IR 05000338/1993008
| ML20056C095 | |
| Person / Time | |
|---|---|
| Site: | North Anna  |
| Issue date: | 03/15/1993 |
| From: | Belisle G, Lesser M, Taylor D NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20056C085 | List: |
| References | |
| 50-338-93-08, 50-338-93-8, 50-339-93-08, 50-339-93-8, NUDOCS 9303300063 | |
| Download: ML20056C095 (15) | |
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UNIT ED STATES
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ATLANTA. GEORGI A 30323
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Report Nos.: 50-338/93-08 and 50-339/93-08 Licensee:
Virginia Electric & Power Company 5000 Dominion Boulevard Glen Allen, VA 23060 Docket Nos.: 50-338 and 50-339 License Nos.:
Facility Name: North Anna 1 and 2 l
Inspection Conducted: January 17 - February 20, 1993 Inspectors:
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M. S:'tgsger, Senior Resident inspector Date Signed 8/L// Le 2 /? - PJ
l D. R.'Tayldr, Resident Inspector Date Signed
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G. A. Belisle,'Section Chief Date Sig'ned Division of Reactor Projects SUMMARY Scope:
l This routine inspection by the resident inspectors involved the following i
areas: plant status, operational safety verification, maintenance l
observation, surveillance observation, safety assessment and quality verification, license event report followup, and action on previous inspection I
items.
Inspection of licensee backshift activities were conducted on the l
following days: January 17, 18, 19, 20, 21, 23, 24, 25, 26, 27, 28, 30, 31 and February 1, 2, 6, 7, 8, 10, 15, 17 and 20, 1993.
Results:
In the operations area, a violation was identified involving a breach in containment during core alterations. A breach in the containment personnel hatch outer door resulted from apparent inadequate training of personnel assigned to operate the door (para 3.a).
In the engineering and technical support area, system engineers thoroughly evaluated cold leg accumulator level transmitter drif t problems.
Based on the evaluations, it was determined that Technical Specification requirements for accumulator levels were not violated (para 3.b).
In the safety assessment / quality verification area, the licensee appropriately i
took information identified at Surry Power Station and applied it to North 9303300063 930315 PDR ADOCK 05000338 G
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h Anna. As a result, the containment gaseous and particulate radiation monitors i
were determined to have been inoperable during refue)jng. An unresolved item i
was opened pending the licensee's final evaluation and issuance of a Licensee i
Event Report (para 3.f).
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In the maintenance area, various activities were observed to be well controlled with good supervisory oversight The Service Water repair project t
has been thoroughly planned and managed to date (para 4).
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In the surveillance area, testing of emergency diesel load sequencing timers identified five failures. The licensee previously developed a plan to
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evaluate each failure which included replacing eight timers this outage. The t
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current failures will be evaluated for future replacements (para 5.b).
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In the safety assessment /ouality verification area, the licensee incorrectly
linked two failures ass 6.iated with Westinghouse ARD relays to a 10 CFR 21 i
unrelated issue. As a result, the Part 21 issue was resolved without
adequately evaluating the two unrelated failures (para 6.a).
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REPORT DETAILS
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1.
Persons Contacted Licensee Employees
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L. Edmonds Superintendent, Nuclear Training R. Enfinger, Assistant Station Manager, Operations and Maintenance J. Hayes, Superintendent of Operations D. Heacock, Superintendent, Station Engineering
- G. Kane, Station Manager
- P. Kemp, Supervisor, Licensing W. Matthews, Superintendent, Maintenance J. O'Hanlon, Vice President, Nuclear Operations D. Roberts, Supervisor, Station Nuclear Safety
- R. Saunders, Assistant Vice President, Nuclear Operations D. Schappell, Superintendent, Site Services R. Shears, Superintendent, Outage and Planning
- B. Shriver, Actg. Asst. Station Manager, Nuclear Safety and Licensing
- J. Smith, Manager, Quality Assurance A. Stafford, Superintendent, Radiological Protection
- J. Stall, Actg. Asst. Station Manager, Operations and Maintenance Other licensee employees contacted included engineers, technicians, operators, mechanics, security force members, and office personnel.
NRC Resident Inspectors
- M. lesser, Senior Resident Inspector
- D. Taylor, Resident Inspector
- S. Lee, Senior Materials Engineer
- Attended exit interview Acronyms and initialisms used throughout this report are listed in the last paragraph.
2.
Plant Status Unit I started the period in Mode 6, off-loading fuel. Core off-load was completed on January 20, at which time the upper internals were placed in the vessel and the vessel head was set. On January 21, the unit was turned over to the contractor for SGRP. The contractor's project is scheduled for 51 days. All three steam generator lower assemblies were cut out and removed from the containment. They have been placed in the Old Steam Generator Storage Facility.
The new lower assemblies were installed. Welding of reactor coolant loops, main steam and feed piping and auxiliaries continued along with girth welding the steam dome assembly.
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Unit 2 operated the duration of the period at full power.
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Operational Safety Verification (71707)~
The inspectors conducted frequent visits to the control room to verify
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proper staffing, operator attentiveness and adherence to approved l
procedures.
