IR 05000445/1990026
| ML20059E238 | |
| Person / Time | |
|---|---|
| Site: | Comanche Peak  |
| Issue date: | 08/28/1990 |
| From: | Chamberlain D NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20059E232 | List: |
| References | |
| 50-445-90-26, 50-446-90-26, NUDOCS 9009100102 | |
| Download: ML20059E238 (18) | |
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APPENDIX U.S. NUCLEAR REGULATORY COMMISSION Region IV NRC Inspection Report:
50-445/90-26 50-446/90-26
j Dockets: 50-445 Unit 1 Operating License:
NPF-87 50-446 Unit 2 Construction Permit: CPPR-127 Expires: August 1, 1992 L,:ensee: TV Electric Skyway Tower I
400 North Olive Street Lock Box 81 Dallas, Texas 75201 Facility Name: ' Comanche Peak Steam Electric Station (CPSES),
Units 1 and 2
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Inspection At: Glen Rose, Texas Inspection Conducted: 1 ly 5 through August 7, 1990-Inspectors:
W. D. Johnson, Senior Resident Inspector R. M. Latta, Senior Resident Inspector S. D. Bitter, Resident Inspector i
A. T. Howell, Resident Inspector
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M. F. Runyan, Resident Inspector D. N. Graves, Resident Inspector M. E. Murphy, Reactor Inspector, Division of Reactor Safety (DRS)
W. M. McNeill, Reactor Inspector, DRS D. L. Garrison, Reactor Inspector, DRS C. E. Johnson, Acting Project Engineer, Division of Reactor Projects Reviewed by:
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9d D. D.VChamberlain, Chie", Project Section B Date Division of Reactor Drojects
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~2-In cection Summary l
Inspection Conducted July 5 through August 7, 1990 LReport 50-445/90-26;
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l 50-446/90-26)
L Areas Inspected:
Unannounced resident safety inspection of plant status, operational safety verification, onsite followup of events, maintenance
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j observations, surveillance observations, followup of' licensee event reports, startup test witnessing, quality assurance for the startup program, licensee
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l self-assessment capability, licensee quality assurance program implementation, followup on unresolved items, followup on construction deficiency reports, and l
Unit 2 activities.
Results:
During this period, the licensee completed its startup and power ascension test program, which was judged to have been well planned and executed.
Two safety injection events occurred on July 26 and 30,1990, while Unit I was g
operating in hot standby. The July 26, 1990, safety injection indicated continuing problems with the implementation of danger-tag clearances.
Problen..
with clearances and the work control process were previously identified by the licensee and NRC.
The licensee is continuing-to implement corrective actions in these areas, and the inspectors are continuing to monitor licensee actions.
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l The July 30, 1990, safety injectica event was the subject of an NRC special team I
inspection. The results of this inspection were documented in NRC Inspection Report 50-445/90-34; 50-446/90-34.'
i Unit 2 major work scope activities continued with engineering efforts for pipe stress and supaarts, plant systems, and civil / structural suspended systems in progress.
During this inspection, two inspector fol'.br;p items were identified.
These included inspection followup of licensee action to provide controls for ladders staged for access to valves required to be operated in contingency actions of the emergency response guidelines (paragraph 3) and followup of licensee's corrective actions associated with an emergency diesel generator fuel injection pump failure (paragraph 4.a).
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i DETAILS 1.
. Persons Contacted
- J. L. Barker, Manager, Independent Safety Engineering Group (ISEG)
- M. R. Blevins, Manager of Nuclear Operations Support
- H. D. Bruner, Senior Vice President
- J. H. Buck, Independent Advisory Group (IAG)
- W. J. Cahill, Executive Vice President, Nuclear
- C. B. Corbin, Licensing. Engir.eer
- W. G. Guldemond, Manager of Si-) Licensing
- J. C. Hicks, Unit 2 Licensing l'enager
-*C. B. Hogg, Chief Engineer
- A. Husain, Director, Reactor Engineering
- J. J. Kelley, Plant Manager
- D. M. McAfee, Manager, Quality Assera. ice (QA)
- J. F. McMahon, Manager, Nuclear T aining
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- J. W. Muffett, Manager of Project Engineering
- W. Nyer, IAG
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- E. F. Ottney, Project Manager, Citizens Association for Sound Energy (CASE).
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- S. S. Palmer, Stipulation Manager
- F. S. Poppe11, Licensing Engineer
- W. O. Porter, Operations Support Engineering i
- C. W. Rau, Unit 2 Project Manager-
- D. M. Reynerson, Director of Construction l
- M. J. Riggs, Plant Evaluation Manager, Operations
- A. B. Scott, Vice President, Nuclear Operations-
- J. C. Smith, Plant Operations Staff
- P. B. Stevens, Manager of Operations Support Engineering
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- C, L. Terry, Director of Quality' Assurance
- 0. W. Thero, CASE l
- T. G. Tyler, Director,. Management Services
- R. D. Walker, Manager of Nuclear Licensing.
