IR 05000289/1990006
| ML20042G733 | |
| Person / Time | |
|---|---|
| Site: | Crane  |
| Issue date: | 05/03/1990 |
| From: | Stewart J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20042G727 | List: |
| References | |
| 50-289-90-06, 50-289-90-6, GL-88-17, NUDOCS 9005160023 | |
| Download: ML20042G733 (46) | |
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U. S. NUCLEAR REGULATORY COMMISSION
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REGION I
- Docket / Report No. 50-289/90-06 License:
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f Licensee:-
GPU Nuclear Corporation P. O. Box 480-Middletown, Pennsylvania 17057 Facility:
Three Mile Island Nuclear Station, Unit 1 Location:
Middletown, Pennsylvania Dates:
February 27, 1990 April 3, 1990
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Inspectors:
R. Brady, Resident Inspector D. Johnson, Resident Inspector
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T. Moslak, Resident Inspector
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F. Young, Senior Resident Inspector
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Approved by:
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J.7. Stewart,. Acting Section Chief
/ jDate Reactor Projects Section No. 48 Division of Reactor Projects
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- Inspection Summary:
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Areas Reviewed:
The NRC staff conducted routine safety inspections of power operations. The inspectors reviewed plant operations, responses to event, maintenance / surveillance activities, radiological practices, security measures, and engineering support activities as they related to plant safety.
Licensee action <on previous inspection findings were also reviewed.
Results: A summary of the results of this inspection are described in the executive summary of this report, details are provided in the text that follows, s
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9005160023 900503
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{DR ADOCK 05000289 PDC
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TABLE OF CONTENTS Page 1.0 Introduction and Overview.................
1.1. Licensee Activities........
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1.2 NRC Activities................
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1,3 Persons Contacted...............
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2.0. Operations (NIP 71707)*.................
2.1~ Facility Inspection.................
2.2 -Turbine Bypass ~ Valve Inoperability.
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2.3 Low Power Reactor Trip.....
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2.4 Turbine /RX Trip................
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'2.5 Once Through Steam Generator Tube Leak,......
3.0 Radiological Control s (71707)..............
4.0 Maintenance and Surveillance (NIP 61726/62703)......
4.1 Surveillance Observations..............
4 '. 2 Reactor Coolant System Leak Rate Surveillance.,..
4.3 Heat Sink Protection System Testing.........
'4.4 Control Rod Drive Mechanism (CRDM)-Motor Flange Repair 11 4.5 Maintenance Observations..............
5.0 Security (71707)....................
6.0 Emergency Preparedness (71707)..............
7.0 Engineering and Technical Support (37700)........
7.1 Reactor Vessel Head Boron Deposits.........
13-7.2 Actions to Prevent loss of Decay Heat Removal (TI 2515/101)......................
8.0. Licensee Action on Previous Inspection Findings (NIP 92703) 14 8.1- (Closed) Violation (50-289/89-17-02) Failure to Include Turbocharger Jacket Coolant Valves in Diesel Procedure OP-1107-3 and Failure to Incorporate Vendor Information-Into Installation Procedure.......
8.2 (Closed) Unresolved Item (50-289/88-29-01) Licensee Review Program to Ensure Replacement Equipment is Compatible With System Requirements.........
9.0 Management Meetings....................
- Denotes inspection modules performed
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Details 1.0 Introduction and Overview 1.1 Licensee Activities At the start of this inspection period, the licensee was performing a i
plant heat-up to 525 degrees F.
The reactor was brought critical at 5:43 am on March 3.
The licensee satisfactorily completed the zero power physics test program on March 4 and a low power reactor trip
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The reactor was restarted and the turbine generator was placed on line on March 4.
This marked the end of the 8R refueling outage.
Power escalation commenced in accordance with fuel preconditioning limits. On March 6
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at 9:00 am, the licensee received indications of primary to secondary tube leakage._The licensee commenced a controlled plant shutdown
prior to exceeding the technical specification limit of 1 gpm.
The reactor was subcritical at 10:00 am, and the plant was in a cold shutdown. condition on March 7.
The licensee plugged two tubes in the
"A" Once-Through-Steam Generator (OTSG).
The plant returned to power operations March 16. The plant output was limited to 77% reactor power (600 MWe) due to a high water level in the "B". 0TSG caused by fouling in the secondary side of the OTSG's. The licensee performed a manual Turbine Trip /Rx Trip on March 30 from 77% power in an attempt to dislodge and redistribute the corrosion products that were fouling the 0TSG's.
The unit was returned to power the following day. The units. output is now limited to 97% due to high level-in the "B" OTSG.
1.2 NRC Staff Activities The purpose of this inspection was to assess licensee activities with regard to reactor safety. The inspectors made this assessment by. reviewing information on a sampling basis, through actual observa-
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. tion of licensee activities, interviews with licensee personnel, or-independent calculation and. selective review of applicable documents.
Inspections were accomplished on both normal and back shift hours.
Back shift inspections were accomplished during the following'
periods:
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Day /Date Time February 27, 1900 12:00 mid - 6:00 am 9:30 pm - 12:00 mid
February 28, 1990 12:00 mid - 6:00 am 10:00 pm - 12:00 mid March 1, 1990 12:00 mid - 6:00 am 10:00 pm - 12:00 mid March 2, 1990 12:00 mid - 4:00 am March 3, 1990 12:00 mid - 7:00 am March 31, 1990 9:00 am - 12:00 am 1.3 Persons Contacted
- G. Broughton, Operations / Maintenance Director
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- J. Colitz, Director, Plant Engineering
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- G. Giangi, Manager, Corp. Emergency Preparedness
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R. Harper, Manager,. Plant Material
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C. Hartman, Manager, Plant Engineering
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D. Hassler, Licensing Engineer
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H. Hukill, Vice President and Director
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- R. Knight, Licensing Engineer
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- M. Nelson, Manager, Safety Review
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M. Ross, Plant Operations Director
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- T. Seaver, QA Auditor-
- H. Shipman, Operations Engineer
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D. Shovlin, Plant Materiel Director
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- G. Simonetti, Manager Emergency Preparedness
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P. Snyder, Manager,_ Plant. Materiel Assessment
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C. Smyth, Manager, Licensing
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- R. Wells, Licensing Engineer
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- Denotes attendance at. final exit meeting (see Section 10.0)
2.0 Plant Operations 2.1 Facility Inspection The resident ~ inspectors routinely inspected the facility to determine-the licensee's compliance with the general operating requirements of Section 6 of Technical Specifications (TS) in the following areas:
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review of selected plant parameters for abnormal trends; plant status from a maintenance / modification viewpoint,
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including plant housekeeping and fire protection measures; control of ongoing and special evolutions, including control
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room personnel awareness of these evolutions;
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control of documents, including log keeping practices;
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implementation of radiological controls; and,
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implementation of the security plan, including access
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control, boundary integrity, and badging practices.
