ML20137B487
| ML20137B487 | |
| Person / Time | |
|---|---|
| Site: | Shoreham File:Long Island Lighting Company icon.png |
| Issue date: | 11/15/1985 |
| From: | Steiger W LONG ISLAND LIGHTING CO. |
| To: | |
| Shared Package | |
| ML20137B457 | List: |
| References | |
| NUDOCS 8511260282 | |
| Download: ML20137B487 (66) | |
Text
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LONG ISLAND LIGHTING COMPANY SHOREHAM NUCLEAR POWER STATION STARTUP REPORT
.,444 y-Ipth' Approved // Date' W. E. Steiger Plant Manager 8511260282 851122 PDR ADOCK 05000322 P PDR R ________.-_____________j
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TABLE OF CONTENTS 1.0 Report Abstract
-2.0 -Overall Evaluation 3.0 Summary of Key Events 4.0 Results 4.1 Chemical and Radiochemical (STP-1 FSAR 14.1.4.8.1) 4.2 Radiation Measurements (STP-2 FSAR 14.1.4.8.2) 4.3 Fuel Loading (STP-3 FSAR 14.1.8.3) 4.4 Full Core Shutdown Margin (STP-4 FSAR 14.1.4.8.4) 4.5 Control Rod Drive (STP-5 FSAR 14.1.4.8.5) 4.6 Water Level Measurement (STP-9 FSAR 14.1.4.8.6) 4.7 SRM Performance and C.R. Sequence (STP-6 FSAR 14.1.4.8.7) 4.8 IRM Performance (STP-10 FSAR 14.1.4.8.8) 4.9 LPRM Calibration (STP-11 FSAR 14.1.4.8.9) 4.10 APRM Calibration (STP-12 FSAR 14.1.4.8.10) 4.11 Process Computer (STP-13 FSAR 14.1.4.8.11) 4.12 RCIC System Startup Test (STP-14 FSAR 14.1.4.8.12) 4.13 HPCI System Startup Test (STP-15 FSAR 14.1.4.8.13) 4.14 Selected Process Temperatures (STP-16 FSAR 14.1.4.8.14) 4.15 System Expansion (STP-17 FSAR 14.1.4.8.15) 4.16 Main Steam Isolation Valve Each Valve (STP-25 FSAR 14.1.4.8.22) 4.17 Relief Valves (STP-26 FSAR 14.1.4.8.23) 4.18 Recirculation Flow Control (STP-29 FSAR 14.1.4.8.26) 4.19 Drywell Piping Vibration (STP-33 FSAR 14.1.4.8.28) 4.20 Recirculation System Flow Calibration (STP-35, FSAR 14.1.4.8.29)
r g TABLE OF CONTENTS - (continued) 4.21 Reactor Water Cleanup System (STP-70 FSAR 14.1.4.8.33) 4.22 Residual Heat Removal System (STP-71 FSAR 14.1.4.8.34) 4.23 RBCLCW and Drywell Cooling (STP-37 FSAR 14.1.4.8.36) 4.24 Service Water System (STP-42 FSAR 14.1.4.8.39) 4.25 loose Parts Monitoring System (STP-814 FSAR 14.1.4.8.40) 5.0 License Conditions Status r
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1.0 Startup Report. Abstract This Startup Report has been written by the long Island Lighting Company for submission'to the Nuclear Regulatory Coomission in compliance with Shoreham Nuclear Power Station Technical Specifications', paragraph 6.9.1.1 through 6.9.1.3, and .
l Regulatory Guide 1.16, Revision 4, section C.I.a.
Shoreham Nuclear Power. Station (SNPS) loaded fuel and achieved initial criticality on February 15, 1985, under the provisions of a 0.001% power license, NPF-19. Plant heatup testing was conducted under a 5% power license, NPF-36. Initial heatup testing has been completed, and the plant .is now in an outage for the replacement of the installed neutron sources and the installation of environmental qualification modifications.
This report addresses each of the startup tests identified in Chapter 14 of the FSAR to be performed in Test Conditions Open Vessel and Heatup. It includes a description of the measured values of the operating conditions or characteristics obtained during the test program with a comparison of these values to the acceptance criteria, and a description of any corrective actions required to obtain satisfactory operation. This report also in-cludes a discussion of license conditions based on other commitments.
Since.SNPS has not completed its startup test program or commenced power operation, supplementary reports describing future testing will be submitted on a periodic basis.
' s 2.0 Overall Evaluation
' Shoreham startup testing has been successfully completed through initial heatup to rated temperature and pressure. The initial test program described in FSAR Chapter 14 encompasses checkout and initial operation, preoperational testing and startup testing. The startup phase includes preparation for initial fuel loading; initial fuel loading and low power tests at atmospheric pressure; initial heatup to rated temperature and pressure; power testing from rated temperature and pressure to 100 percent power; and the warranty demonstration.
The Joint Test Group (JTG) and Review of Operations Committee (ROC) reported their verification of readiness to load fuel on December 18, 1984. The master fuel loading prerequisite check-list (SP 12.075.01 Appendix 12.9, revision 8) was completed on December 21, 1984. The Plant Manager authorized fuel load and open vessel testing on December 21, 1984.
Initial fuel load was successfully completed on January 19, 1985. Initial criticality was achieved on February 15, 1985.
Adequate shutdown margin was demonstrated, and low power testing at atmospheric pressure continued through February 17. The plant was then shut down for an outage. Following the outage ,
control rod drive testing was performed. Test condition Open Vessel test results were approved by ROC on June 20, 1985.
Following receipt of a 5% license on July 3,1985, the Plant Manager authorized entry to test condition Heatup. Ikatup testing continued through October 8, 1985. Test Condition Heatup results are currently under review by the Test Review Committee (TRC) and ROC.
Section 3.0 provides a more detailed chronology of startup test program activities.
During fuel load and low power testing the following startup program activities were completed:
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- 1. The initial core was successfully loaded and verified.
- 2. Adequate shutdown margin was demonstrated and correct core performance was verified.
- 3. The neutron monitoring instrumentation performance was verified and the APRM's were calibrated.
- 4. Chemistry and radiochemistry measurements were taken and water quality met and exceeded all Technical Specification and fuel warranty requirements.
- 5. Radiation surveys proved all plant areas met and exceeded 10CFR20 requirements at low power.
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2.0 'Overall Evaluation - (continued)
- 6. Safety relief valves and main steam isolation valves were verified to operate correctly.
- 7. The control rod drives were demonstrated to function normally at all reactor pressures.
- 8. Drywell piping was verified to expand freely and correctly through three. complete heatup cycles.
- 9. Initial controller tuning was performed for the RCIC system and a successful injection to the vessel at rated pressure was' demonstrated.
10.. The turbine generator was rolled successfully to synchro-nous speed.
Section 4.0 contains a detailed discussion of startup tests performed, including specific test results.
Two outage activities will require startup retesting prior to proceeding to the power ascension test phase. Modifications to the reactor pressure vessel water level instrumentation piping in the drywell and modifications to the HPCI system Woodward governor control system will invalidate the results of the completed portions of STP-9 and STP-15.
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-,. i 3.0 . Summary of Key Events December 7,1984 Receive'd.10w power license .001%.
December 17, 1984 Sources loaded in core.
December 21,1984 Fuel loading commenced.
. January 4, 1985 Partial core shutdown margin test.
January 19, 1985 Puel loading completed.
January 25, 1985 CRD open vessel testing completed.
February 17, 1985- Ir.itial critical and shutdown margin test.
Completed open -vessel testing.
June 4, 1985 CRD open vessel retest completed.
P July 3, 1985 5% low power license received.
July 7, 1985 Reactor critical sequence B.
Test condition Heatup.
July 7, 1985 Heatup to 250*F.
System expansion performed.
IRM performance completed.
July 8, 1985 Heatup to 325'F performed.
APRM calibration. <
July 9, 1985 SRV functional test performed- (STP-26).
l l July 11, 1985 150 psig plateau reached.
j Sys tem expansion DW entry.
l RCIC testing.
HPCI system testing. ;
July 14, 1985 Reactor scram #1 on Rx level.
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July 17, 1985 APRM calibration at 150 psig.
l HPCI testing.
System expansion testing.
RBCLCW performance testing.
July 18, 1985 Reactor shutdown .for RPV level instrumentation work.
July 23, 1985 Reactor critical.
I July 26, 1985 Reactor shutdown for RPV level instrumentation work.
July 29, 1985 Reactor critical.
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- 3.0 ' Summary of Key Events - (continued) ~
p July 31,-1985 Reactor pressure .150 psig.
HPCI system testing.
' August 1, 1985 350 psig plateau.
Drywell radiation survey.
System expansion drywell inspection, system expansion data.
-August'3, 1985 600 psig plateau.
System expansion.
RBCLCW performance.
CRD testing.
August.-5, 1985 800 psig plateau.
System expansion.
CRD testing.
August 7, 1985 Rated pressure plateau.
System expansion testing.
HPCI testing.
RCIC testing.
CRD testing.
RBCLCW testing.
Water level testing.
STP-13 testing.
Chemical and radiochemical testing.
Radiation measurements.
LPRM testing.
August 23, 1985 Reactor pressure reduced to 150 psig.
HPCI testing.
RCIC testing.
August 24,.1985 Reactor shutdown af ter initial heatup.
August 30, 1985 Reactor critical sequence A.
August 31, 1985 Scram #2 on loss of instrument air.
September 3,1985 Reactor critical sequence A. Second heatup to 150*F.
September 4,1985 Heatup to 250*F - 150 psig.
System expansion testing.
September 6, 1985 Reactor pressure 350 psig.
System expansion testing.
September 6, ~ 1985 Reactor scram #3 due to surveillance on level ins trument.
3.0 Summary of Key Events - (continued)
September 7, 1985 Reactor pressure 600 psig.
' System expansion testing. ;
CRD testing.
September 8, 1985 Unusual event due to Reactor level indication problem.
September 10,'1985 Reactor shutdown for repair of Reactor level problem. ,
September 11, 1985 Reactor critical and heatup to investigate level problem.
Septembe r 12, 1985 Reactor scram #4 on low water level indication.
Actual level did not change.
Level instrument problem investigated.
September 18 1985 Reactor critical sequence A.
Septembe r 21,1985 Reactor pressure 800 psig.
. System expansion testing CRD testing.
RPV level problem fixed.
September 21, 1985 Rated pressure reached.
System expansion testing. '
Second heatup.
RCIC testing. '
HPCI testing.
MSIV testing. ,
Water level testing.
CRD testing.
RWCU testing.
Radiation testing.
Chemistry testing.
September 27, 1985 Reactor shutdown.
Hanger placed on B reference leg. Miscellaneous maintenance.
October 3,1985 Reactor critical sequence A. Third heatup to rated pressure.
