IR 05000245/1987003
| ML20205K444 | |
| Person / Time | |
|---|---|
| Site: | Millstone  |
| Issue date: | 03/25/1987 |
| From: | Mccabe E NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20205K366 | List: |
| References | |
| 50-245-87-03, 50-245-87-3, 50-336-87-03, 50-336-87-3, GL-86-10, IEB-79-02, IEB-79-2, IEB-80-10, IEIN-84-94, IEIN-85-045, IEIN-85-45, NUDOCS 8704010585 | |
| Download: ML20205K444 (37) | |
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. i U.S. NUCLEAR REGULATORY COMMISSION
REGION I
Report: 50-245/87-03; 50-336/87-03 Docket Nos: 50-245/50-336 License Nos: DPR-21; DPR-65 Licensee: Northeast Nuclear Energy Company Facility: Millstone Nuclear Power Station, Waterford, Connecticut Inspection at: Millstone Units 1 & 2 Dates: February 10, 1987 through March 9, 1987 Inspectors: Theodore A. Rebelowski, Senior Resident Inspector Geoffrey E. Grant, Resident Inspector Eben L. Conner, Project Engineer Approved: $kh 3 lq5'/87 E. C. McCabe, Chief, Reactor Projects Section 3B Date Summary: Report No. 50-245/87-03; 50-336/87-03 (February 10 to March 9, 1987)
Areas Inspected: This inspection included routine NRC resident inspection (165 hours0.00191 days <br />0.0458 hours <br />2.728175e-4 weeks <br />6.27825e-5 months <br />) and region-based project engineer inspection (40 hours4.62963e-4 days <br />0.0111 hours <br />6.613757e-5 weeks <br />1.522e-5 months <br />) of previously iden-tified items, Standby Gas Treatment System Initiation (Unit 1), Information Notice 85-45 on Seismic Interactions (Units 1 & 2), the Emergency Service Water System (Unit 1), licensee response to vendor service information (Unit 1), surveillance (Units 1 & 2), Average Power Range Monitor review (Unit 1), Plant Operations Review Committee activities (Unit 1), periodic and special reports, observation of Appen-dix R Areas (Unit 2), and Steam Generator surveillance (Unit 2). This report also describes a meeting held with the licensee on Unit 2 Fire Protection in NRC Region Results: Unit 1 - No inadequacies were identified. An area that needs additional licensee review is the Emergency Service Water strainers' susceptibility to common-mode failure (Report Detail 6).
Unit 2 - No inadequacies were identified. The unit returned to power after com-pletion of steam generator repairs. A secondary chemistry program to identify minor primary to secondary leakage (0.15 gpm) has been administratively established (Report Detail 14). Appendix R concerns were identified (Report Detail 11.)
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TABLE OF CONTENTS
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- Persons Contacted.................................................... 1
j Summary of Facility Activities....................................... 1 ,
j Previously Identified Items.......................................... 1
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, 3.1 Operation with an ECCS Subsystem Inoperable..................... 1 3.2 Operation Above the Limit for Power Monitoring with Excore .
3 Detectors....................................................... 2 '
3.3 Design Change Control........................................... 2 3.4 Charging Pump Failures.......................................... 2
, 3.5 10 CFR 50, Appendix J Exemption Requests........................ 3 ,
1 3.6 I EB 79-02, Ancho r Bol t Tes ti ng. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
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3.7 Setting the AGAF Based on APRM Power Leve1...................... 3 j 3.8 Unmonitored Discharge Path to the Sanitary Sewer System......... 4 3.9 Failure of valve Motor-0perator Bevel Gear Housing. . . . . . . . . . . . . . 5 3 3.10 Switch Calibrations and Snubbar Surveillance.................... 5 3.11 HGA Relays not Properly Covered................................. 6 3.12 Leak Tests without Proper Flow Test Box Set Up.................. 6 3.13 Trouble Report Identification of Lead Department. . . . . . . . . . . . . . . . 7
- 3.14 Bus Undervoltage Protection and the Associated Test Program..... 7
3.15 Preparations for Rod Block Monitor Functional Test.............. 7
- 3.16 As-Built Drawing Discrepancy.................................... 8 3.17 PDCR Documentation.............................................. 8 3.18 Condition of Project Hold Materia 1.............................. 8
i Standby Gas Treatment (SGT) System Initiation (Unit 1)............... 9
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! Seal Table Seismic Interaction Inspection (Units 1 & 2).............. 9 4 Emergency Service Water (ESW) System Design (Unit 1)................. 10 J Control of Neutron Flux Noise (Unit 1)............................... 11 Observation of Surveillance (Units 1 & 2)............................ 12
j 5 Average Power Range Monitor (Unit 1)................................. 13 l
1 Plant Operations Review Committee Activities (Unit 1)................ 14
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1 Millstone 2 Fire Protection Meeting (Unit 2)......................... 15
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1 CFR 50 Appendix R Field Observations (Unit 2)..................... 16 1 Review of Periodic and Special Reports (Units 1 & 2)................. 17 i 1 Steam Generator Surveillance (Unit 2)................................ 18
1 Routine Review of Plant Activities................................... 18 1 Management Meeting................................................... 19 l 1
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DETAILS 1. 0 Persons Contacted l
Mr. S. Scace, Station Superintendent Mr. J. Stetz, Unit 1 Superintendent l Mr. J. Keenan, Unit 2 Superintendent The inspector also contacted other licensee employees including members of the Operations, Radiation Protection, Chemistry, Instrument and Control, Maintenance, Reactor Engineering, and Security Department .0 Summary of Facility Activities Unit 1: The unit operated at full power except for routine power reductions to conduct main steam and turbine stop valve testing and condenser backwashin Unit 2: At the beginning of the report period the unit was in Cold Shutdown (Mode 5). On completion of repairs to steam generators and safety evaluation reviews, the unit was restarted and was placed on line on February 16. Since startup, the unit has operated at full power except for minor power reductions for routine surveillance testin .0 Licensee Actions on Previously Identified Items 3.1 (Closed) VIO 336/82-06-01, Operation with an ECCS Subsystem Inoperable This violation involved changing operational modes with an inoperable Emergency Core Cooling System (ECCS) subsystem. The inoperability was '
due to a failure of the boric acid pump discharge valve operator moto The ECCS Limiting Condition for Operation (LCO), Technical Specification (TS) 3.5.2, requires two separate and independent ECCS subsystems. Each subsystem includes a charging pump with a separate and independent flow path from a boric acid tank via the boric acid pump or by gravity fee Failure of the combined boric acid pump discharge valve (common to both trains) made one of the boric acid trains inoperable. This was not recognized at the time of the mode chang '
The licensee responded to this violation by taking administrative actions such as stationing an operator, with no other duties, at the valve except to manually open it when required, temporary changes to ECCS procedures, and Plant Operations Review Committee (PORC) approval of the operational safety evaluatio In addition, operations personnel were briefed on boric acid LCOs and a TS change was requested. The inspector confirmed that the TS change had been authorized by NRC, that procedural controls such as the shift turnover report, logging in the shift supervisor's log, and the heat-up check sheet, were being used, and that this had not been a recurring problem. The inspector had no further question . .
3. 2 (Closed) VIO 336/83-08-2, Operation Above the Limit for Power Monitoring with Excore Detectors This violation involved operation at 100% power contrary to the TS 3. requirement that, when linear heat rate is being monitored by the Excore
- Detector Monitoring System, reactor power level shall be limited to 89%.