In general, the inspector determined that the licensee, from a housekeeping and fire protection perspective, was maintaining the plant in good condition.
Overall, management attention toward plant safety continued to be noted.
Details of the observations are noted below.
2.2 Turbine Bypass Valve Inoperability
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During the plant heatup on February 27, 1990, the licensee found MS-V-8A and 8B out of their required position.
The valves were found
to be shut vice open. The valves isolate the turbine bypass valves which were being used to control plant heatup rate. The~ shift supervisor was touring the intermediate building to investigate the i
severity of steam leakage out of the bonnet of one of the atmospheric dump valves when he discovered the problem.
The control room operators had noted the control of the turbine bypass valves was not as expected based on past experience, however they did not note that the the valves were shut. After discovery, the shift supervisor had MS-V-8A and 8B opened.
j Review of the controlling procedure, operating procedure (0P) 1102-1 I
" Plant Heatup to 525 degrees Fahrenheit", indicated that the main steam f
system was in the proper condition to support heatup in accordance
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with'OP 1106-14'" Main Steam System".
Review of the main steam system operation procedure's valve lineup found that MS-V-8A and B were not checked off as being opened and had not been labeled as deficiencies on the front of the valve line up.
Subsequent investigation found that
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l the shift supervisor responsible for this valve line up could not place MS-V-8 A and B in its proper position due to maintenance / surveillance activities being conducted at the time of the valve lineup. The shift supervisor did not label these as deficiencies on the front of the valve line up sheet, which is the administrative guidance in this case. When the plant heatup procedure prerequisites were being reviewed for the main steam system, the main steam valve line up cover sheet did address this deficiency, therefore the system was
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assumed to be in a line up to support heatup.
MS-V-8 A and B isolate the six turbine bypass valves (MS-V-3 A thru F).
Technical specifications iequire that four of the six valves be operable when reactor coolant system temperature exceeds 250 degrees F.
Although this is an apparent violation of TS 3.4.1.1.c., based on the following -
mitigating circumstances authorized by 10 CFR 2, Appendix C V.G, a Notice of Violation will not be issued. The event was licensee identified, and would be classified as a level IV violation per
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10 CFR 2, Appendix C, Supplement I.d.3.
The licensee met the reporting requirements as specified in 10 CFR 50.73. The licensee's corrective actions included revising OP-1102-1 to verify that the turbine bypass valves were not isolated prior to exceeding 250 degrees F, and to review this event with operators and auxiliary operators to emphasize the netd to follow proper administrative requirements.
The inspector concluded these actions were appropriate This was a personnel error and is not indicative of a programmatic weakness, therefore this could not have been prevented by corrective actions implemented by a previous violation.
For administrative purposes, this item will be tracked as a licensee identified violation and will be given an open item number. This item is considered closed. (50-289/90-06-01).
2.3 Low Power Reactor Trip A high flux automatic reactor trip occurred at 2:28 am on March 4,
1990.
Zero power physics testing (ZPPT) had just been completed.
A reduced high flux setpoint of 0.5% was still set in the reactor j
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protection system from ZPPT.
Boration was in progress to establish
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a -desired rod position (60% withdrawn on group 6) to support power j
escalation. Outward rod movement was required to compensate for the l
boron addition while maintaining reactor power at 3 X 10 E-8 amps in a
the intermediate range.
During the evolution, the operator received an outward rod stop when 2 rods in group 5 reached their "out" limits, while the remaining rods in group 5 had not reached their "out" limit. The.
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operator began to level group 5 to achieve full out indication.
The operator became absorbed in this evolution and did not
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carefully monitor reactor power. When the operator did check l
reactor power, he noted a steadily inmasing power level. He i
attempted to insert rods when the reactor tripped on Hi flux (0.425% reactor power).
The inspector-reviewed the plant incident report for this event.
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The inspector agreed with the licensee's findings that this event t
was due to personnel error. The licensee reviewed this event with
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the on-shift personnel stressing the need for attention to detail, particularly when reduced setpoints are in effect.
The licensee also
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i reviewed this' event with all other operating crews. The inspector i
reviewed the post trip review report and had no further questions or i
safety concerns, f
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2.4 Once Through Steam Generator (OTSG) Tube Leak j
On March 6, 1990 at approximately 9:00 am, the licensee received
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high radiation alarms on the RM-A-5 " condenser off gas monitor".
This is an indication-of a-primary-secondary leak in the OTSG.
The shift technical advisor performed a rough calculation for OTSG primary-secondary leakage using a mass balance method, and change in counts on RM-A-5.
The results showed the leak to be approximately 0.5 gpm. Although the Technical Specification limit of 1 gpm had apparently not been exceeded at this time, the operators commenced a shutdown of-the plant to cold shutdown conditions. The cooldown was completed on March 7, 1990. A resident inspector was on site when the event occurred and monitored the shutdown from the control _ room, i-The licensee's chemical analysis showed that the "A" 0TSG had a high boron concentration as well as high activity.
The "B" 0TSG exhibited-normal chemistry.
Chemical analysis results obtained following the shutdown revealed that the leak was in the "A" OTSG, and the actual leakage was in the range of 1.1 to 1.8 gpm (in excess of the technical specification limit).
During the event, the licensee dose projection due to noble ~ gases was 1,74 E-3 mrem whole body dose at the site boundary.
The licensee had a. radiological control technician take air samples at the south-east corner of the protected area (wind direction at the time of the event). These samples did not show any measurable increase in the dose rate at that location.
The licensee performed a bubble test on the "A" OTSG.
Tube failure was believed to be in the upper tube sheet region.
The bubble test includes filling the primary side of the OTSG to about one and one-half feet above the upper _ tube sheet and the secondary side water level is-approximately five feet below the upper tube sheet support plate.
Nitrogen pressure is applied to the secondary side' air space.
If there is a tube leak in the upper portion of the generator, nitrogen bubbles will be seen on the primary side. The bubble test indicated tube A77-1 was leaking.
Because the primary to secondary tube leakage actually exceeded the one gpm Technical Specification (TS) limit 4.19.3.c required the i
licensee to perform eddy current testing (ECT) on an additional 900 tubes selected on a random basis.
