IR 05000445/1990031
| ML20058A207 | |
| Person / Time | |
|---|---|
| Site: | Comanche Peak  |
| Issue date: | 10/10/1990 |
| From: | Chamberlain D NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20058A100 | List: |
| References | |
| 50-445-90-31, 50-446-90-31, NUDOCS 9010250330 | |
| Download: ML20058A207 (24) | |
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APPENDIX B
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U.S. NUCLEAR REGULATORY COMMISSION l
REGION IV
i NRC Inspection Report:
50-445/90-31 Unit 1 Operating License:
NPF-87 l
50-446/90-31 Unit 2 Construction Permit: CPPR-127 Expires: August 1, 1992 Dockets:
50-445
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50-446
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Licensee:
TV Electric
Skyway Tower
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400 North Olive Street
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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: August 8 through September 18, 1990
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Inspectors:
W. D. Johnson, Senior Resident Inspector R. M. Latta, Senior Resident Inspector S. D. Bitter, Resident Inspector M. F. Runyan, Resident Inspector-D.
N.' Graves,-Resident Inspector A. T. Howell -Resident Inspector
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R. J. Evans, Resident; Inspector D. L. Kelley, Reactor Inspector, Division of kiictor Safety _
Reviewed by:
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- Ac4hte/4 /NO D. D. Cha riain, Chief,
)ro6ect Section B Date
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Division Reactor Projects
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Inspection Summary
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Inspection Conducted August 8 through September 18, 1990 (Report 50-445/90-31:
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I 30-446/90-31)
'f Areas Inspected:
Unannounced, resident, safety inspection of plant status, operational safety verification, onsite followup of events, maintenance observation, surveillance observation, startup test results review, engineered safety feature system walkdown, licensee event report followup, followup on previously identified items, and Unit 2 activitics, i
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Results: Unit I experienced several secondary system induced transients and trips during this inspection period.
Systems generally responded per design, and licensee response to the trips was appropriate. A licensee task team was formed to review secondary plant reliability. A technical meeting between NRC and the licensee will be scheduled to discuss the results of this task team.
I Three violations were identified during this inspection period.
Paragraph 3.c discusses a failure to follow an alarm response procedure.
Paragraph 5
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discusses two examples of failure to follow work order instructions.
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Previously, there has not been a pattern of procedural noncompliance; however,
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these examples of procedural noncompliance may represent a need for increased managament awareness and involvement in this area.
A noncited violation i.
involving failure to perform the required evaluation of pressurizer heatup
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transients is discussed in paragraph 10.a.
Additionally, paragraphs 3, 5, and 6 discuss problems with the adequacy of
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procedures.
NRC Inspection Reports 50-445/90-19; 50-446/90-19 and
50-445/90-22; 50-446/90-22 cited violations regarding the adequacy of
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surveillance and test procedures. Although, these additional examples do not-constitute violations of NRC requirements, they are indicative of a need for
increased management attention in this area.
Paragraph 3 b documents an engineering error made during a review of the containment air cooler condensate flowrate alarm setpoint. Although this error did not result in a violation of the Technical Specifications (TS), it is indicative of a weakness in the engineering review process.
During this inspection, two inspector followup items were identified.
These included inspection followup of the enhancement of the shift turnover process (paragraph 3.h) and followup of the licensee's investigation of a positive high rate trip on Power Range Channel N42 during the calibration of Intermediate t
Range Channel N36 (paragraph 6).
Startup test result reviews were completed with a conclusion that startup
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testing was accomplished in a professional and competent manner.
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DETAILS
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Persons Contacted L
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' *J.. L. Barker, Manager, Independent Safety Engineering Group (ISEG)
'*0. Bhatty, Issue Interface Coordinator
- R. D. Bird, Jr., Electrical Maintenance Manager
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- M. R. Blevins, Manager of Nuclear Operations _ Support
- H. D. Bruner, Senior Vice President
- J. H.-Buck, Independent Advisory Group
- R. C. Byrd, Manager, Quality Control (QC)
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- W. J. Cahill, Executive Vice President, Nuclear
- C. B. Corbin, Licensing Engineer
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- J. Doyle, Citizens Association for Sound Energy (CASE)
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R. Flores, Shift Operations Manager
- W. G. Guidemond, Manager of Site Licensing
- J. C. Hicks, Unit 2 Licensing Manager
- C, B. Hogg, Chief Engineer J. W. Hoss, System Engineer
- A. Husain, Director, Peactor Engineering
- G. E. Jergins, Mechanical Maintenance Manager
- C. F. Kesinger, Accreditation / Administration Training Manager
- G. J. Laughlin, Instrumentation and Control (I&C)
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- H. Lawroski, Consultant
- D. M. McAfee, Manager, Quality Assurance (QA)
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- J. W. Muffett, Manager of. Project Engineering R. M. Howell, QA
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- E. F. Ottney, Project Manager, CASE t
- S. S Palmer, Stipulation Manager
- D. E. Pendleton, Unit 2 Assistant Project. Manager
- P. B. Stevens, Manager of Operations Support Engineering (OSE)
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- C. L. Terry, Director of QA
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- J. R. Waters, Site Licensing-T. A. Weyant, OSE
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- B. W. Wieland, Maintenance Manager
- D. R. Woodlan, Docket Licensing Manager
- 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 administrative members of the licensee's staff.
2.
Plant Status - Unit 1 (7170D The unit was in Mode 1 at the start of this inspection period and in the
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process of raising power when a steam generator (SG) low level reactor trip occurred on August 8, 1990, as a result of a feedwater preheater bypass valve failing shut. The reactor was restarted on August 9 and
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reached 100 percent power on August 10.
On August 11, reactor power was
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reduced to approximately 50 percent to realign the B main feed pump, and subsecuently returned to 100 percent on August 12. At 8 a.m. on August 13, Unit I was declared commercial.
On August 17, reactor power was reduced to approximately 70 percent as a result of a heater drain pump bearing failure. The reactor was returned to 100 percent operation on August 18.
On August 25, the reactor tripped on high SG level when the positioner feedback lever fell off the No. 2 SG main feedwater (MFW) flow control valve (FCV) causing the valve to fail open. The reactor was restarted on August 26 and reached 100 percent power on August 27.
Power was reduced to 90 percent due to flow oscillations in the feedwater heater drain system on August 29 and returned to 100 percent on August 31. A manual reactor trip was initiated on September 7 to prevent an automatic reactor trip on high steam generator level when the positioner feedback lever on the No. 2 MFW FCV broke, causing the valve to fail open.
