IR 05000315/1989018
| ML17328A092 | |
| Person / Time | |
|---|---|
| Site: | Cook  |
| Issue date: | 06/20/1989 |
| From: | Burgess B NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML17328A091 | List: |
| References | |
| 50-315-89-18, 50-316-89-18, IEB-79-14, IEB-89-001, IEB-89-1, IEIN-89-044, IEIN-89-44, NUDOCS 8908070392 | |
| Download: ML17328A092 (32) | |
Text
U.
S.
NUCLEAR REGULATORY COMMISSION
REGION III
Reports No. 50-315/89018(DRP);
50-316/89018(DRP)
Docket Nos.
50-315; 50-316 Licensee:
American Electric Power Service Corporation Indiana Hichigan Power Company 1 Riverside Plaza Columbus, OH 43216 Licenses No.
Donald C.
Cook Nuclear Power'Plant, Units 1 and
Inspection At:
Donald C.
Cook Site, Bridgman, Hichigan Inspection Conducted:
April 26 through June 6, 1989 Inspectors:
8.
L. Jorgensen R.
N. Sutphin D.
G.
Passehl F.
A. Maura J.
K.
He ler
"oproved Oy:
,
.
urg s, Chief
)
Prospects Section 2A s ection Summar Date Zd/Z Ins ection on A ril 26 throu h June
1989 (Re orts No. 50-315/89018 DRP);
No. 50-316 89018 DRP t
inspectors of; actions on. previously identified items; plant operations; radiological controls; maintenance; surveillance; security; outages; safety assessment and quality verification; reportable events; NRC Bulletin, Allegation; and, NRC Region III requests.
No Safety Issues Management System (SIHS) items were reviewed or closed during this inspection.
Results:
Of the twelve areas inspected, no violations or deviations were indent fied in any areas One.Unresolved Item was identified (and 1s d1scussed in Paragraph 6) in the surveillance area.
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DETAILS 1.
Persons Contacted
"W. Smith, Jr., Plant Manager A. Blind, Assistant Plant Manager, Administration
"J. Rutkowski, Assistant Plant Manager, Production
~L. Gibson, Assistant Plant Manager, Technical Support
"B. Svensson, Licensing Activity Coordinator K. Baker, Operations Superintendent
"J.
Sampson, Safety and Assessment Superintendent E. Morse, gC/NDE General Supervisor
"T. Beilman, IBC Department Superintendent J. Droste, Maintenance Superintendent T. Postlewait, Technical Superintendent, Engineering L. Matthias, Administrative Superintendent J. Wojcik, Technical Superintendent, Physical Sciences
"M. Horvath, equality Assurance Supervisor D.
Loope, Radiation Protection Supervisor D. Climer, Performance Engineer
"P. Barrett, Director of equality Assurance, AEPSC
~Denotes some.of the personnel attending Management Interview on June 9,
1989.
I The inspector also contacted a number of other licensee and contract emp'loyees and informally interviewed operations, maintenance, and technical personnel.
2.
Actions on Previousl Identified Items 92701 92702)
a.
Closed)
0 en Items 315/82008-01 316/82008-01 315/82008-02; 316 82008"02
82008-06'16 82008-06'15 82008-11 316 82008-11 315 82008-13'16 82008"13'15 82008-14'16 82008"14 These items all involve hardware and procedures for plant fire protection which were found inadequate to meet the requirements of Technical Specifications or of 10 CFR 50 Appendix R, despite an apparent licensee claim of compliance to the latter in his letter dated March 27, 1981.
The items are subject to two types of additional action by NRC:
further inspection to determine current compliance, and enforcement action for past failure to comply.
Further inspection has been incorporated into a programmatic NRC team inspection process being conducted at all plants.
No "open" items are required to assure completion of this reinspection.
Concerning enforcement, the NRC
Office of Enforcement, rather than NRC Region III, now has the responsibility for any further Agency action, so a Region III
"open" item is not necessary.
Closed)
Unresolved Item 315/87023-01):
Loss of configuration control RCP hatch cover bolting during original construction.
This issue applied to both Units, was reviewed and "closed" in Inspection Reports No. 315/88017(DRP);
No.
316/88020(DRP)
but, due to administrative oversight, only the Unit 2 (Docket 316) item was removed from the tracking list.
This entry corrects the oversight.
Cl osed)
0 en Item 315/87026-02 316/87026-04):
Discrepanci es apparently overlooked sn I. E.Bulletin 79-14 walkdowns.
Additional NRC review in this area has raised further questions about the thoroughness or effectiveness of piping reviews conducted pursuant to the referenced Bulletin.
This has resulted in creation of a
"new" Unresolved Item (315/88028-03; 316/88032-03)
implicating the adequacy of the I.E.Bulletin 79-14 program.
Further, the licensee himself found and reported (reference LER 316/89002)
a long-standing problem which might have been identified much sooner during Bulletin 79-14 work.
Finally, apparently due to inspection prompted by the LER, still another deficiency (reference Paragraph
"Maintenance" ) was found.
See also Paragraph ll, "NRC Compliance Bulletins."
Multiple tracking numbers are not appropriate for the inspection of a single (but potentially broad) problem.
This topic will be tracked by review of the LER No. 316/89002 and the Unresolved Items 315/88028-03; 316/88032-03.
This redundant older item is administratively closed.
Closed)
0 en Items 315/87031-01 316/87031-01):
Upgrading of replacement parts from commercsa to nuc ear" grade needs review.
This has become a generic industry concern for which NRC is implementing specific generic inspections at all plants.
Plant specific "open" items are unnecessary to insure completion of this generic inspection process.
Closed 0 en Item (315/88027-01):
Evaluate bases and criteria for abandoning local va ve position indicator dials "in place".
The licensee contacted the vendor (Limitorque Corporation)
who recommended either removal or repair.
The process of abandonment in place (by painting over the dial) was terminated.
The applicable preventive maintenance procedure was modified to accomplish inspection of the dial indicator as part of each periodic maintenance activity.
Broken or damaged indicators, including any previously abandoned, will be either repaired or removed, as recommended by Limitorque.
For dials to be removed, custom covers have been designed for installation as a cleanliness seal.
A job order search is determining which valves already have painted-over indicators; corrective job orders will address those firs f.
(Closed) Violation 316/89007-01):
Failure to maintain proper valve lineup as described 1n the CILRT test procedure.
The inspector reviewed surveillance procedure 1THP 4030 STP.202,
"I.L. R.T.," Revision 1, and determined that it incorporated the corrective. actions stated by the licensee in their letter (M.