System expansion testing. '
October > 4, 1984 RCIC vessel injection at rated pressure.
System expansion testing.
RWCU system testing.
MSR relief valve testing.
l October 6, .1985 Initial turbine generator roll to rated speed.
October 8, 1985 End of heatup testing.
Begin source replacement outage.
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'4.0 .Stcrtup T;3t Re:ulto This section discusses each of the statutp tests identified in Chapter 14 of the FSAR (Table 14.1.1-1) to be performed in test conditions Open Vessel and Heatup. Tests identified to be performed in test conditions 1 through 6 and during the warranty demonstration are not in the scope of this report.
4.1 Chemical and Radiochemical (STP-1)
The results of the testing showed that up to 5% power the reactor could be operated while maintaining the chemistry of reactor coolant, condensate, feedwater, gaseous and liquid ef fluents and secondary systems within the limits specified by Technical Specifications, Fuel Warranty and Water Quality guidelines.
In the course of the tests, the sampling equipment, monitoring instrumentation and analytical procedures were found adequate to meet all acceptance criteria.
, 4.1.1 Acceptance Criteria Level 1 1.1 Chemical factors defined in the Technical Specifica-tions and Fuel Warranty shall be maintained within the limits specified.
.1.2 The activity of gaseous and liquid ef fluents shall conform to license limitations.
1.3 Water quality shall be known at all times and should remain within the guidelines of the water quality .
s pecifications.
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4.1.2 Test Method /Results L Prior to starting the tests, the following systems were i
reviewed for operability and found acceptables Laboratory instrumentation and procedures Counting Room instrumentation Sampling systems 4 -
Make-up Demineralizer System Reactor Water Cleanup System Closed Loop Cooling Water System Stored Water Radioactive Liquid Waste System Gaseous Waste System Appropriate portions of the Radiation Monitoring Sys.
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4.1.2 Test Method /Results - (continued)
During testing, and when applicable, parameters such as conductivity, chlorides, pH, silica, boron, dissolved oxygen, impurity metals (Fe, Cu, Ni, Cr), turbidity, gross activity and concentration of I-131 and 1-133 were .
determined and found within acceptance limits in the following systems :
. Reactor Water Condensate Condensate Demineralizer Effluent l-Feedwater
- Control Rod Drive Cooling Water.
During Heatup, readings were also taken off the Steam Jet Air Ejector, Of f-gas HEPA filter, and Plant Vent Radiation Monitors. All readings were found within acceptance limits.
An evaluation of the Condensate Demineralizer System efficiency was performed during Open Vessel testing.. The results of 'these tests showed that the condensate.
l demineralizers can provide water of acceptable quality for I a substantial period of time with no appsrent operational problems.
4.1. 3 ' Corrective Actions /Open Items fl None F
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. . 4.2 Radicti:n Mer.curemento (STP-2)
Radiation surveys were performed prior to fuel load to determine natural background radiation levels in the plant. The radiation surveys were repeated af ter fuel load and during heatup testing at 3% power to ensure plant personnel protection in accordance with 10CFR20 and the FSAR section 12.3. The results of the surveys are satisfactory.
4.2.1 Acceptance Criteria Ievel 1 1.1 The radiation exposures of plant origin and the occupancy times of personnel in radiation zones shall be controlled in accordance with the guidelines of the standards for protection against radiation as outlined in 10CFR20.
4.2.2 Test Method /Results STP-2 performance consisted of gamma and neutron area radiation surveys, shield wall and labyrinth radiation surveys and gamma limited radiation surveys. Open vessel surveys were first conducted prior to fuel load on December 15, 1984. These surveys were performed to determine the plant background radiation levels prior to operation for base data on activity buildup.
Open vessel surveys were repeated from January 19, 1985 to January 22, 1985 after fuel load and prior to initial criticality. These surveys were the first step in monitoring radiation 1cvels to assure the protection of plant personnel during plant operatione. All points surveyed were within the limits specified for their location and the acceptance criteria was satisfied.
There were three survey points A-4, S-22, and S-5 that were not directly taken during open vessel testing, due to obstructions. The values recorded are based on readings from as near the area or point as possible. These readings were directly taken during test condition heatup surveys since the obstructions had been removed.
Heatup testing surveys were done on August 11, 1985 at 3%
core thermal power. All points surveyed were within the limits specified for their location and the acceptance criteria was satisfied.
4.2.3 Corrective Actions /Open Items There is one open test exception. It states that the Radiation Monitoring System computer readings and the Local Area Radiation Monitor readings disagree by > + 20% on nine of forty seven points. Since the G.E. test specification and the FSAR do not address this as a criteria, it has been decided to delete the cross check + 20% analysis by Station Procedure Change Notice.
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4.2.3 Corrective Actions /Open Items There is one open test exception. - It states that the l Radiation Monitoring System computer readings and the local Area Radiation Monitor readings disagree by > 120% on nine of forty seven points. Since the G.E. test specification and the FSAR do not address this as a criteria, it has been decided to delete the cross check i 20% analysis by Station Procedure Change Notice. ,
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4.3 Fuel Leading Startup Test (STP-3)
The Shoreham initial core was loaded in 26 days (December 21, 1984 to January 19, 1985). Partial core shutdown margin was demonstrated, control rod functional and control cell subcritical tests were performed in parallel to fuel load. The core was verified and all fuel assemblies were properly loaded, oriented, and seated in the core.
4.3.1 Acceptance Criteria level 1 1.1 The partially loaded core must be suberitical by at e least 0.38% Ak/k with the analytically strongest rod fully withdrawn.
4.3.2 Test Method /Results Five source holders with two source pins each were loaded into the core at coordinates 20-41, 40-33, 24-29, 08-25, 28-17. Fuel was loaded into the core from the center out in a spiral pattern. Fuel loading chambers were utilized to monitor count rates and provide inputs for RPS rod block (1 x 105 cps) and scram (2 x 10 5cps) functions until SRM's could be utilized. RPS was in the non-coincidence scram mode. 1/m plots were utilized to verify subcriticality throughout the entire fuel load. Control rod f unctional and subcriticality vertfication was completed as control cells were loaded.
Shutdown margin for the partially loaded core was demonstrated af ter 144 fuel bundles were loaded. Eight control rods were withdrawn one notch at a time with constant monitoring of nuclear instrumentation. With the eight rods out (including the highest worth rod), no constant positive period was observed, thus demonstrating a shutdown margin of at least 0.38% Ak/k satisfying Level I criteria.
The full core verification was performed on January 24, 1985.
Each fuel bundle is in the correct core location, orientation, and height.
Two RPS trips (scrams) occurred during f uel load. On December 23, 1984, noise spiking on SRM channel A caused an SRM upscale. On January 8, 1985, I&C error during change from FLC to SRM's resulted in a RPS trip (scram).
. o 4.4 Full Core Shutdown Margin Startup Test (STP-4)
The results of this test demonstrated that the Shoreham initial core shutdown margin is 2.74% Ak/k which demonstrates that the reactor will be suberitical throughout the first cycle with any single control rod fully withdrawn.
4.4.1 Acceptance Critetii Imvel 1 1.1 The shutdown margin of the fully loaded, cold (60'F or 20*C), xenon-free core occuring at the most reactive time during the cycle must be at least 0.38% Ak/k with the analytically strongest rod (or its reactivity equivalent) withdrawn. If the shutdown margin is measured at some time during the cycle other than the most reactive time, compliance with the above criterion is shown by demonstrating that the shutdown margin is 0.38% Ak/k plus an exposure dependent increment which adjusts the shutdown margin at the time to the minimum shutdown margin. This exposure dependent increment was determined to be 0.67% Ak/k. Therefore the criteria is 1.05% Ak/k.
Level 2 2.1 Criticality should occur within + 1.0% Ak/k of the predicted critical (predicted critical to be determined later). The predicted or design Kef f = 1.0025.
4.4.2 Test Method /Results The shutdown margin test (SDM) was performed during the initial criticality on February 17, 1985 in conjunction with STP-6 (SRM response to control rod withdrawal for sequence A) and STP-10 (IRM/SRM overlap).
The SDM test was performed by withdrawing sequence A control rods from the "all rod in" configuration until criticality was reached. The control rod sequence contained the analytically strongest control rod (14-43 sequence A).
Initial critical data is listed
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4.4.2 Test Method /Results - (continued)
Startup rod withdrawal sequence -A Last withdrawn control rod bank - Group 3, Bank Pos. 4 Control rod & group on which core is critical 23, Group 3 Notch position of control rod -8 Total notches withdrawn - 1736 Avg. period from SRM channels A, B, C&D - 93 sec.
Avg. moderator temperature - Ill'F The predicted or design Kef f is 1.0025. The measured or actual Keff is 1.0031. The dif ference between the design and as built reactivity is therefore 0.06% A k/k, which satisfies the + 1.0% Ak/k Level 2 criteria.
The shutdown margin for the initial core loading, cold (68'F) xenon-free core (as corrected for temperature and period reactivity) is 2.74% Ak/k. The exposure dependent maximum change in strongest rod out Keff, from BOL derived from Shoreham shutdown margin Kef f vs exposure curve, is 0.67% Ak/k. Therefore, the minimum shutdown margin at BOL must be at least 1.05% Ak/k to satisfy the Level I criteria.
The actual shutdown margin of 2.74% A k/k assures that during the initial operating cycle the Level I criteria is satisfied.
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4.5 Control Rod Drive (STP-5)
The control rod drive system was tested during and af ter fuel load, during plant heatup, and at rated pressure to show there is no significant binding of the control rods of their drive mechanisms at conditions up through rated. Testing consisted of full stroke insert and withdraw timing, continuous insert friction tests,2 notch settle. friction tests (on some rods), and individual rod scrams.
All rods satisfied the acceptance criteria listed below except rod 22-35. Rod 22-35 passed the criteria for Open Vessel tests, however it was not tested at rated pressure due to it being inoperative.
4.5.1 Acceptance Criteria 14 vel 1 1.1 Each CRD must have a normal withdraw speed less than or equal to 3.6 inches per second, indicated by a full 12-foot stroke in greater than or equal to 40 seconds.
1.2 The mean scram insertion of all operable CRD's with functioning accumulators must not exceed the following times t (Scram time is measured from the time the scram pilot valve solenoids are de-energized).
Position Inserted Scram Time From Fully Withdrawn (seconds) l 45 0.43 l 39 0.86 25 1.93 l 05 3.49 1.3 The mean scram insertion time of the three fastest l
CRD's in all groups of two by two arrays must not ,
l exceed the following times: (Scram time is measured l from the time the scram pilot valve solenoids are de-ene rgized ).
l Position Inserted Scrau Time ,
! From Fully Withdrawn (seconds) 45 0.45 l 39 0.92 ;
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4.5.1 Acc:pt:nca Critorio - (c:ntinu:d)
Level 2 2.1 Each CRD must have a normal insert or withdraw speed of 3.0 + 0.6 inches per second, indicated by a full 12-foot stroke in 40 to 60 seconds.
