEM C 1-ST-95 3.12.2 Discussion (Cont'd)
- 8. Containment Temperature
- 9. Suppression Pool Temperature
- 10. Suppression Pool Level
- 11. Reactor Core Flow Associated with validated parameter displays are static and dynamic limit tags. These function to provide a marker on trend display to indicate significant limits for that parameter (e.g. technical specification limits for reactor level scram setpoint, drywell temperature and suppression pool level). In the testing of validated parameters these limit tag values were all verified to be correct based upon current setpoints.
() ERIS Scram Timing Analysis was veritied throughout the test program. Following the CRD data base verification, the CRD hardware / software timing interface was verified. A control rod input to each of the scram timing input modules was scram timed simultaneously using a Visicorder and ERIS. Using the Visicorder as the standard, ERIS scram times to notch position 43, 29 and 13 were verified to be within 10 ms of those from the Visicorder. During actual RPS scrams during plant operation the ERIS scram timing analysis programs and output edits were verified. It was not possible to verify hardware timing and scram time analysis software simultaneously due to failure of scram time analysis functions. This was recorded as TE-01 and resolved by performing the scram time analysis software verification after resolving the software problem. During hardware testing of input modules, it was found that modules SD-6, SD-8 and SD-9 fell outside the required criteria of 10 ms and resulted in TE-02. It was determined based upon Visicorder accuracy and ERIS sampling interval, that no discrepancy from the criteria actually existed and TE-02 was closed. During hardware testing Scram Timing Input module SD-10 was found to be failed. TE-03 was written to retest this module (SD-10) after it was _ replaced. This TE remains open. V 3-214
EMERGENCY RESPONSE INFORMATION SYSTEM l-ST-95 3.42.2 Discussion (Cont'd) Test Exceptions 4 through 8 also remain open. These are due to plant conditions not meeting the test require-ments at the end of the Test Program. The test exceptions for 1-ST-95 are listed below along with the status as of 15-July-86. TE DESCRIPTION STATUS 1 Scram Timing Analysis software failure. Closed 2 SD-6, SD-8 and SD-9 failed 10 ms criteria. Closed 3 Module SD-10 failed. Open 4 RPV temperature validation at cold shutdown Open not performed. 5 Core flow constants not recalculated. Open 6 RPV Level validation at cold shutdown not open performed. 7 Core flow validation at cold shutdown not Open performed. 8 Core flow validation not performed after Open core flow constant recalculation. 9 Scram timing hardware / software verification Closed of rated conditions. O 3-215
PIPING VIBRATION 1-ST-100 3.43 1-ST-100 PIPING VIBRATION 3.43.1 Description The purpose of this test was to verify that steady state and transient piping and small bore / instrument line vibration was within acceptable limits for Main Steam (MSS), Reactor Coolant Recirculation (RCS), Main Steam Safety relief (SVV) , Condensate / Heater Drains (CNM/HDL), Control Rod Drive (RDS), Reactor Core Isolation (ICS), and Feedwater (FWS) Systems. The General Electric Main Steam and Reactor Coolant Recirculation piping vibration testing was performed per procedure 1-ST-33. The acceptance criteria applied to this test are shown in Subsections 3.43.1.1 and 3.43.1.2. 3.43.1.1 Level 1 Criteria
- 1. Transient Level 1 Criteria
(' Vibration displacements greater than the Level
\ 1 criteria listed on individual Test Data Sheets are considered unacceptable until analyzed and resolved by the Stone & Webster Stress Engineer.
- 2. Steady State Level 1 Criteria None 3.43.1.2 Level 2 Criteria
- 1. Transient Level 2 Criteria Vibration levels greater than the Level 2 l criteria listed on the individual Test Data i Sheet are considered unacceptable until analyzed and resolved by the Stone & Webster Stress Engineer.