The licensee requested, and was granted by the NRC, a one time temporary waiver of compliance from TS 4.19.3.c. to allow-the inspection of selected rather than random tubes. The basis for this waiver was that the failure occurred in the lane wedge area of the OTSG where previous industry experience has detected corrosion, fatigue, and fretting wear..The licensee evaluation recommended that an inspection of this area would be more prudent than randomly selecting other sites.
This approach had been previously submitted to, and approved by the NRC, for Oconee 1,2, and 3 plants (B&W plants owned by Duke power).
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The tube failure (tube A77-1) was identified as a circumferential.
360 degree crack, believed to be caused by environmentally assisted high cycle fatigue.
The location of the crack-is the point at which the tube exits the bottom of the upper tube sheet.
This tube was ECT during the 8R outage, hcwever ECT inspection techniques may not identify high cycle fatigue precursor conditions unless performed just prior to tube failure.
This tube and one other were removed from service in the "A" 0TSG, raising the total number of plugged tubes in the "A" OTSG to 1267.
There are approximately 15,500 tubes in one OTSG.
The second tube was removed from service because of eddy current indications not related to high cycle failure.
A management meeting was held in Region 1 on March 13, 1990 concerning the OTSG leak rate; As described in the handout (enclosure 3), the licensee described their methodology for calculating primary to secondary leakage.
It was determined that the licensee's ability to accurately
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. calculate primary to secondary leakage at the beginning of a cycle is-limited due to the lack of buildup of activity in the primary coolant.
Because of this calculation, the licensee shut down the unit based on information that had an accuracy of about one gpm.
The licensee has committed to re-evaluate the information that is available to the operators in making the decision of whether the primary / secondary leakage has exceeded the technical specifications during initial startup when activity levels in the RCS are: low.
The inspector concluded that the licensee responded in a prompt and J
prudent manner in shutting down the plant.
The shutdown and plant cooldown were well controlled. A discussion of emergency planning and notification aspects of.-this event are contained in Section 6.0, below.
2.5 Turbine Trip / Reactor Trip During the plant recovery from the refueling outage, the OTSG levels i
were higher than expected for given power levels.
The unit was limited at 79% power due to a high level in the "B" OTSG. The level / power mismatch is due to secondary fouling in the OTSG's. The fouling is-believed to be caused by metal oxides originating in the feedwater system then depositing in the boiling region of the OTSG. Once these corrosion products deposit in the broach holes in the tube support
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plate, it increases the OTSG pressure drop causing in the water. level in the downcomer region to increase.
This level increase effects the feedwater heating accomplished in the downcomer region and places operational constraints on the unit.
The water level is reduced by reducing power level.
The licensee investigated four options to rectify this problem.
The first option was to operate the remainder of the cycle at a reduced power level.
In a letter dated March 30, 1990 from J.C. Devine,
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Director of Technical Functions, to the NRC, this option was deemed undesirable because operation at lower powers may contribute to high cycle fatigue (HCF) since OTSG tube loading results in higher amplitude tube vibration at reduced power.
HCF is believed to be the
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cause of the OTSG tube failure described in Section 2.4.
The second option is-the use of tiie " water slap" technique. This method was
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rejected due to the added thermal stress imposed on the OTSG during the cooldown. The water slap option:would not be available until early May.
The third option is the performance of chemical injection at power.
This method was rejected since insufficient data exists on the effects of the method.
The fourth option-is to indu e mechanical / hydraulic agitation of the OTSG in the form of a turbine trip / reactor trip at high power. The trip option has been performed once before with success.
This option was chosen by the licensee as
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the "best course of action".
F The licensee presented the information to the NRC during a conference call on March 28, 1990.
Representatives from Nuclear Reactor Regulation (NRR) and Region I participated. The licensee presented the options considered, sequence of events of the reactor trip, and staffing of extra personnel to support the trip.
The inspector reviewed the licensee's special test procedure (STP-027).
This procedure manually trips the turbine at high power causing an automatic reactor trip. After the unit has been stabilized in Hot Shutdown the emergency feedwater system is manually started and used to feed the OTSG's to 50's level in the operating range.
During this time, the reactor coolant pumps are secured and natural circulation cooling conditions are established.
The RCPs are secured for
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approximately.seven minutes and then be restarted.
The OTSG's will then be steamed to the low level limits.
The feeding / steaming cycle of the OTSG's using EFW may be' repeated at the discretion'of the
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operations director.
l The inspectors observed the plant trip on March 30, 1990 from the control room.
The inspector noted that the control room was well staffed with additional licensed operators and that all major control stations were individually manned.
The licensee also had extra off-shift personnel stationed at major components in the plant.
A briefing for all essential personnel was conducted by the shift supervisor and operations director. The inspector found this briefing to be adequate. At 5:00 pm, STP-027 was conducted.
p The plant response was normal. The post trip recovery was well L
coordinated and controlled by the shift supervisor and shift l
foreman in accordance with the approved reactor trip abnormal transient procedure.
The-inspector noted there was good control of the control room environment in that there was no unnecessary i
talking or activities that could distra'ct the operations crew in the post trip recovery.
The operators used the global silence alarm for the first time during the trip.
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alarm is a modification installed during the 8R outage that allows l
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the operator to silence the audible portions of all alsrms for five minutes. The alarms, however, still flash and_ indicate.on the main
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anr.unciator panels.
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The inspector observed the plant startup following the trip.
Power was maximized to calibrate the main feed flow input to the plant i
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computer core power output program. After completion of these tests, power was reduced to 97%.
In order for the unit to run at 97%, the licensee reset the delta TC bias in the integrated control system (ICS).
This allows the OTSG primary outlet temperature (reactor coolant cold leg temp Tc) in the "B" loop to be-bigher. - This results in the feedwater and steaming rate in the "B" OTSG to be reduced, and the feeding and steaming rate of the "A" OTSG to be increased. 1This value is normally set to 0 degrees F., however, OP 1101-2 " Plant Setpoints" allows the operators to set this bias value to 0+/- 5 degrees F.
The licensee has also defeated the OTSG high level main feed water isolation function in the neat sink protection system (HSPS).
This feature is designed to prevent overfeeding the OTSG's, and would normally isolatt main feed water to the affected OTSG.
The EFW actuation and MFW isolation, due to OTSG low pressure, are still enabled. The present configuration of the HSPS does not violate any technical specifications limiting conditions for operations (LCO) or place-the unit in any LCO action statements.
