IR 05000352/1985030
| ML20138D144 | |
| Person / Time | |
|---|---|
| Site: | Limerick  |
| Issue date: | 10/17/1985 |
| From: | Beall J, Gallo R NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20138D142 | List: |
| References | |
| 50-352-85-30, 50-353-85-07, 50-353-85-7, NUDOCS 8510230195 | |
| Download: ML20138D144 (27) | |
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U. S. NUCLEAR REGULATORY COMMISSION
REGION I
Report Nos. 85-30; 85-07 Docket Nos. 50-352; 50-353 License Nos. NPF-39; CPPR-107 Priority --
Category C;A Licensee: Philadelphia Electric Company 2301 Market Street Philadelphia, Pennsylvania 19101 Facility Name:
Limerick Generating Station, Unit 1 & 2
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Inspection Conducted: July 1 - September 22, 1985 Inspectors:
E. M. Kelly, Senior Resident Inspector J. E. Beall, Project Engineer R. J. Bores, Technical Assistant D. J. Florek, Lead Reactor Engineer T. B. Silko, Reactor Engineer Reviewad by:
Am 10!!d 87 J. E. Beall, Project Engi'nEEr dath Approved by:
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R. M. Gallo,' Chief, dats _
Reactor Projects Section 2A DRP Inspection Summary: Combined Inspection Report for Inspection Conducted July 1 - September 22, 1985 (Report Nos. 50-352/85-30; 50-353/85-07)
Areas Inspected: Routine and backshift inspections by the resident inspector and region-based inspectors of: activities associated with issuance of the full power operating license on August 8, 1985 and subsequent power ascension; followup on outstanding items and license conditions; plant tours; observation of startup testing and review of test procedures and results, maintenance and surveillance observations, and review of periodic reports. Also addressed are events that occurred during-the reporting period which include:
corrective-action for cable tray penetration fire seal voids, contaminated water spill on August 1,_a RWCU resin spill on September 7, and a reactor scram on September 11.
I 8510230195 851021
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PDR ADOCK 05000352 O
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Result: Three unresolved items were identified associated with: the potential third offsite 33 kV power source (Detail 2.3); overtime guidelines for shift personnel (Detail 3.4.3); and drywell temperature control (Detail 7.0).
No violations were identified.
This inspection involved 274 hours0.00317 days <br />0.0761 hours <br />4.530423e-4 weeks <br />1.04257e-4 months <br /> of onsite inspection by the Senior Resident Inspector, the Limerick Project Engineer and other region-based inspectors.
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DETAILS 1.0 Persons Contacted
Philadelphia Electric Company J. Basilio, Administrative Engineer
J. Clarey, Construction Superintendent
J. Doering, Operations Engineer
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R. Dubiel, Senior Health Physicist
P. Duca, Technical Engineer J. Franz, Superintendent of Operations r
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L. Hopkins, Test Engineer A. Jer; kins, GE Startup Manager G. Lauderbach, Quality Assurance Engineer
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G. Leitch, Station Superintendent
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i Also during this inspection period, the inspectors discussed plant status and operations with other supervisors and engineers in the PECo, Bechtel
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and General Electric organizations.
t 2.0 Followup on Unresolved Items
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2.1 (Closed) Drawing Control Items from BNL Review i
Automatic Depressurization System (ADS) logic depicted in FSAR Figure
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7.3-8 (Rev. 38) was found to contain an error in the "E" Logic Train.
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j This item was identified by an NRC contractor review of the Automatic
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Depressurization System as described in a Brookhaven National Labora-t tory' (BNL) Technical Review Report forwarded to the licensee by
't Region I on May 30,.1985. Beth the manual initiation button and the i
seal-in feature were shown after the pump permissives', when in actua-
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i lity they are before the pump permissives.
This error is also con-
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tained in and originated from GE Functional Control Diagram (FCD)
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761E557 AD Sheet 3 (Rev. 16).
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The inspector reviewed G.E.'s Field Deviation Disposition Request i
i (FDDR) HH1-3431 which was issued to revise 'FCD 761E557 AD. This I
review confirmed that the logic error noted in BNL's report is
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accurate and complete and that FDDR HH1-3431 will correct the errors, i
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The inspector also reviewed a Licensing Document Change Notice (LDCN)
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which was issued to correct the figure in the FSAR.
This review
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assured that the changes being made to the FSAR were correct and that
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the proper. administrative actions were being taken to include the l
change in the next revision (Rev. 44) of the FSAR scheduled for
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issuance in' late September 1985.
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Other findings from the BNL technical review in the area of drawing control involved:
1) ADS drawings not posted with pertinent FDDRs
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and design changes; 2) errors on sheet 3 of the GE ADS elementary drawing; 3) controlled drawing holders not properly following docu-
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ment control instructions; and 4) excessive design changes outstanding
against GE drawings.
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Regarding item 1), the inspector reviewed selected ADS drawings to ensure that they were currently posted with the pertinent referenced
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FDDRs. Regarding item 2), FDDRs HH1-3431 and HH1-3427 were written to
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correct minor drawing problems identified on Sheet 3 of ADS drawing No. B21-1060-E-3.20. The above documents were reviewed by the inspector to ensure that the FDDRs were complete and that the proper corrections were incorporated into the ADS drawings.
Regarding item 3) above, the inspector performed an audit of various drawing folders to determine if the most recent drawings were available in the field, and that the drawings were posted with the
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pertinent FDDRs and design changes. Four stick files were inspected:
two files controlled by Bechtel Document Control located at the PEco Field Electrical Engineering and Testing and Laboratory offices; and two files controlled by the PECo Nuclear Records Management System (NRMS) Division located in the main control room (STA office) and the Technical Support Center.
The stick files controlled by NRMS were found to be deficient in that: pertinent FDDRs were referenced and not attached to drawings;.
old revisions existed in stick files; drawings which were to be included in stick files were located in the TSC but not " assigned" to their respective sticks. No deficiencies were identified with the stick files controlled by Bechtel.
In response to.the above findings related to drawing stick files controlled by NRMS, the licensee immediately performed a 100% audit of all drawings located in both the control room STA office and the TSC. The audit concentrated on the existence of an up-to-date revision and appropriate attachments to each controlled drawing. ~A
small number of discrepancies were found, and were corrected. A September 11, 1935 memorandum was issued from the plant manager to
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NRMS Division which directed that periodic sampling be performed by NRMS to enhance drawing controls. The inspector conducted a followup
review of the NRMS stick files and no deficiencies were identified.
Regarding item 4) above, the inspector reviewed a sample set of
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drawings and noted that, due to recent drawing revisions, there were not a significant number of outstanding FDDRs against the drawings
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reviewed by the inspector.
This item is closed.