- 2. Steady State Level 2 Criteria l
For steady state points, the acceptance criteria for the remote sensing lanyard potentiometers will be indicated on the appropriate Test Data Sheet. O 3-216
PIPING VIBRATIOtt 1-ST-100 3.43.2 Discussion Table 3.43-1 indicates the systems, system test points, and vibration testing modes covered by the tes*.. Table 3.43-2 breaks the system vibration tests down into test condition and the modes of operation for the system being tested. A summary of the text exceptions written during the testing is attached along with the status as of 15-Jul-86. O O 3-217
O ''"a v'a=^o= 1-ST-100 TEST TE CONDITION DESCRIPTION STATUS 1 Heatup RCIC test point T-326 was not Closed monitored during CST to CST quick start. Retest was performed. 2 Heatup RCIC test. points T-315X and Z Closed failed Level 2 during retest for TE-1. Data was evaluated by S&W and found acceptable. 3 Heatup CNM test point T-955 failed Closed Level 1 & 2 criteria during a pump start /stop and steady state operation. Data was evaluated by S&W and found acceptable. ( 4 Heatup CRD single rod scram was not Closed performed during TC-HU. The test was moved to TC-PA. 5 Heatup RCIC T-315X and Z exceeded Level closed 2 criteria. Test results were found acceptable by S&W. , 6 1 MSS test point.T-220 was not Closed installed prior to test. Re-test was performed and all criteria met. , 7 1 Incorrect sampl'e frequency for Closed SRV actuations. During retest test point T-393 failed Level 1 and T-39X failed Level 2 criteria. The test 'results were evaluated by S&W and found acceptable. 8 Power CRD test points T-80X and Z Closed Ascension failed Level 2 criteria during single rod scram. The test data was reviewed and found acceptable by S&W. 3-218
PIPING VIBRATION 1-ST-100 TEST TE CONDITION DESCRIPTION STATUS 9 3 SVV test point S-39Z failed during Closed 50% power steady state testing. The test data was evaluated and found acceptable by S&W/NuPE 10 3 SVV test point S-39Z was in- Closed operable during MSIV isolation. The test data was evaluated and found acceptable by S&W/NuPE. 11 3 HDL test point T-480X and Z Closed failed criteria during steady state and pump trip. The test data was evaluated and found ac- g ceptable by S&W/NuPE. 12 3 Feedwater test points T-144X and Closed T-346Y failed Level 1 and T-144Y failed Level 2 criteria during water level setpoint step changes. The test data was reviewed and found acceptable by S&W/NuPE. 13 3 ERIS panel 107 in Drywell is Closed inoperable. Accepted by S&W/ NuPE. Data requirements are covered under TE's 19 and 21. 14 5 Failed ERIS Drywell Panel 107 Closed results in loss of 75% power steady state data. Existing test data was evaluated by S&W/ NuPE and found acceptable for continued operation. 15 6 Failed ERIS Drywell panel 107 open results in loss of 100% power steady state vibration data. Open for retest. G 3-219
i () PIPING VIBRATION 1-ST-loo TEST TE CONDITION DESCRIPTION STATUS 16 6 Vibration data not taken for MSS Open i test points T-42 and T-220 during pressure control set point step
. changes. Open for retest.
17 6 Shift Supervisor's signature not closed recorded prior to data collection. Accepted "as is". 18 6 Shift Supervisor's signature closed not recorded prior to data {} collection. Accepted "as is". 19 6 During Feedwater pump trip test Open , (ST-23C) points T144 X & Y failed l Level 1. T-144Z failed Level 2 and there was no data for T-35 due to failed ERIS panel 107. Open pending retest. 20 6 During generator load rejection Open (ST-27) and points MSS T-4ZZ, T-235 X, Y, & Z and FWS T-144X l failed Level 1 criteria. MSS T-42X I and FWS T-144Y and Z failed Level 2 criteria. No data is available for condensate test point T/S-525 since AOV-119 failed to open. The test data was reviewed and found acceptable for continued power operation by S&W/ NuPE. This TE is open pending retest of the condensate test point. l 21 6 Test points MSS T-220, FWS T-39, Open SVV T-39, and T-85 were not l operable during generator load re]ection. Open for retest. 3-220