2.2 With respect to the control rod drive friction test, if the differential pressure variation exceeds 15 paid for a continuous drive in, a settling test must be performed, in which case, the dif ferential settling pressure should not be less than 30 psid nor should it vary by more than 10 paid over a full stroke.
Level 3 3.1 The control rod drive system flow should not change by more than + 3.0 gpm as reactor pressure varies from atmospheric to rated pressure.
3.2 The decay ratio of any oscillatory controlled variable must be f .25 for any flow setpoint changes or for system disturbances caused by the control rod drives being stroked.
4.5.2 Test Method /Results Open Vessel testing of STP-5 was successfully completed December 13, 1985 to January 25, 1985 but was repeated May 2, 1985 to June 4,1985, because Control Rod Drive mechanism cooling water orifices were replaced and hydraulic control unit scram inlet valve seats were replaced with Tefzel. Only the second set of tests is discussed in this summary.
Open Vessel and Ikatup phase tests consisted of the follow-ing:
Timing - Time for continuous insert from position 48 to full in and time for continuous withdraw from position 00 to full out was measured.
Friction Test - The differential pressure between the drive water insert and withdraw lines during the continuous insertion of each control rod was measured. If a rod failed this test the same delta P was measured as the rod was inseted one notch at a time.
Scram Time - Each control rod was scramned individually from the IICU, and the time from initiation to positions 45, 39, 25, and 05 was recorded on the process computer or a visicorder.
These tests were conducted at various plant and IICU conditions as follows:
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4.5.2 Test Method /Results - (continued)
Rods Tested Rod Plant Test Type of All or Seq uence HCU Accum. Pressure Dates Condition Test Selected A,B, or NA N2 Pressure (psig) Performed Open Vessel Timing All NA No rmal 0 05/22/85 -
06/04/85 Open Vessel Friction All NA Normal 0 05/02/85 -
06/04/85 Open Vessel Scram All NA Normal 0 05/02/85 -
06/04/85 Open Vessel Scram Selected NA Alarm Point 0 05/02/85 -
06/04/85 lleatup Scram Selected B Normal 600150 08/03/85 IIca tup Scram Selected B Normal 800150 08/05/85 lleatup Timing Selected B Normal 950+2 0
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08/09/85 lleatup Friction Selected B No rmal 950+20
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08/09/85 IIcatu p Scram All B No rmal 9501j2 08/11/85 -
08/15/85 lleatup Scram Selected B Zero 950+2g
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08/16/85 lleatu p Scram Selected A No rmal 600150 09/06/85 -
09/08/85 IIcatup Scram Selected A No rmal 800150 09/21/85 IIc a tup Timing Selected A Normal 950120 09/21/85 -
09/22/85 IIcatup Friction Selected A Normal 95012g 09/21/85 -
09/22/85 lleatup Scram All A Normal 950+20
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10/01/85 IIcatup Scram Selected A Zero 2 9501 e 09/23/85
4.5.2 Test Method /Results - (continued)
Selected rods are the four rods in a sequence with the slowest scram times and any other rods that exhibited greater than average friction delta P or other unusual behavior during open vessel tests.
All tests were completed satisfactorily, satisfying the acceptance criteria 1.1, 1.2, 1.3, 2.1, and 2.2 except that rod 22-35 was not scrammed at rated pressure. This rod was inoperative at the time of scram testing and it will be tested after its drive mechanism is replaced. Criteria 3.1 was satisfied by taking CRD flow controller output and system flow readings at 0#, 600#, 800#, and 950# reactor pressure. Then, for the same flow controller output, system flow was verified not to have changed by > + 3 gpm from zero pressure to rated.
4.5.3 Corrective Actions /Open items
, When rod 22-35 is replaced, STP-5 Open vessel and Heatup testing will be repeated on rod 22-35. This will be completed prior to entering Test Condition 1.
The other open test item is that the CRD flow controller's decay ratio has not yet been analyzed. This will be performed at rated pressure and temperature following the current outage using the G.E. fTIX controller tuning program. The results will be put into STP-5.
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4.6 Water Level Measurement (STP-9)
The results of the testing identified 1 narrow range level instrument for calibration and 5 wide range level instruments for calibration at rated temperature and pressure during TC lleatup.
4.6.1 Acceptance Criteria Level 1 Not Applicable Level 2 2.1 The Narrow Range IcVel readings should agree with each other within f; 1.5 inches of the average reading.
2.2 The Wide Range level readings should agree with each other within j; 6.0 inches of the average reading.
4.6.2 Test Method /Results At rated temperature (approx. 540'F) and rated pressure (approx. 960 psig) during TC IIcatup (reactor power approx.
3% of rated, core flow approx. 37% of rated, average upper drywell temperature 135 - 140'F), reactor water level instrumentation indications were verified for proper function per design. This test was performed twice, August 9,1985 and September 22, 1985.
The August 9, 1985 test found narrow range instrumnnt transmitter IB21-LT-154C 1.5 inches from the average and indicator IB21-LIS-154C 1.8 inches from the average. A sero adjustment was made to the level indicating switch (LIS) me te r. The September 22, 1985 test found IB21-LT-154C 1.6 inches from the average and IB21-LIS-154C 2.0 inches from the average. This instrument loop will be recalibrated following instrument piping modifications.
The August 9,1985 test found wide range level indicators IB21-LIS-1558, 1821-L15-155C, IB21-LIS-155D, IC61-L1-004 outside the + 6 inch criteria. The indications were 6.1, 6.1, 8.1, anI 6.9, respect ively, f rom the ave rage. The B21 transmitters satisfied the criteria and were 1.4,1.6, and 1.3, respectively, from the average. The indicators were zero checked. The September 22, 1985 test found wide range indicators IC61-LI-004 and IC61-LIT-107 10.0 and 10.5 inches from the average. This instrument loop will be recalibrated following instrument piping modifications.
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,. 4.6.3 Corrective Actions /Open Items During the Heatup testing phase two problems were discovered in the A and B reference legs. The two problems, which were similar in nature, were caused by a water slug forming in the steam leg piping of the reference legs. The first problem occurred during initial pressurization in July 1985.
Upon heatup and pressurization a negative slope was created on the steam leg of reference leg A. This resulted in condensation and a water slug developing in the steam leg of reference leg A. This resulted in improper reference leg ,
performance and reference leg A instrumentation indicating higher than actual level. A spring hanger was placed on the steam leg of reference leg A which maintained the proper slope. Additional insulation was placed on the A steam leg piping to guarantee that design conditions were achieved.
This solved the problem and the water level test was performed on August 9,1985.
The second problem occurred following recovery from scram #3 in September 1985. As reactor pressure was increased the B reference leg instruments drif ted upscale. Upon investigation, it was discovered that a water slug was developing in the steam leg piping of reference leg B. This resulted in improper reference leg B performance and reference leg B instrumentation indicating higher than actual level. A spring hanger was placed on the B reference leg to guarantee positive slope of steam leg piping.
Additional insulation was placed on the B steam leg piping to guarantee that design conditions were achieved. This solved the problem and the water level test was repeated on September 22, 1985. !
Additional corrective actions relative to these two problems are under consideration and will be impicmented during the current outage.
The corrective action identified for Lnval 2 critoria failures is to perform complete instrument loop calibration for the af fected instruments. This will be performed following modifications to level instrument piping.
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4.7 SRM Performance and Control Rod Sequence (STP-6)
This test demonstrated the operability of the SRM instrumentation and verfied the adequacy of the control rod sequences and SRMs to safely and ef ficiently achieve criticality and increase power. The SRM signal to noise ratio was documented to be greater than 2:1 and the minimum count rate greater than 3 cps on all 4 S AMs.
4.7.1 Acceptance Criteria Level 1 1.1 There must be a neutron signal-to-noise ratio of at 1 cast 2:1 on the required operable SRMs.
1.2 There must be a minimum count rate of .7 cps on the required operable SRMs.
1.3 The IRMs must be on scale before the normalized SRM count rate exceeds the rod block setpoint.
4.7.2 Test Method /Results On January 18, 1985, in open vessel testing, the SRMs replaced the FLCs and were fully inserted and withdrawn and the SRM count rates recorded. Theso figures are documented in Table 4.7-1 and verify the signal to noise ratio greater than 2:1 and all four SRM minimum count rates greater than .7 cps.
On February 15, 1985, control rods were withdrawn in sequence 'A'. When each rod was withdrawn fully, SRM and IRM readings were recorded. The reactor was brought to criticality and then power was stab 111 od in the source range. The plots of SRM counts vs. number of control rods withdrawn showed satisfactory trends for ALL SRMs.
On June 12, 1985, control rods ware withdrawn in sequence
'B'. When each rod was withdrawn fully SRH and IRH readings were recorded. Criticality was reached last IRMs had not yet responded. On July 7th, rod withdrawal in sequance 'B' to a stable level in the source range verified proper IMH response on scale while normalised Slui count rate was below the rod block trip satpoint. The plots of SHH counts vs number of control rods withdrawn i showed satisfactory trends for all 4 SRHm. All acceptance !
criteria were satisfied for this test.
4.7.3 Corrective Action /Open Items l None l
l TABLE 4.7-1 Signal to Noise Ratio In Core Reading (eps)
(3) (1)
< 2.0 > 0.7 SM A ea 9 i
SM B 2423 16 SM C 104:1 19 SM D 2949 29.5 t
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- O 4.8 1RM Performance (STP-10)
The portions of this test that were completed have demonstrated a satisfactory SRM-IRM overlap, and a satisfactory IRM range 6 - 7 overlap, by recording and analyzing SRM and IRM readings.
4.8.1 Acceptance Criteria invel 1 1.1 Each IRM channel must be adjusted so that overlap with the SRMs and APRMs is assured.
1.2 The IRMs must produce a SCRAM at 96% of full scale in the REFUEL and STARTUP modos.
4.8.2 Test Method /Results On February 15, 1985, the Open Vessel portion of this test was performed in conjunction with STP-4, initial criticality. Count rate was increased to just below the SRM rod block trip setpoint with all the SRM detectors fully inserted while IRM and SRM readings were recorded. The results, as recorded in Table 4.8-1, satisfied the acceptance criteria but the IRM readings were not 5 meter units greater than the "all rods in" reading as required by SNPS Technical Specifications.
On February 16, 1985 the test was repeated and the SRM detectors were partially withdrawn from the core to prevent their readings from exceeding the trip setpoint but allowing for a "5 meter unit" IRM response. This demonstrated the required SRM-IRM overlap and the data was recorded in Table 4.8.2. Both Tables 4.8-1 and 4.8-2 show IRH readings with "all rods in", and show SRM and IRM readings at the overlap power level with count rate steady state.