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2.2 (Closed) Unresolved Item (85-03-11): Calculations ~for Heavy Load Rigging
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This finding from the NRC Operating Assessment Team (OAT) inspection
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identified a need for improvement in Maintenance Administrative Proce-
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dure MA-7 regarding calculations to size and configuration of rigging
components used in handling heavy loads.
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Revision 5 to MA-7 was issued on July.5,1985 which incorporates a scaling-up of the approximate component weight on the Item Handling
Report to set a minimum rating for rigging / handling equipment.
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factors were added which include a 25% dynamic load correction and a factor of two for redundancy when single-failure proof systems are
required. This procedural revision addresses the concerns identified
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in the 0AT finding, and is in compliance with the heavy loads program.
The inspector had no further questions on this item.
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2.3 (0 pen) Potential Third Offsite Power Source
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FSAR Subsection 8.2.1.1 describes Line Number 2300, a 33 kV source I
which serves as a potential third offsite source for emergency power j
in the event of loss of one of the normal offsite sources. The two j
normal offsite sources are electrically independent, physically
separated and are the Limerick 220 and 500 kV substations, respec-
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tively. A Technical Review of AC Electric. Power Systems, performed
by Brookhaven National Laboratory (BNL) for NRC Region I and issued
to PECo by letter dated March 21, 1985, identified open items
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associated with the degree of completion and physical independence of
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j the third offsite 33 kV source.
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The inspector reviewed the April 19,.1985 response by PECo-to NRC
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i Region I regarding the adequacy and completion of the 33 kV source.
i That response stated the licensee's intent to utilize this third offsite source in order to maximize plant availability and to avoid
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the shutdown that.is required by Technical Specifications upon long-i term loss of one of the normal offsite sources. Use of the third
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source, not completely. installed presently, would require:.use of a
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spare transformer (located onsite); cable pulling in an existing i
underground conduit; disconnecting an existing aerial 33 kV feed to i
the 220 kV switchyard; and an aerial tap off the 33 kV line; connec-i l
tion to the underground cable. run; and installation of control and l
l protective relaying for a 33 kV circuit breaker located near the 101
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safeguard transformer (but not connected).
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Based on discussions with PEco Electrical Engineering personnel and
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inspection of the 220 kV switchyard configuration with respect to the i
proposed routing of the aerial tie-in to the underground conduit, the
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inspector questioned the physical separation between the proposed j
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33 kV source and the existing 220 kV switchyard. The tap off the 33 kV overhead line would most likely be run along the ground within the.
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220 kV yard.
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Also, a modification package is still under preparation for installa-
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tion of protective circuits and relaying.
Further, while Technical
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j Specifications do not refer to specific offsite sources by name, the i
NRC Safety Evaluation Report (NUREG-0991) for Limerick makes no men-i tion of the potential 33 kV offsite source as to its acceptability
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with respect to General Design Criterion 17. Therefore, pending
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further review by the licensee, the acceptability of this source is
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unresolved. (50-352/85-30-01)
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3.0 Review of Plant Operations 3.1 Summary of Events
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The plant was in Operational Condition 4, Cold Shutdown, at the i
beginning of this inspection period, and had been shutdown s'ince
April 17, 1985 due to ASLB hearings associated with offsite emergency
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i planning. The Board issued a Fourth Partial Initial Decision
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l addressing and disposing of those issues on July 22, 1985, and ruling
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in favor of the Applicant.
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A full power operating license was issued on August 8, 1985.
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reactor was made critical on that same day at 7:19 p.m.
Startup l
l testing commenced.in Test Condition (TC)-1, with heatup and pres-l i
surization and ascension to 5% power by early on August 10.
Operational Condition 1 was achieved for the first time at 2:55 p.m.
on August 12 by placement of the reactor mode switch in the Run
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position and rod withdrawal up to 10% power that same day.
Turbine i
shell and chest warming was completed as part of preparation for
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turbine roll, and the generator was synchronized onto the grid for i
j the first time at 5:15 a.m. on August 14.
Reactor power was j
j increased over the next two days to 20% in. support of TC-1 testing.
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The NRC issued an Order on August 16, 1985, restricting reactor
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operation to levels not in excess of 5% of rated thermal power. The
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Order effectuated an August 15 decision by the U.S. Court of Appeals
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for the Third Circuit which stayed the Commission's August 8 authort-r
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zation of a full. power license pending review of' appeals filed by two l
~. parties. A controlled reduction of power from 19% was begun at 12:38 i
p.m. on August 16,. reaching less than 5% power at 5:35 p.m. that same i
day. The plant remained at approximately 3% power, and TC-1 activi-
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ties were conducted.
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The stay remained in effect until August 21 when it was lifted, and the NRC Order was rescinded.
TC-1 was completed on August 21, lasting 12 days.
TC-2 was begun on August 22, and ascension to approximately 22% power was achieved and held for the next five days.
Testing involved validation of process computer programs and calculations, thermal limit checks, and neutron instrument calibration.
Reactor power was increased to a maximum of 38% on August 28 for about six hours, and was then stabilized at about 28% for the following week for feedwater flow control tests.
The first of three major test evolutions was performed on September 11, involving a remote cooldown of the reactor from outside the control room (STP 28.2). The test followed after an unplanned scram occurred at 1:04 a.m. on September 11 from 28% power due to a low vessel level caused by a trip of a condensate pump and subsequent loss of feedwater (see Detail 6.3).
The unit was restarted on August 12 and the second portion of the remote shutdown test (STP 28.1) was conducted from 25% power by initiating a manual scram (see Detail 5.3) from the auxiliary equipment room using the main steam line radiation monitors. The last major test in TC-2, STP 31.1, involving a simulated loss of offsite power was conducted on September 16 from 20% power (see Detail 5.4).
The unit was restarted and placed on the grid at 22% power on September IS, and operated at power levels of from 22 - 28% through the end of this inspection period.
TC-2 was completed on September 23, having taken 33 days.
TC-3 was begun on September 23.
Circulating cooling water makeup had been limited by agreements with the Delaware River Basin Commission (DRBC) to conditions on flow (530 cfs) and dissolved oxygen (5.1 mg/ liter) in the Schuylkill River since June 1985. DRBC approval was obtained on August 9 for addi-tional use of up to 5.2 million gallons per day (MGPD), which is a supplemental allotment contingent upon shutdown of the nearby Titus (20 miles upstream) and Cromby (10 miles downstream) fossil generating stations.
Flow in the Schuylkill varied throughout this inspection i
period, and dropped below the 530 cfs limit on various occasions because of the drought conditions experienced over the preceding six months. The licensee utilized an onsite storage inventory of up to 10.5 million gallons to support operations at various power levels during periods of low river flow. The licensee monitored actual makeup flows, and maintained compliance with DRBC agreements, while scheduling startup test activities contingent upon water availability.