The reactor trip was well controlled and coordinated.
However, l inducing an unnecessary reactor trip to correct an operational problem is not considered prudent, due to the increase in risk by challenging safety systems and components.
3.0 Radiological Controls
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The inspectors observed routine activities associated with radiological control practices. These included dosimetry. control, exiting radiological control areas, routine surveys, and area radiation monitor operation.
No discrepancies were noted.
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4.0 Maintenance and Surveillance Observations On a sampling basis, the inspector reviewed-telected maintenance and surveillance activities to ensure that specific programmatic elements
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described below were'being met. Details of this review are documented i
in the following sections.
4.1 Surveillance Observations
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The inspectcr observed performance of the following surveillance tests to determine that: the test conformed to technical specification (TS) requirements; administrative approvals and
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tagouts were obtained before initiating the surveillance; testing was accomplished by qualified personnel in accordance with an approved procedure; test instrumentation was calibrated; limiting
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conditions for operations were met; test data was accurate and complete;-removal and restoration of the affected components was properly accomplished; test results met technical specifications and procedural requirements; deficiencies noted were reviewed and appropriately resolved; and the surveillance was completed at the required frequency.
These observations included:
Surveillance Procedure 1301-9.2 " Control Rod Program
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Special Check" Surveillance Procedure 1303-5.2 " Loading Sequence and Component
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Test and High Pressure Injection Logic Channel Test" No deficiencies were noted.
4.2 Reactor Coolant System Leak Rate Surveillance Following plant heatup after the completion of the 8R outage, the licensee initiated Reactor Coolant System (RCS) leak rate determinations per Technical Specification requirements.
The licensee utilized surveillance procedure SP 1303-1.1, " Reactor Coolant System Leak Rate" for this function.
Initial lhak rates calculated by the plant computer in the days following plant pressurization to normal operating pressure, indicated negative
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values in the range of -0.25 gallons per minute.
The inspector questioned the licensee on the calculations in light of the fact that a new computer had been installed during the outage and additionally the pressurizer level transmitters had been replaced.
The licensee provided an internal memo' dated February 22, 1990-
- 3310-90-0027 that documented a calculation using the new computer of a previous superimposed leak rate done in 1984 and calculated on the old computer.
The licensee's new computer calculated the same leak rate as the old computer, when corrections were.made for changes that have been made to the leak rate calculation program.
These changes included elimination of the evaporative loss term and addition of a correction factor for introduction of the No. 3 seal purge-
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for the four reactor coolant pumps (RCP). Additionally, review of the licensee calibration data for the pressurizer level instrumenta-tion revealed no inconsistencies,
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i Further licensee troubleshooting revealed that two of the four RCP seal purge regulating valves had failed in such a manner that water was entering the reactor coolant drain tank (RCDT) unmonitored.
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l This unmonitored input to the RCOT, if not accounted for in the calculation, would create a large negative leak rate. The licensee
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has commenced a modification to replace these valves and relocate the
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system flow' meters.
In the. interim, the licensee has made a change to the leak rate surveillance procedure to measure leak rates with flow secured to the #3 seals of the RCP's during the_two hour duration of.the test.
Using this method, leak rates that have been calculated have been near zero (in the order of
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Although some small negative rates are calculated, the near zero leakage is what would be expected after completion of an outage.
The inspector concluded that the licensee had properly evaluated this problem and corrective action for this anomaly in the RCS leak rate determination was taken in a timely manner.
4.3 Heat Sink Protection System Testing The licensee performed a surveillance test SP 1303-11.38 for the main feedwater system isolation function. The main feedwater regulating and block valves are isolated on OTSG high level or low pressure.
During trouble shooting efforts, licensee personnel removed two fuses that were intend d to isolate the 125 VDC control power for the regulating and bypass valves for the "A" OTSG, FW-V-16A/17A. When the fuses FD-1 and FD-2 on panel XCL-A were removed, the solenoid for MS-V-13A was de-energized, causing MS-V-13A to open and 45 seconds later, MS-V-13B opened due to.the time delay relay function.
This caused the steam driven emergency feedwater pump, EF-P-1, to start.
Because the flow control valves, (EF-V-30's) did not open, no water was added to the OTSG's.
Subsequent investigation by the licensee revealed that two electrical schematics 209-143 and 209-032 were incorrectly drawn.
It was not apparent that removal of the fuses would.cause the actuation of EF-P-1.
The licensee evaluated this situation as not reportable as the emergency feedwater system is not considered on ESF system at
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TMI.
The licensee initiated changes to the electrical schematics and also to operating procedure OP 1107-5, Electrical Distribution
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' Component Listing to note the change in fuse isolation function
'for the FW-V-16A and 17A valves.
The inspector questioned the licensee on the guidance in OP 1107-5 for isolation of the MS-V-13 valves. The licensee provided additional guidance that cautioned the operator on the removal of the fuses, for MS-V-13 A/B that could also cause denergization of the circuits for the feedwater regulating valves.
The inspector also questioned the licensee if this situation had been documented in a licensee evaluation such as the plant incident report or abnormal log entry evaluation per AP-1029.
The licensee responded that none of these methods was used but that the shift foremans' log had noted the situation.
It appeared to the inspector l
that this particular situation, due to its complexity, could have
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been more adequately reviewed and documented as a plant event even
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though the licensee assessment and final corrective action was
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complete and adequate.
This was communicated to the licensee management.
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4.4 Control Rod Drive Mechanism (CRDM) Motor Flange Gasket Replacement During the 8R refueling outage, the licensee inspected the condition of the CRDM motor tube flanges on the reactor vessel closure head to-identify if boric acid leakage occurred.
Results of this inspection indicated that fourteen (14) of sixty-nine (69) flanges had experienced a small degree of leakage. As a corrective action, the i
licensee decided to replace the existing asbestos gaskets with spiral wound stainless steel / graphite gaskets. The inspector determined, through review of supporting documentation, that using a replacement gasket material does not change the function or operability of the CRDM's or the gaskets.
Use of the graphite gaskets is authorized by a B&W Field Change Authorization No. 04-4585-00 and stress report No, 33-072-00 and 42-1020713-01. The stress report. certifies that this change meets the structural requirements of the B&W Design Specifica-tion for the=CRDM's and the ASME Boiler and Pressure Vessel Code,Section III, This' change is considered to be within the original design envelope for the CRDM's.
Through review of records, attendance at planning meetings, and interviews with licensee representatives, the inspector concluded r
that the licensee properly classified the activity as Nuclear Safety Related and performed the work in accordance with the requirements of the Quality Assurance Plan and approved procedures.