! l l PIPING VIIRATION 1-ST-100 TABLE 3.43-1 VIBRATION TEST POINTS l l l l SYsnN 11TET POIlff #1TRANSIE!ffisTEADY-STATE SMALL BORE / INSTR l l l Feedwater lT-144 l X l l FW5 l l l l 17-366/s-346 i X l X i' l l l l lT-294/S-294 l X l X l l l 1 l lT-1011 l X l l IT-35/s-35 i X i x l l$-129 l X l X l X l l- l l Main IT-42/s-42 l X l X l steam system l l l l nss IT-235/s-235 l X l x l IT-220/s-22o I x I x ls-128 l l x l l l l ls-127 l l l x I I I l lS-138 l l l X l I I l lS-139 l l l X l l l l lS-142 l l l X Main Steam Safety Relief l lT-39/5-39 l X l X l l h l SW lT-85/5-85 l X l X l l l l l l l Reactor l l l l l Coolant l$-136 l l l X Recirculation l l l l RCS 15-137 l l J X l l l l Control l T-80 l X l l Rod Drive l l X l l RDS l T-160 l l l l l l l l l l l Condensate l T-525/S-525l X l X l Nester l T-955/5-955l X l X l Drain l T-480/S-440 l X l X l Cret/HDL l l l l l l l l l l l l Reactor l T-326/5-326l X l X l Core l T-175/5-175l X l X l Isolation l T-315/5-315l X l X l Cooling l S-132 l l X l-ICS l S-133 l l X l l T-115/5-1151 X l X l g 3-221
O O O PIPING VIBRATION 1-ST-100 TABLE 3.43-2 VIBRATION TEST DESCRIPTIONS l 4 i' SYSTEM TEST DESIGNATION SYSTEM CONDITION MODE OF OPERATION 1 CNM Condensate Heatup Pump Start Pump Trip Steady-State 6 Generator Load Rejection Bypass of Condensate Demineralizers (AOV-119 Actuation) l HDL Heater Drain Lines 3 Pump Start .I Pump Trip
! Steady-State FWS Feedwater Heatup Single Pump Start 2 25% Power Steady-State 2 Second Pump Start , 3 50% Power Steady-State l 3 Water Level Setpoint Step changes Power Ascension Third Pump Start 5 75% Power Steady-State 6 100% Power Steady-State 6 Single Pump Trip 6 Generator Load Rejection 3-222
O O O PIPING VIBRATION 1-ST-100 l TABLE 3.43-2 (Cont'd) VIBRATION TEST DESCRPTIONS j TEST TEST DESIGNATION SYSTEM CONDITION MODE OF OPERATION MSS Main Steam 1 Turbine Trip within Bypass Capacity i 2 25% Power Steady-State 3 50% Powar Steady-State 5 75% Power Steady-State 6 100% Power Steady-State 6 Presure Control Setpoint Step Changes 6 Generator Load Rejection Power Ascension MSIV Isolation SVV Safety Relief 1 Acuation at Rated Pressure 2 25% Power Steady-State 3 50% Power Steady-State 5 75% Power Steady-State 6 100% Power Steady-State 6 Generator Load Rejection Power Ascension MSIV Isolation RCS Recirculation 2 25% Power Steady-State 3 50% Power Steady-State 5 75% Power Steady-State i 6 100% Power Steady-State 3-223
l O O O l PIPTNG VIBRATION 1-ST-100 ! TABLE 3.43-2 (Cont'd) I i VIBRATION TEST DESCRIPTIONS i
- TEST TEST
- DESIGNATION SYSTEM CONDITION MODE OF OPERATION 1
j ICS RCIC Heatup Quick Start (CST-CST at 150 psig) Heatup Steady-State Heatup Pump Trip Heatup Quick Start (CST-Vessel at rated) ! Heatup Steady-State i Heatup Pump Trip CRD Control Rod Drive Power Ascension Single Rod Scram at Rated Pressure i j
- i i
3-224
BOP PIPING THERMAL EXPANSION 1-ST-101 3.44 1-ST-101 BOP PIPING THERMAL EXPANSION 3.44.1 Description The purpose of the thermal expansion test is to verify:
- 1. The amount of thermal expansion is within limits to prevent overstressing the piping systems listed in Table 3.44-1.
- 2. There are no interferences that will constrain the thermal movement of the pipe.
- 3. The piping suspension system (snubbers, spring hangers, etc.) is performing as designed.
- 4. Omni pipe whip restraint gaps for shim installation.
- 5. To satisfy snubber Pre-Service Inspection (PSI) requirements.