P. Alexich to A.
B. Davis) dated April 12, 1989.
This item is considered closed.
g.
Closed 0 en Item 315/89007-02 316/89007-03):
Recalculate as-found and as-eft ype B and C test resu ts using maximum pathway methodology for last Unit 1 refueling outage and for the 1989 and previous Unit 2 refueling outages.
The licensee recalculated the Type B and C test results and communicated the results to the inspector on March 17, 1989, and also in their letter (M.
P. Alexich to A. B. Davis) dated April 12, 1989.
LER Nos.
89-004-00 (Unit 1)
and 89-005-00 (Unit 2) were also submitted.
Using the correct methodology the Type B and C test results failed the 10 CFR 50, Appendix J criteria of 0.6 La in the as-found condition, but were well within the acceptance criteria in the as-left condition.
This item is considered closed.
No violations, deviations, unresolved or open items were identified.
3.
0 erational Safet Verification (71707 71710 42700)
Routine facility operating activities were observed as conducted in the plant and from the main control rooms.
Plant startup, steady power operation, plant shutdown, and system(s)
lineup and operation were observed as applicable.
The performance of licensed Reactor Operators and Senior Reactor Operators, of Shift Technical Advisors, and of auxiliary equipment operators was observed and evaluated including procedure use and adherence, records and logs, communications, shift/duty turnover, and the degree of professionalism of control room activities.
Evaluation, corrective action, and response for off normal conditions or events, if any, were examined.
This included compliance to any reporting requirements.
Observations of the control room monitors, indicators, and recorders were made to verify the operability of emergency systems, radiation monitoring systems and nuclear reactor protection systems, as applicable.
Reviews of surveillance, equipment condition, and tagout logs were conducted.
Proper return to service of selected components was verified.
a.
Unit 1 remained in a scheduled outage throughout the inspection period. Potentially significant matters included problems with the Unit's emergency diesel generators (see Paragraph 5) and problems'ith reactor core reload (see Paragraph 8).
b.
Unit 2 continued in routine power operation throughout the inspection period.
The power run following an 11-month outage for steam generator replacement has continued without interruption since generator synchronization on March 17, 1989, though there have been some interesting operational developments:
By late April, it became evident that the historical containment pressure behavior pattern was not occurring - it had not developed that gradual accumulations of nitrogen and air had resulted in increasing containment pressure.
During previous operating cycles, this pressure buildup had required (because of procedural and Technical Specification limits of 0. 1 and 0.3 psid versus atmospheric pressure)
almost daily pressure relief.
Problem Report 89-520 documented the situation for investigation, and a licensed SRO was dedicated to the "search" for the cause of the condition.
This approach succeeded when a pair of automatic isolation valves on a ventilation unit drain line were identified as the leak source after a fairly exhaustive investigation.
The subject line had lost its normal liquid loop seal and so had become an air-to-air leak path.
Although containment integrity was maintained in these conditions, the licensee isolated the
'ubject penetration and diverted the drainage to a sump.
(2)
(3)
On May 10, 1989 a turbine runback occurred during performance of an instrument surveillance procedure on power range nuclear instrument N-43 (Loop 3).
Electrical load decreased from 1135 MWe to about 1050 MWe.
At the time of the runback, the over-temperature (OT) and over-power (OP) Delta T circuits were tripped for Loop 3, per the surveillance procedure, and a
spurious spike was received on Loop 2.
This initiated the runback on a two out of four coincidence of Delta T within 3-percent of the reactor trip setpoint.
The cause of the runback was attributed to a faulty test switch or relay fai lure.
Connections were checked for tightness and the suspect relay was monitored with no abnormalities being noted.
The test switch and relay are scheduled to be replaced during the next outage.
A "Task Force" investigation was begun on May 3, 1989 into the gradual increase of reactor coolant system unidentified leak rate.
This rate had showed an increase from 0. 15 gpm after startup in mid-March, to about 0.45 gpm by mid-May, ten weeks later.
Technical Specifications limit this type of leak rate to 1.0 gpm.
The plant investigated a number of areas (to determine leakage path and quantity) with mixed results.
Leakage contributors from the containment pipe tunnel and sump, the reactor coolant drain tank (RCDT), and various auxiliary
(4)
building penetrations were quantified (the largest being that leaking to the RCDT) such that actual "unidentified" leak sources total less that 0.4 gpm.
Efforts to locate and repair major contributors with the Unit in service were unsuccessful.
The plant continued to monitor the leakage daily, and scheduled an outage for June 10-12, 1989, for inspection of areas not otherwise accessible for inspection.
The scheduling of a Unit shutdown with this parameter changing very slowly and at less than half the Technical Specification limit is indicative of a safety conservative operating philosophy.
Means for conveying and executing this philosophy to plant operators, to ensure they have unequivocal guidance, was discussed with plant management in light of the fact that no specific administrative limit exists for this (unidentified leakrate)
parameter.
This resulted in a commitment from the Plant Manager to develop and promulgate a specific numerical or rate-of-change limit for operator use.
Level control problems with No.
3 steam generator required the operators to pay very close attention to this parameter.
'evel is normally maintained at 44-percent with a level deviation (low) alarm actuation at 39-percent.
In several instances, the operators caught level slowly falling to 41-percent or 40-percent in time to avoid the alarm.
On some occasions level was then soon returned to the auto controller and on others the manual mode was used to restore and maintain level.
The plant believed the problem was with the feedwater regulating valve controls, and adjustments appeared to improve the situation.
Further work is planned for the next scheduled outage.
An ongoing project to re-engineer the Unit 2 control room annunciation system, such that no annunciators will be lit during routine full power operation, was essentially completed during this inspection period.
This "black board" concept was not an original design basis.
In fact, scores of annunciators were lit during routine power operations (each control room has over 1,300 annunciators)
by original design.
Final work is pending to clear the three annunciators remaining in Unit 2.
A similar project in Unit 1 is likewise nearing completion as that Unit prepares for startup'from its current outage.
Some items of interest were noted during inspector tours and were passed on to the plant for followup action.
Among these were:
Turbine Driven Auxiliary Feedpump (TDAFP) room doors - only one door was found."ajar" vs.
two as specified by Plant Manager Standing Order PMS0.064,
"Administrative Requirements for Control Room and Auxiliary Feed Pump Room Doors".
The problem
was corrected immediately.
The purpose of the stipulation in the PMSO is to limit heat buildup from any steam leaks or breaks in the room, neither of which actually occurred.