4.5 Maintenance Observations The inspector observed portions of selected maintenance activities to-determine that the work was conducted in accordance with approved.
procedures, regulatory guides, technical specifications, and industry-codes or standards.
The following items were considered during this review: limiting conditions for operation were met while components or systems were removed from service; required administrative approvals were obtained prior to initiating the work; activities were accomplished using approved procedures and QC hold points were established where required; functional testing was performed prior to declaring the particular component (s) operable; activities were accomplished by qualified personnel; radiological controls were
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implements; fire protection controls were implemented; and the i
equipment was verified to be properly returned to service:
These observations included the following maintenance activities:
Grour.d Problems on Reactimeter
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Reactor Building Fire Detector Alarm Failure
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Tube Plugging of "A" OTSG Tube 1-77 i
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Turbine Bypass Valve MS-V-3A Repair
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The inspectors reviewed maintenance observations and found that the licensee continues to perform maintenance observations adequately.
5.0 Security i
The inspectors observed routine site access controls including personnel i
and vehicle searches and adherence to vital area access requirements.
No.
'
discrepancies were noted.
6.0 Emergency Preparedness Unusual Event from OTSG Tube Leak
)
i On March 6, 1990, at approximately 9:00 a.m., the licensee received indication of a primary to secondary leak in the "A" Once Through Steam j
Generator (OTSG),
(See section 2.4 of this report for more specific l
details.) The NRC resident inspector, who was on site, was immediately
)
notified and proceeded to the control room.
Upon the resident inspector's arrival in the control room, the licensee briefed him regarding current plant conditions.
All information available to the licensee at the time regarding plant i
status indicated primary / secondary rate leakage was less than 1 (one) gpm.
Based on this information, the licensee did not consider current plant
status as having met the criteria necessary in declaring an unusual. event, i
As a result, the licensee did not immediately notify the NRC Operations
"
Center. The licensee, however, declared the event an item of public interest and made the appropriate notifications to the Commonwealth of..
pennsylvania and local governments. Between 9:00 a.m and 12:00 a.m., the i
licensee issued two press re?. eases related to the tube leak. At 12:09 j
a.m., the licensee made a notification to the NRC Operations Center and i
apprised the duty officer of the situation.
NRC regulations in Title 10 CFR 50.72 (b) (2) vi requires that "any event
]
or situation related to the health and safety of the public or onsite personnel, or protection of the environment, for which a news release.is planned or notification to other government agencies has been or will be made" be reported to the NRC Operations Center as soon as practical and in
all cases within four hours. Given the nature of the plant shutdown and the. notifications and press releases made by the licensee
during the event, the licensee did not' satisfy the "as soon as practical"
,
aspect of 10 CFR 50.72 (b) (2) vi. The subsequent media attention given
!
to the event is indicative of the potential for problems that can occur when notification of the NRC Operations Center significan% lags the licensee reporting of events to local agencies and the pr(
The
..
inspector discussed the issue with the licensee, who agreeo to review the
-
requirements with personnel responsible for making this notification.
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Based on subsequent discussions with plant management plant staff understanding this issue has been adequately addressed.
7.0 Engineering Support 7.1 Boric Acid Deposits on Vessel Head During the 8R outage, the licensee conducted a video inspection of the exterior reactor vessel (RV) closure head. The purpose of the inspection was to determine to what degree boric acid, originating from CRDM flange leakage had deposited on the head and to identify any corrosive damage.that may-have resulted.
Through the use of a remotely ~ operated video camera, virtually all of the RV head surface was examined. Six small patches of boric acid encrustations, varying in size from 1/2 inch to 6 inches across, were identified.-Following cleaning of these areas, the licensee assessed the condition of the affected area using Ultrasonic Testing (UT) and visual examination.
No detectable reduction of wall thickness, corrosion pits, or depressions were found.
From this-evaluation, the licensee concluded that nominal leakage onto the RV head during power operation did not result in significant metal loss.
The licensee intends to continue with follow-up inspections during the next refueling outage.
-7.2 Actions to Prevent loss of Decay Heat Removal (TI 2515/101)
NRC issued Generic Letter GL 88-17, dealing with Loss of Decay Heat Removal and requested short-term and long-term actions. The short-term actions were designated " expeditious actions" and are the subject of this inspection.
The licensee responded to the requested expeditious actions in a letter dated January 3, 1989.
These actions were reviewed by the NRC staff and comments were provided in a letter to the licensee dated June 29,-1989.
In addition to the technical review, the NRC staff conducted verification inspections to assess implementation of the licensee's commitment prior to and during the 8R refueling outage..This inspection included review-of procedure revisions and guidance to operations personnel, review of training activities including awareness of problems that have occurred at other facilities, and observation of operations during the 8R outage with regard to decay heat removal capability.
The licensee's response to the NRC's concerns indicates an
-
understanding of the issue and action to prevent loss of decay heat removal at TMI-1.
During the 8R refueling outage and a subsequent-unplanned outage due to a steam generator tube leak, the RCS was placed in mid-loop operation four times. No challenges to decay heat removal capability occurred.
NRC inspectors reviewed the administra-tive controls implemented by the licensee as well as the systems used to monitor RCS inventory.
The training conducted prior to the last two refueling outages emphasized problems that have occurred at
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l other facilities and how to avoid the problems at TMI-1. All I
personnel interviewed were aware of past problems at other plants and demonstrated a sensitivity for avoiding such problems at TMI-1. To'
,
ensure added sensitivity, the TMI-1 Plant Operations Director issued
'
memoranda to all operations personnel on August 1, 1989, December 27, 1989 and January 2, 1990 to discuss measures to control operations that could potentially affect capability to remove decay heat.
The Operations Engineering Manager has also been very active in
!
sensitizing all: plant personnel having a role in assuring that i
decay heat removal capability is not jeopardized. The inspectors
!
concluded that.the licensee has been very responsive to the NRC l
concerns regarding decay heat removal capability.
The NRC will j
assess-the long-range responses to GL 88-17 in a future inspection
!
report.
I
!
8.0 Open Items I
8.1 (Closed) Violation NC4 (50-289/89-17-02) Failure to Include
Turbo Charger Jacket Coolant Valves in Diesel Procedure OP71107-3 l
and Failure to Incorporate Vendor Information into Installation Procedure This violation concerned two examples of licensee failure to l
properly establish and implement procedures.