On July 7, 1985, power was increased to the icvel necessary to verify IRM rango 6 - 7 overlap and then stabilized. IRM range 6 and 7 readings were recorded and documented in Table 4.8-3. The IRM range 6 - 7 overlap satisfied the require-ments for + 5 mnter units.
4.8.3 Corrective Actions /Open Items Nono
l TABLE'4.8-1 All rods Overlap
, in Range IRM Reading Reading
, 1
- S R S R Overlap A 1.5 1 4 1 SRM Range Reading
- B 1.5 1 5 1 (eps) c 1.5 1 4 1 A 8 x 10 6 D 1.5 1 4 1 g E 2.0 1 5 1 F l',0 1 4 1 G 2.0 1 4.5 1 D 8 x 10" ,, 1g 1 4 1
- < 1 x 105 required
- 8 - scale reading R - range reading TABLE 4.8-2 All rods overlap in Range
" Reading Reading ;
- S R S R i
Overlap UEN Rango A 1.6 1 11.5 1 i Reading *
(cps) D 1.2 1 17 1 C 1.3 1 9 1 A 3 x 10" D 1.3 1 9.0 1 D 3 x 10" E 1.6 1 13.6 1 F 1.1 1 11.5 1 C 2 x 10" ,
a 1.3 1 13.8 1 D 3 x 10" ,, g,3 g 7 g
. < 1 x gos required
- D - scalo reading R - range reading l
l TABLE 4.8-3 IRM A B C D E F G H Range 6 Readings 34 32 29 22 24 27 32 24 Range 7 Readings 4.5 3.0 4.0 2.5 3.0 3.0 6.0 3.5 i
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I 4.9 LPRM Calibration (STP-11)
This portion of the test performed during TC Heatup verified connection and operation of the LPRMs. 10 LPRMs were identified for
're-testing at a higher power level. One LPkM must be repaired and all others responded satisfactorily.
4.9.1 Acceptance Criteria
. Level 1 Not Applicable Level 2 2.1 Each LPRH reading will be within 10% of its calculated value.
No acceptance criteria is applicable at Test Condition Heatup.
4.9.2 Test Method /Results This test was performed concurrently with STP-5, Control Rod Drive. As control rods were withdrawn individually from full in to full out, the response or lack of response of each LPRM in the adjacent string was noted. 'LPRNb that did not respond were scheduled for checks during section 8.6 at a higher power level. 10 LPRMs will be tested in section 8.6.
s 4.9.3 Corrective Actions /Open Items LPRM 20-37-C will be repaired before re-testing in section-8.6.
.S n'
I n, s, l4.10' -APRM Calibration (STP-12)
The objective of this test was' to calibrate the Average Power Range Monitoring; system (APRM). Each APRM channel reading was adjusted to be' consistent with core thermal power as determined by a constant heatup rate method heat balance. This calibration is valid up to 20% power. , This test was completed satisfactorily for the heatup l test condition and all applicable test acceptance criteria was satisfied.
4.10.1 Acceptance Critebia Level 1 1.1 The APRM Channels must be. calibrated to read equal to or greater than the actual core thermal power.
1.2 Recalibration of the APRM system will not be necessary from safety considerations if at least two APRM
~
channels per RPS trip circuit have readings greater or equal to core power. ,
1.3 In the startup mode, all APRM channels must produce a scram at less than or equal to 15% of rated thermal powe r . ,
1.4 APRM scram and rod blocks shall function in a manner consistent with the Technical Specifications.
Level.2 2.1 If the above criteria are satisfied, then the APRM
. channels .will be considered to be reading accurately if they agree with the heat balance to within + 7% of rated power. ,
4.10.2 Test Methods /Results W This low power initial calibration of the APRM's was accomplished while moderator temperature was increasing.
. The testing was initially performed on July 8,1985 but the
,.g f APRM F. meter was sticking. The meter was replaced and the 1
4 , ,wpy' test repeated on July 15, 1985. A heat balance on the
. reactor vessel was performed to determine core thermal d _i power. . This resulted in a calculated core thermal power of 25.5 MWe, - which is 1.046% of rated thermal power. After
- j,.
this calculation, the APRM readings, averaged over the y period of heatup, were divided into the initial percent of rated . thermal power from the heat balance, to come up with an APRM adjustment factor for each APIU. The APRM's were then adjusted by using this adjustment factor to read equal to or greater than the actual percent of rated power. Test results are shown in Table 4.10-1.
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- - . - . . - . _ . , ~ ~ _ - - .. - - . . - ~ . . . . . . . .-
4
- i. 4.10.2 Test Method /Results - (continued) .
By adjusting the ' APRM's to the values shown in Table 4.10-1 p the applicable acceptance criteria were met for TC Heatup.
! 4.10.3 Corrective Actions /Open Items None f
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TABLE 4.10-1 Desired Actual as Left Initial Gain Final Value Final Value in Value in Volts Adj ustment . in Volts and Volts and %
APRM and % Rx Power Factor % Rx Power Rx Power A .0183 .9103 .0167 .0167 .
.229 .209 .209 B .0225 .8308 .0186 .0206
.281 .232 .258 C .0237 .8308 .0196 .0196
.296 .246 .246 D .0192 .9182- .0176 .0176
.240 .220 .220 E .0195 .8723 .0170 .0175
.244 .212 .219 F .0354 .4632 .0163 .0197
.443 .203 .246
4.11 Process Computer (STP-13)
'The results of this test showed that th'e data recorded during the initial Cold TIP Alignment agrees with the. data recorded during the Hot TIP Alignment. The final values of the TIP tube upper limits were verified to be sufficient to prevent the TIP chambers from hitting the top of the tubes.
, The results of the NSSS sof tware comparison showed that the class 1, 2 and 3 NSSS data on the process computer bulk storage unit agrees with the. latest G.E. tape.
.4.11.1 Acceptance Criteria Level 1 Not Applicable Level 2 1.1 Programs OD-1, P1, and OD-6 will be considered operational when:
- 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
- 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
- b. For the case in which the maximum LHCR calculated by the process computer is in a different aasembly than that calculated by BUCLE, for each assembly, the maximum LHGR calculated by the two methods shall' agree within 2%.
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4.11.1 ; Level 2 -'(continued)-
- 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
- b. For the case in which the MAPLHGR calculated by the process computer is in a different assembly than that calculated by BUCLE, for each assembly, the MAPLHGR and APLHGR calculated by the two methods shall agree within 2%.
- 4. The LPRM gain adjustment factors calculated by the .
independent method and the process computer agree to within 2% percent.
- 5. The remaining programs will be considered opera-tional upon successful completion of the static and dynamic testing.
NOTE: - Level criteria listed above is not applicable to testing done during Open Vessel and Heatup testing.
4.11.2 Test Method /Results The TIP alignment consisted of two phases. During open vessel testing on August 8,1985, the Cold TIP alignment data was obtained. The TIP chambers were manually cranked into each- core TIP tube location to determine values for the TIP panel electronico. Proper settings of these values ensures that the TIP system logic knows when the TIP chamber is at " core top" and " core bottom" to allow for accurate plotting and storage of computer data. During the Heatup phase on August 17, 1985, the same data was obtained for the Hot TIP alignment. The Hot TIP values were -
! compared against the Cold TIP values. No subsequent changes were required to be uade to the TIP system logic since the Hot and Cold values were within the expected range of each other.
A preliminary step of the Dynamic System test case was also performed during this test. A comparison was made on August 5,1985 between the class 1, 2 and 3 NSSS data on the computer bulk storage unit against the G.E. tapes, l
- i. using the 4010 Process Computer program "COMPAR". Any discrepancies 'found were accounted for and already
. documented via process computer change forms. ;
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4.11.3 . Corrective Actions /Open Items There are no Test Exception Reports associated with STP-13
- testing done so far.
In general, since the TIP system alignment is required to ensure accurate . plotting and storage of TIP data, the TIP alignment will be repeated due to the removal and replacement of the TIP tubing during the source outage.
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r-4.12 RCIC System Startup Test (STP-14)
The results of the RCIC system testing have verified the system's ability to operate over its expected range of operating pressures, including a demonstration of the system's ability to operate for extended periods of time. Furthermore, tests have demonstrated that the RCIC system is capable of providing rated flow within the minimum time requirements without tripping.
4.12.1 . Acceptance Criteria Level 1
.1.1 The average pump discharge flow must be equal to or greater than 100% rated value after 30 seconds have elapsed from automatic initiation at any reactor pressure between 150 psig and rated.
1.2 The RCIC system shall not trip or isolate during auto or manual start tests.
Level 2 2.1 In order to provide an overspeed and isolation trip avoidance margin, the transient start first and subsequent speed peaks shall not exceed 5% above the rated RCIC turbine speed.
2.2 The speed and flow control shall be adjusted so that the decay ratio of any RCIC system related variable is not greater than 0.25.
2.3 The turbine gland seal condenser system shall be capable of preventing steam leakage to the atmosphere.
2.4 The delta P switch for the RCIC steam supply line flow isolation trip shall be calibrated to actuate at 292% of.
the maximum required steady-state steam flow, with the reactor assumed to be near the pressure for main relief valve actuation.
. ~.. - - .
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4.12.2 -Test Method /Results
.Three ' categories of RCIC system testing were performed between July.11, 1985 and October 4, 1985. These include Condensate Storage Tank (CST) injection testing, Reactor
. Pressure Vessel (RPV) injection testing and Endurance Run testing. Table 4.12-1 summarizes the- RCIC operations performed during the above time period.
The CST injection testing is performed at two differing reactor pressures, 150 psig and rated (920 + 80, -20 psig).
The purpose of the test is to verify proper operation of the RCIC system or make adjustments as required. ; Controlled manual starts of the RCIC turbine are performed and flow is directed ,to the CST via ti;a installed test return valve .
The discharge pressure of the RCIC pump is adjusted to 100
+ 20 psig above reactor pressare by throttling the test .
valve position. Once this valve position has been determined, automatic quick starts of the turbine are performed by de-energizing the vessel injection valve and the test return valve while it remains in the correct position.- The-RCIC turbine is started by use of the initiation pushbutton.
The RCIC endurance run test is initiated by an automatic start from cold conditions (72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> of no turbine ope ration) . The system is then operated for 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> or until equilibrium oil temperatures are achieved. This demonstrates the system's ability to operate for extended periods of time.
The initial controlled manual start and hot quickstart to the CST were performed on July 12, 1985 with reactor pressure approximately 150.psig. Initial calibration of the RCIC flow controller network was accomplished and the test
-results satisfied all acceptance criteria.' The test was repeated at rated reactor pressure on August 16, 1985.
