IR 05000354/1986058
| ML20212J230 | |
| Person / Time | |
|---|---|
| Site: | Hope Creek  |
| Issue date: | 01/13/1987 |
| From: | Petrone C, Wink L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20212J184 | List: |
| References | |
| 50-354-86-58, NUDOCS 8701280111 | |
| Download: ML20212J230 (16) | |
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U.S. NUCLEAR REGULATORY COMMISSION
REGION I
Report No.
50-354/86-58 Docket No.
50-354 License No.
NPF-57 Licensee: Public Service Electric and Gas Company 80 Park Plaza Newark, New Jersey 07101 Facility Name: Hope Creek Generating Station, Unit 1 Inspection At: Hancocks Bridge, New Jersey Inspection Conducted:
December 1-12, 1986 A
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Inspectors:
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E. Ji Wink, Reactor Engineer
/ ddte Approved by:
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,/n !f 7 C. Petr6ne, Chief 7' ddte Test Programs Section, OB, DRS Inspection Summary:
Inspection of December 1-12, 1986 (Inspection Report No.
50-354/86-58)
Areas Inspected:
Routine, unannounced inspection of the overall power ascension program including; test results evaluation and test witnessing, independent measurements and verifications, and QA/QC interfaces.
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Results: No violations were identified.
NOTE:
For acronyms not defined, refer to NUREG-0544, " Handbook of Acronyms and Initialisms."
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DETAILS 1.0 Persons C ntacted Public Service Electric and Gas Company (PSE&G)
- G. Chew, Power Ascension Results Coordinator P. Dempsy, Shift Test Coordinator
- M. Farschon, Power Ascension Manager B. Forward, Power Ascension Administrative Coordinator A. Giardino, Manager-Station Quality Assurance (QA)
R. Griffith, Sr., Principal Engineer - QA
- P. Krishna, Assistant to the General Manager-Hope Creek Operations (HCO)
D. Moon, Shift Test Coordinator
- J. Nichols, Technical Manager, HC0 W. Schell, Power Ascension Technical Director E. Skeehan, General Electric Operation Manager M. Trum, Senior Nuclear Shift Supervisor
- M. LaVecchia, Principal Engineer-QA U.S. Nuclear Regulatory Commission D. Allsopp, Resident Inspector
- R. Borchardt, Senior Resident Inspector
- Denotes those present at the exit meeting on December 12, 1986
The inspector also contacted other members of the licensee's staff including senior nuclear shift supervisors, test engineers and members of the technical staff.
2.0 Licensee Action on Previous Inspection Findings (Closed) Unresolved Item (354/86-55-01) Adequacy of Test Condition 4 (natural circulation) testing. The inspector reviewed the licensee's safety evaluation titled " Safety and Environmental Evaluation TC-4 Test Window Expansion" written to support the FSAR change notice (LP-75) to expand the required plant conditions for natural circulation testing from the 95% - 100% rod lines to the 80% - 100% rod lines. The inspector concluded that, based upon avoiding unnecessary challenges to safety systems, the safety evaluation provided sufficient justification for expanding the natural circulation test window and satisfactory demon-strated that the intent of natural circulation testing (Regulatory Guide 1.68, Revision 2 - Appendix A, Section 5) had been met. On December 8, 1986 the inspector attended the Station Operations Review Committee (SORC) meeting (86-317) at which the safety evaluation was reviewed and approved.
The inspector had no further concerns in this are.
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3.0 Power Ascension Test Program (PATP)
3.1 References Regulatory Guide 1.68, Revision 2, August 1978, " Initial Test Programs for Water-Cooled Nuclear Power Plants"
ANSI N18.7-1976, " Administrative Controls and Quality Assurance for the Operational Phase of Nuclear Power Plants" Hope Creek Generating Station (HCGS) Technical Specifications, Revision 1, July 25, 1986
HCGS Final Safety Analysis Report (FSAR), Chapter 14, " Initial Tests Program"
HCGS Safety Evaluation Report (SER), Chapter 14, " Initial Test Program" Station Administrative Procedure, SA-AP.ZZ-036, Revision 3,
" Phase III Startup Test Program"
Specification NEB 0 23A4137, Revision 0, " Hope Creek Startup Test Specification" HCGS Power Ascension Test Matrix, Revision 8 3.2 Overall Power Ascension Test Program The inspector held discussion with various members of the PATP staff to assess the overall status of the test program and the test results review. All test results for Test Condition 3, 4 and 5 have been formally accepted by licensee management. Testing activities were continuing in Test Condition 6.