The reactor was restarted on September 8 and experienced a trip from approximately 40 percent reactor power when lightning struck the Unit I containment, causing a voltage transient in the rod control system.
The reactor was restarted on September 9.
On September 10, a reactor trip occurred from approximately 90 percent power when a high water level occurred in the B moisture separator reheater and initiated a turbine trip.
The reactor was restarted on September 13. A manual reactor trip was initiated from approximately 54 percent power on September 15 when a heater drain pump tripped, causing a low suction pressure trip of the main feed pump. The reactor was restarted on September 16 and was increasing power at the end of the inspection period.
3.
Operational Safety Verification (71707)
The objectives of this inspection were to ensure that the facility was
being operated safely and in conformance with regulatory requirements, to l
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 were being implemented in conformance with plant policies and procedures and in compliance with regulatory requirements, and to inspect the licensee's compliance with the approved ohysical security plan.
The inspectors conducted control room observations and plant inspection tours and reviewed logs and licensee documentation of equipment problems.
Through in plant observations and attendance of the licansee's I
plan-of-the-day meetings, the inspectors maintained cognizance over plant status and TS action statements in effect.
j During plant tours, the inspectors found the plant material condition and housekeeping to be generally very good in the buildings other than the turbine building.
There were a number of leaks in the turbine building and general housekeeping was poor in some areas.
Some improvement was noted late in the inspection period, especially in the MFW FCV area.
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The following paragraphs provide details on certain concerns and issues identified during this inspection period.
a.
Reactor Coolant Pump Seal Leakoff Flow
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The No. I seal leakoff flows for the No. I and No. 4 reactor coolant pumps (RCPs) were observed to be approaching the procedural limit of i
5 gpm following the plant startup of August 7-8, 1990.
Thi s -increase was attributed to electrophoresis, a collecting of ferrous material on the seal surfaces. The vendor recommended lowering seal injection
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temperature as much as possible and changing the seal injection filters to use an electrostatically charged filter cartridge with a smaller particle entrapment capability.
These actions were performed on August 20, 1990, with a reduction in No. I seal leakoff flow to the normally expected values of 2.5 to 3.5 gpm. An inspection of the
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original filters found no abnormalities in the filter cartridge or any unexpected debris. The licensee was monitoring the performance of the system using the new filter cartridges.
b.
Nonconservative Setpoints for Reactor Loolant System (RCS) Leak
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Detection System On August 10, 1990, the licensee identified that the setpoints for the containment air cooler condensate flowrate alarm were nonconservative.
The instruments were declared inoperable and the action requirement for TS 3.4.5.1 was entered. The action requirement states that plant operation may continue for up to 30 days provided grab samples of the containment atmosphere are
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obtained at least once per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. An Operations Notification and
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Evaluation (0NE) Form (FX 90-2025) was written by the licensee to document and resolve the setpoint deficiency.
Technical Evaluation SE-90-2227 was written to document the actions that needed to be performed to correct the error. A setpoint change was processed to change the flowrate setpoints to values that would detect a 1 gallon i
per minute RCS leak inside containment, assuming three of the four containment coolers were operating. The setpoints were adjusted and
the limiting condition for operation (LCO) was cleared on August 22, 1990.
On August 23, the inspector questioned the adequacy of the system to detect a 1 gallon per minute leak if all four containment coolers were operating.
The licensee determined that the setpoints were nonconservative for four-cooler operation and again declared the instruments inoperable and reentered the LCO later on August 23.
The required termination date for the LCO was recorded as September 22, 1990, which is 30 days from the date the LCO was entered the second time. ONE Form FX 90-2086 was written to document and track this occurrence, On August 24, the inspector questioned the licensee regarding the initiation time of the LCO since it was known that the setpoints were
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-6-nonconservative since the initial discovery on August 10. The licensee revised the LCO tracking form (LC0AR A90-1-411) to reflect the date of initial discovery, August 10, as the start of the 30-day action requirement.
Another setpoint change was processed assuming four cooler operation.
The setpoints were adjusted, and the instruments were declared operable on August 27, 1990.
c.
Steam Generator Hioh Feedwater Nozzle Flow Alarm On or about August 12, 1990, the No. 2 SG feedwater nozzle flow high alarm started periodically annunciating in the control room. This annunciator indicates a high flow condition to the preheater section of the SG. The purpose of limiting SG preheater flow is to minimize the potential for wear of the SG tubes at the preheater baffle plates due to flow induced vibration. The licensee previously noted, in July 1990, high flow conditions to the Nos. 2 and 3 SG feedwater nozzles. As a result, the annunciator alarm setpoint was raised, with Westinghouse's concurrence, from 3.39 million ibm./hr. to
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I 3.46 million ibm./hr. for each SG.
This setpoint change was accomplished while Unit I was shut down during the period July 26 through August 7, 1990.
Plant Technical Support was notified that the No. 2 SG feedwater nozzle flow high alarm started annunciating again after the plant had reached 100 percent power on August 12, 1990.
Power was not reduced, however, in accordance with Step 4 of the subsequent operator actions of Alarm Procedure ALM-0081A, Revision 2, "SG 2 FW NZL FLO HI."
Step 4 of ALM-0081A requires, in part, that turbine load be reduced to clear the alarm condition if feedwater nozzle flow cannot be maintained below the alarm f.etpoint. As a result, Operations department personnel wrote ONE Form FX 90-2055 on August 16, 1990, j
documenting that the alarm response procedure was not being complied with, and requested that a technical evaluation be performed in order to determine the need for a turbine load reduction. Subsequent discussions with Technical Support personnel revealed that a flow indication problem was suspected and, therefore, no load reduction was needed to be performed until an actual high flow condition was
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verified.
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On August 24,1990, Step 4 of the subsequent operator actions of ALM-0081A was revised to require the determination by Technical Support as to whether the actual flow in the preheater is exceeding the limit.
If an actual high flow condition was determined to exist, i
then the revised alarm response procedure required a turbine load reduction to clear the alarm condition.
A note was also added to Step 4 that stated, "The total time that an actual high flow condition should be allowed to exist between eddy current inspections of the steam generator tubes is 100 hours0.00116 days <br />0.0278 hours <br />1.653439e-4 weeks <br />3.805e-5 months <br />." The
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-7-basis for this requirement is found-in Precautions, Limitations and Setpoints Document PLS-D4/5, Revision 1, " Precautions, Limitations and Setpoints for Preheat Stean Generator /Feedwater System Interface Operation."' Item 13 of PLS-D4/5 States:that during the time period-
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first refueling, the total time that the main nozzle flow of any one SG exceeds a flow rate to SG MFW nozzle at which high flow alarm is actuated shall not exceed 100 hours0.00116 days <br />0.0278 hours <br />1.653439e-4 weeks <br />3.805e-5 months <br />. Apparently, the alarm procedure was revised to reflect this requirement as well as=to reflect what the licensee was actually doing (i.e., verifying that FW nozzle flow.
was actually high befor reducing power).