Operation at higher power levels of 50 - 70% in TC-3 has necessitated emergency relief requests presented to the DRBC at the end of this inspection period. Those requests included proposals to pump water
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from an abandoned strip mine near Pottsville, Pa. and reduction in i
.the flow limit of 530 to 415 cfs.
3.2 Operational' Safety Verification
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l The inspector toured the-control room daily to verify proper manning,
access control, adherence to approved procedures, and compliance with LCOs.
Instrumentation and recorder traces were observed'and the status
of control room annunciators were reviewed. Nuclear instrument panels i
and other reactor protective systems were examined.
Effluent monitors were reviewed for indications of releases.
Panel indications for onsite/offsite emergency power sources were examined for automatic operability. During entry to and egress from the protected area and vital island, the inspector observed access control, security boundary
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integrity, search activities, escorting and badging, and availability
of radiation monitoring equipment including portal monitors.
The inspector reviewed shift superintendent and control room super-
visor, and operator logs covering the entire inspection period.
Sampling reviews were made of equipment trouble tags, night orders, and the temporary circuit alteration and.LCO tracking logs.
The inspector also observed several shift turnovers during the period.
i The operations activities observed were performed in accordance with the applicable procedures and requirements and found acceptable.
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j 3.3. Station Tours l
The inspectors toured accessible areas of the plant throughout this t
inspection period, including: the Unit I reactor and turbine-auxiliary
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enclosures; the main control and auxiliary equipment rooms; emergency i
switchgear and cable spreading rooms, diesel generator and radwaste
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enclosures; the spray pond and pumphouse, and the plant site perimeter.
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'During these tours, observations were made relative to equipment
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condition, fire hazards, fire protection, adherence to procedures, radiological controls and conditions, housekeeping, security, tagging i
of equipment, ongoing maintenance and surveillance and-availability j
of redundant equipment.
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No violations were identified.
3.3 Administrative Activities
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3.4.1 Nuclear Review Board (NRB)
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'The inspector attended a portion of NRB Meeting No. 174 conducted on September 5, 1985, during which,.in part, the status of current plant operational experience and startup
testing were presented by the Plant Manager. NRB function, l
composition and review responsibilities were determined to
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be in accord with the requirements of Technical Specifica-tions. -The topics of discussion (i.e., operational safety concerns, equipment problems, suspect LERs) were the more l~
important issues--from a safety perspective--experienced
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No violations were identified.
I 3.4.2 Plant Operations Review Committee (PORC)
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Several PORC meetings were attended by the inspector during the period which addressed the following:
August 6; FSAR Section 15.2.6, Loss of AC power
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transient analysis discrepancy August 8; Review of plant conditions for change in.
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Operational Conditions, criticality and ascension j
above 5% power, including compliance with full power license conditions and Technical Specifications
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August 19; proposed procedural revisions to Adminis-trative Procedures A-3 (Temporary Procedure Changes)
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and A-4 (PORC)
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August 29; review of STP 13.4, Dynamic System Test Case to verify process computer calculations During attendance at these meetings, the inspector noted
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the required Technical Specification compcsition and quorum
for the PORC, as well as appropriate reviews of safety evaluations and issues presented. The inspector also
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reviewed the proposed revisions to Administrative Proced-
ures A-3 and 4 and found these to be in accord with and properly implementing Technical Specification requirements.
The inspector also reviewed an August 19, 1985, internal memorandum which revised and listed the new membership (including alternates) for the PORC, which was in compliance with the Technical Specification.
No violations were identified.
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3.4.3 Plant Staff Working Hour Restrictions i
j The inspector reviewed Administrative Procedure A-40
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(Revision 1, effective January 15, 1985).. " Procedure for
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Working Hour Restrictions," which controls the authorization
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of overtime for shift personnel, health physics and chemistry technicians.
Licensed and non-licensed operators and STAS are scheduled in accord with A-40 such that overtime-is not routinely utilized to compensate for inadequate staffing or
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shift coverage. A-40 implements a Technical Specification
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requirement which is based on TMI Action Plan 0737 Item i
I.A.1.3, Shift Manning. NRC Generic Letter 82-12 issued on l
June-15, 1982, also addresses working of overtime hours by
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personnel involved in safety related activities, the con-
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cern being for possible fatigue which could impair judgment.
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r The inspector reviewed Technical Specification (TS) 6.2.2.f
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which states that shift coverage be maintained without i'
routine heavy use of overtime; the objective being a
" normal" 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> day, 40 hour4.62963e-4 days <br />0.0111 hours <br />6.613757e-5 weeks <br />1.522e-5 months <br /> week.
The TS allows for, en a
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i temporary basis, the use of overtime on an individual. basis
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of up to:
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16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br /> in 24, 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.in 48, and 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.in any 7 l
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8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> breaks between work periods l
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Deviations from the above guidelines are to be sanctioned
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via authorization by the Plant Manager (or his deputy), or
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I higher levels of management. Work hours up to or at these
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j guidelines does not require that authorization; however, exceeding the guidelines is to be considered only as a very
unusual case.
Previously documented NRC clarificatior, of
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l this working hour guidance states that instances where an
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individual's overtime exceeds the guidelines should be (
"very few in number and handled by senior plant management"
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(i.e., Plant Manager, his deputy or higher).
Such devia-
tions must be documented and justified. Procedure A-40
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provides for a Staffing Deviation Form to authorize those
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)l individual case's where temporary deviation from the guide-
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lines is' justified.
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i During the period April 18 through May 2, 1985,114 Health
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j Physics technicians had exceeded the 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> guideline. 'A I
memorandum was issued to the Health Physics Supervisor by i
the Plant Manager on May 13, 1985 which explained the'TS
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requirements and described an apparent misunderstanding j
wherein the 7 day period was thought.to be a pay period as
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opposed to a " sliding" period. While no Deviation Forms
were initiated for these instances, the plant had been shut i
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down on April 17 and was in the beginning of an extended
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outage which lasted _until August 8, 1985. The inspector
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considers this instance not to be in accordance with Pro-
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cedure A-40 and TS 6.2.2. f.
However, it was also an event i
of lesser safety significance which was identified and
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corrected by the licensee, lasting only 2 weeks during
plant shutdown conditions, and without any previous or
j subsequent recurrences.
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i The inspector ~ reviewed a licensee QA Audit no. AC85-58 PR conducted from July 14 to July 26, 1985 which assessed procedures for the
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control of working hour restrictions. Three findings (Items 9,10 and 12) addressed Limerick overtime procedures. As a result of these
audit findings, a revision to A-40 and the Deviation Form is being developed by plant staff.