The licensee revised l
Operating Procedure OP 1107-3, to add the appropriate valves to the.
- ?
line up check list.
The inspector considered this change to be adequate. Additionally, the licensee has
.
initiated a program to ensure that vendor information received on
-
site is appropriately forwarded to the vendor document control
section, to ensure proper notification of maintenance. personnel, or incorporation into procedures, This action was adequate to resolve the violation and the item is closed.
8.2 (Closed) Unresolved Item (50-289/88-29-01) Licensee Review I
Program to Ensure Replacement equipment is compatible with System Requirements The licensee conducted an evaluation of practices to ensure that replacement parts and equipment which are purchased by site personnel are adequate for the intended use.
The licensee conducted a meeting which was documented in an internal memorandum dated August 18, 1989.
The licensee corrective action arising from this meeting included communications with the vendor to assure that more accurate information is provided with replacement parts.
Site engineering and technical functions were requested to provide greater emphasis on critical attribute identification on purchase orders. Receipt inspection personnel have increased their efforts in the areas of inspector training and programmatic inspection techniques to assure that material and items received are what was ordered.
P
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....
.
...
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.
-15
~The inspector toured the licensee receipt inspection facility and reviewed training records and capabilities. The inspector also observed that.the licensee was continuing to implement additional receipt inspection practices and enhancements to better assure-that parts received are what was intended.
Licensee corrective
action in this area was adequate and this item is closed.
i t
9.0 Management Meetings j
The inspector discussed the inspection scope and findings with licensee management weekly and at a final meeting on April 3, 1990.
Those personnel marked by an asterisk in paragraph 1.3 were present at the final management meeting.
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Enclosure'3-
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-50-289/80-06
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NRC/GPUN MEETING PRIMARY-TO SECONDARY LEAKRATE MARCH 13,1990 u
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NRC/GPUN MEETING PRIMARY TO SECONDARY LEAKRATE AGENDA MARCH 13,.1990 j
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NRC REGION 1 OFFICE
- l.
DEFINE ISSUES ll.
PERSPECTIVE ON LEAKRATE VALUE q
111.
LEAKRATE MONITORING PROCESS-IV.
. TECHNICAL BASIS OF QUANTIFICATION METHODOLOGY
.
V.
EVENT SEQUENCE l
VI.
CONCLUSION
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"lSSUE" l
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THE NRC. lS CONCERNED WITH THE.' ACCURACY-AND 1:
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- 1 SPEED OF DETERMINING THE-PRIMARY TO SECONDARY i
LEAKRATE.
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" OBJECTIVES OF MEETING"
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PROVIDE AN OVERVIEW OF PRIMARY'TO SECONDARY
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LEAKRATE MONITORING PROCEDURES ACTION LEVELS.-
,
EXPL.AIN THE METHOD AND TECHNICAL BASIS FOR PRIMARY TO SECONDARY LEAKRATE DETERMINATION.
REVIEW INFORMATION AVAILABLE TO OPERATORS.
REVIEW THE SEQUENCE OF THE MARCH 6,1990 EVENT.
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l-PERSPECTIVE ON PRIMARY-SECONDARY LEAKRATE VALUES
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LIMITS PROVIDE GUIDEPOSTS FOR IDENTIFYING APPROPRIATE PROTECTIVE ACTION a
LIMITS DO NOT REPRESENT ABSOLUTE VALUES AT WHICH SAFETY.lS COMPROMISED l
-
L LOW RCS ACTIVITY REDUCES SAFETY SIGNIFICANCE OF THESE VALUES l
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Page 6 of 24
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ACTION LEVEL:.
>6 GAL /HR ABOVE BASELINE
t SOURCE:
LICENSE CONDITION PURPOSE:
PROVIDE RAPID DETERMINATION OF INCREASE OF PRIMARY TO SECONDARY
LEAKAGE SO THAT APPROPRIATE REPAIRS CAN BE MADE, ACTION:
- SHUTDOWN
)
- TEST
- DETERMINE IF OTSG TUBE FLAW OR JOINT LEAKAGE
- MAKE' APPROPRIATE REPAIR L
L TIMING:
24 HOURS TO CONFIRM l
BASIS:
PRECLUDE TUBE FAILURE COINCIDENT WITH DESIGN BASIS EVENT l
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Page 7 of 24
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' ACTION LEVEL:
>1 GPM PRIMARY / SECONDARY LEAKAGE
'
SOURCE:
- TECH. SPEC. SECTION 3.1.6.3 EMERGENCY PLAN EAL 5.1.8 PURPOSE:
IDENTIFY LEAK REQUIRING SOME SPECIAL ATTENTION
- LIMIT OFFSITE DOSES BELOW 10CFR20 ACTION:
- COLD SHUTDOWN WITHIN 36 HOURS WHEN 1 GPM IS EXCEEDED PER TECH. SPECS.
- DECLARE UNUSUAL EVENT
- EVALUATE SAFETY IMPLICATION OF LEAK WITHIN 4 HRS OF DETECTION
- ENTER EMERGENCY PROCEDURES VIA ATP 1210-5 TIMING:
- REQUIRES STEADY PLANT CONDITIONS PRIOR TO SAMPLE
- REQUIRES 1 TO 2 HRS. ASSUMING A CURRENT APPLICABLE RCS SAMPLE ANALYSES BASIS:
- FSAR OFFSITE EXPOSURE LIMITS POTENTIAL FOR MEASURABLE OFFSITE DOSE VIA CONDENSER IF AT TECH. SPEC. RCS LIMIT
- RCS ACTIVITY LIMIT
- MINIMlZE PROBABILITY OF CRACK PROPAGATING TO TUBE RUPTURE-6-
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Page 8 of 24 I
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ACTION LEVEL:-
>50 GPM
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SOURCE:
- EMERGENCY PLAN EAL 5.1.B
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- ATP 1210-5 i
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PURPOSE:
- MINIMlZE POSSIBILITY OF INCREASING
-
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LEAKRATE
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ACTION:
EPlP ALERT DECLARATION
- TUBE RUPTURE ACTIONS OF ATP 1210 5
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.