The inspector noted the "closed" door was not latched closed, so it would have been free to swing open for a significant steam line break in the room.
Since operators tour this area every shift, the duration of the condition was limited to a few hours.
(2)
Unit 1 ice basket replenishment, utilizing procedure 12-OHP 4021.010.005,
"Operation of Ice Making and Transport System",
was observed.
The system was in automatic operation with no operators present.
Two contract personnel were present and were monitoring the system.
A review of the procedure established that non-operations department personnel may be authorized to operate the system if they have received necessary briefings.
A verification check established the authorization and briefings had been conducted, but the contractor personnel had been instructed to limit themselves to monitoring the system in operation, not to operate it.
This satisfied the inspector.
The copy of.the procedure present at 'the ice making machinery control panel was briefly reviewed; this was not a procedure mandated to be present.
The procedure was missing at least one page, several pages were tom and one was in the wrong sequence, and the attached lineup sheets contained no entries recording valve lineup.
The inspector sought out the
"controlling" procedure and selectively verified proper lineup.
The Operations Department was informed of the poor condition of the procedure noted above; appropriate actions were taken.
A seismic gap seal - basically, an elastic/rubber seal over the small gaps designed between seismic Category 1 buildings or building sections - was missing from a location in the Unit 2 startup flash tank (SUFT) room identical to that in the Unit 1 SUFT room where a seal is installed.
Follow up disclosed the subject gap is not required to be sealed for drainage, ventilation, or fire protection (smoke control) reasons, which form the bases for installation of these seals.
No violations, deviations, unresolved or open items were identified.
4.
Radiol o ical Controls 71707 During routine tours of radiologically controlled plant facilities or areas, the inspector observed occupational radiation safety practices by the radiation protection staff and other worker Effluent releases were routinely checked, including examination of on-line recorder traces and proper operation of automatic monitoring equipment.
Independent surveys were performed in various radiologically controlled areas.
a0 b.
C.
d.
No The inspector attended meetings between NRC Region III and the licensee concerning potential deficiencies in posting and control of an "extreme high" radiation area (a problem originally documented on the licensee's Problem Report No.88-849)
and concerning the licensee s investigative, corrective and preventive actions.
The meeting topics and concerns expressed by NRC on this matter are documented elsewhere.
Subsequently, the licensee re-opened his investigation on Problem Report 88-849 by direction of the responsible Assistant Plant Manager, and initiated additional preventive measures; NRC (Region III and the resident inspectors)
was informed concerning these actions.
Problem Report PR 89-529 documented discovery of a small (curved, 1-inch arc) piece of metal on the reactor vessel flange.
The radiation protection section was promptly notified, and they performed a survey and provided technical input prior to capture of the piece.
The survey showed contact dose readings of around 3 R/hr, a level not requiring special handling measures.
Consultation with radiation protection prior to handling is indicative of an appropriate sensitivity (in this case)
to the extremely high radiation levels which can be associated with innocuous-looking pieces from in or around the reactor.
Several Problem Reports, including 89-670,89-676 and 89-679, showed an increasing emphasis on eliminating personnel contaminations by focusing on individuals who become contaminated more than once.
One case involving a contractor employee was classified as a
"significant adverse trend" because the individual had four contaminations in the Calendar year through May, 1989.
Another example, involving repetitive failure (twice on the same shift) to follow good work practice instructions, resulted in the subject individual being discharged.
Licensee efforts to prevent "hot particle" problems, as experienced occasionally throughout the industry, included utilization of strippable paint to coat the Unit 1 refueling cavity for core offload and reload.
The process has served to control contamination areas to some degree by concentrating it.
Handling of the paint
"skin" during and following the stripping process then becomes critical, and the licensee experienced at least one problem (coordinating ventilation usage)
in that evolution for which appropriate corrective action reviews have been initiated.
violations, deviations, unresolved or open items were identifie.
Maintenance 62703 42700 Maintenance activities in the plant were routinely inspected, including both corrective maintenance (repairs)
and preventive maintenance.
Mechanical, electrical, and instrument and control group maintenance activities were included as available.
The focus of the inspection was to assure the maintenance activities reviewed were conducted in accordance with approved procedures, regulatory guides and industry codes or standards and in conformance with Technical Specifications.
The following items were considered during this review: the Limiting Conditions for Operation were met while components or systems were removed from service; approvals were obtained prior to initiating the work; activities were accomplished using approved procedures; and post maintenance testing was performed as applicable.
The following activities were inspected:
A tour of the Unit 2 West main steam isolation and safety valve enclosure identified significant amounts of extraneous materials (tools, bags, chain hoists, electrical cable, a folding table) which appeared to have been left behind from one or more of the numerous maintenance activities done in the area during the Unit outage which ended weeks earlier.
Further, there was considerable insulation lying about uninstalled.
Plant management was informed of the conditions.
A total of five "open" Job Orders were found applicable to various insulation activities.
Completion of these jobs as the schedule permits will clean up the insulation conditions.
The remaining items were documented for investigative and corrective action, and subsequent tours found evidence of a gradual cleanup of the various items.
b.
Job Orders (JO) 722657/722658:
"Perform check valve inspection per SOER 86-03 and change out body-to-bonnet studs and nuts."
The work was performed on RHR pump discharge check valves 1-RH-108E and 1-RH-108W.
Three Problem Reports (PR) were generated on one or more of the valves (89-567,89-574, and 89-581)
from May 2-4, 1989.
The PRs are related in that they describe a case where work activities should have had better planning.
Separate JO packages were written to change out the body-to-bonnet and block retaining studs or nuts or both, in addition to disassembly and inspection of seating surfaces.
Problems developed when the JO packages were not routed together such that all the work would be completed before valve reassembly.
The result was that the Construction Department performed the body-to-bonnet fastener changeout and seating surface inspection, and reassembled the valves.
Then the Maintenance Department disassembled the valves shortly thereafter and did the block retaining fastener changeout and duplicate seating surface inspection.
This situation evidenced a need for better coordination and planning between Maintenance and Construction Department A follow up inspection was made in the Unit 1 "CD" battery room after completion of work involving replacement of the associated chargers.
A previous inspection (Reports No. 50-315/89014(DRP);
No. 50-316/89014(DRP)
had noted concrete dust accumulation throughout the room and all over the battery assembly.
The follow up inspection found the dust had been completely cleaned up.
Job Order JO A011959: modify hanger 1-AFW-R929.
The "modification" of this auxiliary feedwater piping system hanger was actually to conform the hanger to original design.