- J. R. Waters, Site Licensing
- D. A. West, Project Engineer l
- Present at the exit interview.
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In addition to the above personnel, the. inspectors held discussions with various operations, engineering, technical support, maintenance, and i
administrative members of the licensee's staff.
.2.
Plant Status - Unit 1 (71707)
The unit was at the 75 percent testing plateau at the start of this inspection period. On July 7, 1990, a 50 percent load rejection. test was conducted.
Following this test, power was raised to 75 percent where a licensee self-assessment was conducted prior'to raising power to 100 percent on July 13, 1990.
On July 16,.1990, power was reduced to 75 percent in order to repair a condenser tube leak.
On July 17, 1990;
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power was at 100 percent again.
The 100-hour warranty run was completed on July 23, 1990.
The 50 percent load rejection test from 100 percent power was conducted on July 24, 1990.
On July 26, 1990, the trip test from :100 percent power was conducted.
Later that day there was a flux doubling actuation'and a safety injection actuation. An additional safety injection actuation in Mode 3 occurred on July 30, 1990.
Following this event, the unit was cooled down to Mode 5, reaching this mode on August 1,
'1990. On August 2, 1990, the NRC conducted a technical meeting on site which was open to public observation to discuss the safety injection events and the results of the 100 percent plateau testing. Mode 4 was entered on August 6,1990, and a reactor startup was conducted on August 7, 1990.
3.
Operational Safety Verification _.(71707)
The objectives of.this inspection.were to ensure that this facility was being operated safely and.in conformance with regulatory requirements, to ensure that the licensee's management controls were effectively discharging the licensee's responsibilities for continued safe operation, to assure that selected activities of the licensee's radiological protection programs are implemented in conformance with plant policies and procedures and in compliance with regulatory requirements, and to inspect the licensee's compliance with the approved physical security plan.
The inspectors conducted centrol room observations and plant inspection tours and reviewed logs and licensee-documentation of equipment problems.
Through in plant observations and attendance at the licensee's plan-of-the-day meetings, the inspectors maintained cognizance over plant status and Technical Specifications (TS) action statements in effect.
During plant tours, the inspectors fcund the plant material condition and housekeeping to be generally good.
Contamination control measures appeared to be effective.
In the turbine building there were a number of steam leaks and general appearance was degrading.
Several steam leaks were scheduled for repair during the outage at the end of the inspection period.
The inspector observed that ladders staged for access to valve's. required to be operated in contingency actions of the emergency response guidelines have been missing on two occasions.
These were promptly replaced by tne licensee upon notification. During discussions with licensee personnel, they stated an intention to establish better controls over these ladders, including a periodic check of their availability.
Establishment of these controls is designated as Inspector Followup' Item (IFI) 445/9026-01.
The inspectors concluded that the licensee was sensitive to operational safety and was operating the facility in accordance with regulatory requirements.
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Onsite Event Followup (93702)
a.
Fuel Injection Pump Failure
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On July 12, 1990, the Unit 1 Train A emergency diesel generator (EDG)
had a surveillance test aborted and was declared inoperable. This test. failure was followed up by both resident inspectors and two
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The engine was manufactured by DeLaval; it is a-turbocharged, V-16, Model RV, rated at 9717 horsepower.
The surveillance test was aborted because the temperature of one cylinder (No. 2 right) was very low, which indicated that this cylinder was not carrying an appropriate share of the engine load.
Examination end partial disassembly of the hardware for the No. 2 right cylinder "evealed that there had been a failure of five of nine bolts used to attaen the. fuel delivery valve to the injector assembly.
The licensee commenced a technical investigation of the cause of the
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failure with assistance from an engine maintenance ~ consultant.
Actions taken by the licensee during investigation of this event included a verification of adequate bolt torque for the fuel
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l injectors on both diesel generators.
Diesel fuel oil samples were taken and no problems with contaminants were found. The failed bolts were retained for a metallurgical analysis and the fuel injector pump was returned to the manufacturer for a more detailed
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failure analysis.
Although the cause of the failure was not positively established immediately, it was observed that-packing (an-0-ring) used in the injector assembly was badly eroded or deteriorated.
In a correctly assembled injector, the packing should not be subjected to high l
pressure.
The inspectors speculated that the disintegrated 0-ring-(or some other contaminant) could have caused the fuel-line or injector valve-to restrict fuel. flow. This could result in high pressure in-the injection pump potentially resulting in-the, observed failure of the five bolts. The-licensee replaced th_e failed injector and a surveillance run of.the diesel was satisfactorily completed. Completion of the licensee's technical investigation of this event will be followed to determine if.any further corrective actions are required, including review of any potential generic implications. The licensee's continuing investigation of this area will be tracked as IFI 445/9026-02.
b.