The inspector had.the following concerns with the licensee's_ approach-to resolving the No. 2 SG feedwater nozzle flow high al;rm condition:-
(1) The licensee failed to initially comply with ALM-0081A.
(2) There was no readily apparent reason to not believe that an actual high flow condition existed, particularly since a previous high flow condition necessitated an increase'in the alarm setpoint.
(3) Several days had passed with the annunciator almost continuously lit, without a determination as to whether a high flow condition existed, j!
(4) If a high flow condition did exist, the 100-hour limitation would have apparently already been exceeded and, as a result,
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the licensee would have been in noncompliance with the revised i
version of ALM-0081A.
(5) The method by which the licensee was keeping track of the l
100-hour time limit was questioned. ALM-0081A, Step 1, requires logging the time at which the alarm condition occurs and the-logging-of certain flow parameters at 15-minute intervals.
(6) The effect of a high flow condition on the No. 2 SG.
J The inspector discussed these concerns with licensee personnel. As a result of this discussion and a review of licensee records, the
inspector determined that the licensee was not performing the
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required 15-minute logging of the parameters required by ALM-0081A.
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As a result, the licensee could not definitively determine if the 100-hour limitation was exceeded, although available data indicated
that it was.
Failure to log at 15-minute intervals those parameters listed in Step 1 of ALM-0081A, as well as failure to reduce turbine load per Step 4 of the subsequent operator actions of ALM-0081A, is an apparent violation of TS 6.8.1.a (445/9631-01). However, since licensed operators identified the failure to reduce turbine load and action was taken to correct this condition, this portion of the apparent violation is not being cited.
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F-8-By August-28, 1990, the licensee determined that the No. 2 SG: nozzle flow-derived indication did exceed the alarm-setpoint within thej bounds of instrument accuracies.
In a safety evaluation performed by Westinghouse (SPT-1211 dated August 30, 1990), Westinghouse provided justification for temporarily increasing-feedwater nozzle flow to
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93.9 percent-+ 2.6 percent instrument _ accuracy.
However, Westinghouse advised TV' Electric that operating the SGs at feedwater flow rates above 92 percent is not recommended and doing'so could adversely-affect the SG tubes. Westinghouse recommended that. action be taken to reduce the feedwater preheater flow rates to below the recommended maximum of 92 percent by increasing main feedwater line hydraulic resistance and/or reducing feedwater preheater bypass line hydraulic resistance, d.
Protected Area (PA) Perimeter On August 30, 1990, while performing a routine PA perimeter walkdown, the inspector observed a potential access under the PA fence line.
This condition was identified to the licensee's security supervisor who indicated that the potential access into the PA was previously evaluated and that the existing physical barriers were considered adequate.
However, the security supervisor stated that the reported condition would be reassessed.
Subsequent to the identification of this issue, the inspector determined that, although the existing barrier did satisfy the technical requirements for controlling potential intrusion into the PA, the licensee promptly implemented
compansatory measures and augmented the existing barrier, e.
Licensed Operator License Applications A review was performed of the documentation of several licensed g
. operators' experience as submitted on operator licensing application
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forms (NRC Form 398). The records appeared to support the submitted d
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Component Cooling Water Heat Exchanger Fouling Following the cleaning of component cooling water (CCW) Heat Exchangers A and B on August 15 and 22, respectively, the calculated fouling factors began to increase rapidly such that the heat exchangers would require cleaning again in less than 1 month. An NRC special inspection was performed by Region IV to inspect the i
licensee's service water corrosion and fouling control programs. The
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results of this inspection will be reported in NRC Inspection Report 50-445/90-38; 50-446/90-38. The licensee placed a bromine injection system in service on September 6, and indications at the end uf this inspection period were that this may be effective in controlling biological fouling of the heat exchangers.
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g.
Failure to Meet Staggered Test Basis for Containment Isolhtion Valves
At 12:37 p.m., on August 24, 1990, the licensee identified that the containment and hydrogen purge supply and exhaust inboard and outboard isolation valves were not being tested on a staggered test basis as required by TS 4.6.1.7.2.
The specification requires that at least once per 184 days, on a staggered test basis, the inboard and outboard isolation velves-in each locked-closed, 48-inch and 12-inch containment and hydrogen purge supply and exhaust penetration
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shall be demonstrated operable by-performing a satisfactory leak rate test. _The penetrations were being tested every 184 days, but not on a staggered schedule.
The licensee notified the resident inspector and generated ONE Form FX 90-2092 to document the condition.
The three 12-inch valves isolating Penetrations MIII-18, 1-HV-5542, 1-HV-5543, and 1-HV-5563, were leak tested satisfactorily on August 24, 1990.
The isolation valves for Penetrations MV-1, 1-HV-5536, and 1-HV-5537, were leak tested at 5:25 a.m. on-August 25, 1990, and failed.
The valve stem packing was adjusted on 1-HV-5536, and the leak test was performed again with satisfactory results at 4:16 p.m. on August 25. The isolation valves for Penetrations MV-2, 1-HV-5538, and 1-HV-5539, were leak tested at 2:15 a.m. on August 26 and failed.
The packing on both valves was adjusted and the. leak test was performed again with satisfactory results at 8:29 a.m. on August 26. The isolation valves for Penetrations MIII-19, 1-HV-5540,
-5541, and -5562 were tested satisfactorily on' August 31, 1990.
A review of the TS was performed by the licensee to determine if any other surveillances were not staggered when required.
No. additional
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items were identified.
A technical evaluation'was submitted to the licensing compliance group by the system engineer for a position on the definition of
" staggered test basis."
Licensee followup activities will be reviewed upon issuance of i
l Licensee Event -Report (LER) 90-024-00, h.
Valve Discovered in Wrong Position On August 31, 1990, during the performance of a surveillance test-
that was being performed to verify emergency core cooling l
L system (ECCS) valve lineup, the Train B residual heat removal (RHR)
L heat exchanger FCV, 1-HV-607, was discovered shut instead of open as l-required by TS.
The shift supervisor was immediately notified of the i
situation, and the valve was opened within 12 minutes.