NNEC0's response stated that a computer failure went unnoticed because several " normal" computer indications were being displayed as though they were current values. Corrective steps included periodic logging of com-puter operability and the installation of a computer failure alarm schem The inspector confirmed that the above corrective steps are in effect at the present time. The inspector had no further question .3 (Closed) UNR Items 50-245/84-10-01 and 50-336/84-11-01, Design Change 1 Control This item concerns licensee identified installation errors and inadequate operational procedures for the Post Accident Sampling Systems (PASSs)
at Haddam Neck and Millstone 1. Modifications made under the corporate Plant Design Change Request (PDCR) system were involved. On December
, 13, 1984, an order modifying the Haddam Neck License was issued because of the failure of the reactor cavity seal on August 21, 1984. An issue was management control of the PDCR process. After extensive upgrading of that process, the NRC closed this issue for Haddam Neck as documented in T. E. Murley's letter of April 28, 1986 to J. F. Opeka. Since the PDCR system is a corporate one, the actions taken for Haddam Neck also apply to Millstone. Also, concerns about specific Millstone design changes are pursued on an individual basis, with the associated controls specifically evaluated. Therefore, the inspector had no further ques-tions on this unresolved item for Millstone 1.
- 3.4 (Closed) UNR Item 50-336/84-16-01, Charging Pump Failures This unresolved item concerns repetitive failures of Gaulin positive displacement (PD) charging pumps, originally reported by NNECO as a 10 CFR 21 issue on May 25, 1984. The unresolved issue was the disagreement between the manufacturer and the licensee as to the cause(s) of the pump failure Licensee action on this problem is still in progress. The vendor has
! indicated that the pumps are failing due to problems with the charging
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system design. Metallurgical analysis of the fractured "A" charging pump block by an independent consultant states that pump block cracking was 4 originating at inclusions. However, the inclusions are small, and the failure was attributed to fatigue loading on the charging block. The
"C" charging pump, af ter its charging block cylinder intersecting bore area was shot peened by Gaulin, was reinstalled during the last outag No operational problems have been experienced during the subsequent limited period of operation of the "C" charging pump. However, the B
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charging pump failed in a similar manner on March 6, 1987. No Technical Specification violation occurred because two of the three charging pumps remained operable, as require The inspector reviewed a C-E Power System Improvement Program report in-dicating that positive displacement pumps manufactured by Gaulin, Union, and Armco all have relatively poor overall performance ratings. The licensee is investigating actions such as replacing one PD pump with a centrifugal pump, adding a fourth pump of centrifugal design, replacing all Gaulin pumps, etc. In addition, they have obtained three Gaulin pumps from a cancelled plant. Although the manufacturer and the licensee have not reached agreement on the failure cause, Technical Specification requirements for the charging pumps are being met. No inadequacies have been identified in the licensee's actions and plans. Therefore, the licensee is in compliance with NRC requirements, and this unresolved item is closed. Routine NRC review of plant operations will continue to ad-dress charging system reliability and compliance with NRC requirement .5 (Closed) UNR Item 50-245/84-18-01, 10 CFR 50, Appendix J Exemption Requests This item 1s for licensee submittal and NRC review of Appendix J exemp-tions. Exemptions were requested by NNECO in numerous letters following the August 7, 1984 request from the NRC. On May 10, 1985, the NRC authorized appropriate exemptions from 10 CFR 50 Appendix J. Routine NRC specialist inspections address compliance with Appendix J. The in-spector had no further questions on this issu .6 (Closed) UNR Item 50-336/85-01-01, IE Bulletin 79-02, Anchor Bolt Testing Documentation available at the time of the original inspection did not demonstrate that all IE Bulletin 79-02 provisions had been met. Speci-fically, data on verification of design requirements for unaccessible concrete anchor bolts testing was not available. Since that inspection, NNEC0 letter of April 4, 1985 provided data on inaccessible concrete anchor bolts and a reliability analysis. The inspector reviewed the data and, through consultation with the original inspector, found the April 1985 data acceptable. This item is close .7 (Closed) UNR Item 50-245/85-02-01, Setting the AGAF Based on APRM Power Level This unresolved item is that the Average Power Range Monitor (APRM) trip
! may be non-conservative if the APRM gain adjustment factor (AGAF) is greater than 1.0. The AGAF is an output of the on-line computer. Chang-ing the AGAF potentiometer setting has no affect on the APRM trip set-point but only affects indication. The AGAF setting equals the computer calculated APRM reading (based or the heat balance) divided by the con-trol room meter APRM reading. 'ne previously acceptable AGAF was 1.00 10.03; that is, a power channel .neter reading could be 13% different from
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the computer channel reading. The licensee has revised SP 1040 and Reactor Engineer Form RE 1040-1, both titled "APRM Calibration Using Heat Balance," to state: "The 'as left' APRM readings shall be set equal to the actual percent of core thermal power or higher not to exceed 2 per-cent". The as-left allowable range for AGAF is 1.00 +0.00/-0.02 for 100%
power. These are conservative setting The inspector confirmed the revision to SP 1040 (Revision 7, dated Febru-ary 1,1985) and RE Form 1040-1 (Revision 2, dated July 3,1985) and reviewed some completed forms. The as-left APRM readings and the AGAF values were acceptable. The inspector had no further questions on this issu .8 (Closed) UNR 50-245/85-02-03, Unmonitored Discharge Path to Sanitary Sewer System This unresolved item was initiated when the licensee cleaned out a block-age in a supposedly radioactively clean drain and found radioactivity in the material removed. The issue was also the subject of IE Bulletin (IEB) 80-10, Contamination of Nonradioactive Systems and Unmonitored Radioactive Releases, and IE Information Notice (IEN) 84-94, Reconcen-trations of Radionuclides in Discharges to Sanitary Sewage (SS) System The inspector reviewed licensee internal memos related to the IEB and IEN. NNECO's July 3, 1980 response to IEB 80-10 states that they re-viewed nonradioactive systems that could become radioactive through sys-tem interfaces. The yard drains are listed as such a system. The lic-ensee concluded that adequate sampling / analysis or monitoring programs exist to promptly identify contamination which could lead to an unmoni-tored, uncontrolled release to the environmen In regards to IE Information Notice 84-94, a number of licensee memos were located. In a May 29, 1985 memo, R.J. Herbert recommended the fol-lowing corrective actions to W.D. Romberg: 1) a Project Assignment to identify all SS inputs and bring blueprints up to date; 2) Installing a permanent radiation monitor at the SS final discharge point (Manhole ;
number 14); and 3) adding SS manhole number 14 to the chemistry sampling program. In R.J. Herbert's memo to W.D. Romberg on July 2, 1985, Item 3 above was identified as completed and Project Assignments for recom-mendations 1 and 2 had been issued to Station Services Engineerin Memos from the three operating departments confirming no discharges in-
'. volving radionuclides to the sanitary sewer system were obtained. The last such memo, J.N. Kowalchuk to J.P. Kangley, dated August 13, 1986, concludes that installation of a sewerage system radiation monitor is notjustifiabl In addition to a review of the above memos, the inspector reviewed the sampling program for the site catch basins including manhole # 14 (sewer line to New London). Since the start of this sampling program in 1985 (manhole # 14 was added to the list on July 12, 1985), the principal I
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gamma emitters have been below the minimum detectable value (5 E-7 micro-curies per millimeter). Although there is value in monitoring the sewer discharges from the site, because of not finding any radiation in such discharges for ten months, the inspector, in consultation with the NRC Region I Health Physics staff, agreed that such monitoring is not re-quired. The inspector had no further questions on this issu .9 (Closed) UNR Items 50-245/85-14-01 and 50-245/85-15-04, Failure of Valve Motor-0perator Bevel Gear Housing This unresolved item relates to the failure of a Crane-Teledyne (C-T)
bevel gear housing cn drywell spray isolation valve 1-LP-16A. This housing failed where it attaches to the motor operator with 4 one-inch long cap screws. A licensee special surveillance of all other accessible C-T motor operator units of the T4, T10, and T40 sizes identified 9 other units that were loose. These units were found to be operable before and after corrective maintenanc The inspector reviewed the July 14, 1986 evaluation by the licensee's Materials Testing Laboratory and Component Engineerin This report attributes the gearcase failure to cap screw loosening which created high-stress fatigue at the bolted connection. The loosening was caused by vibration. This condition has been corrected by replacing the C-T cap screws with Nyloc screws, and by using Locktite and/or lock washer The inspector observed a number of C-T valve operators in accessible areas of the plant. The cap screws that loosened are covered by another housing and are not visible without disassembly. The inspector noted an information " Note" in MP 710.9, Rev. 0 (Inspection of Teledyne M0V's).