Charging Flow Diversion This area of inspection was to review the' inadvertent diversion of charging flow during the performance of a surveillance test. On July 26,1990, the licensee was performing Surveillance Test Procedure OPT-489A, " Train B Safeguards Slave Relay K603 Actuation
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l Test." The test was being performed in conjunction with a partial
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Operability," for the start of LtG No. 2.
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-6-The initial conditions for OPT-489A were established to specifically isolate the coolant charging pump high head injecti4. v41ve to
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preclude flow through the coolant charging pump high head injection
. Valve.1-88013 which is cycled open as part'of the surveillance test.
This isolation was accomplished by closing the coolant charging pump flow control valve downstream isolation Valve 1-84838.
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reactor coolant charging is then providad by the positive displacement pump through the normal charging path.
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The surveillance test was commenced at 12:54 a.m. on July-26, 1990, and proceeded satisfactorily to the point of commencing recovery.
In accordance with the procedure, the coolant charging pump high head injection Valve 1-8801B was opened. The unit supervicor, as test conductor, performed a review of' test data and checked on the status of the concurrent test, OPT-214A.
When the unit supervisor reentered Test OPT-489A, at approximately
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2 a.m., he inadvertently skipped two_ steps. One of these steps would have closed. Valve 1-8801B. A subsequent step opened Valve 1-8483B,
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providing a direct flow path from normal charging flor through the safety injection nozzles via Valve 1-8801B.
The reactor operator noted a charging flow reduction and immediately closod the flow.
control valve in manual.
Charging flow returned to normal. The procedure performan:e error was identified. The omitted steps were
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performed and the test recovery was resumed. The' surveillance test-was subsequently completed, satisfactorily.
The licensee ascribed the event to personnel error. The test
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I procedure was being reviewed for a possible revision to eliminate l.
running concurrent tests. The licensee was= assessing the need for a special report concerning thermal cycling of the' safety injection nozzles in ace.ordance with the TS requirements. A special.
back-leakage test was run within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> on-the check; valves-affected by this event.
c.
_ Inadvertent Safety Injection-on July 26, 1990 At 2:16.p.m. (CDT) on July 26, 1990, with Unit 1 in hot standby, an inadvertent safety injection (SI) occurred as a result of a main steam line low pressure actuation signal. All plant safety systems functioned as designed in response to the SI signal.
The. low
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pressure condition resulted from the inadvertent opening of two main steam isolation valves (MSIVs) when fuses associated with the control of the MSIVs were pulled.
The fuses were removed as part of a danger tag clearance (tag-out) that was being initiated for planned maintenance.
The inadvertent opening of the MSIVs resulted from the failure of the clearance to proparly sequence an essential step (isolation of the air supply of the hydraulic pump) prior to the removal of the fases, t
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Borated water from the refueling water stortge tank (RWST) was l
injected into the reactor coolant system (RCS) via the centrifugal L
charging pumps. The irijection was terminated after 19. minutes in L
.accordance with the. plant's emergency operating procedures.
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Pressurizer level increased from 25 to 87 percent in response to the l'
injection, estimated at 8000 gallons.
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The licensee declared a Notification of Unusua' C,ent (NOVE)'at 2:20 p.m.
The safety injection signal was reset at 2:32 p.m.
The NRC was notified via the emergency notification system in accordance with 10 CFR 50.72. All equipment was. returned to a normal lineup and the NOUE was terminated at 5:50 p.m.
A postemergency safety feature
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I actuation evaluation was performed in accordance with Operations
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Department Administrative Procedure 00A-108, " Post RPS/ESF Actuation-l-
Evaluation."
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As a result of the event, the licensee halted all work involving installation of clearances and established two task teams.
One team
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was tasked with determining the root cause of the failure of the clearance prccess to prevent the event, proposing corrective action j
for the. process, and evaluating the adequacy of clearances already installed or waiting to be installed. The other team was tasked with reviewing the-physical cause of the event,-plant and operator response to the event, and wnether it'was appropriate to remain in-hot standby.
The first team concluded 'that the root cause was an ~ inadequate review of the clearance, as a result of a lack of clarity in the clearance procedure, as to who shall perform the reviews'.
Station-Administrative Procedure STA-605,'" Clearance and Safety Tagging," was
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changed to more clearly define the review process for clearances.
All operators and work group planners.were trainea on.the new
. revision before being allowed.to perform clearance-related activitiet The review of installed or pending clearances was
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completed and, although some administrative problems were found and_
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corrected, the clearances were found to'be acceptable. As individuals completed training on the new revision, work requiring clearances was l-restarted.