The General Electric Main (]) Steam Reactor Recirculation pipe expansion testing is performed per Coolant 1-ST-17. The acceptance criteria applied to this test are shown in subsections 3.44.1.1 and 3.44.1.2. 3.44.1.1 Level 1 Criteria The piping response to thermal expansion shall be considered acceptable if the following conditions are met:
- 1. Lanyard potentiometer and scriber readings are within i 1/4 inch or i 25% whichever is the expected thermal movement.
larger of
- 2. Snubbers are not locked up, over/under extended, outside functional range or binding at clevice ends.
- 3. Measurable movement has occurred at the intermediate plateau for all snubbers with an expected movement greater than or equal to one inch, and at rated plateau for all snubbers with an expected movement greater than or equal to one half inch.
O 3-225
BOP PIPING THERMAL EXPANSION 1-ST-101 g l 3.44.1.1 Level 1 Criteria (Cont'd) l l
- 4. Spring hangers are not overloaded, unloaded, or have less than expected thermal movement available at all times.
- 5. No direct interferences to thermal expansion.
- 6. No taut electrical wiring, tubing or flex hoses.
l 7. No damaged hanger or support components. 3.44.1.2 Level 2 Criteria The piping response to thermal expansion shall be considered acceptable if the following conditions are met:
- 1. Lanyard potentiometer and scriber readings are within 1 0.15 inches or i 15% whichever is larger of the expected thermal movement.
- 2. Snubbers are within + 1/4 inch or + 25% of expected deflections for
~
those snubb rs
~
specifically llI indicated with a double asterisk on the test data sheets.
- 3. Snubbers have swing clearance greater than or equal to one inch plus expected thermal movement during heatup and for systems less than 250 deg. F or inaccessible due to radiation.
- 4. Spring hanger movements are with 1 1/4 inch or i 25%
of the expected movement.
- 5. No potential interferences exist (i.e. clearances less than one half inch plus expected thermal movement). At less than rated temperature add an additional one half inch clearance to expected thermal movements due to uncertainty of pipe expansion predictions.
l l 9 3-226 i
, - . . _ . . - - ---- . . - - - , . - - - - . . - - - - - , . - . - , - - . - - - - , , , - - . - - - - - ~ . ,
BOP PIPING THERMAL EXPANSION 1-ST-101 0 3.44.1.2 Level 2 Criteria (Cont'd)
- 6. On return to ambient, movements within + 1/4 inch of initial readings for lanyard potentiometers, scribers, spring hangers and snubbers are acceptable.
3.44.2 Discussion The thermal expansion testing of the piping systems listed in Table 3.44-1 was done where possible, in conjuction with other heatup testing of that system. , Each system was walked down at ambient (70 deg. - 120 deg. F) to check for thermal interferences and to satisfy snubber PSI requirements. Additionally, systems which exceeded 250 deg. F in operating temperature were walked down again at reactor recirculation temperatures of 300 deg i 50 deg. F, normal operating (500 deg. 50 deg. F), and return to ambient (70 deg. - 120 deg. 1 F). At the walkdown plateaus, readings were taken to verify there were no restraints to thermal expansien, all spring hangers and snubbers were performing as nominally O expected and the pipe was expanding as expected. At selected locations remote displacements were recorded by lanyard potentiometers connected to ERIS. Scribers were also used to obtain piping displacement data. Snubbers were checked to verify expected thermal movement and adequate swing clearance. Also, snubbers were inspected to verify there are no visible signs of damage or impaired operability as a result of storage, handling, or installation. I l The major exception (TE-21) to the testing was the l Reactor Water Cleanup (WCS) " Ring Header" located in the i drywell. During heatup the piping could not expand, as designed, due to friction interferences between the piping guides and the pipe clamps. A design modification is in progress to clear this problem. A l l ($) 3-227
BOP PIPING THERMAL EXPANSION 1-ST-101 0 3.44.2 Discussion (Cont'd) retest of the WCS expansion resulted in TE-37 being written due to test point E-56X failing level I criteria and snubber WCS-PSSP-3013-Al failing level 2 criteria. A retest is required per Nuclear Plant Engineering (NUPE) evaluation of the test data. TE-37 will track the retest requirements. Other test exceptions for 1-ST-101 are listed in the following table along with the status as of 15-July-1986. l 9 9 3-228