I The inspector also reviewed completed Surveillances ST-7-107-980-0 i
for the months June and July 1985.
This surveillance is performed monthly by the Administrative Engineer, in accordance with A-40, to
i verify that excessive hours for personnel affected by TS 6.2.2.f are not being assigned. No violations of Procedure A-40 were identified.
The instances' described-above, and subsequent discussions with plant
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staff indicate the need for:
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clarification of when a Deviation Form is required
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instruction to plant supervisinn, particularly Health Physics as to the intent of the TS and implementation of Procedure A-40 clarification as to what would constitute a violation of TS f
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6.2.2.f
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review of corresponding Maintenance Division Administrative i
Procedure MA-23, for consistency with the revised A-40
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consideration of the applicability to other support groups who
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perform safety-related functions at Limerick, such as PECo Construction, Testing and Laboratories, and contractors.
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These items' collectively constitute unresolved item 50-352/85-30-02.
4.0 License Condition 2.C.4 - Shift Advisor l
The resident inspector was informed on August 12, 1985, by the Superinten-i dent of Operations of the licensee's intent to assign a shift advisor to
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a new shift superintendent. The ' advisor was appointed to satisfy Limerick
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Full Power License Condition 2.C.4 which is discussed in Attachment 2 to
j the license. The basis for this requirement is described in'SSER-3, Section 13.1.2.2, with reference to NRR Generic letter 84-16. The licensee requires I
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the provision of an SR0 on each operating shift with six months of " hot" BWR experience, including an' unspecified number of startups and shutdowns
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and six weeks at greater than 20% full power.
Based on review of the new
shift superintendent's on-shift experience log, and a discussion with the
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Limerick Training Manager, the resident inspector concluded that a shift i
advisor was required to satisfy the License Condition.
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The new shift superintendent had witnessed startup and shutdowns and had a nominal 6 weeks power operation experience at Peach Bottom; he had not yet l
j accumulated 6 months of " hot" experience. The advisor selected is a shift
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i superintendent at Limerick and formerly, for almost 10 years, at Peach
l Bottom, meeting the minimum criteria for an advisor.
Effective August 13, 1985, the new shift superintendent joined the rotating shifts in effect replacing the advisor.
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A six shift complement is available at Limerick:
three daytime crews (day, utility and training); and, one (each) afternoon, evening and "off"
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There are five Shift Superintendents who rotate among the six shift crews; that rotation was unchanged with the assignment of the shift
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advisor and the addition of the new shift superintendent. The retention of i
this advisor-is required until the required experience is gained. The
described assignment' does not affect another Shift Supervisor who has had
a shift advisor since low power licensing in October 1984.
The NRC must be notified at least 30 days prior to the release of either of these
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s advisors.
No violations were identified.
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i 5.0 Startup Test Activities
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5.1 power Level Plateau Data Review
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The inspector witnessed portions of the plateau review conducted by I
l the licensee on July 31, 1985, as part of PORC meeting 85-064.
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review assessed the adequacy of low power testing, to permit power j
ascension to greater than 5% power.
The inspector verified that i
the licensee is performing an adequate evaluation of test results, is i
following approved administrative procedures for review evaluation
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i and acceptance of test results, and is maintaining proper test dis-l
cipline concerning test execution, changes and test records. The
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review, followed his administrative procedure and properly authorized i
i plant personnel to proceed into the next test condition. No unacceptable conditions were noted.
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5.2 FSAR Inconsistency Regarding Loss of Offsite Power Analysis During inspector review of startup test procedure STP-31.1 " Loss of Turbine Generator on Offsite Power" Revision 0 dated July 20, 1985 and meeting minutes "STP-31.1 Loss of Turbine Generator and Offsite Power Simulation Run" dated May 30, 1985, the inspector noted dif-ferences in the expected plant response and that described in FSAR chapter 15.2.6 " Loss of AC Power".
Specifically the differences were attributed to the reactor protection system (RPS) and main steam isolation valves (MSIV). The accident analyses describe RPS and MSIV actuation immediately following a loss of offsite power transient due to loss of power to the solenoids.
This analysis was not consistent with the Limerick design in that Limerick utilizes an uninterruptible power source, backed by batteries, to power the.RPS and MSIV. A loss of offsite power by itself will not actuate the RPS or MSIV closure since the solenoids will remain energized by the uninterruptible power supply.
It is only when the sensed parameters such as level or condenser vacuum, fall outside the trip values that this actuation occurs.
If the uninterruptible power supply was lost, however, the RPS or MSIV actuation would occur.
The inspector brought this to the attention of senior licensee management. The licensee took prompt action which was described in a PECo letter to NRC (V. Boyer to W. Butler) dated August 6, 1985.
Included as part of the licensee's action was a reanalysis of the Limerick design for loss of offsite power and review of the Chapter 15 analysis for any other inconsistencies.
The revised loss of off-site power transient was bounded by analyses performed in Chapter 15 and no further inconsistencies were identified.
No violations were identified.
5.3 Shutdown and Cooldown from Remote Panel The remote shutdown test was divided into two parts:
reactor shutdown and initial cooldown (STP 28.1), and cooldown followed by placement on the shutdown cooling system (STP 28.2).
Following the unplanned scram on September 11, 1985, the licensee elec'ted to conduct STP 28.2 first since the plant was already shutdown.
Operators transferred plant controls to the remote shutdown panel, depressurized the plant from about 200 psig to 20 psig using SRVs and RCIC, and successfully placed the unit on the shutdown cooling system. The reactor was restarted and on September 12, 1985, the licensee successfully con-ducted STP 28.1.
Operators transferred plant controls to the remote shutdown panel, initiated a reactor scram from the auxiliary equip-ment room by taking the main steam line radiation monitors out of the " Operate" position, and depressurized to about 600 psig using SRVs and RCIC.
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The inspector observed both tests at the remote shutdown panel.
The inspector monitored the pre-test briefings, operator communications, adherence to approved test procedures, and plant response to the imposed transients. Additional details are provided in Inspection Report No. 50-352/85-37.
No violations were identified.
5.4 Loss of Offsite Power Test The licensee successfully completed the loss of offsite power test (STP 31.1) on September 16, 1985.
The test was initiated from about 20% power and the unit scrammed about one minute later on low reactor water level. The level drop was caused by the loss of power to the condensate pumps which tripped the feed pumps on low suction pressure and caused a loss of feedwater flow to the reactor. All four unit diesel generators automatically started and powered vital loads as designed.
HPCI initiated automatically 23 minutes into the test as reactor level continued to decrease. As level began to increase, HPCI was manually secured to prevent excessive reactor vessel cooldown, and the smaller RCIC turbine pump was manually started and used to restore level. The test was terminated as planned after 30 minutes with the reactor shutdown, vital loads on the diesels, and vessel level being controlled by RCIC.