During the inspection period the licensee completed all maj'or transient testing and preparations were underway to begin the commercial warranty demonstration run.
On December 12, 1986, the inspector attended a SORC meeting (86-321)
to observe management oversight of the power ascension test program.
During the meeting the SORC reviewed and recommended approval of revision to procedures, resolutions of and subsequent actions taken to close identified results deficiencies and test results. A pro-posed resolution to one results deficiency (RDF #174) was rejected due to a lack of adequate detail concerning the subsequent actions to be taken.
Findings No unacceptable conditions were identifie.
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3.3 Power Ascension Test Witnessing Scope The inspector witnessed the performance of the power ascension tests listed in Attachment A and discussed below. The performance of these tests were witnessed to verify the attributes previously defined in Inspection Report 50-354/86-35. The titles of the test and the dates on which the individual tests were performed are indicated on Attachment A.
Discussion TE-SU.AE-233. This test was performed at a power level of 97.4% of rated to verify the feedwater system's response to the trip of a single feedwater pump and the reactor recirculation system's response if the intermediate runback setpoint (level 4: + 30 inches narrow range) is reached. The inspector witnessed the briefing of the control room operators by the test engineers.
Expected plant response was discussed and contingent actions outlined for possible abnormal response. At 0855 the "A" reactor feedwater pump turbine was tripped, reactor water level decreased approximately 5 inches from the initial level of + 35 inches narrow range and an inter-mediate runback of the reactor recirculation pumps occurred as expected and reduced reactor power to approximately 70% of rated.
No operator actions were required and all systems operated as designed. The test acceptance criterion for adequate scram avoidance margin was easily met with a measured margin of 16.9 inches to the low water level scram (acceptance criterion > 3 inches).
TE-SU.AB-252.
The purpose of this test was to determine the transient response of the reactor to the simultaneous full closure of all Main Steam Isolation Valves (MSIVs) and to compare the response to analytical predications contained in the Hope Creek Transient Safety Analysis Design Report (TSADR). The inspector witnessed the test preparations and briefing of the control room operators. The briefing included a discussion of the expected plant response, limitations on operator actions to allow verification of automatic system functions and contingent actions in the event of abnormal plant behavior.
Initial plant conditions were established at 99.5% of rated power with reactor pressure at 1005 psig and level at +35 inches narrow range.
At 1025 a full MSIV closure was initiated by simulating a low pressure condition in the main steam lines. As expected a reactor scram occurred immediately from limit switches on the MSIVs. The reactor scram resulted in an initial decease in both reactor prersure and level (due to void collapse).
Level decreased to the Level 2 setpoint (-38 inches wide range:
123 inches above the top of the fuel), the reactor recirculation pumps automatically tripped and RCIC and HPCI automatically initiated. When the MSIVs fully closed reactor pressure began to increase and at 1047 psig the "H" SRV lifted, as designed, in its lo-lo setpoint mode. HPCI reached rated
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flow and recovered reactor water level but it was noted by the control room operators that RCIC had failed to inject to the vessel.
Plant conditions quickly stabilized with reactor pressure controlled between 905 and 1017 psig by the cycling of the "H" SRV and water level controlled by manual operation of RCIC.
The failure of RCIC to automatically injected into the vessel was documented as a level 2 acceptance criterion failure (RDF #189).
Investigation revealed that the failure resulted from failed contacts in a relay used in the initial opening sequence for the steam admission valve (F045). This valve is initially opened approximately
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10% to prevent a turbine overspeed and then stroked full open after a time delay to allow control oil pressure to increase sufficiently to adequately control turbine speed. The failed contacts prevented the valve from stroking full open after the time delay. When the operator initially noted the failure of RCIC to inject to the vessel and the steam admission valve in mid position, he was able to take manual control of the valve and establish RCIC flow to the vessel.