This note relates to past problems with M0V operators. Safety related M0V's are operationally tested at least quarterly (LPCI and Core Spray are operated monthly) and inspected under MP 710.9 once during each re-fueling cycle. During the refueling inspection, checks are made for loose cap screws with the housing removed. The inspector had no further questions on this issue.
i 3.10 (Closed) VIO Item 50-245/60-15-01, Switch Calibrations and Snubber -
Surveillances This Unit 1 violation related to: 1) Calibration of safety-related pres-sure switches which monitor low suction pressure, start prohibit, and interlocks for safety-related feedwater coolant injection (FWCI) pumps A and B; and 2) Visual inspections of mechanical snubbers did not iden- l tify misaligned self-aligning rod end bushings. The licensee responded !
to this violation in their letter dated November 7, 1985. These issues l were inspected separately, l The inspector reviewed IC 400A, Rev. 12, Change 1, Calibration of In-struments Used to Satisfy Technical Specification Requirements and/or Computer Core Performance Calculation Inputs, and IC 400A-93, FWCI A &
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B Train Pump control and Enable Pressure Switches. Pressure switches PS-2-16, PS-2-20, PS-2-54, and PS-2-56 (the switches that were found in violation) plus numerous other level and pressure switches (identified by the licensee) are included in the I&C surveillance program as correc-tive action for the violations. IC 400A-93 page 8 is a valve line-up sign-off sheet to be completed and verified after switch calibratio Other surveillance forms contain the same type of sign-off sheet Resident inspector review has found that the switches are being cali-brated as required. The inspector had no further questions on corrective actions for this part of the violatio For the snubber issue, the inspector reviewed MP 739.5, Rev. 2, Inspec-tion of Hydraulic Snubbers, and MP 739.6, Rev. 1, Change 1, Mechanical Snubber Visual Inspection. Both procedures had been modified to include inspection of the end attachment spherical ball bushing for movement from the bore that it is pressed int The bushings can be kept in place by using washers to take up most of the extra space between the bushing and the snubber fork. The inspector physically observed a number of snubbers
, for the isolation condensers. In no case was there enough space to allow
the bushing to come out of the bore. Also, resident inspector review has found the licensee's present checks for snubber misalignment to be adequate. The inspector had no further questions on corrective actions for this part of the violatio .11 (Closed) UNR Item 50-245/85-12-02, HGA Relays not Properly Covered Eleven vital relays in control room panel CRP 908 did not have protective covers installed. The inspector confirmed that work order (WO) M1-85-05169, to install covers on HGA relays, was completed. The inspector physically observed the HGA relays, noting all covers were in plac In addition to the covers, Plexiglas sheeting has been installed over the relay panel. The inspector had no further question .12 (Closed) VIO 50-336/85-17-01, Leak Tests without Proper Flow Test Box Set Up l
This violation involved leak testing of the containment purge exhaust isolation valves without: 1) the flow box being set up properly; 2) test valves V-12 and V-13 installed; and 3) removing the air supply prior to recording data. By letter dated May 31, 1985, NNECO stated that the test flow box was modified to conform to the requirements, test equipment valves V-12 and V-13 were installed, SP-2605D (Containment Leak Test-Type C) was changed to require that all supply air shall be physically disconnected prior to the start of data collection, and all personnel involved with containment leak testing have been briefed on these change The inspector reviewed SP 2605D and confirmed the changes were mad IR 50-336/86-28 documents the latest LLRT inspection. No problems re-lated to this issue were identified. Also, resident inspector review has confirmed proper flow test box set up during tests observed. The inspector had no further question . . _ _ _ _ _ _ - .
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3.13 (Closed) UNR Item 50-245/85-20-01, Trouble Report Identification of Lead Department This item involved an inspector observation that ACP-QA-202-C, Admini-strative Control Procedure for Work Orders (W0s) appeared to permit a condition where a designated lead department would not be aware of the writing of a trouble report (TR) and would not meet the responsibilities of a lead department as defined in paragraph 5.0 of the procedur The inspector reviewed a December 24, 1985 licensee evaluation of this even TR 29M1145946 (the TR in question) was initiated by Operations to identify a potential cracked weld in the liquid nitrogen syste Since the WO required a dye check and QC performs dye checks, the NRC inspector (IR 245/85-20) concluded that the lead department should be Q However, the licensee concluded that the properly assigned depart-ment was maintenance (to repair the weld), and that paragraph 5.0 of the subject procedure did not require revision because QC checks work but is not a primary work performing organization. The inspector confirmed that the liquid line was repaired (the area of concern was replaced when a new valve was installed), that the W0s were properly closed, and that paragraph 5.0 of ACP-QA-2.02C is acceptable. The inspector had no fur-ther question .14 (0 pen) UNR Item 50-245/85-24-04, Bus Undervoltage Protection and the Associated Test Program This unresolved item relates to the implementation of the new bus under-voltage protection system and the associated test program. This issue also relates to the NRC generic issue of degraded grid voltage. Comple-tion was originally scheduled for the October 1985 outage, but was de-layed for design improvements and equipment availabilit The inspector reviewed the design change that relates to this project, PDCR 1-120-83 (Undervoltage Detection Modification). It is planned to tie in new undervoltage relay logic with the loss of normal power (LNP)
logic, split the LNP logic into S1 and 52 divisions, and provide for auto-reinstatement of the load shed feature. This work is to be per-formed during an outage. The inspector reviewed licensee and NRC cor-respondence on the degraded grid protection issue. In NNECO's letter of January 13, 1986, they provided additional information in response to staff questions of December 12, 1985. This December 1985 NRC letter concluded that installation and testing during the 1987 refueling outage was acceptable. Installation and testing of the modified circuitry will be reviewed during the 1987 outag .15 (Closed) UNR Item 50-245/86-13-01, Preparation for Rod Block Monitor Functional Test This unresolved item relates to inadequate preparation for rod block monitor surveillance. Although the technicians understood the general intent and sequence of the test, they were using a revised surveillance
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procedure with which they appeared to be unfamiliar. The procedure had not been " walked" or " talked" through prior to its conduct. This created confusion at several points during the surveillance. The licensee's corrective action was to initiate I&C Departmental Instruction 1-I&C-9.07 (Surveillance Good Practices). The inspector evaluated this new instruc-tion and concluded that it should be helpful. It provides guidance in the areas of procedures, test equipment and tools, approvals, performance, and completion. In addition, the resident inspectors have noted that I&C surveillances are being performed proficiently (see Detail 8 of this report for an example). The inspector had no further question .16 (Closed) UNR Item 50-245/86-16-01, As-Built Drawing Discrepancy This unresolved item resulted from a discrepancy between the number as-signed to an Agastat time delay relay in the feedwater timing circuit on the as-built drawings and the number on PDCR 1-36-8 The licensee's corrective actions were to: 1) resolve the discrepancy; and 2) determine its cause. For item 1, drawing change request DCR M1-P-066-86 was pro-cessed and the control room drawings were marked on August 8, 1986 to show the PDCR relay tag number. The drawing was revised on February 12, 1987. Item 2 resulted from a plant engineer approving the renumbering
, of the relays with numbers different than the PDCR and the original DCR submittal. The plant engineer was made aware that, before a change like this can be made, a review of previous documentation is required so traceability and accurate documentation can be maintained. The inspector had no further questions on this issu .17 (Closed) UNR Items 50-245/86-16-02 and 50-336/86-17-01, PDCR Documentation This unresolved item relates to inadequate PDCR documentation pagination and identification of attachments prior to PDCR transfer to the nuclear record facility (NRF). The licensee's PDCR Task Force, after reviewing this item, initiated changes to the PDCR procedure and form to incorporate the page and PDCR number on every page of the package and to identify related attachment The inspector reviewed Revision 6 to ACP-QA-3.10 confirming that the PDCR number and the Revision number are to be placed on each page of the PDC This revision, dated November 21, 1986, resolves the inspector's concer Also, PDCR documentation is periodically reviewed during NRC inspection The inspector had no further questions.