BOP PIPING THERMAL EXPANSION 1-ST-101 TEST TE CONDITION DESCRIPTION STATUS 1 HU A cable to AOV-F041C valve Closed was wedged against handrail. 2 HU Snubbers WCS-PSSP-3013, 3034, closed 3042 failed level 2 criteria. A design modification was re-quired to correct this. Test Exception 21 will track this retest. 3 HU Snubber WCS-PSSP-3013 failed Closed level I criteria. Test Excep-tion 21 will track the retest. 4 HU Numerous potential interferences Closed were observed during the heatup n s-cycle and any direct interfer-ences were fixed. No problems exist after rated walkdown. 5 HU 9 snubbers and 2 spring hangers Closed failed level 2 criteria. S&W evaluated the data and found the results to be acceptable. 6 HU 12 lanyard potentiometers failed Closed level 1 and/or 2 criteria at in-termediate (300 deg. F) temper-ature. S&W reviewed the test data results and found the results to be acceptable. O 3-229
BOP PIPING THERMAL EXPANSION 1-ST-101 g TEST TE CONDITION DESCRIPTION STATUS 7 HU 16 lanyard potentiometers failed Closed level 1 and/or 2 criteria at rated (500 deg. F) temperature. S&W reviewed the test data and found the results to be accep-table. 8 HU Snubber FWS-PSSP-3024 direct Closed interference. Pipe clamp was moved and the interference cleared. The movement was with-in the as built tolerance of 1", so no other action was required. 9 HU At rated temperature, 20 snubbers Closed and 7 spring hangers failed level 2 criteria. S&W evaluated the test result and found the data a to be acceptable. W 10 HU 13 snubbers and 5 spring hangers Closed failed level 2 criteria at return to ambient. S&W reviewed the data and found the results to be acceptable except for the WCS l supports, TE 21 will track the i retest of these supports. l 11 HU Incomplete heatup/cooldown cycle. Closed l Repeated test and all criteria I were met. l l l l (Il 3-230
l l BOP PIPING THERMAL EXPANSION 1-ST-101 %/ TEST TE CONDITION DESCRIPTION STATUS 12 HU Snubber data for ICS-PSSP-3018 Closed (RCIC) was not taken at 300 deg. F. S&W reviewed data for rated / return to ambient and found the \ TE acceptable. I
%d, 13 HU Scribers C-180, C-275, C-332 and Closed C-513 failed level 1 and/or 2 criteria. The test data was evaluated by S&W and found to be acceptable.
14 HU Whip restraint data was taken closed with incorrect labeling. Data is acceptable as indicated with revised labeling. 15 HU Concrete shield plug was not Closed installed prior to 5% power. Shield plug was installed. 16 HU MSS lanyard potentiometers E- Closed 67X and 235X failed level 2 criteria on return to ambient. The test data was evaluated by S&W and E-67X was accepted. E-235X was retested and the data was found acceptable by S&W. 3-231
BOP PIPING THERMAL EXPANSION 1-ST-101 TEST TE CONDITION DESCRIPTION STATUS 17 PA MSS test points E-67X failed level Closed 1,and E-67Y and Z failed level 2 criteria during main turbine heat up. S&W reviewed the test results and found the data to be acceptable. 18 PA SVV test points E-39Y and Z Closed failed level criteria during SRV actuation. S&W reviewed the test results and found the data acceptable. 19 PA MSS test point E-67Z and X Closed were unavailable during testing due to a broken connector. Test points were repaired and retest completed. TE-27 lll documents the resulting test exceptions. 20 PA FWS test point E-941Z and E-35Y Closed failed level 1 and 2 criteria respectively, during FWS heatup at intermediate temperaturo. During the retest TE-23 was written and closed at inter-mediate temperature. TE-29 was written against rated expansion due to a failed ERIS drywell panel, and TE-35 was written for return to ambient data. This TE is closed. TE's 29 and 35 cover the required data. 't O 3-232
BOP PIPING THERMAL EXPANSION 1-ST-101 TEST TE CONDITION DESCRIPTION STATUS 21 HU This TE was written to cover the closed retest of WCS after the implemen-tation of the drywell " ring header" modification. See TE's 2, 3, and
- 10. During retest, test point E-56X failed level 1 and WCS PSSP-3013-Al failed level 2. A com-plete retest is required per TE-37.