Investigation L
revealed that the valve had been closed for approximately 35 hcurs.
The licensee indicated that this incident resulted from maintenance that was performed on the hand controller for the valve.
During the l
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previous shutdown period, control room operators experienced difficulties in operating the potentiometer on the hand controller
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for 1-HV-607. A work request was generated to either clean or repair the potentiometer. The resulting work order ultimately;1ed to the replacement of the. hand controller. After the controller was-replaced, I&C personnel conducted a functional check of the controller and concluded that it performed satisfactorily.
The functional test consisted of opening and closing _the valve 'by using the potentiometer.
However, the control room operators apparently failed to verify that the actual valve position agreed with the demand signal displayed on the controller.
The operators could have-either checked the valve position locally or determined its position.
by using the indicating lamp on the monitor light box (MLB).
Apparently, neither was done and the valve was left closed.
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The licensee generated a ONE Form FX 90-2114 to document this incident.
Furthermore, the incident was determined to be not reportable under the provisions of 10 CFR 50.72 and 50.73 because.
i only one train of RHR had been inoperable and the valve had been shut for-less than 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.
As corrective actions, " lessons learned" were generated to remind the operators not to rely upon the demand signal displayed on the controller. The only indication of 1-HV-606 and -607's position available in the control room was the indicating light on the MLB.
To emphasize this point, a job aid was-placed near the hand controllers for these valves to remind the operators that their positions can be determined only by observing two MLB indicating lamps.
In addition, Operations department management stated that in the future required functional tests will be spt.cified by the licensed
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operator reviewing the work order or test instead of by maintenance personnel.
This incident is significant in several ways:
(1) if the performance of the surveillance procedure had been delayed for another 37 hours4.282407e-4 days <br />0.0103 hours <br />6.117725e-5 weeks <br />1.40785e-5 months <br />, TS 3.5.2 dealing with ECCS operability would have been violated; (2) the shift turnover process appeared flawed in that four shift changes occurred with no one detecting the closed valve; (3) the question of whether the controller was installed incorrectly, or whether the controller was installed correctly but was of a different type, needs to be addressed; and (4) the adequacy of the functional:
test needs to be addressed. This item will be tracked as an inspector followup item pending the completion of the licensee's actions to close the ONE Form FX 90-2114 (445/9031-02),
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Emergency Access Keys i
It was noted in NRC Inspection Report 50-445/90-30; 50-446/90-30 that operations personnel were not routinely checking out emergency access keys on a daily shift basis.
The inspector found that additional management attention was focused on this issue following
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h identification. Subsequent spot checks indicated that auxiliary
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operators had been checking out emergency access at the beginning of; their shifts, as required.
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Inadvertent Isolation of Refueling Water Storage-Tank (RWST) Level
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Transmitter During the. performance of Work Order S90-0660, a calibration of RWST-Level Transmitter 1-LT-0932, the wrong transmitter '(1-LT-0933) was-
isolated.
The transmitters were properly labelled with equipment
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identification tags, but the 0933 transmitter-had "2-LT-0932" writtenL on top of it with a marker pen.
The improper isolation was detected
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by another technician's independent verification of the transmitter isolation valves' position'and was promptly corrected.
This'is indicative of inattention to detail during maintenance activities in that the equipment to be worked on was not properly'
verified-by the technician.
However, the independent verification
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corrected the improper isolation quickly such that the action statement for TS 3.3.2 was entered for only approximately 2 minutes.
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The inspectors concluded that licenses management'was responsive to
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identified concerns and that they were operating the facility in-accordance with regulatory requirements, with the exception cf tha alarm response procedure.
4.
Onsite Event Followup (93702)
a.
Reactor Trip on Closure of Preheater Bypass Valve On August 8, 1990, with reactor power at 17 percent, a reactor trip
was-caused by low level in SG No. 4.
Low level in this SG was. caused
by inadvertent closure of the associated feedwater preheater bypass valve. Operating personnel responded to the trip in accordance.with emergency operating procedures and stabilized the unit in Mode:3.
The auxiliary feedwater-(AFW) system actuated on low SG level per
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design.
The licensee's investigation of the event found that the feedwater preheater bypass valve closed following a loss of control power caused by a loose fuse in the control power circuit.
Inspection of the control power fuse clip indicated low spring tension which allowed the fuse to make intermittent contact. A large sample of E
similar control power fuse blocks was inspected by licensee
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personnel.
Several other fuse clips were found to be slightly loose.
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E The inspector observed a number of these inspections. Adjustments were made to the spring tension on the loose fuse clips. To prevent
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L recurrence, licensee personnel were instructed to inspect fuse clips L
for proper operation when installing fuses.
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The licensee's actions in response to this trip were considered to be appropriate. The unit was restarted on August 9, 1990.
The inspector will review this event further during review of LER 90-023-00.
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b.
Reactor Trip Due to Turbine Trip
On August 25, 1990, at 12:38 a.m. (CDT), with Unit 1 operating at 94 percent power, a reactor trip occurred as a result of a turbine trip. The turbine trip occurred on hi-hi level in the No. 2 SG when
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the.No. 2 MR/ system FCV (1FCV-520) failed open. All-safety systems functioned as designed, and the plant was stabilized in Mode 3.
- Licensee investigation of the failed open FCV revealed that the feedback positioner arm had fallen off the valve controller. This resulted in a full open demand signal causing IFCV-520 to go full
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open. The licensee determined that the fastener that holds the feedback positioner arm in place had fallen off because it was not secured by a lock washer.
The three other FCVs were inspected, and lock washers were found to be installed, however, one was installed incorrectly.
1FCV-520 was repaired, and the unit was taken critical at 1:37 p.m. on August 26, 1990. The inspector noted that this was the second reactor trip caused by problems with MFW FCVs, which are
exposed to the environment.
This reactor trip will be reviewed further following' issuance of LER 90-025-00.
c.
Plant Transient Due to Feedwater Heater Level Oscillations On August 28, 1990, at approximately 10:30 p.m. (CDT), FW Heater 2A level began oscillating between the high and low level alarm points, r
The normal draii valve, 1-LV-2509, was cycling excessively. The air supply to the valve was isolated to fail the valve closed in order for the alternate drain valve to control heater level.
The alternate drain discharges directly to the main condenser, while the normal drain discharges to the heater drain tank. Once the 2A heater alternate drain was open to the condenser, the heater drain pump, which takes a suction from the heater drain tank, began to provide fluctuating flow to the main feed pump suction. The decrease in feed pump suction caused the low pressure heater bypass valve, LV-2286, to open.