i TIMING:
- RAPID ESTIMATE OF RCS LEAKAGE POSSIBLE
+
PRESSURIZER AND MU TANK LEVELS
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BASIS:
POSSIBLE 360* TEAR IN TUBE c
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Page 9 of 24
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l Primary To Secondary Leak Rate Monitoring Process
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Normal Operation Primary To Secondary Look wnhh Obtain Condweer
.-. san.....uncio6er Airm c.a.1 u. Ann OP 1102-2 4h Vocuum Pump
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Dischage Somple RtWW/ 18 m-AS-w condenser vecuum Plont Stortup
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SP 1301-1 Delbr Offgoe kob U
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Somple Leak Rote Offgoe Web Doly Checke SP 1301-1 E1 la Somple Look Rote P 1301-1 C1 IS
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SP 1303-1.1 Shutdown (omo Lashnes = 0)
n Shutdown PAGE 8
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Page 10 of 24
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PRIMARY TO SECONDARY LEAKRATE MONITORING PROCESS
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THE FOLLOWING ITEMS MAY BE PERFORMED BY THE CONTROL ROOM PERSONNEL BASED ON EXPERIENCE AND TRAINING:
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PERFORM OFF-GAS MONITOR LEAKRATE CALCULATION
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l-f EVALUATE VALIDITY OF RADIATION MONITOR INFORMATION AND i
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BASE A SHUTDOWN DECISION ON THE RADIATION MONITORS l
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Page 11 of 24
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i OTSG P/S LEAKRATE CALCULATION
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CONDENSER OFF-GAS METHOD
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THEORY-
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(OFF-GAS ACTIVITY) * (OFF-GAS FLOW)
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(RCS GAS ACTIVITY)
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i CONDENSER OFF-GAS ACTIVITY & FLOW MEASUREMENTS
OFF-GAS RADIATION MONITOR (RM A 5):
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BETA SCINTILLATOR TUBE IN A MONITORING CHAMBER MONITOR EFFICIENCY BASED ON XE 133 i
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YlELDS COMPOSITE ACTIVITY INDICATION
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i MARINELLI BEAKER SAMPLE AT ATMOSPHERIC CONDITIONS
-
COUNTED ON A GELI DETECTOR
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APPROXIMATEl.Y 1 TO 2 HRS TO GET RESULTS
-
YlELDS NUCLIDE SPECIFIC ACTIVITIES
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OFF-GAS FLOW MEASUREMENT:
THERMAL CONDUCTIVITY TYPE FLOWMETERS IN VACUUM PUMP EXHAUST
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RCS ACTIVITY MEASUREMENTS
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PROCESS
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PURGE SAMPLE LINE
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OBTAIN SAMPLE
-
STRIP GAS FROM SAMPLE
-
OBTAIN RCS DISSOLVED GAS CONCENTRATION
-
COUNT GAS SAMPLE IN GELI COUNTER
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l COUNT ANY REMAINING GAS ACTIVITY IN LIQUID
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REPORT RCS GAS ACTIVITIES
-
TOTAL EQUIVALENT XE-133
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INDIVIDUAL GAS ACTIVITIES
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APPROXIMATELY 2-1/2 TO 3 HRS TO GET RESULTS
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Page 15 of 24 OTSG P/S LEAKRATE SURVEILLANCE PROCEDURE
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SP 1301-1 ENCLOSURE I l
( PERFORMANCE OF THE OTSG P/S LEAKRATE CALCULATION IS )
" REQUIRED IF ALL OF THE FOLLOWING PLANT CONDITIONS
-
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ARE PRESENT: "
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1. RCS TOTAL EQUlv XE-133 ACTIVITY iS > 3E-1 uCl/ml.
2. OTOG'S ARE STEAMING TO THE TURBINE OR THE CONDENSER.
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3. AT LEAST 4 HRS HAVE ELAPSED SINCE THE LAST POWER CHANGE OF > 15%.
!
VALIDATION ITEMS:
'
1. CHECK FOR EQUIPMENT FAILURE OR HUMAN ERROR IN THE
-
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CALCULATION.
L 2. WAS THERE A CHANGE IN STEAM FLOW ?
i 3. WAS THERE A CHANGE IN OFF-GAS FLOW ?
l 4. WAS THERE A CHANGE IN THE RCS ACTIVITY
-
l-FROM THE LAST RCS SAMPLE ?
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CALCULATION INPUTS
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Approx. Calc impact i
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KEY INPUT DATA
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- MAKE-UP TANK LEVEL 30 gal /in.
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PRESSURIZER LEVEL 15 gal /in.
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- RCS TEMPERATURE 95 gal / F
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KEY ASSUMPTIONS i
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RCS IS AT STEADY STATE NO POWER CHANGES NO SIGNIFICANT PRESS / TEMP CHANGES
NO WATER ADDITIONS / WITHDRAWALS
TIME INTERVAL IS SUFFICIENT TO HAVE A MEANINGFUL MASS CHANGE i
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Page 19 of 24:
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RCS MASS BALANCE l
POTENTIAL ERROR ESTIMATES
Potential Error (gpm)
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TMI-1 SEQUENCE OF EVENTS
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3/6/90 PLANT SMUTDOWN
,
Initial Conditions:
TMI-1 operating at 75% steady power in 30 hour3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br /> hold for restart physics testing.
3/6/90 0801 Hrs RM-A-5 and RM-A-15 begin to increase above their steady value of 100 cpm.
This change was recognized on 3/7/90 during the event review.
0805 Hrs RM-G-26 begins to increase above its steady value of 20-60 cpm.
This change was recognized on 03/07/90 during the event review.
,
0823 Hrs Computer and main annuciator alert alarm for RM-G-26
received in the Control Room.
This is the first recognized indication of activity changes in the OTSG'S.
0834 Hrs SS, Plant Ops Director, Plant Engineering Director and V.P. TMI-1 briefed in the Control Room of all indications of RCS leakage.
0835 Hrs Radiological Controls supervision manned in the TMI-1 control Room and by 0841 Hrs the first offsite dose projection indicated no EAL criteria met.
OS43 Hrs RCS leakrate calculation initiated on the plant
computer per SP 1303-1.1.
0853 Hrs RM-A-5 offgas grab sample obtained.
0900 Hrs Plant Operations Director briefs the NRC Resident Inspector by telephone of the RMS indications and their significance.
Preliminary indications from
.
rough calculations indicate less than 0.5 gpm leakrate by RCS mass balance and 0.5 to 0.75 be estimates of
_'
make-up tank decrease.
,
0905 Hrs The V.P. of TMI-1 contacts the President of GPUNC and briefs him of the TMI-1 status relative to the indications of a primary to secondary tube leak.
The V.P. of TMI-1 indicates to the President of GPUNC that a plant shutdown is probable.
0911 Hrs The Plant Operations Director and Plant Engineering Director recommend that a plant shutdown commence.
The V.P. of TMI-1 concurs and the order to shutdown the plant is given to the Plant Operations Director.