22 PA Rated and return to ambient data Closed required for snubber HVP-PSSP-6035-A3 data was taken during HPCS diesel run. Test data was accep-table. 23 PA During retest of TE-20 FWS test Closed O points E-35Y and E-50Y failed level 1 criteria. E-35X and Z, E-50Z and E-9412 tailed level 2 criteria. S&W/NUPE evaluated the test data and found the results acceptable 24 PA Unable to complete rated piping Closed walkdowns for Feedwater and Con-densate due to high radiation levels in heater rooms. NUPE accepted the test exception "as is". The return to ambient walk-down will check for any damage (TE-30). O 3-233
BOP PIPING THERMAL EXPANSION 1-ST-101 g TEST TE CONDITION DESCRIPTION STATUS l 25 PA Unable to take snubber data for Closed FWS PSSP-173A4 and 115A4 due to high radiation in heater rooms. Scribers FWS C-53Z, CNM C-114Y and Z failed level I criteria. FWS C-13X and C-227X failed level 2 criteria. Spring hanger FWS PSSH-231A4 failed level 2 criteria. The snubbers were inspected at return to ambient and found ac-ceptable. NUPE reviewed the test data for the scribers and spring hanger and found the results ac-ceptable. 26 PA Unable to take rated data on Closed snubber RHS PSSP-2100A2 due to high radiation in steam tunnel. The snubber was inspected at ll) return to ambient and found sat-isfactory. NUPE evaluation was acceptable pending satisfactory return to ambient inspection. 27 PA Intermediate main steam / turbine Closed expansion data was not taken per TE-19. MSS test point E-67Z failed level I criteria at rated temperature. NUPE reviewed the tost data and found the results to be acceptable. O 3-234
BOP PIPING THERMAL EXPANSION 1-ST-101 O (_) TEST TE CONDITION DESCRIPTION STATUS 28 PA Unable to perform main steam Closed piping walkdown of control valve / stop valve areas and take spring hanger MSS-PSSH-085-A4 data at rated temperature due to high radiation. This test exception was accepted "as is" based on NUPE/S&W evaluation. See TE-36, 29 PA Unable to take rated Feedwater Open expansion data, per TE-20, for test points E-35, E-50 and E-941 due to a inoperable ERIS drywell panel. A retest is underway. 30 PA Perform return to ambient piping Closed walkdowns for Feedwater and Con-() densate piping. The walkdowns were performed and the results were acceptable. 31 PA Perform return to ambient snubber Closed inspection for Feedwater and Con-densate piping.. The required snubbers were inspected and found acceptable. I I 3-235
BOP PIPING THERMAL EXPANSION 1-ST-101 O TEST TE CONDITION DESCRIPTION STATUS 32 PA Perform return to ambient spring Closed hanger inspections for Feedwater and Condensate piping. The re-quired spring hangers were in-spected and found acceptable. 33 PA Take return to ambient scriber Closed measurement for Feedwater and Condensate piping. The return to ambient data was taken and all criteria were met. 34 PA Take return to ambient Omni pipe Closed whip restraint data. The return to ambient data was taken and the results forwarded to NUPE. 35 PA Take return to ambient Feedwater Closed ggg lanyard potentiometer data per TE-20. The return to ambient data was taken and all criteria were met. 36 PA Perform return to ambient main Closed steam walkdown and obtain data for spring hanger MSS PSSH-035-A4. See TE-28. The walkdown and required data were completed with acceptable results. i O 3-236
BOP PIPING THERMAL EXPANSION _ l-ST-101 TEST TE CONDITION DESCRIPTION STATUS 37 HU During retest of Reactor Water Open Clean Up per TE-21, WCS test point E-56X failed level 1 and WCS snubber PSSP-3013-Al failed level 2. A complete retest is required. 38 PA Procedure step sign off verifi- Closed cation table has steps that have been indicated as not applicable. The data required to be taken, per the Test Data Sheets, was inconsistent with the sign off steps. O O 3-237 l
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DRYWELL COOLING
.O l-ST-103 V
3.45 1-ST-103 DRYWELL COOLING l 3.45.1 Description The major objective of this test is to verify the ability of the Drywell Cooling System to maintain the Drywell below the limits specified in the Plant Technical Specifications and the ability of the Containment Cooling System to maintain the Containment below the limits specified in the Plant Technical Specifications. The acceptance criteria applied to this test are shown in Subsections 3.45.1.1 and 3.45.1.2. 1 3.45.1.1 Level 1 Criteria None 3.45.1.2 Level 2 Criteria
- 1. The Drywell Air Temperature O below the limit is maintained at or specified by Technical Specifications, that states, Drywell average air temperature shall not exceed 140 degrees F.