It had been found to deviate from design during inspections conducted in follow up to discovery of a damaged pipe support in the safety injection piping system - a matter reported to NRC in the licensee's Licensee Event Report 316/89002.
As noted in Paragraph 2.c above and discussed further in Paragraphs 10 and ll below, these findings may indicate deficiencies in the licensee s implementation of actions for I.
This requires further inspection.
During this inspection, the licensee discovered damage to the "A" low pressure turbine rotor in Unit 1, which was not schedul'ed for overhaul this outage. 'he damage was indicative of a small foreign object impacting a few of the blades and the shroud associated with the twelfth stage.
The inspector made occasional inspection of the blade replacement and shroud repair.
Further inspection by the licensee after the turbine cover was removed for the repair showed no additional damage.
The foreign object was not located or otherwise identified.
On April 10, 1989, the Unit 1 "CD" emergency diesel generator oversped upon disconnection from its bus.
Subsequent NRC evaluations of this event were performed by the resident inspector office (reference Inspection Report 315/89014(DRP);
316/89014(DRP),
by Region III (to be documented separately),
and by the Office of Nuclear Reactor Regulation (NRR).
The overall emphasis on these inspections was toward understanding the root cause of the problem and verifying adequate and appropriate corrective and preventive actions.
At the conclusion of the inspection period, reported upon herein, these efforts remained incomplete.
The resident inspector office conducted some inspection activities in parallel to the above, as follows:
(1)
Job Order JO A000273: plant instrument and control group de-termination (and subsequent re-landing) of electrical connections as required for removal and replacement of the 1CD diesel generator rotor.
The licensee utilized existing administrative mechanisms in the form of procedure PNI-1190 Attachment 4 "Lifted Wire Form" to precisely document both the performance of the activities and their independent verification.
Several hundred disconnection/re-connections were completed without error.
(2)
Job Order JO A005765: civil and mechanical support from contractor to remove 1CD diesel generator rotor and install a
new rotor.
Activities covered included removing the diesel room end wall, fabricating and erecting special rigging frame and cribbing, moving the rotors, and post-job restoration.
The inspector observed various of these activities and reviewed the associated documentation package.
Appropriate generic procedures were used where applicable, and appeared to be properly followed and documented.
A "guideline" was used,
.
however, in lieu of an approved procedure, to provide specific instructions for rigging and moving the rotors.
The use of guidelines for activities which can affect the performance of safety-related equipment is a current enforcement issue, for which the licensee is still developing corrective/preventive action, so no detailed review was made in this case to classify whether or not this was a legitimate or proscribed use of a guideline.
(3)
Job order JO A000274: electrical support from contractor on 1CD diesel generator rotor replacement.
This activity primarily addressed electrical interference removal (conduit and cabinet)
for heavy equipment movement, and subsequent restoration.
(4)
Meggaring of the removed rotor was observed, in part, prior to its return to the vendor (General Electric) for more detailed testing and - if required - repair.
All resistances measured at greater than 40 mega-Ohm, indicating an absence of any insulation damage or displacement.
g.
Some portions of the repair activities associated with emergency diesel generator
"AB" (in Unit 1) were observed.
This diesel apparently experienced governor problems during and after a test run, then twice tripped out on overspeed on verification testing attempts after adjustment.
NRC Region III included evaluation of this issue in its reviews associated with the
"CD" diesel referred to above.
The results of the Region III inspection are being documented separately.
No violations, deviations, unresolved or open items were identified.
6.
Surveillance 61726 42700)
The inspector reviewed Technical Specifications required surveillance testing as described below and verified that testing was performed in accordance with adequate procedures, that test instrumentation was calibrated, that Limiting Conditions for Operation were met, that removal and restoration of the affected components were properly accomplished, that test results conformed with Technical Specifications and procedure requirements and were reviewed by personnel other than the individual directing the test, and that deficiencies identified during the testing were properly reviewed and resolved by appropriate management personnel.
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The following activities were inspected:
Eddy current examination activities were periodically observed by the inspectors.
Westinghouse's examination of Unit 1 steam generators began April 23, 1989 and was completed May 1, 1989.
All previously non-plugged tubes were analyzed averaging roughly 3300 tubes per generator.
Conservative steam generator tube plugging criteria were applied similar to that of a July 1987 Eddy current inspection.
The result was that a total of 281 tubes were plugged, of which 23 were plugged based on Technical Specification requirements (greater than 40-percent degradation).
Some equipment breakdowns occurred and had some schedular impact, but there were no major problems.
b.
Revisions to licensee procedures 1 and
OHP 4030 STP.Oll,
"Containment Isolation and ISI Valve Operability Test," which addressed observations made by the inspector and documented in Inspection Reports No. 315/89009(DRP);
No. 316/89009(DRP),
were reviewed and approved during this inspection period and were made effective on May 26 and May 30 for Unit 1 and Unit 2 respectively.
The inspector had no further questions on this matter, which involved data-keeping associated with valve inservice (stroke-timing) inspections.
C.
""12 THP 4030 STP.227,
"Multiple Entry Personnel Airlock Leakage Surveillance Test,"
was examined (again)- as it relates to the issue of using a lubricant on the airlock door 0-ring seals.
As noted
.
'n Inspection Reports No. 315/89009(DRP);
No., 316/89009(DRP),
NRC understood lubricant application to be a routine preventive maintenance activity which had been accepted by the vendor.
Further review showed there is, in fact, no routine preventive maintenance practice involving seal lubrication.
Procedure
~"12 MHP 5021.001.030,
"Air Lock Doors Repairs (Seals, Interlocks and Air Valves),"
specifies use of lubricant for aid in installation of new seals, but the Maintenance Department does not apply lubricant as a
preventative and believed no such routine application should be practiced.
Further follow up with the Technical Department showed they believed "maintaining" the door seals with silicone grease was acceptable.
When the vendor (TrenTec)
was contacted, however, they advised it is not acceptable to use silicone grease as an adjunct to door seal performance.
The subject procedure and related procedure STP.204 were flagged to ensure their guidance with respect to the door seals is clear:
no grease!
The inspector verified the seals have frequently passed surveillance testing in the past without lubricant, and that all such seals are currently OPERABLE on the basis of testing them lubricant free.
Further, instructions have been issued to refer any future seal leakage problems to the Maintenance Department for adjustment or repair.
Wiping-down and regreasing during testing, as described in Problem Report PR 89-034 (which focused on the leak test failure, not its resolution) will no longer be permitted.