The licensee had conducted extensive preparation for this test, including several hours of scenarios run on the site simulator with those shift and test personnel taking part in the test. The scenarios were not limited to the expected course of events, but included sequences of events containing failures of key components such as one or more diesels failing to auto start.
The inspector monitored the pre-test briefings in the Control Room and noted that they were thorough and of high quality.
The briefings were interdisciplinary in nature, included potential "what-if" scenario variants, and clearly outlined the announcements which would be made to abort the test prematurely and the major restorative actions. The importance of good communications was stressed, and exhibited, throughout the test.
Additional details are provided in Inspection Report 50-352/85-37.
No violations were identified.
6.0 Event Followup 6.1 Contaminated Water Leak.Into Unit 2 i
6.1.1 Description of Event i
On August 1, 1985, at about 10:00 p.m., a security guard reported to licensee management the accumulation of water
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in a pit (Unit 2 Pipe Tunnel and Access Room) near the Unit L
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2 offgas holdup piping. The water level in the pit rose
from about 1/2 inch to about 18 inches on August 2.
Health
physics personnel analyzed this water and found low levels
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of radioactive contamination. Approximately 4 E-6 micro-l curies /cc of C0-58, and lesser levels of Co-60 and Cr-51 in
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some samples were found in water sampled from the Unit 2 Pipe Tunnel and Access Room, the location where the water
accumulation was first noted.
The highest concentrations
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j, were about 4% of the 10 CFR 20, Appendix B limits for unrestricted areas.
j The licensee's investigation identified the source of the
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water as an open 3/4 inch manual vent valve on drain piping i
from the Unit I liquid radwaste system Equipment Drain i
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Collection Tank.
Liquid waste was being transferred from
the Equipment Drain Collection Tank to the larger Equipment
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Drain Surge Tank to provide additional available tank
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capacity in the former. With the 3/4 inch manual vent
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l valve V-2104 open, liquid was apparently siphoned from the
I Unit 1 Equipment Drain Surge Tank (through the piping) to
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the Unit 2 Pipe Tunnel and Access Room.
The source was
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identified and isolated on August 2, 1985. Confirmation that the open valve and the Equipment Drain Surge Tank were
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the cause of the leakage was based on:
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the licensee's review of drawings;
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cessation of leakage after valve isolation;
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activity concentrations of comparable levels, and
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a slight downward trending in the Equipment Orain l
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Surge Tank level after the completion of the transfer
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t 6.1.2-Clean-up Activities I
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The licensee initiated timely actions to identify and
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isolate the source'of the leakage, to sample all Unit 2
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sumps (several others were found to contain low levels of l
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contamination), and to begin the processing of the water (estimated at 10 to 20,000 gallons) through the radwaste
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processing system. The contamination in the other sumps
was traced to either pumping from the Unit 2 Pipe Tunnel
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and Access Room or gravity flow from that area. No other
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sources were identified.
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All Unit 2 sump water had been transferred to the radwaste j
system by the end of August 2, 1985.- The sump walls and floors were monitored for contamination.
The highest level
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of contamination was about 5000 dpm per 100 square centimeters
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in the Pipe Tunnel and Access Room. Most of the other sumps were about 300 dpm per 100 square centimeters. Since
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these are normally " Clean" sumps, all were being decontami-
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nated. Although the contamination levels were low, the l
l licensee posted the areas as Radioactivity Areas to j
minimize possible spreading of contamination.
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The licensee's sampling program included all Unit 2 sumps,
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the settling pond (last hold-up point on site before i
discharge) and a low point in the discharge hose from the
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Unit 2 Reactor Enclosure Floor Drain Sump.
This sump has an automatic level control and therefore would automatically pump to the settling pond when the level rose past the trip point. No detectable activity was found in water samples
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i taken from the discharge hose, nor from the settling ' pond.
j This would indicate that no contaminated water had been i
discharged to the settling pond. The licensee lifted the
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pump electrical leads of the Unit 2 Reactor Enclosure Floor Drain Sump to assure no discharge of slightly contaminated water from the sump could recur without appropriate
processing.
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j 6.1.3 Corrective / Preventive Activities i
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The licensee closed, locked and tagged valve V-2104, although
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it was not determined how or when this valve had been opened.
Numerous previous waste water transfers from the Unit 1
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Equipment Drain Collection Tank to the Equipment Drain
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Surge Tank had taken place with no identified leakage, j
Routine surveillance of all noncontaminated sumps and J
systems in response to IE dulletin 80-10 was conducted as
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recently as July 18, 1985. No contamination had been found l
previously.
The licensee indicated that V-2104 may have l
been overlooked in the valve lineup procedures because it
was thought to be a Unit 1 valve, yet it does-have a Unit 2 coding on the P & 10.
Consequently, it was apparently
omitted from the s'urveillance procedures from both units.
Valve V 2104 was incorporated into the valve lineup checkoff
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list on August 6 and also incorporated in the monthly
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surveillance procedure.
In addition, the licensee has directed that, in the future, all Unit 2 sumps will be l
l sampled and analyzed prior to transfer to Unit 1 for
appropriate processing.
Finally, the licensee has initiated i
a third independent review of all the Unit 1/ Unit 2 inter-
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faces in radwaste piping; this had been underway by the
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Limerick Radwaste Coordinator, and was scheduled for completion by August 8, 1985.
Two previous reviews of these interfaces had been conducted of this area; one by Bechtel and the other by PECo.
6.1.4 Summary PECo Upset Report UR-012 dated August 2, 1985 was reviewed.
The inspector noted that the actual radiological consequences of this event were insignificant, although the potential for more serious concerns existed. The licensee's actions to (1) contain the contaminated water, (2) isolate the source of the leak, (3) investigate additional sources and the extent of contamination, (4) process the contaminated water and decontaminate the sumps, (5) review generic implications and (6) implement corrective and preventive actions were timely, thorough and appropriate.
The inspector had no further questions.
No violations were identified.
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6.2 Contaminated Spill at Unit 1 Reactor Building, Elevation 313
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On September 7,1985, the licensee experienced a spill of a highly contaminated resin-water mixture at elevation 313 of the Unit 1 Reactor Building.
The spill was caused by the failure of a RWCU demineralizer vent valve to close while valving the system on line.
An area about 20 feet by 30 feet was contaminated to levels of about 800,000 dpm per 100 square centimeters; no personnel contamination occurred.
The inspector reviewed the radiological protection measures imple-mented by the licensee to cleanup the spill while limiting the poten-tial for airborne contamination and personnel exposure. The initial steps by the licensee included tenting off the corridor surrounding the spill, frequent air sampling and use of respirators by cleanup
personnel. The inspector reviewed the radiation work permit (RWP)
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and verified that the personnel involved in survey and cleanup activ-ities were following RWP requirements.