The inspectors attended, plant status meetings and reviewed i
operator logs on a daily basis to verify operational safety and l
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compliance with TS and to maintain awareness of the overall operation of
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the facility.
Instrumentation and ECCS lineups were periodically l
reviewed from control room indications to assess operability.
Frequent plant tours were conducted to observe equipment status, fire protection
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programs, radiological work practices, plant security programs and l
housekeeping.
Deviation Reports were reviewed to assure that potential i
safety concerns were properly addressed and reported.
Selected reports l
were followed to ensure that appropriate management attention and j
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corrective action was applied.
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i a.
Containment Breach l
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The inspectors reviewed events associated with a breach of l
l containment during core alterations on January 16 and 17.
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licensee discovered that a small manually operated equalization i
valve which is an integral part of the emergency personnel escape l
hatch was cracked open.
If a fuel handling accident were to
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from containment to the Auxiliary Building if the inner personnel l
hatch was opened for personnel transit into or out of containment.
i The valve was apparently cracked open inadvertently by a laborer
i who was assigned to operate the hatch for normal passage. The l
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licensee determined that at least one hatch operator was using the j
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valve handle to pull the door closed.
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The inspectors reviewed 1-PT-91, Containment Penetrations, which establishes containment integrity prior to core alterations. The
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PT does not specifically check for the emergency escape hatch j
equalizing valve, but states that at least one door in each
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airlock is closed.
In addition, the inspectors reviewed a j
containment breach incident during the refueling which occurred in i
February 1991. The 1991 event was caused by an inadaquate i
procedure (1-PT-91) which resulted in inadequate control over
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temporary penetrations through the equipment hatch (refer to NCV
50-338/91-03-01).
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The inspectors also reviewed a December 1989 event where the Unit l
r 1 equipment hatch escape air lock pressure equalizing valve was l
l partially open during power operations.
This, in conjunction with
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a failed outer door seal, resulted in a containment breach (refer
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to violation 338/89-35-01).
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Although the duration and consequences of the most recent event
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were minimal, the inspectors were. concerned with continued j
problems associated with containment penetrations.
i TS 3.9.4 requires that all containment building penetrations be
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l either closed or capable of being closed by an operable automatic
containment purge and exhaust isolation valve during core i
alterations or otherwise suspend all core alterations. After
discovering the mispositioned valve, the licensee appropriately i
stopped fuel movement. A four hour report was made to the NRC l
pursuant to 50.72(b)(2)(iii)(c) and the licensee will submit a 30 i
day LER.
The licensee also initiated corrective action which
included a trained operator to man the airlock and a team assigned -
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i to review previous events and recommend additional steps to.
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preclude recurrence.. Failure to maintain containment penetrations during core alterations as required by TS 3.9.4.C is identified as.
violation, VIO 50-338/93-08-01:
Failure to Maintain Containment i
Penetrations During Refueling.
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b.
Cold Leg Accumulator Level Calibration i
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The inspectors reviewed DRs 200 through 204 that documented out-
'i of-tolerance as-found calibration data for 5 of 6 cold leg
accumulator levei transmitters.
Each of three accumulators has
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two level transmitters that provide indication, and high and low l
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level alarm functions in the control room. - Discussions with j
personnel indicated that these Barton level transmitters have a
long history of being out-of-tolerance, including instrument drift
problems during power operation which necessitate containment
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l entries at power to correct.
It was also indicated that calibration methods and the small instrument span contributed to
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the out-of-tolerance condition.
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The inspectors reviewed the history for the above five transmitters and identified that each of the transmitters had at j
least one additional out-of-tolerance condition during their two
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previous calibration checks.
Further discussion with the licensee
indicated that the level transmitters have been the subject of l
l various studies because of the drift problem. The licensee i
included these failures as a Unit 1 outage safety issue to be l
evaluated by engineering.
The inspectors discussed with the system engineer the extent of
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the out-of-tolerance data to determine if a TS level limit was exceeded. A review of the ICP and engineering calculations
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indicated that as long as accumulator levels were not in an alarm condition and redundant channels were within tolerances, no TS violation occurred. A review of accumulator levels for the month
prior to the Unit I shutdown verified that no limits were
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exceeded. The inspectors determined that the licensee's
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procedures for checking redundant channels would most likely
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assure that a drifting condition would be identified and corrected
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prior tc exceeding a TS requirement. The~1icensee's evaluation of
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this issue appears thorough.
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c.
Loose Coating on Steam Generators
i The licensee removed the mirror insulation from the old steam l
generators as part of the Unit.1 SGRP. The old steam generators j
were coated with a silicon aluminum paint by Westinghouse during
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fabrication. When the steam generator insulation was removed, l
most of the coating was found to be loose and not adhering to the l
steam generator surface. UFSAR Section 3.8.2.7.6 indicates that j
the coating is unqualified and does not meet the standards of the
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American National Standards Institute for coating inside i
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containment.
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The inspectors questioned the potential significance that loose j
coating debris could have on loss-of-coolant recirculation that
may occur during an accident. This is no longer a concern for Unit I steam generators because the coating came off the steam i
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domes after the insulation was removed and the steam generator j
j lower assemblies are being replaced with uncoated shells.