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Enforcement questions remain, relating to the adequacy of the testing and of procedures which involved use of lubricant on the seals, and to the adequacy of controls differentiating testing from maintenance.
Pending further inspection in this area, this is considered an Unresolved Item (315/89018-01).
d.
""2 THP SP. 124, "Auxiliary Feedwater Flow Retention Test Verification."
This test was a rerun of previous testing for which the gA group found support documentation had been lost.
e.
""1 THP 4030 STP.203,
"Surveillance Test Procedure Type B and C Leak Rate Test."
This area was reviewed in followup to licensee identification (ref.
Problem Report PR 89-539) of an implied violation of this procedure when valves 1-ICM-250 and 1-ICM-251 were replaced and no "as-found" leakage test was performed to quantify how much the old valves had been leaking.
The licensee had previously had a similar occurrence when valve 1-gCR-300 was repaired before an "as-found" leak test was performed; refer to Inspection Report No. 315/87029(DRP).
An NRC "Unresolved Item" was written to verify effective licensee action to prevent recurrence of the 1987 event.
This was closed in late 1988 (ref. Report No. 315/88024(DRP))
because the problem had not recurred.
The 1989 event described here re-raises a question about the effectiveness of the licensee's previous actions.
The licensee intends to include an analysis of this issue, and to discuss further actions, in a previously-scheduled update to Licensee Event Report (LER) 315/89004 on the topic of Type B and C testing.
The matter will be reviewed further in follow up. inspection on the LER.
This was discussed at the Management Interview.
Special slow-speed test runs of the Unit 1 "CD" diesel generator were observed on May 11, 1989.
Job Orders A010546 and A010547 were in effect to create a special governor linkage setup to prevent normal response to speed changes, and to perform individual cylinder fuel feed adjustments.
A guideline prepared for the purpose of this special test - and reviewed and approved by the plant Nuclear Safety Review Committee as creating no unreviewed safety questions
- was present and was being followed.
The test was basically an effort to quantify the relationship between increased injector fuel flow(s)
and increased engine speed for an unloaded engine.
The test did not succeed in its intended quantification objective.
With the normal governor output and control defeated, engine speed was being controlled via the "load limiter".
This control was unstable, leading to doubts about whether any observed speed change could be ascribed to cylinder fuel feed adjustments.
In one case, speed appeared to be "stable" (for perhaps a minute) at 440 rpm, so fuel feed was increased to one cylinder by opening its injector setting one-fourth to one-half turn.
This was less than a
10-percent feed increase to only one of twelve cylinders.
Shortly, apparently in response to the fuel adjustment; engine speed began to increase.
The speed continued to increase until plant personnel intervened via the "load limiter" at about 520 rpm.
The magnitude of the speed increase appeared out of proportion to the magnitude of the fuel adjustment, so even this trial was considered qualitative rather than quantitative.
g.
An NRC Region III inspector reviewed Surveillance Procedure No. ~"1 THP 4030 STP.202, Revision 1, dated April 28, 1989,
"I.L.R.T," relative to the requirements of 10 CFR 50, Appendix J; ANSI N45.4-1972; and the Technical Specifications.
The inspector's comments were communicated to the licensee by telephone on May 25, 1989.
The licensee agreed to follow the clarifications given in Inspection Reports No. 50-315/89007(DRS);
No. 50-316/89007(DRS).
One unresolved item, and no violations, deviations, or open items were identified.
7.
Securit 71707 Routine facility security measures, including control of access for vehicles, packages and personnel, were observed.
Performance of dedicated physical security equipment was verified during inspections in various plant areas.
The activities of the professional security force in maintaining facility security protection were occasionally examined or reviewed, and interviews were occasionally conducted with security force members.
a.
The inspector observed various aspects of the licensee's implementation of security enhancements in response to an apparent case of tampering with a pair of safety related electrical switches.
This included:
(1)
Extensive walkdowns to attempt to identify any additional evidence of tampering or other unauthorized equipment operation; (2)
Increased uniformed security officer patrols; and, (3)
A "Security Awareness" newsletter edition which highlighted the need for the entire plant staff to remain on the alert to potential tampering or unauthorized manipulation of equipment or controls.
b.
An unauthorized entry into the protected area occurred May 30, 1989, at the main access control turnstiles.
The problem was immediately corrected and the inspector and the NRC Region III Security section were notified.
Corrective action documentation will be followed up by Region III.
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c.
Meapons training/qualifications for uniformed security officers were observed in progress at the dedicated onsite firing range on June 6, 1989.
No violations,'eviations, unresolved or open items were identified.
8.
Outa es 42700 60710 86700 a.
Fuel reload - Unit 1 core reload commenced the second week of Hay with problems developing shortly thereafter.
An explanation follows:
On May 14, 1989, following the mid-day refueling crew shift change, core reloading was suspended when fuel bundle BB-55 was observed to have a damaged rod.
The bundle, which had been thr ough one operating cycle, was "parked" in core location N2 at the time because refueling crews had been unsuccessful on two attempts the previous day to place it in its designated (A7) location.
The damage, recorded by video-camera inspection, involved a corner rodlet which was bent inward and to the side between the upper most grid strap and the top plate, with scratches on adjacent rodlets.
The bent rod appeared to have an approximate one inch cladding crack.
There were no abnormalities in radiation readings at any time.
Inspection of other bundles, specifically those adjacent to location A7 where placement problems had occurred, showed no damage, though there appeared to be a small mark on the corner of the top nozzle of the bundle in location AS.
The damaged bundle was brought back out to the spent fuel pool (rotated 90-degrees to keep the damaged area on top while in the transfer carriage)
and placed in location TT31 pending final disposition.
Core reload was temporarily suspended pending an evaluation of the event.
(2)
Fuel reloading was suspended on May 16 for a second time, again because of damage occurring to fuel during fuel handling.
Two bundles (No.
AA61 and No.
BB47) both incurred grid strap damage when the bottom grid strap on AA61 hooked the fourth grid strap on BB47 (indicated by the mast overload alarm)
as AA61 was being lifted.
Both are previously burned bundles which were in temporary in-core storage because they are bowed and additional straight bundles were being placed to "box" their designated permanent locations.
Host of the previously used bundles exhibited bowing.
Corrective/preventive actions established during a management meeting on Hay 16 included:
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(a)
assigning another SRO to refueling, dedicated to fuel placement and equipped with his own radio headset; (b)
dedicating a contractor employee to crane position verification, thereby allowing the contractor supervisor to focus on placement; and, (c)
adding a retractable light immediately adjacent to the mast.