Calibration of the RCIC speed and flow control network was -
repeated. Operation of the system was satisfactory; ;
however, the EGM output signal from the RCIC turbine speed controller exhibited a decay ratio greater than 0.25. The condition was considered acceptable due to the correct operation of the flow controller network.
An automatic quick start with the turbine in a cold condition was performed on September 26,'1985 as indicated in Table-4.12-1. The RCIC system performance was
-acceptable. The RCIC pump discharge pressure did not reach the required range during' testing due to an improper throttle position on the CST test return valve. The valve position was adjusted to raise pump discharge pressure to 1040 psig to support performance of the RCIC endurance run f _-# '+7'q --e M-<e=r- Yr q% s - -Py--er -g--yr ?--7 .gr - y y9s g1r- yryry w m 9 vi---v- = yww- r*y, - -y- myp'v-sy
. ~ . . . - _ _ . - - ._ . _ . _ .- _ _
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4.12.2 Test Method /Results - (continued) -
I
, test. The RCIC system was operated for 65 minutes ndth a flow of' 405 gpm and turbine speed of 4200 rpm. Equilibrium oil temperatures were achieved in 50 minutes at a temperature' of 110*F.
,p i . Reactor vessel injection testing was. performed on September 26, 1985 and October 4,1985.- The initial test involved a hot quickstart with reactor pressure equal to 924 psig.
Control system oscillations were observed approximately 15 seconds after initiation. This condition was considered a violation of the Level I criteria since a stable flow to the reactor vessel could not be achieved. Following recalibra-tion of the flow controller network while injecting to the reactor vessel, the quickstart was = repeated. The system-response was acceptable while at rated flow conditions; however, flow oscillations. were again observed at a reduced system flow of approximately 200 gpm.
4.'12.3 Corrective - Actions /Open Items The. following demonstration tests remain to be performed on the RCIC system:
- 1. CST injection quick start from cold conditions.
- 2. RPV injection quick start from cold conditions.
- 3. RPV injection with reactor pressure of 150 psig.
These demonstration tests will be performed following the successful repeat testing of RCIC speed and control system tuning in both ' the CST and RPV injection modes. The emphasis of -the tuning will be to stabilize -the RCIC turbine speed control circuitry, making the turbine slightly less responsive to small speed changes. This tuning will be j l considered complete 1following successful reactor . vessel injection testing under low flow (200 gpm) conditions.
'l The final .setpoint for the RCIC steam flow isolation instrumentation will be determined based on the worst case
-value of steam flow obtained after completion of all
, demonstration tests.
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Level 1 Level 2 Initia. Dischg. Reactor Dischg. + + Speed Peak Oscilla- Seal 6P Switch Date MType _. Path Press. Press. Flow Time Trip First/ Subsequent tions Leakage- Setting 7/12/85 1/2 CST 158 260 405 7.2 NO 1000/2700 NONE NONE Note 1 8/23/85 1/2 CST 159 260 400 7.2 NO 1000/2600 NONE NONE Note 1 8/16/85 1/2 CST 923 1040 408 17.8 NO 2400/4083 YES NONE Note 1 9/26/85 3 CST 925 940 405 17.8 NO 2400/3950 NONE NONE Note 1 9/26/85 1/2 RPV 924 Oscilla- Oscilla- NA NO 2500/4250 YES NONE Note 1 ting ting 10/4/85 2 RPV 930 960 405 18.4 NO 2520/4125 YES NONE Note 1 0 1 = Manual start 2 = Ilot quick start 3 = Cold quick start
+ Maximum allowable time is 30 seconds. Minimum allowable flow is 400 gpm.
Note 1: Data has been obtained for steam flows during initiation. Final switch setting to be made based on highest readings received from all RCIC testing.
TABLE 4.12-1 RCIC SYSTEM TEST RESULTS
y; e ,
4."13 ' HPCI System Startup Test (STP-15)
The results _ of the testing demonstrated proper operation of the HPCI system during the condensate storage tank (CST) injections performed -
at reactor pressures ranging from 150 psig to rated pressure during
-Test Condition .Heatup.
4.13.11 Acceptance Criteria Imvel 1 1.1 The average HPCI discharge flow must be equal to or greater than 4250 gpm af ter 25 seconds have elapsed from initiation on cold quickstarts at any reactor pressure between 150 psig and. rated.
.1.2 .The HPCI turbine shall not trip or isolate during auto or manual starts.
Level 2 2.1 The turbine speed seal condenser system shall be capable of preventing steam leakage to the atmosphere in excess of allowable releases. For the purpose of this test, less than or equal to 0.1 MPC airborne activity in the vicinity of the HPCI unit is considered allowable releases.
2.2 The differential pressure switches for the HPCI steam supply line high flow isolation trip shall be calibrated to actuate at 290% of the maximum required steady-state steam flow (with the reactor assumed to be near the pressure-for main relief valve actuation).
2.3 The speed and flow control loops shall be ' adjusted so that the decay ratio of any HPCI sys tem variable is not greater than 0.25.
2.4 In . order- to provide an overspeed and isolation trip -
avoidance margin, the transient start first peak shall not : come closer than 15% (of rated power) to the overspeed trip, and subsequent speed peaks .shall not be greater than 5% above rated speed.
b
.____._ ____= _ _ __._______ _____ _ __________________ _._ _ ____ ________________ _ ________ _ _.____________ _____________ _ ________ _ _
- e 4.13.2 Test Method /Results Initial HPCI system testing was performed in July 1985 at a reactor pressure of 160 psig. Initial Woodward governor calibration checks were performed first. The HPCI system was then tested and evaluated by performing an automatic start of the HPCI system and performing 5 and 10% rated flow steps for controller stability testing. The automatic start was a " Hot Quickstart" where the hot condition is achieved by initially starting the HPCI turbine manually and running the turbine for a period of time. The test bypass valve to the CST was throttled until the HPCI pump discharge pressure of > 100 psig over reactor pressure was achieved. The turbine was then tripped and the system prepared for an automatic start. The Hot Quickstart and subsequent flow steps demonstrated adequate performance of the HPCI system with the initial preoperational control system settings.
Table 4.13.2-1 contains the data.
At approximately 900 psig reactor pressure the HPCI stop valve balance chamber adjustment was performed in order to insure proper HPCI stop valve performance. While performing this adjustment, problems were encountered with the HPCI control oil system. The problem was determined to be caused by insufficient control oil pressure and improper relief valve setpoints. A complete HPCI lube oil flow balance was performed which corrected this problem. The HPCI stop valve balance chamber adjustment was completed satisfactorily.
The HPCI control system was tuned during August 1985 with the system in the CST injection mode. Af ter completion of the tuneup the rated pressure Hot Quickscart and controller stability demonstrations were performed. The testing satisfied all criteria except the Level 2 overspeed margin (see Table 4.13.2-1 for results). The manual start at rated pressure also exceeded this criteria (4562 rpm on the first speed peak where < 4400 is the criteria). Section 4.13.3 contains the corrective actions which are planned. The 150 psig Hot Quickstart and stability demonstration verified the adequacy of the CST to CST controller settings at the low pressure operability point of the HPCI system. Table 4.13.2-1 contains these results.
A HPCI CST injection " cold" auto start was attempted on September 24, 1985. " Cold" is defined as a minimum 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> without any kind of HPCI operation. The system reached average flow of 4250 gpm in 22.5 seconds; however the HPCI pump discharge pressure was only 710 psig. This invalidated the test since the criteria for CST injections requires that the HPCI discharge pressure be 100 psig greater than reactor pressure. The test bypass valve to the CST was throttled incorrectly which caused the discharge pressure to be low.
o .
4.13.2 Test Method /Results - (continued)
The HPCI endurance run was attempted on September 24, 1985.
The test was aborted due to high indicated suppression pool temperature prior to satisfying the criteria of the endurance run.
Dates, test conditions and results of HPCl testing are shown in Table 4.13.2-1.
4.13.3 Corrective Actions /Open Items Evaluation of the overspeed test exception concluded that this should be solved prior to attempting actual vessel injections where the system gain is greater.
In order to improve HPCI system reliability and increase turbine overspeed margins, FDDR's KSI-1245 and KS1-212 are planned for implementation. These system improvements involve installing a hydraulic bypass around the EGR actuator and relocating the Woodward governor and RGSC enclosure.
These control system modifications will necessitate repeating the 150 psig and rated pressure HPCI tuning and testing prior to exceeding the heatup test condition power limitations.
The limitation on the cun time for the "HPCI endurance run" caused by high suppression pool temperatures is under investigation. The temperature elements used to monitor suppression pool temperature are located on the perimeter of the reactor vessel pedestal, one foot and two feet below the normal pool level. Based on RHR inlet temperature and RHR heat exchanger heat load calculations, the high indicated pool temperature is believed to be caused by thermal stratification. Corrective actions are under evaluation.
.- . _ . _ - _ . - . _ _ _ _ - _ _ _ _ - - _ _ - _ _ _ - _ - _ _ _ . .-. _ . _ - -,_ - .~_
LEVEL - 1 LEVEL - 2 I 2 I 2 gp 3 4 Date Test Pressure Time to No -Speed Peak Condi- Test Rated Flow Trip Seal Switch Decay Initial / Subsequent tion < 25 sec. Leakage Setting Ratio < 4400/< 4200
< .25 1
07/31/85 Heatup 15.1 150 24 sec. NO NONE Note 4 Acceptable < 3200 08/23/85 Heatup 15.2 Rated 20.4 sec. NO NONE Note 4 Acceptable 3000/4360
- 2 08/23/85 Heatup 150 15.1 12.3 sec. NO NONE Note 4 Acceptable 2900/2500 2,3 09/24/85 Heatup 15.3 Rated 22.5 sec. NO NONE N/A N/A N/A Note 3 Note 3 Note 3 Note 3 Notes: 1) Initial HPCI controller setting. Adjustments were made to HPCI controller following this test.
, 2) Final Heatup CST to CST HPCI controller settings.
1 1
- 3) The HPCI pump discharge pressure did not satisfy test prerequisites of 100 psig over reactor pressure.
The Cold Quickstart is invalid. (Discharge press 710 psig) l 4) Data taken. Final analysis not performed at Heatup.
l 15.1 CST to CST Hot Quickstart and flow steps 15.2 CST to CST Hot Quickstart and flow steps 15.3 CST to CST Cold Quickstart
- exceeds criteria TABLE 4.13.2-1 O
l
L .- ,
4.14 ' Selected Process Temperatures (STP-16)
This test demonstrated that thermal stratification does not occur at a minimum speed of 24% for each of the reactor recirculation pumps.