Following repairs, the RCIC system was satisfactorily retested.
During the test the inspector observed and evaluated overall shift crew performance. The actions of both test and operations personnel were judged to be excellent. All required actions during the test and recovery were carried out in an expeditious and professional manner.
Following the test the inspector reviewed the data obtained and verified that all level 1 acceptance criteria were satisfied.
This test was also witnessed by the Resident and Senior Resident Inspectors. Additional details may be found in Inspection Report 50-354/86-56.
TE-SU.CH-273.
The purpose of this test was to determine the transient response of the reactor and its control systems to a full power generator load rejection and to compare the response to analytical predications contained in the Hope Creek Transient Safety Analysis Design Report (TSADR).
The inspector witnessed the test preparations and briefing of the control room operators. The briefing covered expected plant response, limitations on operator actions to allow verifications of automatic actions and contingencies in the event of abnormal plant response.
Initial plant conditions were established at 97.1% of rated power with reactor pressure at 1001 psig and level at +34 inches narrow range.
A generator load rejection was initiated at 1110 by simultaneously opening the generator output breakers BS6-5 and BS2-6. As expected, the reactor scrammed and the recirculation pumps tripped due to the fast closure of the main turbine control valves. The bypass valves fully opened and reactor pressure increase to 1080 psig causing the opening of the "H" and "P" SRVs in their lo-lo set mode. The Sitial pressurization transient caused a " ringing" response in reactor water level indication similiar to that experienced during some previous
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testing.
Indicated water level rapidly varied from greater than level 8 (+54 inches wide range) to less than Level 2 (-38 inches wide range).
These wide swings in indicated level caused trips of the main turbine and all feedwater pump turbines and the initiation of HPCI and RCIC.
Plant conditions quickly stabilized with reactor water level at -30 inches wide range, controlled by RCIC, and reactor pressure controlled by the turbine bypass valves.
The inspector observed and evaluated overall shift crew performance during the conduct of the test and subsequent recovery actions. The overall performance of test and operations personnel was judged to be excellent. All required actions were carried out in an expeditious and professional manner. The test was also witnessed by the Senior Resident Inspector. Additional details may be found in Inspection Report 50-354/86-56.
Following the test, the inspector reviewed the licensee's evaluation of the test data.
Four failures to meet acceptance criteria were noted. A Level 1 acceptance criteria failure (RDF #199) occurred when the reactor recirculation pump drive flow coastdown exceeded the design time constant of 4.5 seconds for the time period -from.25 seconds to 1.5 seconds after the pumps were tripped.
This failure caused the licensee to declare the end-of-cycle vecirculation pump trip (EOC-RPT) function inoperable. Based on preliminary data from a previous test, the licensee had prepared and submitted a request for a technical specification amendment which would allow operations with an inoperable EOC-RPT function by imposing potential restrictions on the operating limit minimum critical power ratio (MCPR).
Due to this acceptance criteria failure the licensee requested expedited consideration of this technical specification amendment. The amend-ment was granted on December 9, 1986.
The licensee issued a level 2 results deficiency (RDF #200) on maximum main turbine overspeed following the load rejection. While the actual measured overspeed (1900 RPM) was within the acceptance criterion limit (1967.4 RPM-109.3% of rated turbine speed) the validity of the results was questioned due to a main turbine trip generated from a high reactor water level (Level 8) signal as a result of the " ringing" of the level instrumentation.
An engineering evaluation will be performed to determine whether the main turbine trip (stop valve clesure) affected the maximum measured turbine overspeed.
A result deficiency (RDF #201) was issued due to the failure of two level 2 acceptance criteria resulting from level instrumentation
" ringing". The acceptance criteria required that the feedwater control system avoid a loss of feedwater flow due to a high water level (Level 8) trip and that a low water level (Level 2) initiation of HPCI and RCIC not occur. The " ringing" phenomenon caused both these events to occur. The licensee has made plans to investigate the reason for the " ringing" phenomenon and plans to take appropriate corrective actions following isolation of the source of the proble.
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Following the completion of these actions the NRC will review their effectiveness in eliminating this phenomenon.