Extraction steam to FW Heater 1A isolated on high level in the 1A heater.
This resulted in much cooler FW entering the SG. The operators reduced turbine load and reactor power to approximately 85 percent while stabilizing the heater drain system.
Severe waterhammer was reported in the heater drain lines during this event. A number of valves were identified that had experienced loosened fasteners, leaks, and broken components as a result of the water hammer.
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As a result of the problems experienced with the secondary system, a l
task team was established by the licensee to review various designs
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of systems and control systems in the secondary to determine if
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modifications need to be made in order to provide more reliable plant:
performance. An inspection of various indicators, transmitters, level sensors, valves, and controllers was performed by the-licensee.
ONE Form FX 90-2109 was written by the licensee to document the incident. Reactor power and turbine load were maintained 80-90 percent until repairs were made to the components identified
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during the licensee's inspection.
Reactor power was returned to-100 percent on August 30, 1990.
d.
Manual Reactor Trip Due to High SG Level
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On September 7, 1990, at 12:36 a.m. (CDT), with the plant operating at 100 percent power, a manual reactor trip was initiated as a result of a high level in the No. 2 SG.
The cause of the high level was the
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failure of the No. 2 MFW FCV.in the full open position. The plant was stabilized in Mode 3 immediately following the trip'.
The FCV, 1-FCV-520, failed open when its positioner feedback arm broke. Without the feedback from the positioner feedback arm, the-positioner senses that the valve is shut and provides full opening-air pressure to the valve actuator. An "SG #2 STM & FW FLO MISMATCH" annunciator was received in the control room, and the operators observed FCV 1-FCV-520 demand at approximately 45 percent, which is low for 100 percent power.
Feedwater flow through 1-FCV-520 was higher than the flow through the other FCVs. The operator placed the controller for 1-FCV-520 in manual and attempted to reduce the FW flow to the No. 2 SG with no effect. The operator tripped the reactor at approximately 80 percent narrow range level in the No. 2 SG following the shift supervisor's direction.
No other equipment malfunctions were observed during the event.
Additionally, an AFW actuation. signal occurred at 2:34 a.m. when the No.-4 SG level was allowed to decrease below the AFW actuation setpoint of 28 percent. However, the motor-driven AFW pumps were already running and being used to maintain SG levels. AFW flow was increased to the No. 4 SG and level was restored to clear the actuation.
Plant response was normal for the actuation.
On August 25, 1990, the positioner feedback arm on 1-FCV-520 had fallen off, resulting in a turbine trip on high SG level and subsequent reactor trip.
The decision was made by the licensee to replace the FCV positioners as necessary following inspection of the positioners. The positioners for 1-FCV-520, -530, and -540 were replaced and calibrated. The cam and associated roller bearing in the positioner for 1-FCV-520 were replaced and the positioner was calibrated. All four FCVs were also repacked and stroke tested satisfactorily.
The reactor was taken critical at 3:25 a.m. on September 8, 199 :
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b The post-trip evaluation performed in accordance with Operations
- Department Procedure ODA-108, " Post RPS/ESF Actuation Evaluation,"
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was reviewed by the inspector and no' deficiencies were noted.-
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Licensee followup actions will be reviewed upon issuance of
~LER 90-027-00.
e.
Reactor Trip Due to Lightning Strike
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At 2:28 p.m.-(CDT) on September 8, 1990, with Unit 1 operating at approximately 40 percent reactor power, a reactor trip occurred as a result of a ligntning strike. This apparently caused an overvoltage condition in rod control Dower Cabinet 2AC, which tripped two +25 volt DC control pcwer supplies.
This resulted in the 10 control rods associated with Dower Cabinet 2AC dropping into the
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core, thereby generating a high negative power range flux rate trip.
All safety-related equipment functioned as required, includina the motor-driven AFW pumps which automatically started as a result of a momentary lo-lo No. 3 SG level indication. Howevcc, it was noted that three of the.four low pressure turbine stop valves on the. main turbine indicated open following the reactor trip, and the CG blowdown and sampling valves did not isolate.
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Subsequent to the reactor trip, it was determined that the low pressure turbine stop valves indicated closed and that
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operational testing of both the high pressure and low pressure turbine stop valves demonstrated that they functioned normally.
Additionally, it was ascertained that the failure of the SG blowdown v
and. sample valves to isolate was attributed to the relatively short duration (0.13 seconds) of the it-lo SG level indication, which did not produce an actuation signal o? sufficient duration to activate
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the associated latching relay.
Unit I was rest:cted with the reactor critical at 5:50 a.m. and the-main gener: Lor breakers were closed at 9:57'a.m. on September "u, 1990. Additional details involving this event will be documented in a subsequent inspection report which will evaluate associated LER 90-028-00.
f.
Reactor / Turbine Trip on High Moisture Separator Reheater Level On September 10, 1990, with reactor power at 92 percent, a reactor trip was caused by a turbine trip due to high level in a moisture
. separator reheater (MSR).
The high level occurred during an attempt by an operator to transfer control of the MSR separator drain tank level from the alternate drain valve to the normal drain valve.
The high level alarm on the separator drain tank did not actuate during the transient. Operating personnel responded to the event in j
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accordance with emergency operating procedures and stabilized the unit in Mode 3.
The AFW system actuated on low SG level per design.
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The licensee's investigation of the event.found that the separator drain. tank normal drain valve was manually isolated and that this i
tank's high level alarm was not. functional. Because of' poor communications during shift turnover and incomplete information on
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the caution tag on the alternate drain valve controller, operators were not aware of _the nonavailability of the normal drain valve.
During the outage following this trip, the licensee reviewed the
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maintenance backlog and scheduled performance of outstanding s
secondary plant items which could affect secondary. plant control or plant' reliability. This included repair or replacement and f
functional testing of MSR drain tank level alarms and drain valve -
controllers. While the formal root cause evaluation was continued, several short-term corrective actions involving turnover enhancements
and operator job aids were completed. The licensee's response to-this trip, including the investigation and initial corrective actions appeared to be appropriate. The inspectors reviewed the licensee's written evaluation (00A-108) of this event.
The unit was restarted on September 13, 1990.
The inspector will review this event further during review of LER 90-029-00.
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g.
Manual Reactor Trip Following Trip of Heater Orain Pump i
Cn September 15, 1990, with reactor power at 54 percent, a manual reactor trip was initiated due to decreasing-SG levels.
A-loss _of MFW flow occurred as the result of the loss of the.' running heater
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drain pump and tripping of the running MFW; pump on low suction
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pressure. Operating personnel responded to the trip in accordance
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with emergency operating procedures and stabilized the unit in Mode 3.