- 2. The Containment Air Temperature is maintained at or below the limit specified by Technical Specifications that states, Primary Containment Average Air Temperature shall not exceed 90 degrees F. .
3.45.2 Discussion Drywell and Containment Temperatures were measured during three test conditions (Heatup, TC-3, TC-6) using permanent plant instrumentation. The temperatures were averaged according to Technical Specifications and compared to the specified limits. All acceptance criteria were met. A data table and list of test exceptions and their resolutions follows: O 3-239 + - - ___. . _ - _ . . - _ - - - . . _ - _ - - _ . _ .- - _ _ - - . - - _ - _ -
ERYWELL COOLING l-ST-103 O TE DESCRIPTION STATUS 1 Reactor temperature was only above 500 Closed degrees F for 36 hours prior to test-ing, violating the initial condition which requires the reactor temperature to be above 500 degrees F for 3 con-secutive days prior to testing. Accept as is, since Drywell temperature is changing by less than 2 degrees F/ hour and is therefore stable. 2 One suppression pool temperature RTD is Closed failed. Accept as is, since this signal is not required for criteria evalua-tion. 3 A prerequisite to this test requires the reactor temperature to be above 500 Closed lll degrees F at test condition 3 for three consecutive days prior to testing. The reactor was above 500 degrees F for three days, but was only in the TC-3 window tor approximately eight hours prior to testing. The Drywell temperature stabilized around 123 degrees F. Accept as is since the average Drywell temperature calculated for the test is 123 degrees F showing Drywell stabilization in TC-3. O 3-240 1
O O O DETWELL COOLING 1-ST-103 TABLE 3.45-1 TEST AVERAGE DRYWELL TECH SPEC AVERAGE CONTAINMENT TECH SPEC CONDITION TEMPERATURE LIMIT TEMPERATURE LIMIT l Heatup 107 Degrees F. 140 Degrees F. 80 Degrees F. 90 Degrees F. 3 123 Degrees F. 140 Degrees F. 79 Degrees F. 90 Degrees F. 6 126 Degrees F. 140 Degrees F. 80 Degrees F. 90 Degrees F. 3-241
ESF AREA COOLING 7x 1-ST-104 U 3.46 1-ST-104 ESF AREA COOLING 3.46.1 Description The major objective of this test is to verify the ability of the RHR and RCIC room ventilation to maintain room temperatures below those required in BWR Equipment Environmental Interface Data Specification during equipment operation. Ambient temperatures in the LPCS, HPCS, RHR, and RCIC rooms will also be measured at 50% power and 100% power to insure the normal temperature limits are not exceeded. The acceptance criteria applied to this test are shown in Subsections 3.46.1.1, 3.46.1.2, and 3.46.1.3. 3.46.1.1 Level 1 Criteria None 3.46.1.2 Level 2 Criteria None 3.46.1.3 Level 3 Criteria
- 1. At 50% (nominal) and 100% (nominal) of rated thermal power the RCIC room, RHR rooms, LPCS room and HPCS room environments will be less than or equal to 90 degrees in the vicinity of the major equipment when the major equipment is not in service.
- 2. The RCIC room and RHR rooms will not exceed a temperature of 122 degrees F, as indicated on the sensors at the elevation of the major equipment, during operation of major equipment.