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L Tha :9cond team concludad that the cause of the event was the
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sequence of removal of the fuses for the MSIV solenoids' prior to.
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closing the air supply valve that caused the valve to open. Operator l
response to the event was good.
The plant responded as expected with I
the exception that several monitor light boxes (MLBs), indicating
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l-load shedding of buses and actvation of components, :ppeared to malfunction. The equipment referenced by the MLBs functioned as required, but the MLBs did not reflect actual conditions.
The MSIVs.are hydraulically-nperated valves. One MSIV is located in l
each of four main steam lines.
When the MSIVs:are-in the open.
position, four Rockwell solenoid valves in the hydraulic bleed-off-L l
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-8-lines of each MSIV are
, with their associated solenoids deenergized. This permit..ydraulic fluid supplied from an air-operated hydraulic pump to maintain the valve actuator open
.against.the backpressure supplied from a. nitrogen-filled dome.
The air supply to the hydraulic pump is controlled by an ASCO solenoid valve which is deenergized in the open (pump operating)-position.
When the MSIVs are required to close, the Rockwell solenoids in the nydraulic. bleed-off lines are energized to open,; enabling the nitrogen pressure to force hydraulic fluid through the bleed-off lines to a reservoir while repositioning the valve actuator to the closed position. At the same time, the ASCO solenoid valve is-energized to close, isolating the air supply to the hydraulic pump-which ceases to operate.
The inspector interviewed licensee engineers and reviewed the following' plant drawings:
Drawing No.
-Sheet No.
Revision No.
l El-0039
CP-2'
CP-2 M1-2202
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02A CP-2 PD-153692
CP-2 These drawings are associated "ith the No. 1 main steam line, but are functionally identical to.the other three main steam lines. The inspector determined that all MSIV control systems functioned as designed during the event. The solenoid valves in-the two hydraulic bleed off lines are powered from Class ~1E' Train A.cnd Train B 125-volt:
DC power supplies, respectively. 'When the fuses for these circuits were. removed, the Rockwell' solenoids in both lines deenergized, causing the solenoid valves to close.
This isolated both hydraulic lines, blocking the vent path to the reservoir. Additionally, two parallel contacts opened in the non-1E 125-volt DC ASCO solenoid control circuit (one contact associated with Class 1E Tr:in A power, the other, Train B), deenergizing the ASCO solenoid, which opened the-air supply solenoid valve to the hydraulic pump.
In Main Steam Lines 2 and 4, the hydraulic pump operated as designed to open the corresponding MSIV.
MSIVs in Main Steam Lines 1 and 3 remained closed because the air supply to the ASCO solenoid valves in these lines had been manually isolated on a clearance associated with a -
separate maintenance item.
Steps to isolate the air supply on Main Steam Lines 2 and 4 were included in the subject clearance, but were incorrectly sequenced after the fuse removal steps.
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-9-The inspector's review centered on whether the NRC's previous acceptance of the MSIV control design should be teconsidered in light of this event. With respect to the acceptability of the MSIV design from a regulatory perspective, the only additional consideration resulting frcm this event was the understanding that the failure of two fuses (a Train A fuse and a Train B fuse) will cause a closed MSIV to open.
In the event of a main steam line break (MSLB)'outside containment, the failure of a MSIV to remain closed could permit a nonfaulted steam generator to backfeed through the break, resulting in an excessive cooldown and reactivity addition to the primary plant. Generally, the failure of two independent components (two separate fuses in this case) is not considered a. credible accident within the bounds of single-failure analysis.
However, the inspector
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questioned whether one fuse could blow and remain undetected for a lengthy period of time, after which a fuse on the alternate train could blow and cause-the MSIV to open. One blown fuse would cause one of the-two hydraulic bleed-off lines.to isolate, but would not-cause an MSIV to reposition.
The licensee stated that a blown fuse-on, Train A control power would be noted quickly due to the deenergization of indicating lights on the control room MSIV handswitch.
A blown fuse on Train B control power would not affect control room indications but would be discovered during a quarterly slave relay test performed on a safeguards test cabinet, which contains indicating lights that would reveal the discrepant condition.
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The inspector considered the quarterly frequency to be adequate-in that (1) no inherent failures have occurred to the 3-amp fuses in question and (2) the fuses are rated in excess of a 40 year qualified life.
Two other issues were discussed with licensee engineers. The inspector asked whether the MSIVs would close within 5 seconds as required by the FSAR.if the non-1E power supply to the ASC0 ' solenoid valve were lost (and the hydraulic pump continued to operate)~. The licensee provided documentation showing that, in a test, the MSIV closed within 5 seconds with the hydraulic pump running and one of the two hydraulic lines isolated. The inspector also questioned whether the controi circuitry for the ASCO solenoid could have bien designed to be electrically isolated from the hydraulic solenoid circuitry, which-would have prevented the MSIV from opening in the-July 26, 1990, event. The licensee stated that such a design would have been possible but not necessarily desirable from a complexity and reliability standpoint.