The AFW system actuated on low SG 1evel per design.
The licensee's investigation of the event found-that the heater drain i
pump tripped on neutral overcurrent protection, when starting a 1-condensate pump, due to induced current in the heater drain pump power cables.
Testing performed after the trip reproduced this condition.
Breaker cabinet inspection indicated that the heater drain pump power cable shield ground strap was not routed through the i
l current transformer loop as required. This strap was rerouted and-l subsequent testing indicated that induced current caused by starting l-a condensate pump was properly compensated and that the heater drain pump neutral overcurrent protection relay (50/N) no longer tripped when the condensate pump was started.
It appears that the improper
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routing of the ground strap occurred during construction.
L The inspectors reviewed the licensee's written evaluat. ion (0DA-108)
of this event.
Operator actions and equipment response were considered to be appropriate.
The unit was restarted on
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September 16, 1990. The inspector will review this event further
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during review of LER 90-030-00.
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-16-s The licensee's responses to these events were considered to be appropriate.
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Post-transient evaluations were' adequate as were. root cause evaluations.
As a result of the secondary induced transients and trips, the licenseeL
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expanded the scope of the task team that was formed following the secondary
transient that occurred on August 28, 1990 (paragraph 4.c).
The task team
will ~ review the reliability of the secondary plant, and recommend corrective actions to improve reliability.. A technical meeting with the
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licensee will be conducted in order to discuss the results of this task team. The schedule for this meeting will be established by separate correspondence from the NRC Region IV office.
5.
Monthly Maintenance Observation (62703)
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Station maintenance activities for the safety-related and nonsafety systems and components listed below were observed to ascertain that they l
were conducted in accordance with approved procedures, regulatory guides, and-industry codes or standards and in conformance with the TS.
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Maintenance activities observed included:
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Drilling of holes for alignment dowels on the A train coolant charging pump (Work Order C90-641).
Cleaning of the_A and B trains' CCW heat exchanger tubes (Work-
Orders C90-4782 and C90-5392).
- Calibration of Channels 5402 and 5403 of the average containment temperature instrument (Work Order C90-5475). The emergency response facility (ERF) computer point indication was out of tolerance.
The procedure contained an error in sequence such that, if it was followed exactly, the steps that addressed correcting the out-of-tolerance values would not have been performed. The-procedure was changed to correct the sequence.
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Changing the oil in A train CCW pump (P90-4974).
Cleaning of the A train safety injection pump oil cooler service water strainer (Work Order P90-5176).
Calibration of the valve positioners on MFW FCVs 1-FCV-520 (Work Order C90-5807) and 1-FCV-530 (Work Order C90-5819) following positioner replacement.
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Inserting incore flux detectors to verify thimble tube operability following clearing of 10 thimble tubes (Procedure NUC-102).
- Recoupling of chilled water recirculation pump (Work Order C90-5219).
- Changing the oil in the A train residual heat removal pump motor (P90-4254). The work order required the technician to perform Steps 8.2.1 through 8.2.8 of Electrical Maintenance
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Procedure MSE-PO-4312. "RHR Pump Motor Inspection," with the exception
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of Step 8.2.3.1, which was covered by a separate work order.
Step 8.2.4, flushing the motor bearings with clean oil, was not.
performed and was marked as N/A (Not Applicable) in the work order.
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However, Station Administrative Procedure SIA-606, " Work Requests.and
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Work Orders," Revision 14, Step 6.6.2.9, requires, in part, that work'
should be performed in accordance with tne instructions and in the-sequence listed except when a specific exception is written into the
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instruction or the steps are not applicable and marked N/A.
Additionally, Step 6.6.2.13 requires, in part, that the work package is-revised if the intent of the work instructions must be changed or if the scope of the work increases. The step marked N/A was applicable, but the supervisor at the job stated that it would be an ALARA concern to perform the step because it took so long.for the oil to drain through the bearings and the location of the drain plug was in a potentially-contaminated area.
The work package was'not revised to reflect the change in' work instructions.
Failure to follow work order. instructions or revise the instructions accordingly is a violation of TS 6.8.1.a (445/9031-03).
- Changing the oil in the A train coolant charging pump (Work Order C90-5224). The mechanics did not drain the oil from the oil cooler as required by the work order.
Step 4 of the work order stated:
" Remove drain plugs, rework as necessary to remove all oil possible from reservoir, pump, (inboard and outboard) oil cooler,
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lines and gear reducer." The system engineer and mechanic
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performing the task discussed whether the oil needed '
be drained from '.he oil cooler.
The system engineer stated that cne oil cooler would have to be disassembled to drain the oil due.to the
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inaccessibility of the drain plugs and that draining the cooler
would not be necessary due to the relatively small amount of oil conta'ned in the cooler (approximately 5 gallons).
Step 4 was signed off in the work order as complete with no work order revision to documer.t that the oil cooler had not been. drained.
The inspector questioned the-system engineer later to determine if the oil had been drained out of the cooler prior to closure of the work order and he confirmed that it had not. This is a violation of. Station Administrative Procedure STA-606, "Wnrk Requests and Work Orders,"
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Revision 14, Step 6.6.2.9, that requires,-in part, that work should be performed in accordance with the instructions and in the sequence
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listed except when-a specific exception is written into the instruction or the steps are not applicable and marked N/A, and Step 6.6.2.13, that requires, in part, that the work package is revised if the intent of the work instructions must be changed or if
the scope of the work increases.
It was not noted in the work order that the oil had not been drained from the cooler even though the oil was being changed as a result of high water content in the oil.
Failure to follow work order instructions or revise the instructions accordingly is an additional example of a violation of TS 6.8.1.a.
(445/9031-03)
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-18-Maintenance observations were generally acceptable. The'two examples of failure to follow work order instructions indicate-an increased-need for
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licensee personnel to pay closer attention to procedural adherence, 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 performed in accordance with the TS. The applicable procedures were reviewed for adequacy, test instrumentation was verified to be in calibration, and test data was reviewed for accuracy and completeness.
The inspectors ascertained that any deficiencies identified were properly.
reviewed and resolved.
The inspector witnessed portions of the following surveillance' test activities:
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Analog Channel Operation Test (ACOT) on No. 2 Main Steam Line Pressure, Protection Set II (Work Order S90-1660).
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Calibration of Intermediate Range Channel N36-(Work Order S90-0467).
During performance of this procedure, INC-7380A, the instrument power-fuses were reinstalled at Step 12.2.7 When the fuses were installed, a positive high rate trip was received on Power Range Channel N42.