The licensee's approach was
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consistently conservative with respect to radiation protection measures from the discovery of the spill until the corridor area was released
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for general access. Additional review of this incident is provided in Inspection Report 50-352/85-28.
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l No violations were identified.
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6.3 Reactor Scram on Low Water Level At 1:04 a.m. on September 11, 1985, the unit scrammed from 28% power on low reactor water level. The low level was caused by a loss of feedwater flow due to the trip of one of the two on-line condensate pumps tripping the two operating feed pumps on low suction pressure.
The condensate pump tripped on a spurious high suction strainer dif-ferential pressure signal generated while valving the third conden-sate pump into operation.
Reactor water level was restored by HPCI and RCIC.
The cause of the transient was associated with temporary modifications in the condensate and feedwater system.
The three condensate pumps each have a temporary (construction) suction strainer. At the time of the event, each strainer had an associated differential pressure r
trip circuit to trip the pump at 5 psid. One pump had been secured for strainer cleaning and was being valved back into service. There was no formal procedure for restoring a condensate pump after taking I
one out of service to clean the strainer. When the operator bumped open the suction valve of the offline pump to fill the volume drained for strainer cleaning, the pressure transient in the common suction piping caused the spurious trip of an operating condensate pump.
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The licensee's initial response was an evaluation of the method for
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restoring an offline condensate pump.
The tripped pump's strainer was examined, and the pump was placed in service with the drained
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volume vented to the condenser prior to valve motion. No trips
occurred. After discussions with the pump vendor, the licensee
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deleted the suction strainer pump trip and replaced it with an alarm only feature.
The alarm setting is 3 psid which should allow suffic-1ent time for operator action to protect the pump while preventing any similar condensate system transient.
Another temporary modification which contributed to the event involves the feed pump minimum recirculation valves. The Limerick design uses a microprocessor to assure a minimum of 40% through pump flow to prevent excessive vibration. When the required flow to the reactor vessel is less than 40*.' pump flow, the recirculation valve opens to send sufficient flow back to the condenser so as to maintain total pump flow at 40%. The system has worked to properly maintain
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40% pump flow, but excessive pump vibration has still been experienced.
Licensee and pump vendor personnel were still taking data and con-sidering long term corrective actions at the close of the inspection period.
l The short term corrective action for the pump vibration problem was to increase the minimum through pump flow, and this mode of operation l
contributed to the September 11, 1985 scram on low water level. Two feed pumps were operating when one of the two condensate pumps tripped l
as described above. Although one condensate pump had the nominal capacity to feed the reactor at the existing power level, the l
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remaining condensate pump was unable to support the operation of the two feedpumps in their temporary operating mode.
The result was a loss of feedpump suction pressure, the autor..atic trip of both feed pumps, and a subsequent reactor scram on low water level.
The inspector discussed the event and the status of.the condensate and feedwater systems with the operators, maintenance personnel and station management. The inspector noted a heightened awareness of the significance of activities taking place within those systems and a commitment by station aanagement to resolve the identified system problems.
During the inspection period, the condensate pump suction strainer trip was replaced with an alarm and the licensee continued to pursue resolution of the feedpump vibration problem.
No violations were identified.
7.0 Drywell Temperature Drywell temperature is limited by Technical Specifications to a volumetric average of 135 degrees F at four elevations within the drywell. That
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limit is based on the initial condition assumed for. containment pressure and temperature calculations associated with accident analyses which predict a peak of 340 degrees F following a design basis main steam line break. Although not contained in TS, FSAR Section 9.4.5.2 also describes a maximum normal area temperature of 150 degrees F for purposes of environ-mental qt.alification of equipment within the drywell.
The inspector reviewed trending of drywell temperatures during the month of August which consistently showed average temperatures in the range of 130-133 degrees F.
The average temperature is computed daily, as part of operational surveillance, by logging 15 temperature readings. The inspec-tor noted that element TI-77-1028 readings have been recorded, but not used, due to this detector's proximity to main steam lines at elevation 320 ft.
The inspector reviewed PORC meeting 85-023 minutes from February 28, 1985, which justified not using this detector's readings since it was judged to be not representative of general area temperatures and is a local hot spot with no nearby equipment. The inspector noted that this element read in excess of 160 degrees'F during the period in question; however, plans are being considered to relocate that element at a future date. The inspector discussed this issue with licensee personnel during this inspection period. Drywell temperature control is reliant upon the availability of both loops of drywell chilled water supplying the eight coolers located within the drywell. On September 3, the "A" chiller tripped and could not be successfully started due to a problem with its
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"B"' chiller were unsuccessful ~and
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average drywell temperature reached 139 degrees F before being brought to within the TS limit about 31/2 hours later. The TS require a reduction of temperature to within 135 degrees F within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />, or a plant shutdown.
j The inspector noted that increased temperatures should be expected as recirculation pump speeds are increased and power level is raised as the
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startup program progresses.
The licensee is considering a number of measures to reduce heat loads in the drywell, and improve chilled water and cooler operation, including insulation of piping supports and hangers.
Drywell temperature will continue to be monitored as part of future in-spections, and measures to control and limit that temperature is an unresolved item. (50-352/85-30-03)
8.0 Licensee Reports
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8.1 In-Office Review of Licensee Event Reports The inspector reviewed Unit 1 LERs submitted to the NRC Region I
office to verify that details of the event were clearly reported, including the accuracy of description of the cause and adequacy of
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corrective action. The inspector determined whether further informa-tion was required from the licensee, whether generic implications were involved, and whether the event warranted onsite followup.
The following LERs were reviewed:
LER Number Title
- 85-052 Inadvertent motor start of the D-13 diesel generator
85-053 Failure to meet hourly fire watch requirements85-055 Automatic isolation of Reactor Water Cleanup system inboard
isolation valve 85-056 Automatic isolation of primary containment instrument gas outboard isolation valves85-057 Safe shutdown cables not enclosed by fire barrier
- 85-058 Failure to check the 0-14 Diesel Generator Day Tank for water 85-059 Actuation of Control Room Emergency Fresh Air System due to failed chlorine analyzer 85-060 Failure to meet hourly fire watch requirement 85-061 Engineered safety feature actuation of Reactor Water Cleanup isolation valve 85-062 Failure to meet one hour limit on fire watch patrol 85-063 Actuation of Control Room Emergency Fresh Air System due to
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failed chlorine analyzer
'85-064 Noncompliance with Technical Specifications paragraph 3.4.9.2 dealing with shutdown cooling
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!85-065 Non-conservative phosgene gas alarm limit in control room
- 85-066 RPS Actuation - Reactor Mode Switch Misposition
- 85-067 Reactor Enclosure Ventilation System Isolation 85-068 Reactor Water Cleanup System Isolation 85-069 Failure to Perform Surveillance Test Within Specified Time Period
- 85-070 Ineffective Fire Seals
- previously discussed in Limerick Inspection Report 50-352/85-25
- Further discussed in Detail 8.2
- Further discussed in Detail 9.1 8.2 Onsite Followup of Licensee Event Reports For those LERs selected for onsite followup (denoted by asterisks in Detail 4.1), the inspector verified the reporting requirements of 10 CFR 50.73 and Technical Specifications had been met, that appropriate corrective action had been taken, that the event was reviewed by licensee, and that continued operation of the facility was conducted in accordance with Technical Specification limits.