4.14.1 Acceptance Criteria level 1 1.1 The reactor recirculation pumps shall not be started nor fl increased unless the coolant temperatures betwec~ che steam dome and bottom head drain are within 145'F (81*C).
1.2 The recirculation pump in an idle loop must not be started unless the loop suction temperature is within 50*F (28'C) of the active loop suction temperature if one pump is idle or the steam dome temperature if two pumps are idle.
Level 2 j 2.1 During two pump operation at rated core flow, the l
bottom head coolant temperature, as measured by the
! bottom drain line thermocouple, should be within 30*F (17'C) of the recirculation loop temperatures.
4.14.2 Test Method /Results This test was performed during Test Condition Heatup on October 7,1985. The speed of the reactor recirculation pumps was decreased in 1% steps from 30% initial pump speed to the lowest stable speed or the low speed stop.
Reactor dome pressure, bottom head drain temperature and reactor recirculation loops inlet temperatures were recorded during the step changes. Additional process parameters were monitored during the test but were not used in the data analysis. The 'B' reactor recirculation pump minimum speed was 24% based on a + 3% limit cycle observed to occur at speeds below 24%. The ' A' reactor recirculation pump minimum speed was 23% based on reaching a scoop tube low speed limiter setpoint.
The observed steam dome temperature to bottom head drain temperature differential was negligible within the accuracy of the two instruments. The recirculation loop temperatures to bottom head drain temperature dif fer-entials were negligible at a core flow of 39.4% and a reactor power of 2.5%. Based on the data acquired during this test no measurable thermal stratification occurred while operating the reactor recirculation pumps at a speed of 24%.
i
.- i l-4.14.3 Corrective Actions /Open Items Testing scheduled to be performed in Test Condition 3 will make adjustments to the flow control systen which, in addition to optimizing controller settings,.are expected to eliminate or greatly reduce the limit cycles observed on the 'B' side. In the interim, the low speed stops for both the 'A' and 'B' loops will be set to approximately 24% to prevent limit cycle operation. The low speed stops will be reset to 20% and thermal stratification test will be repeated, as required by the procedure, following the controller timing and adjustments.
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4.'15 System - Expansion (STP-17),
The results of .the testing showed that the main steam piping
- . 'inside the containment _ and reactor recirculation system piping were free to ' move without unplanned obstruction or restraint during heatup and cooldown, that this system piping behaved in a manner consistent with assumptions of the stress anlaysis, and that 'there was agreement .between calculated and measured values of displacement.
! System. expansion monitori~ng of piping systems and pipe restraining
! devices took place during the first three plant heatups. nsta was recorded on GETARS (transient recording system) from remotely i mounted displacement instrumentation located on piping for system. .
expansion testing. Recorded data was compared with design calculated values to determine acceptable piping movement.
.4.15.1 Acceptance Criteria Level 1 i
- 1.1 There shall be no obstruction which will interfere L with thermal expansion of the main steam and -
recircuation piping systems..
l.
1.2 The displacements at the established transducer locations shall not exceed the allowable values, as provided by. the General Electric Piping Design r Subsection. The allowable values of displacement shall be based on not exceeding ASME Section III code stress allowables.
Level 2 2.1 The displacements at the established transducer locations shall not exceed the expected values as provided by the General Electric Piping Design Subsection.
4.15.2 Test Method /Results STP-17 was divided into two parts and each part was performed until shakedown had taken place (three thermal cycles). The first part involved visual inspections of drywell equipment while the plant was cold and for the first heatup only, at an intermediate temperature and at rated temperature and pressure.
During the visual inspections, wherever radiation and temperature levels permitted, hanger positions of the major equipment and piping in the Nuclear Steam Supply
( System (NSSS) and Auxiliary Systems were recorded.
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3' ;i-E4.15.~2- Test Methods /Results - (continue'd)
Additionally, inspections for obstructions to free and unrestrained motion for all' ma.'.or equipment were made at an intermediate temperature and,-if possible, at rated temperature. Adjustment.s to achieve the intent of-the. criteria were made as 1ecessary.
- The second part of the system expansion test involved data gathering .to verify free expansion of the NSSS.
The movement of selected recirculation and main steam piping was monitored every 50*F using Lanyard Potentiometers. The Lanyard Potentiometers were installed on the following piping systems:
- 1) Three potentiometers (mutually orthogonal) at each of four locations on each recirculation loop to monitor pipe movement along three axes.
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- 2) Three potentiometers at each of two locations on each steam line to monitor pipe movement along three axes.
In order to properly assess pipe motion during heatup, when temperature equilibrium is difficult to verify, two permanent plant installed RTD's mounted in the l recirculation loop suction lines and one temporary installed RTD on the A recirculation loop discharge !
riser just ahead of the RHR~ connection were monitored.
In addition, two temporary RTD's, one each on steam lines A and C located on the lower portion of the lines '
were monitored.
The first heatup was conducted between July 6,1985 and August 14, 1985. The plant was placed in a HOLD position when. two L.P. 's (SD-UY and RA-DYL) violated L Level-I criteria. The Level 1 failure of RA-DYL was
[- due to a calibration error (incorrect GETARS slope).
l -The error:was rectified and RA-DYL passed the Level'1
! criteria. ' Initially, the Main Steam Line Isolation Valves and the Main Steam Line Drain Valves were shut, resulting in condensate collecting in the Main Steam Lines. Shortly af ter the Main Steam Line Drains were opened Level I criteria was met. Subsequent test data indicates that the Level I criteria failure was due to the Main Steam Lines remaining cold as the Reactor Pressure Vessel heated up (no steam flow path and condensate in steam lines). At rated temperature and pressure there were no Level 1 L.P. violations and the-
. nineteen Level 2 L.P. violations were considered acceptable by the General Electric Piping Design Subsection.
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4.15.2 Test Method /Results - (continued)
Drywell walkdown inspections were conducted at cold, intermediate and . rated temperatures and pressures.
Three hangers were inaccessible at intermediate temperature, and at rated temperature and pressure,'
three hangers and snubbers were inaccessible. For variable support hangers, the General Electric Piping Design criteria is that actual readings must agree within the maximum of either + 3% or + 500 lbs. of the J design readings. Main Steam Idne "D" Hanger HD-3 )
exceeded the criteria at medium and rated temperatures and pressures. "A" Recirculation Line Hanger HA exceeded the criteria at rated temperature and pressure. These violations were considered acceptable by the General Electric Piping Design Subsection. All potential thermal-expansion constraints were identified and resolved.
The second heatup was conducted between August 26, 1985 and September 21, 1985. At rated temperature and g
pressure, there were no Level 1 L.P. violations and the nineteen Level 2 L.P. violations were considered
, acceptable by the General Electric Piping Design
[ Subsection. Drywell walkdown inspections were o conducted at cold temperatures. Main Steam Line "D"
! Hanger HD-3 exceeded the General Electric Piping Design criteria, but was considered as acceptable. Ove rall, inspected piping systems and components were functioning correctly, so medium and rated temperature l and pressure inspections were considered to be t
unnecessary.
The third heatup was conducted between October 1,1985 and October 4,1985. At rated temperature and pressure, there were no level 1 L.P. . violations = and the twenty-two Level 2 L.P. violations were considered acceptable by the General Electric Piping Design Subsection. Drywell walkdown inspections were conducted at cold temperatures. Overall, inspected piping systems and components were functioning correctly, so medium and rated temperature and pressure inspections were considered to be unnecessary.
4.15.3 Corrective Action /Open Items As ' previously ' described, Level I criteria were violated during the first reactor heatup for point SD-UY (at or tbout 220*F). Subsequent test data indicated that' the criteria failure was due to the hot RPV expanding upward while the cold Main Steam Lines .did not expand downward. The MSIV's had been kept closed by station
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1 "1 i. ,3 4.15.3 Corrective Action /Open Items - (continued) procedure until 15 PSIG main steam pressure was indicated. Based on the station's operating procedures, which~resulted in the steam lines remaining relatively cold until steam pressure = 15 PSIG, San Jose Engineering provided revised Level I criteria for points SA-UY and SD-UY. 1Rie revised criteria allowed ;
continuance of operations as previously described while meeting Level 1 acceptance criteria. The revised criteria were never violated. It was initially thought that water accumulation in the steam lines caused the Level 1 failure, Subsequent data did not support this t heo ry. The cause of the Main Steam Line expansion anomoly was not accumulated water, but the inability to attain isothermal conditions between the RPV and the Main Steam Lines until =15 PSIG reactor pressure.
4.16 Main Steam Isolation Valves (STP-25)
The results of the testing demonstrates that each MSIV is functional and can close upon initiation within the prescribed time period of 3 to 5 seconds as per Plant Technical Specifications and the Final Safety Analysis Report. The testing also demonstrated adequate movement of the valve stem, the correct console warning light indication, and correct reactor protection system interface.
4.16.1 Acceptance Criteria level 1 1.1 MSlV closure time, exclusive of electrical delay shall be no faster than 3.0 seconds (average of the fastest valve in each steam line), and no slower than 5.0 seconds, including electrical delay (each valve, not averaged). The fastest valve closure time shall be >
2.5 seconds.
1.2 For the full MSIV closure from full power, predicted analytical results based on beginning of cycle design basis analysis, assuming no equipment failures and applying appropriate parametric corrections, will be used as the basis to which the actual transient is compared. The following table specifies the upper limits of these criteria during the first 30 seconds following initiation of the indicated conditions:
Initial Conditions Criteria
- Power Dome Pressure Increase in Increase in
(%) (psia) Simulated Thermal Dome Presa.
Power (%) (psi) 100 1020 2 171
- Defined in SNPS-1 Transient Analysis Design Report Supplement #1 1.3 Feedwater control system settings must prevent flooding of the steam lines.
Level 2 2.1 During full closure of individual valves peak vessel pressure must be 10 psi below scram, peak neutron flux must be 7.5% below scram, and steam flow in individual lines must be 10% below the isolation trip setting.
Peak simulated thermal power must remain 5% below the scram trip point.
4.16.1 level 2 - (continued) 2.2 The RCIC system shall adequately take over water level protection. The relief valves must reclose properly (without leakage) following the pressure transient.
2.3 For the full MSIV closure from f ull power, predicted analytical results based on beginning of cycle design basis analysis, assuming no equipment failures and applying appropriate parametric corrections, will be used as the basis to which the actual transient is compared. The following table specifies the upper limits of these criteria during the first 30 seconds following initiation of the indicated conditions.
Initial Conditions Criteria
- Power Dome Pressure Increase in Increase in
(%) (psia) Simulated Thermal Dome Pressure Power (%) (psi) 100 1020 0 146
- Defined in SNPS-1 Transient Analysis Design Report Supplement #1 4.16.2 Test Method /Results Individual closure of the MSIV's was performed at Test Condition Heatup (Rx Thermal Power 2.5%). MS1V closure times, exclusive of electrical delay, varied from 3.43 to 4.18 seconde, which meet the acceptance criteria. MSIV closure times, inclusive of electrical delay, varied from 3.87 to 4.44 seconds, which meet the acceptance criteria.