The licensee's position on the adequacy of the MSIV control system is documented'in Plant Incident Report (PIR) FX90-1966.
The licensee concluded that the design was adequatt. and that no mcdifications were required or desired. The inspector determined that this incident did not provide any reason to recommend reversal of the previous NRC acceptance of the MSIV control system design.
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Future inspection followup of the licensee's corrective actions will
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be~ conducted after the issuance of the licensee event report.(LER)_
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for this event, a
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Source Range-Flux Doublira
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At 10:36 a.m. (CDT) on July 26, 1990, an ESF actuation of the source range flux doubling circuit occurred.
The-reactor was in hot standby.
' f following completion of Startup Test ISU-284A, " Dynamic Response'to l
l Full lJad Rejection and Turbine Trip." Neutron level the. reactor
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was still decreasing-as indicated by the source range _sclear instrumentation.
Upon actuation, the charging pump suction shifted
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from the volume contrcl tank (VCT).to the RWST.
The flux doubling actuation circuit was blocked and the charging pump suction was
realigned to the VCT.
l The cause of the actuation signal was a decrease in the. indicated neutron level on source range Channel N32 followed by an increase 1.n I
indicated neutron level on the same channel.
Source range
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Channel N31 appeared to be unaffected.
Both channels were indicating decreasing counts and tracking. closely with each other.. Chan'nel N32 level then dropped sharply.below the N31 channel's indication, but continued to decrease at approximately the same rate as before, Af ter approximately 10 minutes, the N32 indication increased sharply i
l to approximately the same level as the N31 channel was indicating.
l This sudden increase in N32 level exceeded the flux-doubling setpoint.
l of less than 9 minutes and actuated.the flux doubling circuitry.
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Licensee response to this event was appropriate. This event will be
reviewed further following issuance of the associated LER.
5.
Monthly Maintenance Observation (62703)
l Station maintenance activities for the safety-related and nonsafety systems and components listed below were observed to ascertain that they.
were conducted in accordance with approved procedures, regulatory guides, and industry codes or standarr',, and in conformance with the TS.
Maintenance activities observed included:
Reassembly of Diesel Generator-Starting Air Compressor 1-04 (Work Order C90-4701),
011 heater replacement on Control Room Air Conditioning Unit-01 (Work Order C90-1582),
Replacement of the compressor on Control Room Air Conditioning Unit-02 (Work Order C90-44e.6),
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Troubleshooting and repair of a compressor leak on a control room air conditioning unit (Work Orders C90-1582 and C90-17500),
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Adjustment of N-16 Channel 3 (OPT-309),
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Inspection of d!esel generator starting air Compressor 1-01 (Work OrderC90-4511),and J
Disassembly sf steam.lenerator Atmospheric Relief Valve 1-PV-2327 (Work Order C96-5056).
No problems were noted with performance of the above mair.tenance
activities.
6.
Monthly Surveillance Observation (61726)
The inspectors observed the surveillance testing of safety-related systems and components listed below to verify that the activities were being
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. performed in accordance with the TS.
The applicable procedures were
. reviewed for adequacy, test instrumentation was verified to be in t
calibration, and test data was reviewed for accuracy-and completeness.
The inspectors ascertained that any deficiencies identified were properly l
reviewed and resolved.
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The inspector witnessed portions of the following surveillance test activities:
a.
Slave Relay Test l
l The inspector witnessed the performance'of OPT-450A,." Train A Safeguards Slave Relay K640 Actuation Test."
b.
Solid State Protection System-(SSPS) Actuation Test The inspector witnessed the performance of OPT-446A, " Solid State Protection System Train B Actuation Logic Test." Thi: procedure had previously been performed by instrumentation and control (I&C)
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technicians as an I&C procedure and had recently been converted to an OPT procedure to be performed by operations department personnel.
Two areas were identified by the operators performing the task as needing clarification in the procedure.
Which of the two meters specified in Section 7.0, " Test Equipment," should be used when making the voltage reLdings in Steps 8.8,4 and 8.11.1.
One of-the meters was a meter required to be used on quality related (Q) measurements and the other was not.
The licensee subsequently determined (Technical Evaluation WC-90-2085) that the non-Q meter was acceptable for use on-the. step in question.
- Step 9.1 of OPT-446A required the operator to align-the SSPS
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Train B to an operable condition in accordance with S0P-711A,
" Solid State Protection-System," Section 5.2; however, no i
specific guidance was.provided to align the SSPS Train B.to one
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-12" of the switch configurations specified in SOP-711A.
OPT-446A was subsequently revised to place the SSPS in a' lineup conforming to SOP-711A.