3.18 (0 pen) UNR Items 50-245/86-16-03 and 50-336/86-17-02, Condition of Project Hold Material l This unresolved item resulted from finding materials, issued against previous Millstone Units 1 and 2 project authorizations, being held in i' the project hold area for about two years. These items were covered with dirt and debri l l
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i The inspector confirmed that the licensee has moved the subject materials, after cleanup, to a covered storage in the new warehouse. Also, in re-
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sponse to with an INP0 finding, the licensee is upgrading the materials
- management program. All materials stored in the warehouse are being
, entered into an inventory control program scheduled to be complete by l January 1, 1988. In addition, a system for controlling degradable, j limited shelf-life items is to be in place by July 1987. This item is l left open for review after corrective actions are complet )
j 4.0 Standby Gas Treatment (SGT) System Initiation (Unit 1)
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j On February 21, the SGT system automatically initiated on a main steam tunnel ventilation high radiation signal. The SGT system auto-initiates and the main
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- steam tunnel ventilation system isolates on a ventilation system radiation j level of 12 mrem /hr or greater. The ventilation system high radiation level i j was caused by increased steam tunnel general area radiation. That resulted j from an air addition to the feedwater system when the "B" condensate de-j mineralizer was placed in service. The phenomenon of elevated main steam i line radiation following air injection has been observed at Millstone and
- other Boiling Water Reactor The air addition results in a brief rise in I short-lived Nitrogen-16, causing the radiation levels in the main steam lines 1 and tunnel to increase briefly before returning to normal. In this instance, j the radiation spike exceeded the alarm setpoint (3X normal) and was just below the scram setpoint (approximately 6X normal). Af ter verifying a normal re-
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sponse and return to normal conditions, operators returned the SGT system to standby statu The licensee is investigating the root cause of this air injection. Prelimin-ary indications are that a two and one-half foot section of piping in each of the demineralizers provides a dead leg where air can accumulate. The i
resident inspector had no further questions concerning the SGT system initi-
! ation but, during routine inspections, will review the licensee's actions to i minimize air injection i
- 5.0 Seal Table Seismic Interaction Inspection (Units 1 & 2)
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- NRC Information Notice (IN) 85-45 covered the potential for seismic inter-
] action between the movable in-core flux mapping system and the seal table at
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d Westinghouse designed facilities. Although primarily relevant to Westinghouse Pressurized Water Reactor (PWR) designs, the inspector reviewed the Unit 1
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Traversing In-core Probe (TIP) system (an in-core flux mapping system) for l similar seismic concern ,
At Westinghouse facilities, potential seismic interactions exist because flux
! mapping system components that have not been seismically analyzed are directly
- above the in-core instrumentation tubing / seal table. Failure under a seismic i
stress might cause multiple failures in the flux mapping tubing or fittings and a small break loss of coolant accident (LOCA).
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Unit 1 Inspection revealed that design differences between the Westinghouse and Unit 1 flux mapping systems make the seismic interaction concerns raised in IN 85-45 not applicable to Unit 1. First, the in-core instrumentation tubing in the Westinghouse design is a " wet" system normally subject to primary coolant at design pressure. A break in this tubing represents a small break loss of coolant accident (LOCA). The TIP tubing at Unit 1 is a " dry" system which is not subject to primary coolant pressure unless there is a break in the tubing internal to the reactor vessel. Therefore, there is much less likelihood of a small break LOCA. Second, unlike the "over-under" Westing-house arrangement, the TIP system components at Unit 1 are generally in a horizontal plane without any large non-seismic loads suspended above the The licensee conducted a similar investigation of the concern raised by IN '
85-45 in September 1986 and also concluded that it was not applicable to the TIP system. At the same time, the licensee investigated the seismic integ-rity of the TIP system shear and ball valve arrangements. These valves are located outside of containment, provide isolation if a leak develops within the instrumentation guide tube, and also provide primary containment integrity in the event of a Group II isolation condition. The valves are presently mounted on the same platform as the associated leaded shield chamber. The licensee review centered on the desirability of having containment isolation valves mounted on the same structure with heavy shield chambers. Preliminary results indicate that a design change will be issued to separate the support structures for the two components in order to minimize the potential for un-favorable seismic interactio Unit 2 The plant is of Combustion Engineering design, which does not have a movable in core flux mapping system and thus is not susceptible to the problem de-scribed in IE Notice 85-4 Summary The licensee's response to IN 85-45 and their additional design review were found to be soundly based and well documented. The inspector had no further questions in this are .0 Emergency Service Water (ESW) System Design (Unit 1)
During a routine Engineered Safety Feature (ESF) walkdown of the Unit 1 ESW system, the inspector discovered a potential lack of independence in the two
, trains of ESW, and a potential susceptibility to a single failure loss of ESW I system capability. The ESW system removes heat from the Low Pressure Coolant Injection (LPCI) system via the LPCI heat exchangers. Following either a LOCA l
or initiation of the automatic pressure relief system, energy from the reactor vessel is released to the suppression pool. The LPCI system circulates sup-pression pool water through heat exchangers and returns it to the suppression
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1 pool. ESW flow through the other side of the heat exchangers removes the hea The ESW system may also be used to supply water to the LPCI system for injec-tion into the vessel. Because that would introduce salt water into the vessel, this measure is a last resor The ESW system consists of two independent and redundant train In an indi- ,
vidual train the ESW pumps take a suction from the "E" Bay of the intake structure and discharge through isolation valves to a common header. Flow passes through a rotating basket-type strainer to the LPCI heat exchanger.
! Flow is controlled by a pressure control valve downstream of the heat ex- :
change The strainer in each train is self-cleaning and designed to filter il out material greater than 1/8" in size. The ESW pumps are powered from the I 4160 volt safeguards buses (14E and 14F). Both strainer motors are powered i from the same 480 volt Motor Control Center (MCC-CD-5), which is capable of j being powered from either of two 480 volt distribution buses (12C and 120). ;
! The inspector's design concern is the ESW strainers. If the rotating basket
! motors fail, the strainers will eventually fou The fouling rate will depend j upon the input debris levels and could be relatively fast during high marine
- growth seasons. Because the strainers have no bypass capability, fouled I strainers could interrupt ESW flow and the LPCI system could lose heat dis-
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sipation capability. Since power to both of the strainers is provided by MCC-j CD-5, loss of that MCC would secure both strainer motors and cause eventual loss of ESW flow in both train *
The inspector identified this design concern to the licensee, who is currently i conducting a design analysis and revie Should a modification be appropriate, '
j potential remedies include separation of strainer power supplies and/or in-stallation of strainer bypasses. Final action is dependent upon the licen-
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see's findings. The resident inspector will continue to monitor this matte .0 Control of Neutron Flux Noise (Unit 1)
i
The General Electric (GE) Company's Nuclear Services Department issued Service
, Information Letter (SIL) No. 380, " Control of Neutron Flux Noise in Low Damped j Operating Conditions" on August 11, 1982. This SIL identified the potential
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' for establishing a combination of core conditions in a limited portion of the power / flow regime (typically high power / low flow) that could lead to an in-j
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crease in the normally experienced neutron flux noise. (The SIL also stated that any abnormal increase in the amplitude of the neutron flux noise result-ing from these conditions was not a safety conc 9rn since the reactor protec-
tion system provided adequate protection and assured continued high fuel re-liability and performance.) The most likely time for this phenonenon to occur is during plant start-up after establishing the full power rod patter The
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SIL recommended operator actions to avoid or control any increased neutron l flux noise.