8.2.1 LER 85-066; RPS Actuation - Reactor Mode Switch Misposition Startup of Limerick Unit I from Operational Condition 4 (Cold Shutdown) began at 1:30 p.m. on August 8, 1985 with coolant temperature at 135 degrees F and all rods fully inserted. The first step in this procedure was a change in mode switch position from SHUTDOWN to STARTUP. The Reactor Operator, upon initiating that position change at approxi-mately 1:49 p.m., went beyond the STARTUP position, which was enough to engage mode switch contacts in the RUN position.
Moving the mode switch to the RUN position, caused the j
initiation of a scram signal since all MSIVs were still fully closed, as well as the initiation of a Group 1 primary containment isolation signal. All rods were already fully inserted at the time that the scram signal was
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received, and all MSIVs and steam line drain valve were
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fully closed at the time that the Group 1 isolation signal was received.
The reactor remained in Operational Condition 2 (STARTUP),
and the mode switch was not repositioned to SHUTDOWN, since the plant remained in a stable, safe condition: no rods were required to be inserted, the reactor was subcritical prior to the scram, and MSIVs were already fully closed.
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At 1:50 p.m. control room operators suspended plant sta'rtup.
l Immediate actions included verification that rods remained i
fully inserted, and that the cause of the scram and Group 1
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isolation signals was the momentary positioning of the mode
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switch in RUN. These signals were reset, in accordance with procedures GP-8 and 11; however, Scram Review Procedure
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GP-18 was not implemented since its prerequisite is d
a..." scram condition when rods are withdrawn and irsertion occurs (or should have occurred) to complete the scram."
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Emergency Operating Procedure T-100 was followed, with the j-step was not performed, as determined and agreed upon by exception of placing the mode switch in SHUTDOWN.
This the PORC, the STA and the ISEG supervisor for the following reasons:
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j all rods were verified to remain full-in
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avoidance of another unnecessary challenge to the RPS l
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the bases for selection of the SHUTOOWN position in T-100 were not applicable to this RPS actuation
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The mode switch, prior to April 1985, had required a strong
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(two-handed) force to select different positions.
Because
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of this condition, and a cracked escutcheon plate, the.
switch handle and plate had been replaced under MRF-85-02679 i
on April 23, 1985.
The replacement switch, which is now I
easier to position, moves similar to the mode switch installed
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j on th-- simulator.
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i The inspector reviewed the post-scram computer printout l
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which verified the actual scram signal receipt and subse-
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quent reset conditions.
Scram discharge volume level i
increased only to the 3 gallon alarm setpoint; therefore, movement to the SHUT 00WN position was not required to reset l
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the scram (which includes the SDV vents and drains reopening)
j since high SDV level scram setpoint was not reached. The
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L licensee also considered other potential, similar non-i
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modification maintenance or replacements which may have l
l occurred during the'past four months when the plant remained in Operational Condition 4 (wherein relatively few mode
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.l switch position changes were made) and for which no formal
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l operator training would have been conducted -- none were
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identified. The LER attribeted the cause of this event to i
personnel error, although there was a contribution from the modification previously raade to the switch. The startup
resumed at 3:17 p.m. after PORC and plant management' evaluation.
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The inspector had no further questions concerning this
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8.2.2 LER 85-070; Ineffective Fire Seals
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i On August 14, 1985, during preparations for cable pulling
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'I associated with a modification, the licensee discovered
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voiding within a cable tray penetration from the cable I
spreading to inverter rooms in the Control Structure.
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Investigation of the voiding resulted in a decision to.
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i sample.10% of all suspect penetrations and, based on those j
results, 100% cf the total 77 affected penetrations. The
affected penetrations (approximately 80% were safety i
i related) are sealed with BISCO SF-20, a 3 hour3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> fire rated l
barrier material manufactured as Dow Corning 3-6548 silicon
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RTV foam. The penetration seal consists of a 9 inch minimum
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thickness of foam, with 1 inch ceramic boards installed on
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either end which act as damming during initial installation
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and are subsequently left in place and considered as part
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of the fire barrier.
The boards are required to be left in
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place tecause the cable tray is aluminum and therefore
contributes to higher heat conductivity than would be seen
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with a steel tray.
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The inspector observed the condition of three penetrations
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in the Control Structure which were found to exhibit voiding.
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Penetration 763-E009 was the first to be inspected by the i
licensee and was found to have more than-50% voiding, prin-
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cipally at the lower edges around which the-SF-20 material
had not sufficiently flowed during initial installation and i
expansion. The. licensee instituted compensatory fire
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watches as required by Technical Specifications in all
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appropriate affected locations,- and those watches remained
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in effect through this inspection period. Temporary repairs I
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for voids found included stuffing the penetration with
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' approved fire seal material and/or re-sealing voids with t
SF-20 foam. Also inspected were penetrations 761-E003 and i
4 located between Control Structure emergency switchgear
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rooms and a corridor at elevation 239. Those penetrations
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were found to exhibit similar voiding as described above
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and required the same immediate corrective action.
Vendor (
j document packages for these three penetrations were reviewed
for proper material controls and. installation records, j
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Seal material testing confirmed proper density cell structure
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and final thickness The pours were made and final inspections l
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The apparent cause of the inadequate installation of the foam was due to its high expansive properties in a relatively quick time (1 to 3 minutes) and the fact that final in-stallation inspection was performed for these penetrations with the damming material left in place.
Review of the BISCO Installation and Inspection Procedures'SP-105 and QCP-103 confirmed that the seals had been inspected by use of sight holes through the ceramic board through which the material had been originally injected. Due to the expansive properties of SF-20 foam, the inspection for voiding at the sight holes was not conclusively indicative of possible voiding at other areas within the seal.
The licensee had completed their inspection of 150 of the total 154 penetration sides affected by August 30, and had found some measure of voiding at 60 sides.
Temporary repairs were implemented immediately, although approxi-mately half of the 60 voids found were observed to be minor.