Discussion and resolution of these two areas did not affect satisfactory completion '.,f-the surveillance within the 2-hour action requirement imposed by Yechnical Specifications 3.3.1 and 3.3.2 for surveillance testing, c.
Calibration of Intermediate Range Nuclear Instruments The inspector witnessed the calibration of Intermediate Range Nuclear-Instrument Channels N-35 and N-36 low compensating voltage bistables in accordance with Procedure INC-7015A, " Channel Calibration Intermediate Range Detector Compensating Voltage Adjustment,"
Section 11.3 (Work Order S90-1446),
d.
Service Water Pump and Valves The' inspector observed service water system testing performed in accordance with Procedure OPT-207A, " Train B SSW Pump and Valves Operational Test."
The inspectors found that these surveillance tests were conducted in an appropriate manner by qualified personnel using adequate procedures.
7.
Onsite Followup of Written Reports of Nonroutine Events (92700)
The inspector reviewed the be kw listed LER to determine whether corrective actions were taken u. stated and whether response to the event
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was adequate and met regulatory requirements, license conditions, and i
commitments.
(Closed) LER 50-445/90-018-00, " Inadvertent Automatic Start of Auxiliary Feedwater Pump Due to Personnel Error."
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This LER documented an inadvertent start of the A train motor-driven auxiliary feedwater pump that occurred on-June 13, 1990,. during the performance of Surveillance Procedure OPT-467A, " Train A Safeguards Slave
Relay K609 Actuation Test." Corrective actions included issuance of a
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'*1essons learned" memorandum describing the event and its causes which must be reviewed by all control room operating personnel; the placing of the plant incident report (PIR) addressing this event in the-PIR log in the control room for review by all control room pet sonnel; and revisions to the steam generator draining procedure, SSPS operating procedure, and slave relay testing procedures to ensure that the systems are in the proper configuration-to perform the rcquired tests. This LER is closed.
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8.
Startup Test Witnessing (72300, 72302)
l The inspectors witnessed selected startup tests in order to verify
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.conformance by the licensee to testing commitments and procedural i
requirements, to observe staff performance, and verify that adequate test
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program records were maintained._ The following items were considered
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during test witnessing:
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Availability cf current revision of test procedure,
Minimum crew. requirements,
Test prerequisites and initial conditions,
Calibration status of test equipment,
-Technical adequacy of test procedure,
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Test coordination and crew performance,
Preliminary results satisfactory or deviations documented for
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further evaluation, and Adherence to Technical Specifications during testing.
In addition, the inspectors reviewed various logs and reports and attended meetings and crew briefings related to the test program.
Juring this inspection period, the following startup. tests were observed:
a.
ISU-236A, "Large load Reduction Test," from 75-Percent Power-i On July 7,1990, two inspectors witnessed the performance of Procedure ISU-263A, "Large Load Reduction Test."' The test was initiated from 76 percent reactor power by manually decreasing turbine load from approximately 830 Megawatts electric (MWe) to
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250 MWe.
Power initially stabilized at approximately 59 percent as a result of a fault in the rod control system. The steam dumps performed as designed.
The operators began borating the RCS to reduce reactor power to approximately 33 percent-Turbine load was
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subsequently increased to reduce steam dump demand to zero.
Unexpected plant responses that occurred during test performance were:
A rod control system " URGENT FAILURE" annunciator was received which terminated automatic rod motion. The alarm was on Power Cabinet 1AC with a fault indicated on Card J1.
I&C was called to investigate.
This prevented the rod control system from reducing RCS temperature to the value corresponding to the planned reduction in reactor power. A RCS boration was made to reduce RCS temperature. High temperature in the rod control l
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cabinets was previously suspected of causing rod control malfunctions. A temporary modification-to increase cooling inside the rod control cabinets was subsequently installed, The
licensee initiated action to install a permanent design
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modification to improve rod control cabinet cooling. Completion of this. modification will be reviewed-during followup of IFI 445/9019-01..
The heater drain pump was tripped by the operators as a result
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of erratic pump indications.
The turbine building operator reported that significa;, waterhammer or flashing was occurring in the pump suction and a system engineer reported that the pump suction strainer differential pressure was high, indicating a possible clogged suction strainer.
The strainer was subsequently cleaned.
These noted problems did not affect acceptance criteria for this test.
b.
ISU-236A, "Large Load Reduction Test," from 100-percent Power i
On July 24, 1990, three inspectors witnessed the performance of procedure ISU-253A, "Large Load Reduction Test."- The test was
initiated from 100 percent reactor power by manually decreasing
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turbine load from approximately 1140 MWe to approximately 575 MWe.
Reactor power stabilized.at approximately 50 percent following the transient, with the rod control, steam. dump, and feedwater control systems responding as expected.