Both the fuel vendor (Mestinghouse)
and the refueling machine vendor (Stearns-Rodgers)
had representatives onsite.
Westinghouse reviewed videotapes of the damage to determine if the bundles were reuseable.
(3)
One of the three damaged assemblies (BB-47) was deemed useable sub'ject to the exercise of special handling precautions to reduce the potential for exacerbating the damage or causing damage to adjacent assemblies.
Subsequent to the second fuel loading suspension, NRC Region III directed three-shift coverage of the refueling operations, with inspector observations described in the following section.
The positioning of fuel assemblies in the core was observed on three consecutive shifts on May 16-17, 1989, after the problems discussed above.
Movement of fuel was not in sequence as called for in the procedure (~"1 OHP 4050.FHP.003).
Upon further review the inspector noted this was permitted (to store assemblies in temporary core locations, for example)
and was properly recorded in enclosure D of the procedure,
"Fuel Movement Deviation Report."
Inspector observations showed the fuel handling equipment was not a problem.
To minimize equipment problems during. actual fuel movement, a complete wet and dry run was performed prior to actual fuel movement.
One of the corrective actions established by plant management after the second fuel loading suspension was to add a
retractable light immediately adjacent to the mast.
This was
. intended to improve visual acuity as the fuel assembly moved with the mast.
The crew on restart on May 16, however, did not know of the commitment made for the extra light. It was installed on inspector prompting.
Later, as the inspector watched the crew commence fuel movement the evening of May 16, the light was not on.
The inspector asked a member of the crew if the light was needed, and it was then turned o The inspector noted there were good communications and coordination between crew members and the control room.
As mentioned earlier, bowed bundles had to be placed in temporary core locations while straight bundles were used to form a "box" to give added lateral support to the bowed bundles.
This required a total deviation from the planned step-by-step core load sequence, and required extra attention of crew members.
Deviations were properly documented.
Subsequently, NRC issued Information Notice 89-51, "Potential Loss of Required Shutdown Margin During Refueling Operations,"
which described.a need for careful control in placing fresh, more highly enriched fuel bundles in proximity to each other.
In light of the step deviations during reload being analogous to the event described in the Notice, the inspector requested a review to ascertain shutdown margin was not significantly affected.
The licensee agreed to examine the issue.
Core reload was successfully completed May 19, 1989 at 9:37 a.m. with no additional problems.
Despite the greatly expanded number of handling steps, core verification found neither position nor orientation errors.
The Quality Assurance (QA) group provided 100-percent coverage of the Unit 1 refueling activities in addition to NRC's increased inspection coverage.
Problem Report (PR)89-655 documents the QA group concerns and identifies that certain core reload activities were.not performed in accordance with the language of one statement in the procedure.
b.
Besides the problems with the fuel reload, there were instances of miscoordinated activities as evidenced by:
The cycling of valve 1-ICM-ill, when two check valves (1-SI-166L2 and L3) in the flow path were disassembled, resulted in a 50 to 100 gallon spill of primary coolant into containment.
This resulted in an increase of radiation levels as well as a shifting of resources away from other productive work to clean up the spill (ref.
PR 89-532).
(2)
(3)
(4)
Some "keep clear" areas in the Turbine Room were found being used as storage areas and in need of better housekeeping (PR 89-553).
Lead shielding was removed from two valves in the letdown line (1-QRV-113 and 1-QRV-114) without notifying the plant ALARA group (PR 89-570).
Construction was found installing anchor bolts without the required procedure present (PR 89-569)
and doing work on the Auxiliary Building freight elevator with no Job Order (PR 89-615).
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(5)
While refueling operations were temporarily put on hold for lunch breaks on Hay 15 and 16, two containment radiation monitors were removed from service, one at a time, for filter changeouts.
However, containment purge was "on" while the radiation monitors were inoperable for the filter change.
This may have violated inferred requirements (to keep one monitor in service or shut down the purge) of Technical Specification 3.3.3. 1.
Further review of this matter is anticipated on receipt of an associated Licensee Event Report, or in follow up on Problem Report 89-643.
No violations, deviations, unresolved or open items were identified.
9.
Safet Assessment/ ualit Verification (35502 40500 40704 92720 The effectiveness of management controls, verification and oversight activities, in the conduct of jobs observed during this inspection, was evaluated.
The inspector frequently attended management and supervisory meetings involving plant status and plans and focusing on proper co-ordination among Departments.
The results of. licensee auditing and corrective action programs were routinely monitored by attendance at Problem Assessment Group (PAG)
meetings and by review of Condition Reports, Problem Reports, Radiological Deficiency Reports, and security incident reports.
As app'licable, corrective action program documents were forwarded to NRC Region III technical specialists for information and possible followup evaluation.
The 'inspector reviewed the licensee's activities associated with Quality Assurance Program (QAP) implementation and Self-Assessments.
Organizations and activities reviewed included:
Quality Assurance, Quality Control, Plant Nuclear Safety Review Committee, Nuclear Safety and Design Review Committee, Safety and assessment Department, Plant Staff and Site Engineering Activities.
Quality Assurance (QA) verification of implementation of QAP changes was not previously accomplished as a specific separate objective of the QA Audit Function.
As a result of this determination the licensee plans to make this verification of the implementation of QAP changes a clearer objective for future audits.
The Safety and Assessment Department has programs for trending that have been in place for several months, and are presently being expanded to encompass new techniques and areas of interest, including NPRDS and HPES.
gA personnel are involved in several activities providing self assessment and assurance of equality including reviews of personnel certifications, codes and standards matrix, procedures matrix, procedure reviews, problem reporting systems, surveillances, audits, human performance evolutions, weekly reports and quarterly reports of plant and gA activities.
The equality Control (gC) Section of the Safety and Assessment Department have, in addition to regular planned inspections, instituted a program of gC surveillances which continuously sample all of the activities of the entire plant staff and are producing a valuable reference, of objective information, regarding the performance of plant personnel, equipment, systems, and conditions.
The Safety and Assessment effort includes also new efforts in Human Performance Evaluations and a equality Team program.
Safety Committee activities including the Plant Nuclear Safety Review Committee (PNSRC)
and the Nuclear Safety and Design Review Committee (NSDRC) have generally exceeded performance guidelines established by the Technical Specification and continue to operate in a generally effective manner.
The licensee does not have an Independent Safety Engineering Group (ISEG), which was required of new licensees after TMI, however, they are aware of the need for occasional independent technical or engineer studies or evaluations and plan to accomplish them when appropriate or required.
a 0 Some of the findings from equality Assurance (gA) group audits and sur veillances'
which have continued to demonstrate a good degree of both technical orientation and insistence on precise literal compliance - are noted elsewhere in this report.
b.