I j On February 10, 1984, GE issued Revision 1 to SIL No. 380, "BWR Coro Thermal
- Hydraulic Stability," replacing the original SIL in entirety. Revision 1
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provided more information and insight regarding this phenomenon (called Limit i
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- Cycle Neutron Flux Oscillations). It also recommended an expanded and more
, detailed list of operator action These were "information only" recommenda-tions to BWR 2/3's due to their low power density design.
! On June 13, 1986, GE issued Rapid Information Communications Service Informa-tion Letter (RICSIL) No. 006, "BWR Core Thermal Hydraulic Stability". This RICSIL provided more new information on limit cycle neutron flux oscillations based on new testing experience and new operating experience at a BWR-3. The observance of this phenomenon at a BWR-3 prompted GE to advise operating staffs of BWR 2/3's to review the monitoring and control recommendations con- l tained in SIL No. 380 Revision 1 and to assure operator familiarity with the
action '
The licensee's response to the first SIL No. 380 was to brief appropriate personnel and route the SIL as required reading. Licensee reactor engineering personnel reviewed Revision 1 to SIL No. 380 for information only as it was not applicable to BWR/3's at that time. Upon receipt of RICSIL No. 006 (with its increased applicability to BWR-3's), the licensee initiated a study of the new informatio No changes to procedures have yet been identifie The licensee presently requires that a reactor engineer be present during all
startups and be notified or present for power changes in excess of 50 MW Limit cycle neutron flux oscillations have not been observed at Unit 1 to dat The licensee's response to this matter will be reviewed when their study is complet .0 Observation of Surveillances (Units 1 & 2)
Unit 1 I
On March 2, 1987, the inspector observed several surveillances conducted by
- licensee Instrument & Controls (I&C) department personnel. Tests were ob-i served from both the control room and equipment locations (Reactor and Turbine Buildings). Special inspector attention was given to review of the survell-lance procedures for Technical Specification conformance, adherence to ad-ministrative controls, observation of the test, and review of completed test documentation. Discussions with licensee personnel conducting the surveil-lance found adequate preparation and a high level of knowledge pertinent to
, the test. Additionally, the inspector observed the initial implementation of a formalized On-the-Job Training (0JT) program. The program consists of both training and evaluating activities. During the surveillances, a licensee evaluator observed the performance of two experienced technicians. Use of a standard, procedure-specific checklist facilitated the evaluation. At the 4 conclusion of one of the surveillances, the evaluator demonstrated the tech-
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! nique for adjusting the calibration of a Yarway hydraulic-mechanical level instrument. These Yarway indicators do not often lose their calibration and 4 technicians are infrequently required to recalibrate them. Having an experi-i enced technician demonstrate correct procedures for such infrequent operations !
) is an excellent technique for increasing the quality of I&C activitie Sur- I f
veillances observed included: 1 l
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SP 412C, Reactor Low-Low Water Level Functional and Calibration Tes This test checks the low reactor water level Emergency Core Cooling System (ECCS) initiation signal and the 2/3 core coverage Containment Spray inhibit signal.
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SP 408J, Condenser Low Vacuum Scram Functional and Calibration Tes Test checks the Main Condenser low vacuum signal input to the Reactor Protection System (RPS) and subsequent scra SP 408E, Main Steam Line Isolation Valve (MSIV) Closure Functional Tes This test checks the MSIV closure signal input to the RPS and subsequent scram.
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SP 408F, Turbine Stop Valve (TSV) Closure Functional Test. This test
- checks the TSV closure signal input to the RPS and subsequent scra No unacceptable conditions were identifie Unit 2 Surveillance functional testing provides assurance that the Technical Speci-
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fication system operability requirements are acceptable. The following tests were reviewe SP2404K Containment Process Radiation Monitoring - Gaseous and Particulate RM 8123 A/B and 89262 A/B Functional Test (T.S. Requirements 4.3.2.1.1, 4.3.2.1.4, and 4.3.3.1).
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SP24078 Inadequate Core Cooling System Functional Test (T.S. Requirement 3.3.3.8).
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SP240AT Steam Jet Air Ejector Radiation Monitor (RM 5099) Functional Test.
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2402M Functional Test Auto Auxiliary Feedwater Initiation Logi While minor errors in annotations were found such as lack of definitive +/-
- values, no inadequacies were identifie ! 9.0 Average Power Range Monitor Unit 1)
On February 24, 1987 a spurious momentary noise spike occurred in Local Power Range Monitor (LPRM) 36-45 causing the following alarms:
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APRM lli Flux
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Although the APRM channel associated with LPRM 36-45 tripped on Hi-Hi Flux, the expected Reactor Protection System (RPS) channel "B" half-scram did not occur. The control room alarm printout indicated that the APRM had tripped and reset at the same time. The licensee postulated that the trip and reset i of the APRM was so quick that it provided insufficient time for the associated RPS channel scram relay to drop out. Licensee review of the circuit design supported the premise that a fast enough APRM trip and reset could cause a Hi-Hi Flux annunciator alarm without an associated RPS half-scra i
The licensee developed a special procedure to test the theory and demonstrate
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the proper relay trip response and sequence. The procedure tested the APRM that experienced the noise spike and an APRM in the opposite RPS channel.
, The test inserted an artificial LPRM noise spike and, using a high speed re-
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corder, measured the time delays in the various relay path '
Conducted on March 3, the test substantiated the licensee's analysis and con-
. firmed correct relay response and sequence. The APRM Hi-Hi Flux annunciator
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alarm precedes the RPS scram relay actuation by approximately 15 millisecond Thus, a fast enough LPRM spike could trip and reset the APRM before the RPS i half-scram could occur. The inspector reviewed the test results and had no further questions in this area.
I 10.0 Plant Operations Review Committee Activities (PORC)
Unit 1
, The resident inspector attended Unit 1 PORC meetings on February 25, 26, 27 i
and March 3 and 4. Technical Specification 6.5.1 requirements for committee
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composition were met. PORC reviews included the following:
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Committee discussion and analysis of a February 24 spurious Local Power Range Monitor (LPRM) spike causing the associated Average Power Range Monitor (APRM) to trip on Hi-Hi flu The expected Reactor Protection System (RPS) half-channel scram did not actuate. The discussion covered
, possible causes and the need for a special test to determine relay
, sequences.
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The Plant Design Change Request (PDCR) covering a change to the Reactor Building crane movement limit switch logic.
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The PDCR changing the Emergency Gas Turbine (EGT) fuel flow starting i sequenc '
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The PDCR covering the removal of some control room ceiling tiles for j
- surveys in support of planned Appendix R modification .
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The PDCR covering the limited transfer of non-vital parameter points from l the current process computer to the new syste !
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The PDCR covering changes to High Radiation Area gate alarm system Licensee Event Report concerning a missed surveillanc A special test developed in response to the February 24 LPRM noise spik The PDCR for a new spent fuel storage rack to support full core offload capability after the June 1987 refueling outag Technical Specification change request pertaining to Section 6.3, Shift Technical Advisor qualification Various Plant Incident Reports (PIRs).
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Bypass Jumper audit.
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Minor operations and maintenance procedure changes and setpoint change The presentations elicited active questioning and discussions. Adequate review and analysis of the issues were conducted prior to the meeting, as shown by several of the items being resubmittals that upgraded previously rejected items. Also, items having unresolved questions were tabled pending further analysis. PORC members presented an informed and critical overview of plant design and operations. No deficiencies in PORC performance were observe .0 Millstone 2 Fire Protection Meeting (Unit 2)
On February 24, 1987, a working meeting requested by Region I was held with the licensee to discuss Appendix R Status at Millstone 2. (The meeting agenda is attached as Attachment 1 and the meeting attendees are listed in Attachment 2). In opening remarks, the staff and the licensee noted the required January 15, 1987 completion date for modifications which can be completed without a plant shutdown. In accordance with 10 CFR 50.48, this date is nine months following issuance of the staff's Safety Evaluation on April 15, 198 (Attachment 3 shows the licensee's associated " Time Line.") The licensee stated that approximately 95% of all required modifications were completed and that the remaining modifications required plant shutdown and would be cnmpleted during the 1988 refueling outage. (Attachment 4 is the licensee's listing of Appendix R Modifications.)