The feedwater heaters-and heater drain system experienced a waterhammer which caused some' damage to piping insulation and created insulation dust in'the. turbine building.
Following the test, the license conducted a turbine building inspection which verified that no structural or system damage occurred.
c.
ISU-284A, " Dynamic Response to Full Load Rejectien and-Turbine Trip" On July-26,1989, three inspectors witnessed the performance of ISU-284A, " Dynamic Response to Full Load Rejection and Turbine Trip."
The test was initiated from 100 percent power by opening the main generator output breakers. All plant systems responded as rxpected.
'A review of the licensee's posttrip evaluation (0DA-108) was conducted and no deficiencies were noted.
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Performance of these tests was well coordinated between the test engineers and operations personnel. Control room operators were well briefed prior to each test by the cognizant test engineer.
Operator performance during all three transients was excellent.
9.
QA for the Startup Test Program (35501)
During the startup testing program, the QA department provided surveillance coverage of startup testing activities on a shift basis.
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15-personnel were present for hold point coverage of each of the many startup l
tests witnessed by th* inspectors during the initial power ascension program. The inspec.a* found that the QA personnel involved were well qualified and that tiie, had an appropriate degree of independence. The
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results of their QA surveillance activities were documented in weekly
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reports and these reports were approved by QA management.
Items requiring i
resolution were documented and tracked to completion.
The QA coverage of startup test program activities was well planned, comprehensive, and effectively implemented, o
10.
Licensee Self-Assessment Capability (40500)
The objective of this inspection was to evaluate the effectiveness of the licensee's self-assessment programs.
This inspection was a continuation of a previous inspection (see NRC Inspection Report 50-445/90-24; 50-446/90-24) and was limited to Operations Review Committee (ORC) meeting activities. The inspector attended regular ORC Meeting-90-05 and participated-in the briefings and plant tecr held the day before.
Observations of the inspector were as follows:
The depth of review and discussion of agenda items appeared satisfactory with a number of probing questions being asked on issues.
The handling of, action items by the ORC appeared to be effective. Of particular note was the review during the regular ORC meeting of each open action item by the full committee.
Overall, the ORC appeared to be discharging the responsibilities identified in Technical Specifications satisfactorily.
11.
Evaluation of Licensee Quality Assurance Program Implementation (35502)
l On July 18, 1990, regional _ management performed an evaluation of the (
effectiveness of the licensee's QA prograrr. implementation in conjunction f
with a scheduled quarterly plant performarice review of CPSES.
This review l
included an evaluation of the following:
l a.
NRC inspection reports for the past 12 months.
b.
The last systematic assessment of licensee performance (SALP) report j
results.
c.
Enforcement history and licensee corrective actions for NRr inspection findings.
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Licensee event reports issued since issuance of the opet ating license in February 1990.
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Results of event followup and operational readiness assessments performed by the NRC, including the extensive 50 percent power plateau assessment.
On the basis of the evaluation, no negative performance trends were noted-in any of-the eight SALP-functional areas assessed.
Therefore,.no
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performance based adjustments to regional inspection plans were-recommended as a-result of the above evaluation.
12. Action on= Previous Inspection Findings (92701)
(Closed)UnresolvedItem(445/8978-U-06):
This item involved the-licensee's bounding analysis approach.used to qualify Unit I safety related instrumentation tube supports.
Since the NRC questioned the validity of this analysis, the licens?e.has performed an extensive review and reanalysis of this commodity, including a 100 percent plant walkdown of accessible supports.
Some discrepancies were discovered during this effort, but all supports were determined to be acceptable in their as-found condition.
The above activities are documented in Design Calculation 16345-EM(S)-547 and attachments; " Engineering Assessment Procedure, Verification of I&C Supports," Revision 0, dated February 5, 1990; and " Engineering Report, Results of. I&C-Support Verification per
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DE0-DE0-EAP-CS-043," Revision 0, dated February-12,-1990. The inspector reviewed the above documentation and concluded that the licensee had demonstrated reasonable assurance that safety-related instrumentation tube-supports.in Unit I will function as desianed.
This unresolved item is-closed.
13.
Licensee Action on 10 CFR Part 50.55(e) Deficiencies (92700)
a.
(0 pen) Construction Deficiency (SDAR CP-90-02):
" Diesel Generator Starting Air Receiver Tank Relief Valves."
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l This deficiency involved aL10 CFR Part 21 report. submitted by Cooper I
Energy Services (Report No.152 dated January 17, 1990) which l
identified the potential for the diesel generator air receiver relief l
valve (s) to lift due to mechanical agitation without subsequently resetting until the receiver was below the emergency start interlock pressure. The Part 21 report indicated that the potential defect was generic to the type of relief valve supplied with the CPSES diesel generator starting air receivers (Crosby Model JMBU). Additionally, Plant Incident Report 89-328 documented several instances between November 1,1989, and February 2,1990,'where relief valves lifted on one or more of the Unit 1 diesel generator starting air receiver tanks due to mechanical agitation.