An Event of Potential Public Interest is declared due to the plant shutdown order and as a result of the indications of minimal activity in the "A" OTSG.
i Appropriate parties are notified in accordance with l
AP 1044.
An Emergency Action Level (EAL) declaration is not initiated since criteria for an EAL is not met.
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Page 22 of 24
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0912 Hro. Pltnt chutdtwn c:mm0nc33 ct cbout 2% per Qinuto.
- -
0912-0926 Hrs The Manager Nuclear Safety contacts the operations Engineering Manager in the Control Room to confirm that the plant shutdown was not a result of unsafe RCS leakage or as a result of exceeding a T.S. LCO for RCS leakage.
0917 Hrs NRC Resident Inspector arrives in the THI-1 Control Room and is appraised of current plant conditions.
j 0925 Hrs The V.P. of TMI-1 notifies the Pennsylvania State i
Representative of THI-1 shutdown due to activity
detected in the "A" OTSG.
i 0926 Hrs 'The Manager Nuclear Safety arrives in the SS office to
!
confirm that the plant shutdown is not considered to be required by Technical Specifications.
0943 Hrs The 1 Hour RCS leakrate results are available but invalid due to the plant shutdown transient.
'
0958 Hrs The Turbine Generator is taken off line.
1035 Hrs The Plant Operations Director contacts the Resident NRC Inspector and it was decided that plant status update information by Red Phone communications was not-required at this time.
1042 Hrs The reactor is subcritical and RMS indications continue to decrease from the time that reactor
,
shutdown commenced.
l 1200 Hrs The Manager Nuclear Safety arrives in the Control Room L
to discuss the need for a 10CFR50.72 report based on an earlier GPUN press release.
1210 Hrs Based on the above discussion, the Plant Operations i
Director provided an update of plant status to the NRC
.
via Red Phone.
l 1433 Hrs Secured RC-P-1A and commenced a normal RCS Cooldown after having met normal cooldown prerequisites.
.3/7/90 0641 Hrs Initiated DHR on
"B" DHR string.
!
0730 Hrs RCS is in cold shutdown.
1825 Hrs Red Phone notification is made by the Manager Nuclear Safety to the NRC to explain that the RCS calculated leakrate, based on all data retrieved from the event, indicates an initial RCS leakrate of 1.1 - 1.8 gpm.
The Manager Nuclear Safety indicates that if this had been known an EAL would have been declared and a shutdown, based on an LCO violation, would have been initiated.
3/8/90 1725 Hrs RCS at atmospheric pressure and drain down of RCS l
commences.
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CONCLUSION
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o PRIMARY TO SECONDARY LEAKRATE MONITOAING INFORMATION
AND PROCEDURES ARE ADEQUATE:
!
I PROCEDURES ARE ADEQUATE FOR STEADY STATE AND
'
-
EMERGENCY CONDITIONS
'
INACCURACY OF PRIMARY TO SECONDARY LEAKRATE
-
!
DETERMINATION WITH-LOW PRIMARY COOLANT ACTIVITY
'
,
WAS ANTICIPATED.
i ALTERNATIVE METHODS ASSURE DETECTION.
CONCLUDE; PROCEDURE IS ADEQUATE AND INFORMATION IS
.
SUFFICIENT l
.
t o MUST WElGH THE MERITS OF OPERATING THE PLANT AT POWER TO GET A VALID LEAKRATE VS PLACING THE PLANT IN A SAFER CONDITION (SHUTDOWN)
CONCLUDE:
PROMPT SHUTDOWN ACTION MAY PRECLUDE OBTAINING A VALIDATED PRIMARY TO SECONDARY LEAKRATE
,
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TSS 1/90 Page 24 of 24 MARCH 13, 1990 MEETING WITH GPU
'1
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-PRIMARY TO SECONDARY LEAK CALCULATION
'
NRC Participants E. Wenzinger Chief, DRP
.
R. Hernan Acting Section Chief, DRP J. Strosnider Chief, DRS A. Lohmeir Reactor Engineer, DRS R. Winters Reactor Engineer, DR$
-W. Johnston Deputy Director,.DRS J. Kottan Laboratory Specialist, DR$$
J. Jang.
Sr. Radiation Specialist, DRSS F. Young Senior Resident Inspector, TMI W.l015en Reactor Engineer, DRP J. Trapp Sr. Reactor Engineer, DRS W. Ruland NRC Participant
.
'GPUN Participants H. Shipman-GPUN/ Ops. Engineering Mgr.
J..Colitz GPUN/ Plant Engineering Dir..TMll R. Shaw GPUN/ Radiological Control Dir.
H. Crawford.
GPUN/TMI' Fuel Projects M..Sanford-GPUN/T.F. Eng. and Design T. Broughton GPUN/ Director O&M, TMI)
R. McGoey-GPUN/ Manager /Pwr Licensing G. Capodanno GPUN/ Director Engineering and Design L. Lanese GPUN/Mgr.', Mech. Systems D. Bowman GPUN/ Material Engineering.
L S. Giacobbe GPUN/Mgr. Mat. Engineering Commonwealth of Pennsylvmia Participants R. Cook PA DER /Pwr Group Leader L
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F. Young--
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INSPECTOR'S REPORT
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R.-Brady Docket #/ Inspection #/ Sea. #:
D. Johnson 50000289/90-06 (A)
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licensee / Vendor:
Transaction Type:
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Middletown,-PA 17057 0 - Delete
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Organization Code
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Period of Inspection:
Inspection Performed By:
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From To Region Office Staff Region Division Branch X ResidentInspector(s)
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,4/3/90 Performance Appr. Team RI B
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N/A-N/A
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, r MODULE INFORMATION - A/B/C/D
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-Complete Status
B-01 530703
~2 N/A N/A B-02 571707 165.30 100 CL
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CL-B-04 562703:
80 CL
'B-05 571715
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.B-06 537828 21,5 100 CL B-07 593702-
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OUTSTANDING ITEMS FILE I
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SIW5LE DOCKET ENTRY FORM
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SUMMARY
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' Docket / Report No.:' 50-289/90-06 Originator: D. Johnson-
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Report Period: 02/27/90 - 04/03/90 Reviewing Supervisor: J. Stewart ho rep 0RT-HOURS /NO. OF FINDINGS (V#/U/F/M
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f L-1. Operations-(PLT)
7. Outages (REF)
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This was a routine safety
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X OI History Updated
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~ T 766 Complete
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