Sensitivity to and knowledgeability about quality requirements were demonstrated by various staff or contractor personnel, such that conditions with the potential for adverse effects on quality were identified for resolution and the adverse effect(s) prevented.
(1)
A receipt inspector found a miscommunication on a Purchase Order change had resulted in offsite work being done without full gA controls.
The questionable part was placed in "hold" pending resolution of its acceptability.
(2)
A plant equality Control (gC) inspector, performing routine visual inspection of seismic-restraints, noted indications of a boric acid leak resulting in buildup of boric acid around the Unit 1 East RHR pump flange studs.
Actions were initiated to assure carbon-steel studs were protected from damage by boric acid.
No (3)
A contractor gC inspector identified excessive inherent
"stringers" in plate steel used for fabrication of pipe restraints.
This initiated technical and safety verifications of restraints adequacy prior to placing them in service as
"operable".
violations, deviations, unresolved or open items were identified.
10.
Re or table Events 92700 The inspector reviewed the following Licensee Event Reports (LERs) by means of direct observation, discussions with licensee personnel, and review of records.
The review addressed compliance to reporting requirements and, as applicable, that immediate corrective action and appropriate action to prevent recurrence had been accomplished.
a 0 b.
C.
d.
(Open)
Licensee Event Report LER 315/89004:
Containment Type B and C Leakage Exceeds LCO Value due to Degradation of Isolation Valve Seating Surfaces.
As noted in Paragraph 6.e above, the licensee plans a Supplement to this LER on or before August 15, 1989.
This will include discussion of the circumstances surrounding the replacement of two containment boundary valves with new valves without first obtaining an "as-found" leak test on the old valves.
(Closed)
Licensee Event Report LER 315/89007:
Failure to complete Technical Specification Fire Door Inspection as Required.
As noted in the discussion of Paragraph 12 below, the NRC Office of Investigation (OI) has.been provided information r'elating to potential investigation of this matter.
They 'have authority within NRC to investigate implications of dereliction of duty and/or falsification of documents.
Civil enforcement review, and verification of corrective and preventive actions related thereto, are complete.
(Open)
Licensee Event Report LER 316/89002:
Non-Service-Induced Deformation of Emergency Core Cooling system Suction. Line Seismic Restraint.
As noted in previous paragraphs 2.c and 5.d, this LER and other findings raise questions concerning the efficacy of the licensee's actions responsive to NRC Bulletin 79-14.
This matter will be formally assigned within NRC Region III for follow up in concert with further review of an Unresolved Item on the question of seismic design "as-built."
(Closed)
Licensee Event Report LER 316/89009:
Rated Thermal Power Exceeded Due to Computer Error.
This event applied to both Units, and involved failure of the software programmer for the Mestinghouse P-250 computer to include a term involving steam generator blowdown into the heat balance equations.
The error was nonconservative whenever blowdown was in service, because heat lost by discharge of blowdown was absent from the calculated primary system nuclear
power.
The matter was reportable because nuclear power was set with a bias such that indicated power was lower than actual, and examples occurred involving unidentified operation above the licensed Rated Thermal Power (RTP) limits in each Unit.
Evaluation of the event showed a maximum potential error of about 1-percent RTP, whereas accident analyses bound initial conditions by assuming a 2-percent RTP error.
Thus, operations remained within analyzed limits.
A review of previous plant operations at full power, with the "startup" flash tank in service, identified the worst cases from the previous (before 1989) operating cycle:
(1)
Unit 1 - operated at 100-percent RTP from 2:00 a.m.
August 5, 1988 through 8:00 p.m. August 19, 1988.
During this time, the startup flash tank was in service for four hours and 18 minutes on August 14, 1988.
Maximum power was limited (by calculation given current knowledge) to 101.08-percent.
(2)
Unit 2 - operated at 100-percent RTP from 10:05 a.m.
on February 17, 1988 through 12:35 p.m. the same date.
The startup flash ta'nk was not utilized.
The above were also the only significant potential excursions for the entire previous core cycle.
For the current cycle (1989) only Unit 2 was exposed to the problem.
(3)
Unit 2 operated at 100-percent RTP from 4:20 p.m.
on March 28, 1989 through about 4:00 a.m.
on March 31, 1989.
During this time, the startup flash tank was in essentially continuous service at various blowdown flowrates.
The maximum power was limited (by subsequent calculation) to 100.81-percent.
The magnitude and duration of excursions above the licensed power limits were both limited - by coincidence of independent circumstances.
First, prior to replacement of the. Unit 2 steam generator lower assemblies during 1988, both Units had been administratively held below rated thermal power (with rare, brief exceptions)
since 1985.
This was done as a steam generator tube conservation measure.
"Normal" power for Unit 1 was held to 90-percent RTP, while Unit 2 was normally at 80-percent RTP.
This limited duration.
Separately, blowdown via the "startup" flash tank, which is capable of flowrates five or six times greater than the normal blowdown system, was a relatively rare event in prior years, before the adoption of very stringent secondary system chemistry control limits promulgated by the Electric Power Research Institute (EPRI).
This limited both duration and magnitude of unidentified overpower condition The chronic nature of the error had its most significant practical effects in cumulative under-estimation of core burnup.
The licensee s reviews emphasized this aspect of the situation, because fuel with incorrectly determined (by a f'rection of a percent)
burnup is to be utilized for future operations.
The corrected calculations did not show any violation of "tolerance" already incorporated into the vendor calculations.
Violations of regulatory requirements occurred.
The inspector evaluated them against the criteria of the NRC Enforcement Policy contained in 10 CFR 2 Appendix C, as follows" they were identified, reported and corrected by the licensee;
~
their safety significance is at Severity Level IV;
~
they were corrected, and timely preventive measures have been undertaken; and, they.were not repetitive of previous similar problems.
These criteria govern when NRC will not generally issue a Notice of Violation; no Notice is being issued in this case.
Some indications existed that licensee control room operators had a general distrust of the power output displayed by the P-250 computer, which events proved to be erroneous as detailed in the subject LER.
The implication is that operators had become inured to, or had been "trained" to ignore, inaccuracy of an important indicator of operating information.
Evidence on this separate aspect of the topic is incomplete.
So further inspection is planned.
No violations, deviations, unresolved or open items were identified.
11.