In response to these events, the inspector reviewed the licensee's final report for this construction deficiency contained in TV Electric letter TXX-90064 dated March 7, 1990. This review indicat7d that TV Electric performed an analysis of the applicable seismic test data and determined that three of the four CPSES relief l~
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valves were enveloped by this test data and would not have lifted
under design. basis safe shutdown earthquake accelerations. Thus, as j
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stated bylthe licensee in the reference correspondence, a >aismic event did not have the potential to cause a common mode failure.
Additionally, the support structure on the fourth relief valve a
(100-229)_was modified and this relief valve is currently enveloped by the' applicable test data.
Based on the above review process, the-inspector determined that the licensee's corrective actions relative to the ability of the subject relief vali as to retain air receiver tank pressure during a seismic event appeared adequate.
However, the deficiency which existed in the final design of these valves, as released to construction, which
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resulted-in the excessively low blowdown pressure (i.e., below the
' emergency-start lockout pressure) was not addressed in the licensee's final-response letter. As stated in PIR 89-328, the recommended long-term corrective action consisted of the replacement of all of t
the starting air receiver relief valves (100-123, -129, -223, and -229) with suitable replacements at the next available opportunity.
Although the installed valves do not present an operability concern, the licensee is currently in the process' of procuring suitable replacement relief valves.
Therefore, pending scheduled replacement =
activities, including an updated final response letter, this construction deficiency will remain open, b.
(closed - Unit 1 only) Construction Deficiency (SDAR CP-90-05):
9use Size / Type Inconsistencies."
This reportable construction deficiency involved inconsistencies which were observed in the design and installation of fuses.
In particular, numerous fuse types / sizes were found to be in conflict
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with the applicable one-line diagrams and as-found fuse
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configurations during plant equipment walkdowns.-
As a result of related concerns, identified by the Operational Readiness Assessment Team in NRC Inspection Report 50-445/89-200; 50-446/89-200 regarding the lack of verification during electrical
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system lineups, Deviation 445/89200-0-06 was id o tified. The q
licensee's corrective actions relative to fuse control issues were subsequently reviewed and closed'in NRC Inspection
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Report 50-445/90-20; 50-446/90-20. Based on the acceptability of the licensee's response-to this deviation, which included corrective
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actions for fuse size / type controls, this construction deficiency is-closed for Unit 1.
However, pending-the implementation of similar corrective / preventive measures for Unit 2, this item remains open for Unit 2.
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14.
Unit 2 Activities (71302, 37055)
During this inspection period, routine. tours of the Unit 2 facility were conducted in order,to assess equipment conditions, security,-and adherence to regulatory requirements.
In particular, plant areas were examined for evidence of fire hazards and installed instrumentation damage and to determine the acceptability of system cleanliness controls and general housekeeping. Additionally, the inspector conducted evaluations of existing plant programs for-the preservation and maintenance of installed systems and components as well as a overview of the' licensee's ASME Code controls for Unit 2.
Based on the overview of.the ASME Code controls for Unit 2 it appeared that the-licensee had established a program-to implement ASME Code requirements.
Impleinentation of code requirements in various safety-related areas will be addressed during subsequent inspection activities.
During the conduct of general plant tours of the Unit 2 facility a relative strength was identified in the area of housekeeping which was judged to be very good.
This determination was based on the cleanliness of the Unit 2 reactor containment building and safeguards building which were typically well maintained and controlled.
Unit 2 major work scope activities appeared to be tracking on schedule with engineering efforts for pipe stress and supports, plant systeLas, and civil /strte+ ural-suspended systems in progress.
Similarly, c, :struction activities for the installation of the Unit 2 startup transformers, permanent equipment transfer hardware walkdowns, construction procedure development, construction work package' review, and review of as-built ASME pipe supports were also in progress.
Unit 2 startup activities were also reviewed with positive efforts identified in the TV Electric program to implement the owner's group recommended diesel generator overhaul on an expedited basis, performance of required preventive' maintenance or installed plant equipment, and development of enhanced startup administrative procedures.
On July 17, 1990, a meeting was conducted at the_NRC Region IV office in Arlington, Texas, pertaining to TV Electric's proposed construction plans for Unit 2.
This Unit 2 project status presentation, which was open to public observation, was regarded as beneficial in providing program status.
15.
Exit Meeting (30703)
An exit meeting was conducted on August 7, 1990, with the persons identified in paragraph 1 of this report. -The licensee did not identify as proprietary any of the materials provided to, or reviewed by, the
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inspectors during this inspection.
During tnis meeting, the NRC inspectors' summarized the scope and findings of the inspection.
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