3.46.2 Discussion During heatup, on November 24, 1985, RCIC room temperatures were measured in conjunction with 1-ST-14, RCIC System, extended operation demonstration at 15 minute intervals using local permanent and temporary temperature indicators. The maximum temperature measured at the elevation of the major equipment was 93 degrees F which is less than the criteria value of 122 degrees F. 3-242
i ESF AREA COOLING l-ST-104 O During Test Condition 3, RHR, RCIC, LPCS, and HPCS room temperatures were taken with locally installed temporary temperature indicators and ESF area temperature records, to determine ambient room temperatures under normal conditions. HPCS, LPCS, and RHR temperatures were all below the Level 3 criteria of 90 degrees F, while the RCIC exceeded this value by 7 degrees F. TE-1 documents this violation. This Test Exception has been evaluated and accepted by General Electric Engineering. During Test Condition 6, RHR room temperatures were taken while in shutdown cooling mode at 15 minute intervals using permanent temperature indicators. The maximum temperature recorded was 97 degrees F. which meets the specified criteria of 122 degrees F. Local temperature indicators were not monitored at the specified 15 minute intervals due to prohibitive high radiation levels in these areas. TE-3 documents this. One set of local temperature readings was recorded at all levels of rooms "A" and "B". The maximum reading was 90 degrees F near the completion of the run. This meets the specified criteria. Temperatures were also recorded for the HPCS, LPCS, RCIC, RHR A, RHR B, and RHR C rooms during normal conditions (equipment not in service). For the RCIC room, the maximum temperature was 112 degrees F which exceeds the Level 3 criteria of 90 degrees F. This is documented by TE-2. The following is a list of test exceptions for 1-ST-104 along with the status as of 15-Jul-86. TE Description Status 1 RCIC room temperature exceeds Level 3 Closed criteria of 90 degrees F. 2 Measured ESF room temperatures in the Open HPCS, RCIC, RHR A, RHR B, RHR C exceed Level 3 criteria of 90 degrees F. Evaluation being performed by General Electric Engineering 3 Local temperature indicators in the RHR Closed "A" and "B" rooms were not monitored at the specified 15 minutes intervals due to prohibitive high radiation levels in these areas. Readings taken at the end of the run met the criteria. 3-243
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O >=====arzo= ============ ==== l-ST-105 3.47 1-ST-105 PENETRATION TEMPERATURES TEST 3.47.1 Description The major objective of this test is to verify the passive cooling ability of the piping penetrations in the shield building. Selected high energy penetrations will be monitored to insure concrete temperatures in the vicinity of the penetrations do not exceed 208 degrees F. The acceptance criteria applied to this test are shown in Subsections 3.47.1.1 and 3.47.1.2. 3.47.1.1 Level 1 Criteria None 3.47.1.2 Level 2 Criteria (} The penetration collar temperatures adjacent to the shield building concrete do not exceed the predicted value for normal plant operation which corresponds to a maximum concrete temperature of 200 degrees F. 3.47.2 Discussion Thermocouples were installed on selected high energy penetrations in the steam tunnel adjacent to the shield building. The temperatures were recorded during heatup and Test Condition 6. The maximum temperatures for each penetration at both test conditions are listed in Table 3.47-1. All penetration temperatures met the less than 200 degrees F acceptance criteria. No test exceptions were taken during this test. O 3-244 \
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4 [w r - ouze swarms urzzzrzzs conwnwr ArVER BENO STATION POST OFFICE BOX 220 ST. FR ANCISylLLE. LOUIS!ANA 70775 arf n Couf.504 635 6094 346-8651 July 31, 1986 RBG ,24132 File Nos. G9.5, G9.25.1.5 Mr. Robert D. Martin, Regional Adminfstrator U.S. Nuclear Regulatory Coiamission Region IV 611 Ryan Plaza Drive, Suiten1000 * ' Arlington, TX' ~75011 - 9
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Dear Mr. Martin:
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River Bend Station - Ur[it 1 - Docket No.'50-458 Enclosed is the Startup Roport for River Bend Station - Unit 1. This report covers the period from fuel loading (August 31, 1985) through , July 15, 1986. This information is provided pursuant to Technical Specifications 6.9.1.2 and 6.9.1.3 and- Regulatory Guides 1.16 and 1.68. An additional report wi".1 follow within 3 months pursuant to Technical Specification 6.'9.1.3. Sincer ly, l J. C. Deddens' Vice President River Dend Nuclear Group cc: Director of Inspection and Enforcement U.S. Nuclear Regulatory Commission Washington, D.C. 20551 Attn: Document Control Desk 4 0 I l s [f.[Q1 _}}