NRC Com liance Bulletins (92703 I.E.Bulletin 79-14, "Seismic Analyses For As-Built Safety-Related Piping Systems" was issued to inform licensees of instances of inaccurate information input to seismic analyses as a consequence of the analyzed configuration not being duplicated by the plant "as-built" configuration.
Licensees were requested to identify documentary sources of design input, to inspect plant systems for conformance thereto, and to report the results of the inspection of the NRC.
Nonconformances were to be dispositioned according to criteria established in the Bulletin.
The licensee's actions on the Bulletin were inspected during and subsequent to their implementation.
Various correspondence ensued; letters and reports from the licensee, Bulletin Supplements and
inspection reports from the NRC.
NRC inspection identified some problems (Reports No. 50-315/79020; No. 50-316/79017; No. 50-315/82027; No. 50-316/82007)
but review of the matter was considered sufficient by 1983 that the Bulletin was "closed" in Inspection Reports No. 50-315/83005 and No. 50-316/83005.
More recently, as noted in Paragraphs 2. c, 5. d and 10. b, NRC and licensee findings both suggest a reexamination of the thoroughness of the reviews done under the subject Bulletin is in order.
As indicated in the referenced Paragraphs, this will be tracked via an NRC Region III Unresolved Item and a Licensee Event Report - the Bulletin will remain
"closed."
No violations, deviations, unresolved or open items were identified.
Alle ations 93702 (Closed) Allegation (RIII-89-A-0061): failure to 'inspect fire doors and falsely documenting performance of fire door inspections.
The licensee identified and reported this matter, and the facts are not at issue:
a contractor employee assigned to perform certain daily inspections of specified fire doors did not in fact do so in all cases, but he documented his activities as though he had.
Licensee Event Report 315/89007 provided a factual discussion of the event.
The matter was assigned an "allegation" tracking number as this is the mechanism required for referral to the NRC Office of Investigation (OI).
That Office has concurred in Region III proceeding with any applicable civil enT'orcement on the issue without awaiting the outcome of any investigation OI may choose to do.
Inspection Reports No. 50-315/89014(DRP)and No. 50-316/89014(DRP)
include an evaluation of the enforcement policy implications relating to the matter.
A violation of requirements occurred, but it fit criteria established under the Enforcement Policy under which NRC does not usually issue a Notice of Violation.
Therefore, no such Notice is being issued in this case.
Civil.review and evaluation are considered complete.
No violations, deviations, unresolved or open items were identified.
Re ion III Re uests 92705)
In response to a Region III request concerning certain Westinghouse steam generator tube plugs found to be susceptible to stress corrosion cracking (ref.
an evaluation on D.
C. Cook's mechanical plugs was received.
(1)
Plugs fabricated from heat numbers NX3513 and NX3962 are not in service at D.
C.
Cook.
(2)
After Westinghouse provided its preliminary assessment of plug problems, they identified an additional heat (NX4523) with corrosion rates comparable to those identified in the plugs discussed earlier.
b.
An investigation showed that Unit j. has 279 tubes with the suspect plugs installed (for a total of 558 plugs).
Westinghouse has developed an algorithm to address the estimated time remaining to the plant when a CN u-wall circumferential crack could develop, in effective full power days (EFPD).
For D.
C.
Cook that estimate is greater than 500 EFPD.
The plant intends to start up with the plugs in place; this information was forwarded to Region III.
In response to a Region III request, the inspector briefed plant management on two potentially significant issues involving recent operational events at other U.S plants.
(j.)
The first event involved the failure of a freeze seal which disabled power to safety related equipment, due partly to inadequate temperature monitoring of the seal.
(2)
The second event involved findings by NRC inspectors who identified a hydrogen tank farm on the roof of the control room.
C.
d.
In a subsequent memorandum related to item 13.b(2) above, the inspectors canvassed the plant to obtain the following information:
(1)
Distance from the hydrogen storage facility to the nearest safety-related structure or air intake.
(2)
Maximum volume of gaseous or liquid hydrogen stored in standard cubic feet or gallons respectively.
The results wer e forwarded to Region III.
The plant was also alerted to this potential safety problem in NRC Information Notice 89-44,
"Hydrogen Storage On The Roof Of The Control Room."
The inspectors received a Region III request for information regarding State of Michigan oversight of D.
C.
Cook.
The information requested was submitted to the Region's Office of State and Government Affairs.
e.
The licensee was notified by Region III of a problem with the Solid State Protection System (SSPS) wiring connections for Salem Unit l.
D.
C.
Cook has a similar system.,
The plant initiated a Problem Report (PR 89-699) to document the investigation.
A visual inspection of both Units did not disclose connector problems similar in appearance to those found at Salem, No violations, deviations, unresolved or open items were identified.
14.
Unresolved Items Unresolved Items are matters about which more information is required in order to ascertain whether they are acceptable items, violations, or
deviations.
An Unresolved Item disclosed during the inspection is discussed in Paragraph 6.c.
15.
Mana ement Interview 30703)
The inspectors met with licensee representatives (denoted in Paragraph 1)
on June 9, 1989 to discuss the scope and findings of the inspection.
In addition, the inspector also discussed the likely informational content of the inspection report with regard to documents or processes reviewed by the inspector during the inspection.
The licensee did not identify any such documents/processes as proprietary.
The following items were specifically discussed:
a.
Actions on and operating philosophy demonstrated toward a gradually increasing unidentified leak, in the Unit 2 reactor coolant system (Paragraph 3.b);
b.
Maintenance and repair s (Paragraph 5.f) and followup testing (Paragraph 6.f) subsequent to an overspeed event on the Unit 1 "CD" diesel generator; c.
Indicators of a need to inspect seismic design further in light of indications some deficiencies escaped detection during reviews pursuant to I. E.Bulletin 79-14 (Paragraphs 2,c, 5. d, 10. b and ll);
d.
An "Unresolved Item" concerning acceptability of the historical practice of performing air lock door seals testing on seals coated with lubricant (Paragraph 6.c);
e.
A need for further information with LER 315/89004 to address replacement of containment boundary valves without a prior
"as-found" leak test (Paragraph 6.e).
g.
Special inspections and findings associated with followup of two cases of minor fuel bundle damage during the Unit 1 core reload (Paragraph 8.a);
Status of follow up to selected previous items (Paragraph 2 and 10)
specifically including an item being tracked via the NRC allegation tracking system (Paragraph 12); and, h.
Status of Safety Committee activities, the make-up of the Nuclear Safety and Design Review Committee (NSDRC) and activities related to independent technical and engineering reviews.
25