The system engineer was consulted, ONE Form FX 90-2067 was generated,
and the procedure was completed. The problem was being investigated by the licensee and will be tracked as Inspector. Followup Item 445/9031-04.
Performance of the containment airlock leak rate test, " Type B and C Local Leak Rate Tes+" (Work Order S90-1413).
- Performance of the Train B Solid State Protection System (SSPS)
l Actuation Logic Test (Work Order S90-2057).
Section 8.8 of Procedure OPT-446A, " Solid State Protection System Actuation Logic Test," required that the obtained voltage reading should be less than 1 volt DC.
Using the Keithley multimeter referenced in Section 7.0,
" Test Equipment," of the OPT, the voltage reading was approximately 7 volts DC. This step had previously been performed using a Simpson l
Model 260 multimeter, but the Simpson had recently been removed from the list of test equipment required in Section 7.0.
During the observed performance of this test, the Simpson was used to measure the diode voltage with the Keithley meter connected in parallel.
The difference in readings using the two instruments is a result of
L the difference in input impedances, with the Keithley having a much higher input impedance than the Simpson, resultin, in a higher l
l voltage reading. ONE Form FX 90-2148 was written by the licensee to I
obtain resolution of the matter.
The procedures for A and B trains'
SSpS logic tests have been revised to specify the use of the Simpson i
L meter to perform the diode voltage check and to add the Simpson L
meter to the list of test equipment required.
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ACOT and channel calibration of steam pressure, Loop.4, Protection.
Set II Channel 0545 (Work Order S90-1662).
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Partial-stroke testing of SG atmospheric relief valves-(Procedure PPT-TP-90A-031). This test was performed on August 8,.
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1990, to verify that the valves opened and closed upon demand from a
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main control board signal. This test was in response to problems encountered on July 30, 1990, when an inadvertent SG atmospheric-
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relief valve opening led to a safety injection actuation.
The valves performed properly during this test.
Train A safeguards s1 ave Relay K615 actuation test (Work
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Order S90-1345, Procedure OPT-469A).
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Safety chilled water operability test (Work Order S90-1812, Procedures OPT-209A and EGT-151).
- Turbine overspeed protection system test (Procedure OPT-217A).
The surveillance tests observed were conducted by qualified personnel using adequate procedures, but Procedure OPT-446A was in need of minor
revision.
i 7.
Startup Test Results Review (72624, 72616, 72301)
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The inspector selected six startup tests for test results review. The review was performed to' verify that each test had been properly conducted, reviewed, and approved by the licensee. The attributes checked by the inspector were the entry of all required data, procedural step sign off, correct disposition of technical evaluations and retests, and proper review'and approval of procedure changes.
_p The tests reviewed included:
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ISU-263A,-Revision 3, "Large Load Reduction Test." (This test was performed at 100 percent power with a 50 percent load reduction.)
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ISU-284A, Revision 3, " Dynamic Response to Full Load Rejection."
- ISU-204A, Revision 4, " Operational Alignment of Nuclear Instrumentation." (This test was performed at the 100 percent power plateau.)
L ISU-281A, Revision 5, " Full Power Performance Test."
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L ISU-260A, Revision 2, "75% Reactor Power Test Sequence." (This test included 15 startup test summaries.)
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ISU-280A, Revision 2, "100% Reactor Power Test Sequence."
(This test included 24 startup test summaries.)
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the responsible personnel.
The overall testing performance was deemed by the inspector to have been accomplished in a professional and competent manner by well qualified personnel.
8.
Engineered Safety Feature System Walkdown (71710)
The inspectors performed a walkdown of selected safety related systems-to determine whether as-built conditions matched drawings and procedures.
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The inspector found that valves and electrical breakers observed were in the correct position for normal system operability. The following systems were inspected:
a.
Emergency Diesel Generators and Auxiliaries
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The following discrepancies were noted:
(1) 'Approximately 24 valves noted on the applicable piping and instrument drawings (P& ids) had depicted valve positions that differed from the required positions noted in System Operating Procedure (S0P) 609A, Revision 7, " Diesel Generator System."
(2) Eight valves on the applicable P& ids were not listed in SOP-609A.
(3) Four other valves were not listed in SOP-609A and their actual-position differed from the position depicted on the P&ID.
(4) Some instruments listed in the valve' lineup of.50P-609A did not i
have valve numbers.
The instruments had isolation and root.
valves although the S0P-609A valve lineup (pages 67-70) implied there was only one valve per instrument.
(5) Limitation 4.4 of System Operating Procedure SOP-610A, Revision 4, "DG Fuel Oil and Transfer System," disagreed with SOP-809A, Revision 4, "DG Rooms Ventilation System," Step 4.1 and Design Basis Document (DBD) ME-302A.
(6)- There were some typographical errors associated with
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Procedures SOP-609A and 610A.
i (7) Valves 100-410 and -411 were listed in the SOP-610A valve lineup as drains, but were shown as test connection valves on the
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p? ids.
l (8) The No. 1 EDG air intake cubicle door was found open.
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The inspector provided the licensee with these observations'for resolution. The licensee initiated a ONE Form FX 90-2070 to track the resolution of these observations.
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b.
Safety Injection System (SI)
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The following minor observations were noted:
(1) Three valves noted on the applicable-P& ids had depicted val've
positions that differed from the required positions noted in the system operating procedures.
I (2) The control switch lineup'(Attachment 2 of SOP-210A) was not in the control room system s+.atus file for the SI system, but was found in the QA vault.
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(3) The technical support centar controlled technical manual for the SI pump (CP-0001-032, Conttolled Copy 603) was -i z ing several pages.
These observations were given to the licensee and the licensee initiated actions to correct them.
No discrepancies affectir.g the operability of the emergency diesel i
generators or the SI system were identified.
9.
-Onsite Followup of Written Reports of Nonroutine Events (92700)
The inspector reviewed the below itsted LERs to determine whether corrective actions were adequate and whether response to the event was adequate and met regulatory requirements, licer.se conditions, and Corm i tmen ts.
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a.
(Closed) LER 90-003-00, " Blocking' of Flux Doubling Actuation Due to Personnel Error."
This LER documented an inadvertent blocking of both source range flux
doubling (SRFD) actuation signals for approximately 4 1/2 hours.
Corrective actions included the issuance of a standing order which required:
(1) shift technical advisors to review each Technical Specification action statement entry and exit, and (2) operators _to address each lit annunciator on the control board prior to assuming licensed duties. The procedure for restoring the SSPS was revised to
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require an independent verification that SRFD actuation is in service whenever SSPS is taken out of a disabled configuration.