The licensee stated that, based on discussions with the NRR staff reviewer, including a August 28, 1986 working meeting where they discussed six of the i proposed exemption requests and their understanding of Generic Letter 86-10, !
they had concluded that no formal exemptions were necessary. This is based ;
on the licensee's assumption that fixes approved at Haddam Neck, Millstone '
1, and other plants are acceptable for Millstone 2. The licensee stated that documented analyses of various fire barrier deficiencies would be available j for NRC review at the site. The licensee was informcd that acceptance of i specific provisions at one site does not assure acceptability elsewhere, and l does not eliminate the need for exemption request ,
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The licensee's listing of Appendix R Compliance Status by Fire Zone (Attach-ment 5), which had been covered during the August 28, 1986 meeting with NRR, was discussed. The licensee stated they had desired a second working meeting with the NRR staff. However, the NRR Project Manager requested official sub-mittal of all exemption requests prior to another meeting. No such submittal was made as of the end of the reporting perio Exemption Requests were discusse The NRC stated that barrier deficiencies did not appear to be enveloped by the April 15, 1986 NRC Safety Evaluation, and that the intent of the Generic Letter 86-10 guidance was to specify that formal exemption requests were not required for minor barrier deficiencies in fire walls and doors. Some of the barrier deficiencies appear sufficiently significant to warrant an exemption request. The licensee noted that, should their draft exemption request on barriers be submitted and approved, no fur-ther modifications need be made to achieve compliance with barrier require-ment NRC Region I management stated, based on the limited review of the information provided during the meeting, that: 1) no significant safety issue has been I identified; 2) compliance with 10 CFR 50.48 will be reviewed later; 3) the licensee should request needed exemptions in a timely manner; and 4) the lic-ensee should consider interim compensatory measures. The licensee stated that i the subject exemption request could be submitted by March 31, 1987 and that I they would review the need for any compensatory measure Licensee compliance with Appendix R requirements is unresolved pending submis-sion of and NRC action upon the exemption request (s) (UNR Item 50-336/87-03-01).
12. 10 CFR 50, Appendix R Field Observations (Unit 2)
The following areas were inspected for fire protection measures on February 2 Control Room Door The control room doors separate the control room (Appendix R Area R-1) and I
' the adjacent 480 volt load center room (Appendix R Area R-11). The inspector verified that a double swinging door of heavy gauge steel construction with a 10" by 10" glass insert is installe One door is fixed closed; the other '
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serves as a security door to the control room. Smoke detectors were observed in Area R-11. Fire suppression equipment was available in the control room and 480V switchgear room. No combustibles were found in the control room or I the 480V switchgear roo Water Curtain Appendix R requires that the licensee address the need for the separation of redundant components with a 3-hour fire barrie _ . . .. - .- - . . . -. . . .. . - . _ --.
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The licensee review of Appendix R addressed two areas where physical barriers could not be located due to physical constraints and a need to provide access /
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egress routes. The licensee has proposed " water curtains" in lieu of-physical barriers for these areas.
i MCC Enclosure The " water curtain" at MCC B-61 was in plac Sprinkler locations appear to conform with drawings depicting the 14'6" elevation of the auxiliary j buildin Charging Pump Cubicles The " water curtain" at the minus 25'6" elevation was in place and con-formed to drawing Fire Doors An inspection of five doors in stairwell areas verified that doors and door frames were similar to Underwriter's Laboratory Approved three-hour fire doors; the doors were not labeled and documentation of original construction speci-fications were not availabl Main Steam Isolation Valve Rooms (MSIV)
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The inspector verified that the MSIV rooms do not contain combustibles that could contribute to fires in adjacent areas. The ceiling heights (2100 ft.)
were observed and prevailing air flow appeared to confirm the licensee's statement that heat and smoke, if generated in these areas, would rise ver-tically, eliminating exposure to the adjacent MSIV roo Summary No fire hazards were identified. Further review of 10 CFR 50 Appendix-R adherence will be the subject of NRC specialist inspectio . Review of Periodic and Special Reports (Units 1 & 2)
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Upon receipt, periodic and special reports submitted pursuant to Technical Specifications were revi~~d. This review verified that the reported infor-mation was valid and incluued the NRC required data, that test results and supporting information were consistent with design predictions and performance specifications, and that planned corrective actions were adequate for the resolution of the problem. The inspector also ascertained whether any reported information should be classified as an abnormal occurrence. The following reports were reviewed:
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Annual Report - January 1 to December 31, 1986 Units 1 & 2 (Selected
Modifications).
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Monthly Operating Reports for plant operations January 1 to January 31, 1987 (Unit 2).
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10 CFR 20.407 Statistical Summary of Personnel Monitoring Informatio No unacceptable conditions were identifie Monthly Operating Report for Plant Operation January 1 to January 31, 1987 (Unit 1).
No deficiencies were identifie . Steam Generator (SG) Surveillance (Unit 2)
At the beginning of this report period, Unit 2 was in cold shutdown for SG tube leak repair and plugging of potentially defective tubes. Of particular concern was the SG-2 tube at Line 25, Row 19, which showed a circumferential flaw (see Inspection Report 50-336/87-01). On 2/13, after repairs, the lic-ensee completed their SG Safety Evaluation reviews. Unit 2 was returned to power on 2/1 The Safety Evaluation addressed the analysis of the circumferential flaw and discussed the potential for complete tube severance due to such a flaw. The review of measures taken to provide for protection by staking of adjacent tubes to guard against fretting damage was found acceptable by the licensee's Nuclear Review Boar Additional review was conducted on reducing the Technical Specification (TS)
allowed leak rate from 0.5 to 0.15 gpm per SG. This change was promulgated onsite by a licensee administrative order. The licensee committed to submit a TS change for a leakage limit of 0.15 gpm per S Also, the Eddy Current Testing (ECT) program is under licensee review in re-gard to training level 2 and 3 reviewers, equipment changes to include addi-tional rotating probe use with robotics, and measures to reduce ALARA doses during such EC The steam generator primary to secondary leak rates are monitored daily and have identified zero leakage. The leak rate is being reviewed by the resident inspector daily. The inspector has no further questions on this item at this tim l 1 Routine Review of Plant Activities (Units 1 & 2)
In addition to the inspection activities described in the proceeding report )
details, routine daily control room checks and plant tours were conducted to
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review safety and compliance with NRC requirement No discrepancies were identifie j
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15. Management Meetings At periodic intervals during this inspection, meetings were held with senior plant management to discuss the finding No proprietary information was identified as being in the inspection coverage. No written material was pro-vided to the licensee by the inspecto . . - _ .
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__ ATTACHMENT 1 NRC REGION I INSPECTION REPORT 50-245/87-03; 50-336/87-03
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PROPOSED AGENDA MILLSTONE UNIT 2 APPENDIX R COMPLIANCE STATUS 1. Introduction Purpose of Meeting Appendix R Compliance Schedule Outage and Non-Outage Mode (50.48 Schedule) Evolution of Relevant Technical Exemptions 2. History Sequence of Events (Time Line)
(1) Past Correspondence (2) Telephone Conversations
.(3) Meetings
] (4) Commitrents/ Exemptions
, 3. Status of Modification Implementation 4. Technical Exemption Status 5. Safety Significance of Fire Protection Issues 6. Conclusion
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ATTACHMENT 2 NRC REGION I INSPECTION REPORT 50-245/87-03; 50-336/87-03
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LIST OF ATTENDEES .