Since the " ringing" of the reactor water level instrument lines presents the possibility of unnecessary safety system challenges, and since the phenomenon may not be bounded by the plant's transient / accident analysis, the adequacy of the transient response of the reactor water level instrument lines will remain unresolved (354/86-58-01) pending completion of licensee actions and subsequent NRC review.
TE-SU.BB-301. This test was performed to verify the plant response to the trip of a single Reactor Recirculation pump and subsequent restart of the pump.
Initial conditions were established at 98.6%
of rated power and 98% of rated core flow.
Initial reactor water level was set a +32 inches natrow range to provided additional margin to the high reactor water level trip setpoint.
At 1400 the "A" Reactor Recirculation pump was manually tripped. The overall plant response was as expected. During the transient reactor water level swelled approximately 7 inches and then return to the nominal setpoint of +32 inches.
Reactor power decreased to approximately 70*. of rated and total core flow indicated approximately 50%.
Prior to restarting the pump, the "B" recirculation loop drive flow was reduced to less than 50% as required by technical specifications.
This reduced reactor power to approximately 59%.
The test engineer calculated the margin to the APRM heat flux scram and determined that it was less than the 5% desired. To avoid the possibility of a scram on pump restart, the decision was made to reduce power to 55% by inserting control rods prior to restart of the pump.
At 1537 the "A" reactor recirculation pump was successfully restarted. At 1552 both pumps were verified to be in operation with match speeds.- Reactor power was determined to be 60% of rated and core flow was 55%. All test acceptance criteria were met.
Findings No unacceptable conditions were noted. An unresolved item involving adequacy of the transient response of the reactor water level instrumentation was identified.
3.4 Power Ascension Test Results Evaluation Scope The power ascension test results listed in Attachment B were evaluated for the attributes identified in Inspection Report 50-354/86-24. A summary of significant test results and identified test results deficiencies is provided in the discussion below. The performance dates of the tests and full test titles are indicated on Attachment.
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Discussion TE-SU.ZZ-019. The are no acceptance criteria associated with this test.
It was performed to measure the quality of the steam exiting the reactor pressure vessel and assess the overall characteristics of the RWCL system. The test was terminated prematurely by a reactor scram on November 14, 1986 (see Inspection Report 354/86-55 for details) but sufficient data had been obtained to satisfy the test objectives.
Reactor exit steam quality was determined to be
> 99.997%.
The RWCU half-time (period of time to remove one-half of the reactor water's ionic impurities) was measured to be 8.3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> and it was determined that the system could be out of service for 35 hours4.050926e-4 days <br />0.00972 hours <br />5.787037e-5 weeks <br />1.33175e-5 months <br /> before limits on reactor water conductivity were exceeded.
TE-SU.SE-122. This test was performed twice: Test Condition 5 (65%
power, 55% core flow) and Test Condition 6 (97.7% power, 98.4% core flow). All APRMs were conservatively calibrated at both test conditions and all acceptance criteria were satisfied.
TE-SU.BJ-153. This test (Run #2) was performed following turbine control loop re-tuning and hydraulic system adjustments to resolve previously identified deficiencies. All acceptance criteria were satisfied with cold start time to rated flow of 23.8 seconds (acceptance criterion 5 27 seconds).
TE-SU.BJ-154.
This test was performed twice in Test Condition 6.
The first performance obtained baseline surveillance data at the lower end of the HPCI operating range (200 psig). All acceptance criteria were satisfied with a time to rated flow of 11.7 seconds (acceptance criterion 1 27 seconds).
The second performance demonstrated the ability to run HPCI for extended times. MPCI was run for 87 minutes (78 minutes at rated flow). The test was termin-ated due to technical specification limits on suppression pool temperature (105*F) during tests but all acceptance criteria were satisfied.
TE-SU.ZZ-173. This test was performed at 93% power with final feedwater temperature of 416.5 F to measure the thermal expansion of the NSSS piping. All level 1 acceptance criteria were satisfied.
A level 2 results deficiency (RDF #165) was identified for 6 points on the reactor recirculation piping and 7 points on the main steam piping which exceeded predicted displacements. The results were transmitted to General Electric for engineering evaluation.