This LER is closed, b ',
(Closed) LER 90-005-00, " Inadequate Implementation of Procedural Requirements Resulting in the Failure to Perform a Visual Inspection."
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.-22-This LER documented the failure to follow the procedural requirement-l to' conduct _a visual inspection of the affected areas of containment.
Corrective actions included changing the security post order for.the.
containment access point.to require the security officer to check that each work party entt. ring containment.has the correct documents t
for performance of the required visual inspection;-a sign was placed at the containment access point advising work parties entering
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containment of the documentation requirements for containment entry;
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the operations department performed a visual inspection in accordance
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with the applicable station procedure to verify that no loose debris was in accessible areas of containment. The Operations department began keeping a control room log of containment entries.
Station
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administrative procedures were revised.to include a mechanism for ensuring that a visual inspection of the areas affected within containment is performed and documented following the completion'of
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containment entry. This LER is closed.
c.
(Closed) LER 90-006-00, " Source Range Flux Doubling Actuation Due to Inadvertent Reset of Source Range Flux Doubling Block."
This LER documented a source range flux doubling actuation due to inadvertent reset of the source range flux doubling block during a j
reactor startup.
Corrective action included revising Integrated Plant Operating Procedure IP0-002A to instruct the reactor operator
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to hold the SRFD block switch in the block position while the neutron flux level is passing through the P-6 permissive setpoint, and changing the SRFD actuation alarm window color from yellow to red.
A lessons learned package dealing with the concerns of operator performance was developed, and the manager of operations met with each shift crew to discuss the concerns identified in the lessons
learned package.
This LER is closed.
10. Action on Previous Inspection Findings (92701)
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a.
(Closed) Inspector Followup Item (445/9034-07): This item involved the licensee's failure to document, in its initial evaluation team report, an evaluation of the pressurizer heatup transient that occurred following the main steam line low pressure SI that occurred on July 30, 1990. This evaluation is required in accordance with TS 3.4.8.2 when pressurizer heatup exceeds 100 F in any 1-hour period. As a result of NRC questions about this evaluation, the licensee determined that an evaluation was performed and that the
structural integrity of the RCS and the pressurizer had not been l
affected by the transient. However, the scope of this review'was an engineering review for fatigue impact and not fracture analysis. TS limitations were not considered as part of the engineering review for the July 30, 1990, SI event, nor an earlier SI event that occurred on July 26, 1990.
Failure to determine that the structural integrity of the pressurizer remains acceptable for continued operation following the July 26 and 30, 1990, pressurizer heatup transients prior to reentry into Mode 2 is a violation of TS 3.4.8.2.
However, the
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licensee discovered that TS~3.4.8.2 was violated and promptly corrected the condition by performing an evaluation with concurrence-from Westinghouse which indicated that the transients had no adverse
effect on pressurizer integrity. Additionally, operations department'
administrative procedures were revised to provide guidance to
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determine if heatup or cooldown limitations are exceeded during an off-normal transient. 0ther corrective actions will be reviewed
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during a future followup inspection of LER 90-022-00, which documents-the failure to comply with TS 3.4.8.2.
This violation is not being cited because licensee actions meet the criteria for a noncited violation as described in the NRC Enforcement Policy.
This inspector i
followup item-is closed.
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11. Unit 2 Activities (71302, 37051, 37055, 50071, 50073, 50075)
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 f
determine the acceptability of system cleanliness controls and general
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housekeeping. Additionally, the inspector conducted evaluations of existing plant programs for the preservation and maintenance of installed systems and components as well as the utility's preparations for the resumption of construction activities for Unit'2.
a.
Licensee's Preparations for Resumption of Unit 2 Construction The inspectors met with several members of the Unit 2 construction engineering staff to discuss the status of outstanding Unit 2 work packages.
Because Unit 2 construction was halted in April 1988, there are approximately 30,000 work packages representing work activities in various states of completion.. The licensee is currently reviewing this backlog of packages for completeness, design adequacy, and constructability. After issuing the " rolled-up"
drawings that stem from this review process, the licensee will issue revised construction work packages that contain only the specific documentation needed to complete the " work-to ge." - Furthermore, these revised work packages will differ from those used previously on Unit 1 in that each package will address components instead of systems.
The inspectors will monitor the licensee's Unit 2 construction work activities, and will document-the results in future inspection reports.
b.
Unit 2 Diesel Generator Rework The inspectors evaluated the licensee's plans and programs for the rework of the Unit 2 Trains A and B EDGs.
This rework resulted from recommendations made by the Owners Group Design Review and Quality Revalidation Program (DR/QR) which was performed as a result of
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operational and regulatory issues involving Transamerica Delaval'(TDI)
diesel. generators'. These recommendations, which have been implemented
.for the Unit'l diesel generators, specify the performance.of detailed inspections and the upgrading / replacement of various components.
Additionally, the licensee plans to implement various corrective actions associated with 10 CFR Part 21 issues'and lessons learned from Unit I diesel generator rework activities.
The inspectors viewed the initial portions' of the Unit 2 Train A EDG.
disassembly.
The inspectors noted that parts were segregated and marked, procedures were available and in use, and access control was being maintained, Major scheduled activities include the replacement-of. pistons, cylinder heads, fuel pumps, crankshaft'
bearings, push rods, and fuel oil lines.
In addition, the inspectors will monitor the licensee's component inspection activities-associated with,this rework.
These activities include verifying dimensions, performing liquid dye penetrant tests, performing eddy current tests, radiographing, and blue-checking critical mating. surfaces, c..
Materials Staging Building l
During this inspection period, the licensee has made significant progress relative to the construction of a new three-story building j
referred to as the materials staging building (MSB). The first story of this building will function as a warehouse / staging area' The
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remaining two stories will serve as office space.
Immediately
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adjacent to the MSB is a new, smaller building, characterized as the material inspection building (MIB). The two new buildings are intended to support both Unit 1. operations and Unit 2 construction.
The MSB will serve as a storage area for high-turnover parts / tools j
and the MIB will serve as'a point through which materials destined
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for. Unit 2 construction will pass.
12. Exit Meeting (30703)
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An exit meeting was conducted on September 18, 1990, with the persons l
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identified in paragraph I of this report, The licensee did not identify i
as proprietary any of the materials provided to,' or reviewed by, the I
inspectors during this inspection.
During this meeting, the NRC l
inspectors summarized the scope and findings of the inspection.
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