FIRE PROTECTION MEETING 4 MILLSTONE UNIT 2 FEBRUARY 24, 1987 i Northeast Nuclear Energy Company i
R. Bates, Assistant Engineering Supervisor, Millstone 2 M. Ciccone, Senior Engineer, Licensing
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F. Dacimo, Engineering Supervisor, Millstone 2 R. Ewing, Engineering Specialist A. Patrizza, Fire Protection Specialist J. Roncaioli, Fire Protection Engineering G. vanNoordennen, Senior Engineer, Licensing l U.S. Nuclear Regulatory Commission C. Anderson, Chief, Plant Systems Section, Division of Reactor Safety (DRS)
E. Conner, Project Engineer, Reactor Projects Section 3B, Division of Reactor Projects (DRP)
D. Jaffe, Project Manager, DRP W. Johnston, Deputy Director, DRS A. Krasopoulos, Reactor Engineer, DRS E. Wenzinger, Chief, Projects Branch No. 3, DRP
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ATTACHMENT 3 (
I NRC REGION I INSPECTION REPORT
{ Time Line 50-245/87-03; 50-336/87-03 Millstone Unit No. 2 Appendix R Documentation
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Date Description March 1,19S2 - Twelve exemptions to Appendix R,Section III.G filed with the NR July 16,1982 - Revised exemptions from twelve to eight due to modifications in several fire area ~
January 6,1933 - NRC draf t safety evaluation denies six out of the eight exemption request April 15,1983 - Additional information provided including commitments May 25,1933 to provide additional fire protection in areas where January 31,1935 exemptions would have been denie August 7,1985 April 7,19S6 April 15,1986 - NRC approves all eight exemption requests and provides safety evaluation for compliance with Appendix April 24,1986 - Generic Letter 86-10 issued which provides guidance on implementation of Appendix R requirement July 11,1986 - NRC formally notified of proposed revisions to Appendix R shutdown proces August 28, 1936 - Meeting with NRC to discuss Millstone 2 Appendix R issue September 11, 1986 - Meeting minutes of August 28, 1986 meeting published by NR January 14, 1987 - Structural steel position letter submitted to NR j l
January 15, 1987 - Non-outage Appendix R modifications complete February 10, 1987 - NRC Project Manager alleges Unit 2 is in non-compliance with Appendix February 27, 1987 - Provide update on structural steel fire protection effort March 1987 - Submit additional exemption Submit Appendix R Compliance Review Repor Submit comments on April 15,1936 SE July 13 - 17,1987 - Region I Appendix R Audit 1933 R.O. - Implement remaining Appendix R modification Obtain NRC approval of additional exemption _ _ _ _ _ _ _ _ _ _
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ATTACHMENT 4 NRC REGION I INSPECTION REPORT Millstone Unit No. 2 50-245/87-03; 50-336/0?-03 Appendix R Modifications Project Description Cost Status Install Fi re Shut- Provide new shutdown panel $ 1,885,000 Complete down Panel independent of Control Room and C-21 panel Fire Water Systems Install two water curtains and $ 3,354,000 Complete previde four new sprinkler systems Install Fire Barrier Enclose required electrical $ 941,000 Complete cables with 3 hour3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> cable wrap Emergency Lighting Install 95 emergency lights $ 578,000 Complete throughout plant Fire Damper Mod Modify existing or install new $ 1,234,000 Complete fire dampers to assure closure under flow and appropriate fire rating Stock Spare Parts Provide spare parts available $ 510,000 Complete on site to assist in getting the plant to cold shutdown Curbs, Fire Doors, Install fire doors, flammable $ 2,186,000 On-Going Steel Coating liquid spill control curbs and structural steel fire proofing Charging & Auxiliary Change actuators to allow for $ 150,000 (3) Valves Spray Valve Mod manual operation Complete (1) Valve 1988 Outage Cable Spreading Area Extensive modifications to Conceptual Appendix A Suppression System existing manual deluge system Cost deficien-to provide automatic closed $ 2,000,000 cies - 1988 protection for area and Outage structural steel D.C. Equipment Rooms Provide Halon systems for Conceptual 1988 Outage i protection of both rooms Cost 1 (in lieu of coating steel) $ 1,500,000 l
TOTAL $14,338,000 JJR/ jet 02/23/87 35.52 I i
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ATTACHMENT 5 ,
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, NRC REGION I INSPECTION REPORT 50-245/87-03;.50-336/87-03 -
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MILLSTONE UNIT NO. 2 Page 1 COMPLIANCE STATUS WITH APPENDIX R
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i CHANGES TO
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, FIRE PREVIOUS APRIL 15, 1986 SER SER PROPOSED DUE ZONE EXEMPTION PROPOSED MODIFICATIONS MODIFICATIONS STATUS DATE A-1A No Spare parts (equipment-cabling) None Complete 1/15/87 will be stored on site to support s necessary repairs that may be re-quired to achieve cold shutdow Repair procedures will be developed None Complete 1/15/87 to assure that cables needed to achieve cold shutdown will be repaired promptl A-1B Yes Provide a 1-hour fire-rated enclo- Now using 3-hour- Completed 1988 RO sure for charging pump cables as protection and some early shown on drawing 34022 (Charging rerouting of Z2 train Pump Train B and B-swing). to outside fire are Stock spare parts (connectors- None Complete 1/15/87 '
C cabling) required to support post-fire repairs to cold shutdown equipment within a reasonable tim Develop repair procedures to assure None Complete 1/15/87 that cables needed for cold shut-down will be repaired promptly and within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />, as required by Appendix __ _ __
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a MILLSTONE UNIT NO. 2 Page 2 COMPLIANCE STATUS WITH APPENDIX R CHANGES TO APRIL 15, 1986 APRIL 15, 1986 SER SER PROPOSED DUE FIRE PREVIOUS PROPOSED MODIFICATIONS MODIFICATIONS STATUS DATE ZONE EXEMPTION A radiant energy shield consisting Changing to replace Complete 1/15/87 of marinite board will be erected pump moto Motor on-around RBCCW pump and Motor sit Wet pipe sprinkler system to form Write repair procedures Complete 1/15/87 water curtain between LPSI pump cable trays and installation of early warning ionization detector A-2 No Non A-3 No Non A-4 No Non Spare parts (connectors-cabling) None Complete 1/15/87 A-5 No will be stocked on site to support repair of cables needed for cold shutdow Repair procedures will be developed to assure that cables needed for None Complete 1/15/87 cold shutdown can be temporarily repaire A-7 No Non A-8 No Non Yes Provide a fire rated enclosure to A three-hour wrap Complete 1/15/87 A-9 charging pump cables Train A and is provided on all three train .
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o MILLSTONE UNIT NO. 2 Page 3 COMPLIANCE STATUS WITH APPENDIX R CHANGES TO APRIL 15, 1986 FIRE PREVIOUS APRIL 15, 1986 SER SER PROPOSED DUE ZONE EXEMPTION PROPOSED MODIFICATIONS MODIFICATIONS STATUS DATE Install a curb / dike at front of None Complete 1/15/87 each charging cubicl A-14 Yes Charging Pump A and A (swing) ch- The A (swing) Completed 1988 RO bles which run parallel to the die- power cables have been earl sel B Cables in this area will be rerouted outside this area, rerouted outside the fire are The vertical run (from ceiling to floor) of charging pump A and A (swing) cables remaining in the area will be enclosed in a one-hour fire barrier. A marinite board radiant energy shield will also be installed around this cable ru Stock spare parts (connectors-cabling) None Complete 1/15/87 required to support post-fire repairs to cold shutdown equipment within a reasonable tim Develop repair procedures to assure that None Complete 1/15/87 cables needed for cold shutdown will be repaired promptl .
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e MILLSTONE UNIT NO. 2 Page 4 COMPLIANCE STATUS WITH APPENDIX R CHANGES TO APRIL 15, 1986 FIRE PREVIOUS APRIL 15, 1986 SER SER PROPOSED DUE ZONE EXEMPTION PROPOSED MODIFICATIONS MODIFICATIONS STATUS DATE A-15 No ,
Spare parts (equipment-cabling) None Complete 1/15/87 l will be stored on site to support necessary repairs that may be re-quired to achieve cold shutdow Repair procedures will be developed None Complete to assure that cables / equipment needed for cold shutdown will be repaire A-19 No Non A-24 Yes Reroute Diesel B cables which run Not required. MP1 to N/A N/A along the hallway in close proxim- MP2 backfeed eliminates ity to Diesel A cables outside this the diesel power cables fire area, as safe shutdown equipment for this are Install a water curtain in the west Barrier installed Complete 1/15/87 end of fire area A-24 to segregate as a water spray on
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remaining Train B cables and motor environmental enclosure control center from Train A cable for MCCB6 Enclose Train B cables which pass Rerouting Train B Completed 1988 RO through the water curtain in a one- cables or wrapping early hour barrie in three-hour fire protectio .