The peak values for reactor vessel pressure and neutron flux were determined to be acceptable, however, no meaningful data was obtained for simulated thermal power or steam line flow due to the low power at which this test was perforned.
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4.17 Safcty/Relicf Valv0c (STP-26)
This test serves to confirm the proper operation of the primary system safety / relief valves (SRV), including discharge piping flow and proper seating of the valves following operation; and to obtain baseline information on safety / relief valve response for subuequent comparison per FSAR 14.1.4.8.23.
4.17.1 Acceptance Criteria Level 1 1.1 There should be positive indication of steam discharge during the manual actuation of each SRV.
Level 2 2.1 The observed decay ratio for pressure control related variables must be less than or equal to 0.25.
2.2 The temperature measured by the thermocouples on the discharge side of the SRV's shall return to within 10*F of the temperature recorded before the valve was opened. The pressure on the discharge side of the SRV shall return to its initial value following valve closure.
2.3 During the 250 psig f unctional test, the steam flow through each relief valve, as measured by the initial and final bypass valve position, shall not be less than 10% of valve position under the average of all valve responses.
2.4 During the rated pressure test the steam flow through nach relief valvo, as measured by MWE, shall not be less than 0.5% of rated MWE under the average of all the valve responses.
4.17.2 Test Method /Results Safety / relief valve (SRV) functional testing was conducted on July 9,1985 at approximately 1.0 percent reactor power with reactor dome pressure at 144 psig during Test Condition lleatup. Testing at 150 psig satisfied SRV operability per plant procedures as well
, as performing the startup test. This limited the number of cycles the SRVs would see at a low reactor pressure manual initiation. Each SRV was manually cycled to verify proper operation with each valve held I open for approximately 10 - 20 seconds to allow pressure control system related variables to stabilize.
All eleven SRVs were tested. Eight valves did not return to within 10*F of their initial tailpipe t empe ra ture. One of the eight also failed the initial and final bypass valve position being less than 10 percent of the valve the valve responses. position under the average of all
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4.'17.3 Corrective Actions /Open Items The eight SRVs (A, B, C, D, E, F C,11) that failed the test criteria relating to the tailpipe temperature not returning to within 10'F of the initial reading, were deemed acceptable. This is the result of the test being performed at a low pressure that was insufficient ;
to properly back seat the SRVs to prevent weeping. The test will be repeated at rated pressure, Test Condition 2.
SRV 'A' which failed the steam flow as measured by bypass valve position being less than 10 percent of valve position under the average of all valves will be redone at rated pressure, Test Condition 2. This decision was made to limit the amount of cycling of the SRVs at a lower reactor pressure.
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4.18 Recirculation Flow Control System (STP-29)
The results of the testing performed during Test Condition Heatup demonstrated the interim recirculation flow controllers settings to be acceptable for the local manual mode.
4.18.1 Acceptance Criteria Level 1 1.1 The decay ratio of any oscillatory variable must be less than 1.0.
Level 2 2.1 The decay ratio of any oscillatory controlled variable must be j( 0.25.
2.2 Flow Control system limit cycles (if any) must produce turbine steam flow variation no larger than + 0.5% of the rated steam flow value.
2.3 Reactor scram shall not occur due to Flow Control system maneuvers. The APRM flux margin shall be j( 7.5% and the simulated thermal power margin shall be 15.0% of the rated value.
2.4 The Automatic Load Following range along the full power rod line shall be at least 35% of rated power (i.e., 65%
to 100%).
2.5 The load change resulting from a maximum ramp increase in load reference within the limits of the automatic flow control range shall be achieved within 60 seconds, if operating restrictions permit. In addition + 10% and 20% power step changes must be performed within 40 seconds.
2.6 Following a 10% speed demand step at the low end of the speed control range, the time from the step demand until ,
the generator speed peak occurs, must be j( 25 seconds.
2.7 Reponse of each speed control (closed) loop following a step input, between 90 and 100% speed, shall be adjusted so that 10% of the demanded change will be reached within 2 seconds and the response time between 10 and 90% of the demanded change will be no greater than 5 seconds. Deviations from this response below 90% speed shall not prevent complying with criteria above.
NOTE: only level 1 and Imvel 2 #1 and #3 apply to T/C Heatup.
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4.18.2 Test Method /Results The testing was performed during Test Condition Heatup (< 5%
rated reactor thermal power). 6% MG Set speed steps were performed between 24% and 30% MG Set speed. 24% MG Set speed had been determined during previous testing to be lower limit before limit cycles were observed. ( STP-16) .
The 6% speed controller step (local manual mode) for the A-MG Set exhibited stable response characteristics with no oscillatory response. The test criteria were satisfied.
The 6% speed controller step (local manual mode) for the B-MG Set exhibited stable response to the step change. The B-MG Set did exhibit a limit cycle when speed demand was approximately 24% with an amplitude of approximately 5% and a period of approximately 100 seconds. This violated the Level I criteria and a TER was generated. This limit cycle also prohibited completion of this section of the STP.
4.18.3 Corrective Actions /Open Items The limit cycle on the B-MG Set to believed to be caused by non-linearities which exist in the acoop tube position vs speed characteristics in the 20% to 30% speed range. In the 20% to approx. 25% speed range, a .1 inch scoop tube position change results in a 5% speed change. From approximately 25%
to 30% speed, a .45 inch scoop tube position change results in a 5% speed change.
Corrective action has been taken to prevent operations of the B-MG Set in this non-linear region. The low speed stops on both A & f ecoop tubes will be reset to 24% electrical, prior to entering TC-1.
Af ter a complete evaluation of the recirculation flow control system (scheduled to be performed during TC-1, 2, & 3) the non-linearities can possibly be compensated for by shap3ng the cam.
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4.19 Vibration Measurenents -(STP-33)
The results of the testing showed that the main steam line vibration limits during Safety Relief Valve (SRV) functional testing met all test criteria and' applicable sections of FSAR 14.1.4.8.28.
4.19.1 Acceptance criteria Level 1
.1.1 The measured amplitudes in the main steam lines during '
relief valve operation shall not exceed the allowable design values.
Level 2 2.1 The measured vibration displacements of the main steam system following relief valve operation shall not exceed the expected range of displacement.
4.19.2 Test Method /Results-The heatup phase of STP-33 was performed on the dates of July 9, 1985 and July 10, 1985 at a reactor power of 1.6% and a reactor pressure of 150 psig. Eleven SRVs were tested individually with vibration measurements of the main steam lines acquired by the General Electric Transient Analysis Recorder (CETARS) during each test. The maximum peak to pesk amplitude of vibration for each sensor location was compared to the Level 1 and 2 design values for vibration on the main steam lines. No peak to peak amplitude of vibration exceeded Level 1 and 2 test criteria during the performance of this test.
4.19.3 Corrective Actions /Open Items None L
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4 4.20- Recirculation System Flow Calibration (STP-35)-
The purpose of this test is to perform a complete calibration of reactor recirculation flow instrumentation, based on data obtained
~ with the reactor recirculation pumps operating at the speed required 1 to produce rated core flow at rated power. This' test cannot be performed in Test Conditions Open Vessel or Heatup.
Initial calibration of recirculation flow instrumentation was performed during preoperational testing, and surveillances are w periodically performed in accordance with Technical Specifications.
This -test is scheduled to be performed in Test Condition 3.
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4.21 Reactor Water Cleanup System (STP-70)
The Reactor Water Cleanup (RWCU) System was operated in the Blowdown Mode during Test Condition Heatup. Satisfactory performance was demonstrated by comparing actual plant data during this operation with values from the G.E. process diagram.
4.21.1 Acceptance Criteria Level 1 Not Applicable Level 2 2.1 The temperature at the tube side outlet of the non-regenerative heat exchangers shall not exceed 130*F in any mode.
2.2 The pump available NPSH will be 10 feet or greater during the Hot Shutdown mode defined in the Process Diagram (Reference 4.9).
2.3 The cooling water supplied to the nonregenerative heat exchangers shall be within the flow and outlet temperature limits indicated in the Process Diagram (Reference 4.9) and system specifications. (This is applicable to " normal" and " blowdown" mode).
4.21.2 Test Method /Results Calibration of the Bottom Head Drain Line Flow Indicator (FI-001) was attempted during Test Condition Heatup. The RWCU system was aligned so that all system flow was through the bottom head drain line. FI-001 was found to be off scale (> 150 gpm) at a known flow of approximately 125 gpm.
This test was stopped, several test exceptions were written, and investigation of the problem was initiated.
The RWCU Blowdown Mode- and Normal Mode were tested. Reacto r Building Closed Loop Cooling Water (RBCLCW) was aligned to provide flow to the non-regenerative heat exchangers and the RWCU pumps. Data was recorded and analysis indicated acceptable performance of Normal Mode. Then the RWCU syster was operated in the Blowdown Mode with partial system flow returning to the vessel to test the regenerative heat exchanger capacity. Next, the system was operated in the Blowdown Mode with no flow returning to the vessel to test the non-regenerative heat exchanger. Criteria 1 and 3 (Level 2) were satisfied and test results indicated acceptable performance of Blowdown Mode and Normal Mode.
During the performance of this test several RWCU isolations were experienced due to high dif ferential flow indication and a test exception was generated. Investigations were performed to determine the cause of these high differential flow indications, and corrective actions were taken.
4.21.3 Corr:ctiva Actien3/Open Itica An investigation was conducted to determine why the bottom head drain line indicator / transmitter indicated off scale
(> 150 gpm) when actual flow was approximately 125 gpm. A test transmitter was used in parallel to FT-001 during a retest of Appendix A, to determine actual delta P seen by FT-001. The results indicated the existing FT-001 (0 - 150" H2O range) was being exposed to delta P of up to 561" H20, which explained the offscale readings observed. An EEAR has been generated to change out the existing transmitter with i one of greater range (0 - 750" H2O) during the source change outage. New data for Appendix A will be obtained af ter the changeout.
An investigation of the high dif ferential flow trips experienced in performance of blowdown mode demonstration revealed several causes.
The flow transmitters that provide inputs to the delta flow indicator were calibrated at hot conditions so that individually each transmitter would indicate correct flow at normal operating conditions, however this resulted in high differential flow indications (35 gpm) without blowdown. -
When blowdown was initiated, high dif ferential flow rose to reach its setpoint (44 gpm) and would initiate RWCU isolation.
The RWCU high differential flow isolation circuit monitors system inlet, system outlet and system blowdown flows to determine if leakage is occurring, and isolates the system if high leakage is detected. The differential flow isolation is designed to be sensitive at ambient conditions.