Based on calculated pipe stress, General Elect.ic engineering recommended that the test results be accepted "as-fs".
TE-SU.BB-191.
This verification of core thermal hydraulic limits was performed at 97.7% power and 98.2% core flow. All acceptance criteria were satisfied and the results are summarized below:
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- Parameter Measured Value Limit LHGR(KW/FT)
11.53
$ 13.4 CPR 1.465
> 1.22 APLHGR (KW/FT)
9.27 510.86 TE-SU.BB-221. This test was performed three times: Test Condition 4 (39.3?; power, 38.2% core flow), Test Condition 5 (61's power, 49.4*;
core flow) and Test Condition 6 (97.0% power, 95% core flow). All acceptance criteria were satisfied at all test conditions.
TE-SU.BB-222. This test was performed at 72% power during Test Condition 3 to verify the response and stability of the pressure regulator when both control valves and bypass valves are free to respond simultaneously to a change in reactor pressure. All acceptance criteria were satisfied.
TE-SU.AE-231.
This test was performed three times:
Test Condition 4 (41.1?; power, 38.5% core flow, "B" and "C" feedwater pumps in service), Test Condition 5, (64.3's power, 56's core flow, all feed-water pumps in service) and Test Condition 6 (97.6'4 power, 95% core flow, all feedwater pumps in service). All acceptance criteria were satisfied at all test conditions.
TE-SU.AE-232. This test was performed to verify the reactor response to the limiting loss of feedwater heating event against analytical predictions made in the Hope Creek Transient Safety Analysis Design Report (TSADR).
The test was initiated from 83.8% power, with initial feedwater temperature of 408*F, by opening a feedwater heater bypass valve (1AD-HV-1623). With this valve open a portion of the total feedwater flow bypasses the 3rd, 4th and 5th stage feedwater heaters. As a result, colder feedwater enters the reactor, causing a power increase.
The measured decrease in final feedwater temper-ature was less than 22 F (acceptance criterion 1100 F) and resulted in less than a 3% increase in reactor power.
The actual increase in heat flux (103.22% of initial) agreed well with the predicted increase (103.5*4ofinitial).
The post test minimum critical power ratio was 1.614 (limit 3 1.25). All acceptance criteria were satisfied.
TE-SU.CH-242. This test was performed to determine the maximum power level at which surveillance tests of the main turbine control valves can be performed with adequate margins to all scram setpoints. A previous performance of this test at 97% power resulted in a reactor scram (see Inspection Report 50-354/86-55 for details).
This test was successfully performed at 93.2% power and the limiting scram margin occurred for neutron flux with a measure value of 8.0%
(acceptance criterion 3 7.5%). Based on the results of this test a recommendation was made to perform periodic surveillt.nce testing of the main turbine control valves at 5 92.5% powe.
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TE-SU.SV-281. This test sas a continuation of the Remote Shutdown test performed in Test Condition.' and demen.strated the ability to cool the reactor from hot standby to cold sh'utdown using.the Shut-down Cooling Mode of RHR.
The test was initiated from 70'psig and demonstrated a cooldown of 56 F.in 39 minutes. All acceptance criteria were satisfied.
TE-SU.BB-291. Thistest.Asperformedat68.5*4powerand90*4 core flow in Test Condition 3 to demonstrate the reactor response to recirculation flow control maneuvers and adequate scram avoidance margins. All acceptance criteria were satisfied.
TE-SU.BB-292. This test was performed twice: Test Condition 3 (71.3P. power, 96?; core flow) and Test Condition 6 (95.2*4 power, 95*;
Core Flow) to demonstrate the reactor response to recirculation flow control maneuvers in the Master Manual Mode and adequate scram avoidance margins. All acceptance criteria were satisfied at both test conditions.
TE-SU.AB-331. All acceptance criteria for main steam piping steady state vibration were satisffed at 98.5*e power.
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TE-SU.BB-332. All acceptance criteria for recirculation piping steady state vibration were satisified at 98.2% power.
TE-SU.BB-342. All acceptance criteria for recirculation piping dynamic response were satisfied during the reactor recirculation pump restarts at the completion of Test Condition 4.