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d MILLSTONE UNIT NO. 2 Page 5 COMPLIANCE STATUS WITH APPENDIX R CHANGES TO APRIL 15, 1986 FIRE PREVIOUS APRIL 15, 1986 SER SER PROPOSED DUE ZONE EXEMPTION PROPOSED MODIFICATIONS MODIFICATIONS STATUS DATE Stock spare parts (connectors- None Complete 1/15/87 cabling) required to support post-fire repairs to cold shutdown ,
equipment within a reasonable
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tim Develop repair procedures to None Complete 1/15/87 assure that cables needed for cold shutdown will be repaired promptl A-25 No Non A-26 No None.
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A-27D No Non A-28 No Non A-29 No Non A-35 No Non A-36 No Non __
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e MILLSTONE UNIT NO. 2 Page 6 COMPLIANCE STATUS WITH APPENDIX R CHANGES TO APRIL 15, 1986 FIRE PREVIOUS APRIL 15, 1986 SER SER PROPOSED DUE ZONE EXEMPTION PROPOSED MODIFICATIONS MODIFICATIONS STATUS DATE A-37 No Non A-40 les Extend automatic wet-piped Not required for N/A N/A sprinkler system to include diesel Appendix R. MP1/M2 power cables Train backfeed, Fire Shutdown Panels, and fire protection of selected cables eliminate this nee Provide passive, one-hour fire No longer require N/A N/A barriers between redundant cables MP1/M2 backfeed, Fire at the crossover point Shutdown Panels, and fire protection of selected cables eliminate this nee Develop and implement customized No longer require N/A N/A administrative controls to MP1/MP2 backfeed, Fire effectively restrict the Shutdown Panels, and introduction of flammable fire protection of materials including liquids in the selected cables cable vaul eliminate this nee _
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MILLSTONE UNIT NO. 2 Pega 7 COMPLIANCE STATUS WITH APPENDIX R CHANGES TO APRIL 15, 1986 FIRE PREVIOUS APRIL 15, 1986 SER SER PROPOSED DUE ZONE EXEMPTION PROPOSED MODIFICATIONS MODIFICATIONS STATUS DATE
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A-41 No Non A-42 Yes Customized administrative controls None Complete 5/15/86 (similar to those accepted for Haddam Neck) will be implemented to minimize introduction of flammable materials in the control roo Normal operating procedures will None Complete 5/15/86 be revised to require an inspection each shift in the control room for flammable material A transfer scheme utilizing a Hand switches are Completed 1988 R0 Wiedmuller Test Block (or provided for control early equivalent) to isolate required circuits on fire instrumentation from the control shutdown pane room and redirect the Instrumentation has instrumentation signals to the new Spec 20) isolators built remote Fire Shutdown Panel will be i installe Disconnecting devices for Changed location to Completed 1988 RO pressurizer PORVs, main steam be in fire area A-15 early isolation valves, atmospheric dump (i.e., West 480V valves, and SG blowdown valve Switchgear Room control circuitry will be installed directly outside to assure closure of these valves Control Room door).
during a control room fir . ,
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MILLSTONE UNIT NO. 2 Page 8 COMPLIANCE STATUS WITH APPENDIX R CHANGES TO APRIL 15, 1986 FIRE PREVIOUS APRIL 15, 1986 SER SER PROPOSED DUE ZONE EXEMPTION PROPOSED MODIFICATIONS MODIFICATIONS STATUS DATE The MP1/MP2 4kV cross-feed bus will None To be com- 1988 RO be modified to facilitate the pleted as a alignment of Unit No. 1 emergency Unit 1 AC power to the Unit No. 2 project by emergency buse end of next Unit outag Manual / air operated valves to provide RCS level and pressure Change to add handwheel Open 1988 RO control for cold shutdown will be to CH-192 and SI-657 installed in charging and auxiliary spray flow path CH-517, 518, & 519 Completed early The pressurizer and reactor head Changed to proced- Approved 1988 RO vent control circuits will be dure to open de breaker & available modified to protect against hot shorts for control room fire These modifications include removing the fuses to the control circuits during plant operation, separately fuse the indication portion of the circuit so that valve indicators will not be lost when the fuses associated with the solenoid valves are removed and insure the switchboard was associated with the solenoid valves are not susceptible to t.ot shorts.
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e MILLSTONE UNIT NO. 2 Page 9 COMPLIANCE STATUS WITH APPENDIX R CHANGES TO APRIL 15, 1986 FIRE PREVIOUS APRIL 15, 1986 SER SER PROPOSED DUE ZONE EXEMPTION PROPOSED MODIFICATIONS MODIFICATIONS STATUS DATE l
A remote Fire Shutdown Panel in None Completed 1988 R0 Fire Zone T8 will be installe early Procedures to assure the following None Approved 1988 RO will be developed: & available o capability to achieve safe shutdown with the loss of equipment in any one of the two fire zone o Spurious operation of affected equipment can be compensated for using alternate systems and manual actio o Actions being taken outside the control room are achievable considering a fire in the control room, time needed to accomplish the function and manpower require _-. _ _ _ _ _ _ - . _
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MILLSTONE UNIT NO. 2 Page 10 COMPLIANCE STATUS WITH APPENDIX R CHANGES TO APRIL 15, 1986 FIRE PREVIOUS APRIL 15, 1986 SER SER PROPOSED DUE ZONE EXEMPTION PROPOSED MODIFICATIONS MODIFICATIONS STATUS DATE T-4 No Will incorporate an electrical The Shutdown Fire Panel Completed 1988 RO isolation control transfer scheme does this by isolating gj, in required control circuit both the Control Room and C-21 circuits.
T-5 No None.
T-6 No None.
T-7 No None.
T-8 No None.
T-9 Yes None.
T-10 No Provide a fire-rated enclosure for Service water Completed 1/15/87
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service water cables (Z-1). pumps / cables only required for cold shutdown. Repair procedures used as neede Provide a fire-rated enclosure for Service water Completed 1/15/87 service water cables (Z-5). pumps / cables only required for cold shutdow Repair procedures used as neede _ - - - _ _ _ _ _ _ _ _ _ __-_--
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MILLSTONE UNIT NO. 2 Page 11 COMPLIANCE STATUS WITH APPENDIX R CHANGES TO APRIL 15, 1986 FIRE PREVIOUS APRIL 15, 1986 SER SER PROPOSED DUE ZONE EXEMPTION PROPOSED MODIFICATIONS MODIFICATIONS STATUS DATE
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I-1 Yes Enclose / wrap all cabling / conduit Service water Completed 1/15/87 associated with service water pump pumps / cables only Train A with a one-hour rated fire required for cold barrie shutdown. Repair procedures used as neede Provide dike / curbing around Service Service water Completed 1/15/87 Water Pump pumps / cables only required for cold shutdown. Repair procedures used as neede Install an automatic water curtain Service water Completed 1/15/87 spray system around Service Water pumps / cables only Pump required for cold shutdown. Repair procedures used as neede l
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MILLSTONE UNIT NO. 2 Page 12 COMPLIANCE STATUS WITH APPENDIX R CHANGES TO APRIL 15, 1986 FIRE PREVIOUS APRIL 15, 1986 SER SER PROPOSED DUE ZONE EXEMPTION PROPOSED MODIFICATIONS MODIFICATIONS STATUS DATE C-1 No A radiant energy shield will be Tray covers, conduit Completed 1988 RO thru installed between redundant reroute and fire stops early C-6 pressurizer instrumentation cable added instead.
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