The flow transmitters were recalibrated to read accurately at cold conditions, which resulted in steady state system dif ferential flow with no blowdown flow of approximately 12 gpm hot and 0 gpm cold.
The other cause of high differential flow trip was attributed to an incorrect system configuration as defined in the procedure. The procedure was revised accordingly.
Af ter both problems (procedure change and calibration change) were corrected the blowdown test was repeated with satisfactory results.
4.22 Residual Heat Removal System (STP-71)
The purpose of this test is to demonstrate the ability of the RHR system to remove residual and decay heat from the reactor and the suppression pool.
The steam condensing mode of operation will not be tested or demonstrated as long as the license condition that the steam condensing mode shall not be operated remains in effect.
The heat removal capability of the RHR heat exchangers in the shutdown cooling mode will be demonstrated later in the power ascension test program when there will be more decay heat.
Data from the HPCI endurance run and RHR suppression pool cooling mode operation show that there is some thermal stratification in the suppression pool and that the installed instrumentation, located approximately one foot and two feet below normal pool level, indicates temperatures higher than bulk pool temperature. This phenomenon is still under evaluation.
The heat removal capability of the RHR heat exchangers will be demonstrated af ter the evaluation is completed and any corrective actions deemed to be appropriate are implemented.
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8 9 4.23 Reactor Building Closed Loop Cooling and Drywell Cooling (STP-37)
This test demonstrated that with RBCLCW supply temperature 91 + 4*F, flows are adequate to meet the cooling requirements of the supplied components at Test Condition Heatup.
4.23.1 Acceptance Criteria Level 1 1.1 Drywell temperature control will meet or exceed design requirements.
Level 2 2.1 Reactor building closed loop cooling system water supply temperature will meet design requirements.
2.2 The RBCLCW system process temperature is 91*F + 4*F and is adequate to meet the cooling requirements of the supplied components. '
4.23.2 Test Method /Results This test was performed at three reactor pressure plateaus:
150 psig, 600 psig and 1000 psig. At each plateau, the Level 2 criteria were evaluated by establishing RBCLCW system supply temperature of 91 + 4*F and verifying that the specific coded component outlet temperature was less than the design maximum outlet temperature; component cooling water flow was equal to or ' greater than the design component flow; or that the RBCLCW temperature rise across the cooled component was less than the design value.
At the 150 psig plateau, the RBCLCW system temperature was not est 1blished at 91 j; 4*F. The data was taken and proved to satisfy the criteria at the lower temperature. At this pinteau, insufficient heat load existed to achieve 91 j; 4*F without significantly throttling service water flow. Test exceptions were taken against data acquired at the 150 psig plateau based upon the 600 psig and 1000 psig plateau performance (see section 4.23.3). RBCLCW sys tem temperature was established at 91 + 4*F and the data taken satisfied the Level 2 criteria. Test exceptions were taken against data acquired at these plateaus. See section 4.23.3 for resolution.
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4.23.3 Corrective Actions /Open Items Two test exceptions were taken due to inadequate drywell air temperature data. Since these data only apply to the Level I criterion, and the Level I criterion is only applicable at Test Conditions 5 and 6, test results for Test Condition Heatup were accepted.
The test exception against the 150 psig plateau RBCLCW heat
[ exchanger temperature being less than 91 + 4*F was resolved
[ as follows : Since the 600 and 1000 psig plateau testing adequately established this condition and passed the criteria the 150 psig plateau testing did not require repeating.
At the 600 and 1000 psig testing plateau the CRD pump cooler '
RBCLCW outlet temperatures were not consistent with the Level 2 criteria. The CRD pump bearing temperatures were recorded at all three plateaus and were below the maximum safe operating temperatures for the bearings. The CRD pump bearing temperatures were accepted as adequate demonstration for adequate cooling flow from the RBCLCW system.
At the 600 psig plateau the recorded RWCU pump 'A' cooler outlet temperature indicated 148'F; the maximum value being 140*F. This reading was found to be that of the RWCU pump
' A' bearing temperature. At the 1000 psig plateau the cocler outlet temperature was obtained with a hand held pyrometer and found to be within specification.
A test exception was taken against the RHR pump cooler RBCLCW flow. This flow could not be accurately determined.
Since no heat load problems existed the data was accepted as is and an HWR was written to have the transmitters checked for correct operation. This testing will be repeated at Test Condition 2. Heatup retesting was not required.
Test exceptions were taken against RHR pump cooler RBCLCW cooling temperature differential and the drywell equipment drain cooler RBCLCW cooling temperature differential. The cooler outlet temperatures were found to be acceptable and the RBCLCW cooling performance was accepted as is. This testing will be repeated at Test Condition 2. Heatup retesting was not required.
4.24 Service Water System (STP-42)
The purpose of. this test is to demonstrate that the service water system adequately cools all its normal service loads.
Various flow and temperature data for the service water system and for systems supplied by the service water system are recorded and evaluated against the system design values for acceptability. This test, although scheduled for Test Condition
.Heatup, was not performed prior to the current outage. It will be performed before entering Test Condition 1.
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4.25 Loose' Parts Monitoring System (STP-814)
- The purpose of this test is to perform the initial set-up of the loose parts monitoring system, to adjust the system's .
sensitivity and alarm setpoints as required for normal plant operation, and to demonstrate the ability to detect impacts as required by Regulatory Guide 1.133.
This test was scheduled to be performed concurrently with neutron monitoring instrumentation detector drive in and drive out operations during plant startup and shutdown during Test Conditions Open Vessel and Heatup but plant personnel were unable to successfully complete the initial sensitivity adjustment- following the vendor's instructions. A vendor-representative has been requested to come to the site to inspect and evaluate the loose parts monitoring system, and-to provide additonal instruction to plant personnel and technicians on its operation and maintenance, if required. .This test will be scheduled for performance at the first opportunity af ter _the current outage.
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- O 5.0 License Conditions Status 5.1 Technical Specifications requires that the Startup Report include any specific details required in the license conditions which affect plant startup and power escalation testing. The specific license conditions are delineated in paragraph 2.C of the Shoreham Operating License (NPF-36 of July 3, 1985). Each condition is summarized and its status, as it applies to the completed portion of the test program, is provided below.
5.1.1 Condition
The maximum core thermal power shall not exceed 5% rated core thermal power.
Status: The low power test program was conducted within the prescribed power limitations during Open Vessel Testing (less than 0.001 percent per NPF-19) and Heatup (less than 5 percent per NPF-36) with one exception. On a single occassion, core thermal power exceeded the 5% limitation during a transient due to a mechanical failure of a feedwater level control valve. The maximum power level observed during the transient was 5.8 percent. Core thermal power was quickly restored to the license condition restriction, and there were no associated problems.
The event was reported to the NRC, and a more complete description of the event is contained in a Licensee Event Report (LER) which is currently in preparation.
5.1.2 Condition
The plant shall be operated in accordance with the Technical Specifications and the Environ-mental Protection Plan.
Status: The Low Power Test Program has been conducted in accordance with Technical Specifications and the Environmental Protection Plan. In a very few circumstances, the provisions of Technical Specifica-tions were exceeded. Each circumstance has been previously reported to the NRC and has been the subject of a Licensee Event Report (LER).
5.1.3 Condition
The plant shall maintain the fire protection program as described in the Fire Hazards Analysis Report and in the FSAR.
Status: Except as described in LER's85-004, 007, 014, and 028, the provisions of the fire protection program have been followed during the period of low power testing.
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5.1.4' Condition: Changes to the initial test program shall
= be reported within one month.
- Status: ' All changes. to - the test program as described '
.by Chapter 14 of the FSAR have been reported to the .
NRC prior'to their implementation.
- 5.1.5 Condition: The initial inservice inspection shall be developed and implemented before the first refueling outage.
Status: This condition is not affected by the Low Power Test Program. Development of the inservice
. inspection program is in progress.
5.1.6 Condition
Control rods shall be tested for boron loss after the first refueling outage.
Status: This condition is not yet applicable.-
5.1.7 Condition
The provision of the NUREG-0757 action ,
planned described in the SER, supplements '1 and 4, shall be followed.
5.1.7a Status: To date the qualification of 5 of the required 7 backup STA's have been submitted to and approved by the Commission. The remaining-2 positions are unfilled.
5.1.7b Status: The requirement to mark control room indicators with operating limits, trip and alarm {
values is not yet implemented. The requirements of j the provision remain under review and shall be implemented as required.
5.1.7c Status: Modifications to the post accident sample facility to enable sampling using a modified core damage procedure are in progress.
5.1. 7d Status: The station modifications to implement the provisions of Attachment I to the license to improve the Emergency Response Capabilities are in progress.
5.1.8 Condition
Prior to November 30, 1985, all electrical equipment shall be qualified.
Status: Station modifications to environmentally qualify required electrical equipment are in progress.
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5.1.9 Condition
The remote shutdown system shall be improved prior to the first startup following the:
first refueling outage.
Status: The modifications will be -implemented as required.
5.1.10 Condition: The RHR system may not be operated under the steam condensing mode except under emergency conditions.
Status: The station procedures have been modified to preclude the steam condensing mode of operations except as a last resort when all other methods of core and containment cooling have failed.
5.1.11 Condition: Two containment isolation barriers in series will be installed by the end of the first refuel outage.
Status: Methods to satisfy this condition are under engineering consideration.
5.1.12 Condition: The provisions of Appendix 3 to the license shall be satisfied as they apply to the TD1 diesel generators.
Status: Scation procedures and maintenance schedules have been modified to include the required TD1 diesel generator testing and inspections.
'5.1.13 Condition: The .results of the independent design review shall be incorporated prior to exceeding 5 percent power.
Status: Complete 5.1.14 Condition: a) Four radiation monitoring panels require qualification prior to exceeding 5 percent power,'and b) prior to use, the incore storage racks shall be qualified.
Status: a) The four radiation monitoring panels have been environmentally qualified, b) the invessel storage racks have been administrative 1y precluded from use.
5.1.15 Condition: The plant shall have on shif t advisors as -
required - by Attachment 2 of the license.
Status: The plant currently has sufficient numbers of qualified on shift advisors to satisfy this l condition.
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5.1.16 Condition: The ECCS peformance shall be . reanalyzed for the second cycle and beyond, utilizing models that account for burnup gas pressure and local oxidation and which are approved by the NRC.
Status: This condition is currently under engineering evaluation.
5.1.17 Condition:' The licensee shall implement the response to Generic Letter 83-28 on schedule.
Status: Implementation of the provisions stipulated in SNRC-1013 and SNRC-1116 are proceeding in accordance with the schedule.
-5.2 The current status of all license conditions is in compliance with the provision of the license and satisfactory with res pect to the performance and completion of low power testing.
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