The remaining 4 penetrations were repaired by the end of this inspection period. The permanent disposition and repair of voids found (i.e. re-sealing with BISCO SF-20) will be reviewed in a future inspection. (50-352/85-30-04)
8.3 Review of periodic and Special Reports Upon receipt, periodic and special reports submitted by the licensee were reviewed by the inspector.
The reports were reviewed to deter-mine that the report included the required information,'that test results and/or supporting information were consistent with design predictions and performance specifications, that planned corrective action was adequate for resolution of identified problems, and whether any information in the report should be classified as an abnormal.
occurrence.
The following periodic and special reports were reviewed:
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Monthly Operating Reports - June, July, August 1985
Semi-Annual Effluent Releases, Report No. 2; January through
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Special Report - Inoperable Seismic. Monitoring, June 13 and July
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l Special Report - Notification of Application of Respiratory
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l Protection Program, dated July 31, 1985 I
t These reports were found acceptable.
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9.0 Monthly Surveillance and Maintenance Observation
i 9.1 Surveillance Activities
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The' inspector observed the performance of selected surveillance tests l
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the surveillance test procedure conformed to i
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technical specification requirements; administrative approvals and
tagouts were obtained befort initiating the test; testing was accom-
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i plished by qualified personnel in accordance with an approved sur-
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veillance procedure; test instrumentation was calibrated; limiting
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conditions for operations were met; test data was accurate and com-j j
plete; removal and restoration of the affected components were pro-t j
perly accomplished; test results met Technical Specification and
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procedural requirements; deficiencies noted were reviewed and appro-
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priately resolved; and the surveillance was completed at the required l
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l These observations included:
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ST-6-107-885-1; Thermal Limits Determination, performed on I
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September 3, 1985 t
j ST-6-092-314-1; D14 Diesel Generator Operability Test Run, per-
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formed on August 26, 1985 i
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ST-6-020-234-1; D14 Diesel Generator Fuel 0:1 Transfer Pump,
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l Valve and Flow Test performed on August 26, 1985 L
ST-6-107-590-1; Daily Surveillance Log /0PCONS 1, 2 & 3 i
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ST-6-092-314 and 020-234 were run concurrently on August 26 for diesel I
i 014 to demonstrate mor+.hly engine operability, fuel oil transfer j
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capability, and a quar.erly pump and valve IST verification.
These i
j surveillances were selected because of the events reported in LER-058
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and discovered on June 11, 1985, whereby the D14 engine had been t
i operated on four different occasions for greater than one hour
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without checking for accumulated water in its fuel oil day tank as
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required by TS. Both of the above procedures were found to contain
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steps to check for water accumulation, and these were followed during i
j completion of the tests. The inspector had no further questions, t
L 9.2 Maintenance Activities t
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The inspector periodically reviewed the status of selected maintenance
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activities to verify compliance with the station's administrative
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procedures and to assess the technical adequacy of the repair technique.
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9.2.1 Condenser Tube Leaks During this period, work under Maintenance Request Form (MRF)85-06784 on the Intermediate Pressure "0" condenser water box was observed.
The water box was drained as part of the licensee's investigation into possible condenser tube leaks which were first suspected during a power reduction from 19 to 4% power on August 16 - 17 at which time conduc-tivity sampling showed higher than expected values. Tubes were subsequently plugged on the "D" loop on August 21 -
23. During this inspection period, the licensee has inspec-ted almost all tubes in the condenser (high, intermediate and low pressure condensers) on all four circulating cooling water loops. Approximately 750 - 1000 tubes have been plugged, following helium gas leak testing and eddy-current inspec-tions.
The plugged tubes have all exhibited a pattern of
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steam-side cracks or indications, at mid-span and at similar lower peripheral locations in the tube arrays.
Licensee engineering personnel are evaluating the nossible causes of this problem, including a suspected de-zincification of the
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Admiralty tube material.
The licensee was still experien-cing higher than expected conductivity, approximately 0.5 micromho/cm at the end of this inspection period, although less than the TS limit of 1.0 micromho/cm.
No violations were identified.
9.2.2 Spray Pond The inspector reviewed Temporary Circuit Alteration (TCA)-351 which was approved by PORC on August 27 to raise the normal spillway height by about ten inches within the spray pond.
This modification added a plywood board at the pond spillway under MRF 85-6966 which allowed for pond capacity of up to two feet above the minimum TS limit (elevation 250 ft) and an additional 2.7 million gallons of additional possible inventory in the pond.
The board was observed by the inspector, and the associated safety evaluation
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was discussed with the responsible Test Engineer who authorized it.
The inspector noted that proper consideration had been given for the effect of this modification on pond thermal performance, and that no unreviewed safety questions or TS changes were involved.
The inspector found the Test Engineer to be knowledgeable of this TCA and the bases for the safety evaluation's conclusions.
The inspector did note that the TCA was in effect indefinitely, although the TCA log would be periodically reviewed, and that subsequent
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cold weather operation would most probably result in a
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freezing of the pond surface this coming winter.
This could possibly dislodge a: damage the board across the i
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spillway; however, loss of the added stored water would not result in any obvious safety hzard since water would drain into the spill pit until normal pond level was stabilized.
The inspector had no further questions.
10.0 Diesel Generator Brush Arm The diesel generator support arm for the rotor slip ring brushes at Millstone Unit 3 failed by fatigue after minimum run time during preopera-tional testing in August 1985. The Millstone support arm is approximately 24 inches in length.
As followup, the four diesel generators at Limerick were examir.ed in the rotor brush support area.
The Limerick generators have two support arms on each unit, with lengths of approximately 12 inches.
The support arms have double brush sets on both slip rings for a total of eight brushes per generator. The inspector observed that the design of the Limerick brush
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holder support is apparently less susceptible to failure than those at
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Millstone due to the shorter support arm length. The licensee has initiated contact with Millstone representatives and Beloit (the generator manufac-turer). The Limerick diesel generators currently have between 700 and 1000 hours0.0116 days <br />0.278 hours <br />0.00165 weeks <br />3.805e-4 months <br /> of operation. The licensee plans to inspect a brush arm holder from the Limerick Unit 2 generators which are stored on-site.
The senior
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resident inspector will follow the licensee's evaluation and possible corrective action for this problem. (50-352/85-30-05)
Unresolved Items Unresolved items are items about which more information 1. required to ascertain whether they are acceptable or constitute a deviation or a violation. Unresolved items are discussed in Details 2.3, 3.4.3, and 7.0.
11.0 Exit Meeting The NRC resident inspector discussed the issues and findings in this report throughout the inspection period and at exit meetings held with Mr. G.
Leitch on September 6 and 20, 1985.
At these meetings, the representatives of the licensee indicated that the items discussed in this report did not involve proprietary information.
No written material was provided to the licenseee during this period.
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