TE-SU.BB-351. The acceptance criterion was satisfied. The jet pump flow instrumentation was adjusted so that the total flow recorder
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will indicated correctly at rated core flow.
TE-SU.GT-721.
This test was performed at 99.2% power to verify that average drywell air temperature and certain local air temperatures are within limits. A level 2 results deficiency was identified for six points in the drywell where the temperature exceeded 150 F, these same points had previously been identified during the performance of i
this test in Test Condition 3.
A second Level 2 results deficiency occurred when the madmum steam tunnel temperature exceed 120 F (measured 120.1 F).
This failure was attributed to a small RWCU
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flange leak in the steam tunnel. All other acceptance criteria were satisfied.
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TE-SU.GT-724.
The acceptance criterion for maximum drywell shield l
wall concrete temperature was satisfied at 97.5% power.
TE-SE.EG-751. This test was performed to resolved RDF #130 for the
"A" Loop of SACS. The deficiency involved failure to meet the level 2 acceptance criterion for heat remo' val capacity.
The retest wa's l
successful and the heat removal capacity of the "A" loop of SACS was meaurrJ to be 206.8 MBtu/hr (acceptance criterion > 201.4 MBtu/hr).
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In addition to the test results discussed above the inspector reviewed all open results deficiencies (total of 34 RDFs). The
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inspector determined that.these remaining results deficiencies were being properly addressed.
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Findings:
No unacceptable condition were identified.
4.0 Independent Measurements and Verifications The inspector performed multiple independent measurements and verifica-tions including margins to scram during feedwater and recirculation pump
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trips, proper performance of HPCI and RCIC upon automatic initiation and j
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appropriate plant conditions prior to initiating major transient testing
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during the witnessing of power ascension testing (paragraph 3.3).
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addition, during the evaluation of test results (paragraph 3.4), the
inspector independently verified the licensee's determination of conform-ance to acceptance criteria for HPCI system response times, core thermal hydraulic limits, feedwater and pressure regulator stability and decay ratios, reactor response to a loss of feedwater heating and scram avoid-
ance margins during recirculation flow maneuvers.
In all cases the inspector's measurements and verifications agreed with those of the licensee.
No unacceptable conditions were noted.
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5.0 QA/QC Interface with the Power Ascension Program During the course of witnessing power ascension tests, the inspector observed QA engineers performing surveillances of test activities. The Manager-Station QA informed the inspector that a Quality Assurance Request (QAR) had been issued for failure of test engineers to notify QA prior to performing power ascension test TE-SU.BB-301, Recirculation System Single Pump Trip. This tast had been designated by QA as a mandatory witness test. This represents the second instance of power ascension engineers failing to properly notify QA of the performance of tests.
The inspector also verified that the results of power ascension tests had been review by QA engineers.
No unacceptable conditions were noted.
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6.0 Unresolved Items
Unresolved items are matters about which more information is required in order to determine whether they are acceptable, an item of noncompliance or.a deviation.
Unresolved items disclosed during the inspection are discussed in paragraph 3.3.
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7.0 Exit Interview At the conclusion of the site inspection on December 12, 1986, an exit meeting was conducted with the licensee's senior site representative (denoted in paragraph 1.0)
At no time during the inspection was written materials provided to the licensee by the inspector.
Based on the NRC Region I review of this report and discussions held with licensee representatives during the inspection, it was determined that this report does not contain informa-tion subject to 10 CFR 2.790 restriction.-
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ATTACHMENT A i
POWER ASCENSION TEST WITNESSED TE-SU.AE-233 Feedwater System Feedwater Pump ~ Trip Test, performed December 2, 1986 TE-SU.AB-252 Main Steam Isolation Valve Full Isolation' Test, performed December 3, 1986
'TE-SU.CH-273 Full Power Generator Load Rejection Test, perfomed December 6,1986 TE-SU.BB-301 Recirculation System Single Pump Trip Test, performed December 2,1986
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ATTACHMENi B POWER A3 TENSION TEST RESULTS EVALUATED TEST CONDITION THREE
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TE-SU.BJ-153 HPCI Reactor Pressure Vessel Injection - Cold Quick Start, Revision 6, completed November 6, 1986, results accepted November 24, 1986 TE-SU.BB-222 Pressure Regulator Test - Bypass Valves Incipent, Revision 4, completed October 28, 1986, results accepted November 21, 1986 TE-SU.BB-291 Recirculation Flow Control System Loop Manual Testing, Revision 3, completed November 2, 1986, results accepted December 4, 1986 TE-SU.BB-292 Recirculation Flow Control System Master Manual Mode Test, Revision 3, completed November 2, 1986, results accepted December 3, 1986 TE-SU.BB-351 Recirculation System Flow Calibration Verification, Revision 6, completed October 30, 1986, results accepted November 21, 1986 TEST CONDITION FOUR TE-SU.BB-221 Pressure Regulator Test-Control Valves Controlling, Revision 9, completed November 7, 1986, results accepted December 4, 1986 TE-SU.AE-231 Feedwater System Level Setpoint Changes, Revision 5, completed November 7, 1986, results accepted November 25, 1986 TE-SU.BB-342 Recirculation Piping Dynamic Response, Revision 2, completed November 8, 1986, results accepted November 21, 1986 TEST CONDITION FIVE TE-SU.SE-122 APRM Calibration at Power, Revision 4, completed November 7, 1986, results accepted November 28, 1986 TE-SU.BB-221 Pressure Regulator Test-Control Valves Controlling, Revision 9, completed November 7, 1986, results accepted November 20, 1986
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TE-SU.AE-231 Feedwater System level Setpoint Changes, Revision 5, completed November 8,1986, results accepted November 25, 1986 TEST CONDITION SIX TE-SU.ZZ-019 Chemical and Radiochemical Reactor Water No-Cleanup Test, Revision 2, completed November 14, 1986, results not yet accepted.
TE-SU.SE-122 APRM Calibration at Power, Revision 4, completed November 13, 1986, results accepted November 28, 1986 TE-SU.BJ-154 HPCI Surveillance Test (200 psig) Demonstration, Revision 8, completed November 29, 1986 results not yet accepted TE-SU.BJ-154 HPCI Surveillance Test (Endurance Run) Demonstration, Revision 9, completed November 29, 1986, results not yet accepted i
l TE-SU.ZZ-173 NSSS Systems Piping Thermal Expansion Sensor Data, Revision 2, completed November 9, 1986, results accepted December 3, 1986 TE-SU.BB-191 Core Performance, Revision 3, completed November 13, 1986,
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results accepted November 28, 1986 TE-SU.BB-221 Pressure Regulator Test-Control Valves Controlling, Revision 9, completed November 11, 1986, results accepted December 4, 1986 TE-SU.AE-231 Feedwater System Level Setpoint Changes, Revision 5, completed November 11, 1986, results accepted November 25, 1986 TE-SU.AE-232 Feedwater System Loss of Feedwater Heating Test, Revision 1, completed December 3, 1986, results not yet accepted TE-SU.CH-242 Turbine Control Valve Surveillance Test, Revision 4, completed December 2, 1986, results not yet accepted TE-SU.SV-281 Shutdown from Outside the Control Room-Cold Shutdown Demonstration, Revision 3, completed November 15, 1986, results accepted December 6, 1986 TE-SU.BB-292 Recirculation Flow Control System Master Manual Mode Test, Revision 3, completed November 12, 1986, results not yet accepted
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TE-SU.AB-331 NSSS Main Steam Piping Steady State Vibration, Revision 3, completed November 11, 1986, results accepted
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December 3, 1986 TE-SU.AB-332 Recirculation Piping Steady State Vibration, Revision 2, completed November 11, 1986, results accepted December 3, 1986 TE-SU.GT-721 Drywell and Steam Tunnel Cooling System Normal Operation Performance Test, Revision 5', completed November 13, 1986, results not yet accepted TE-SU.GT-724 Containment Penetration Cooling Normal Operation Performance Test, Revision 3, completed November.13, 1986, results not yet accepted TE-SU.EG-751 Safety and Auxiliary Cooling System Operational Performance Test, Revision 6, completed November 11, 1986, results accepted November 25, 1986 i
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