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However, this coating is still on the Unit 2 steam generators and
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the inspectors also identified it on the Unit 1 pressurizer.
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i Loose coating inside containment may not have been considered l
adequately in the design basis because page 6.2-81 of the UFSAR l
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states that "... all protective coatings (paints) on exposed
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concrete and carbon steel surfaces remain intact if subjected to the environment associated with a postulated LOCA." The coating
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on the steam generators was loose and would have come off freely
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during a high energy line break in those areas where the
insulation would have come off.
Furthermore, the quantity of this
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loose coating may be potentially significant. Table 3.8-11 of the
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UFSAR states that there is 11,700 square feet of this unqualified
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coating. This information may affect previous staff evaluations because Section 6.3.6.3 of the staff's safety evaluation report i
(NUREG-0053, Supplement No. II, August 1980) states that periodic surveillance inspections would detect occurrences of paint chips
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resulting from degraded materials, and design avoids the use of
materials in the containment, which would be likely to produce
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small-sized debris in significant quantities.
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The licensee is considering performing an evaluation in accordance j
with 10 CFR 50.59 to address loose coating. The inspectors will
review this and discuss the results with NRR in order to determine acceptability and potential generic concern. This is identified I
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as IFI 50-339/93-08-02: SG Shell Unqualified Coating.
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d.
Damaged Feedwater Supports i
During a plant walkdown on February 13, the inspectors identified
two Unit I feedwater pipe monoball-sliding supports that prevented
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l full movement by their respective slotted supports. The monoball i
support is designed to move for the thermal expansion of the pipe e
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i-in the sliding plate collar. The inspectors reported the
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condition to the licensee.
DR N-93-304 was initiated immediately to evaluate the damage and work Requests 013961 and 013962 were
written to disassemble and inspect the center shaft which provides
the structural support. The licensee also intends to perform NDE
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on the pipe welds near the supports.
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e.
RCC Shuffle The inspectors observed RCC shuffle activities in the spent fuel i
pool building on February 12. Operators used 1-0P-4.17, RCC l
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Change Tool, to operate the fuel handling tool and the North Anna j
1 Cycle 10 Nuclear Analysis and Fuel Handling Report in order to j
determine fuel assembly location for RCCs. A report.is computer l
generated to identify the most efficient sequences for RCC i
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i shuffles and to minimize the opportunity for operator error. The j
evolution was closely supervised by a refueling SRO.
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Containment Radiation Monitor Operabil ty l
The inspectors reviewed DR 93-301 which documented that
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containment gaseous and particulate radiation monitors became j
i inoperable with no containment air recirculation fans running.
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The monitors are used to provide a signal to isolate containment
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purge and exhaust valves in the event of a fuel handling accident.
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This issue was initially identified by Surry Power Station, and i
also applies to North Anna.
Radiation monitors RM-RMS-159 I
J (particulate) and RM-RMS-160 (gaseous) draw suction from inside the containment air recirculation duct at the air cooler
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discharge. Without containment air recirculation fans running, j
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the air inside the duct does not provide a representative sample j
of containment atmosphere.
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TS 3.9.9 requires the purge and. exhaust isolation system to be i
operable or otherwise close each of the purge and exhaust
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The licensee identified that no containment
recirculation fans were operating during the present mode 6 core alterations. This in effect rendered two of the three purge and i
exhaust isolation radiation monitors inoperable. The inspectors-verified that the third (manipulator crane area monitor) was operable during mode 6.
Failure to maintain the purge and exhaust i
system isolation operable during refueling is considered unresolved pending the licensee's evaluation and LER submittal,
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URI 50-338/93-08-03: Containment Gaseous and Particulate Rad
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Monitor Operability During Refueling.
i One violation was identified.
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4.
Maintenance Observation (62703)
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Station maintenance activities were observed and reviewed to ascertain
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that the activities were conducted in accordance with approved procedures, regulatory guides and industry codes or standards, and in conformance with TS requirements.
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a.
FRV Maintenance l
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On January 29, the inspectors observed troubleshooting of the A
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FRV, 2-FW-FCV-2478, per WR 862102. The valve was being worked
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because it exhibited sluggish response when returning to automatic
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i control from manual. The problem was originally documented on DR
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93-50 written January 9.
At that time, the final control card, C
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6326, was replaced. The same card'was replaced during this
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troubleshooting because the tracking and feedback circuit was not i
responding correctly.
Following card replacement, the valve was i
tested by varying the demand in manual and then switching to I
automatic.
ihe valve appeared to respond correctly, but the WR j
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was being left open to allow for further observation. The i
I inspectors noted that the pre-job brief was detailed and
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communications were appropriately established between the instrument rack room, control room, and mechanical equipment room.
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b.
EDG Fuel Oil Level Calibration On February 1, the inspectors observed the licensee perform Instrument Calibration Procedure EG-1-L100A, EDG Underground i
Storage Tank Level Indication.
To access the float level l
instrument, the missile shield blocks were removed. Operations
i personnel properly entered the required TS action during the i
evolution. The inspectors noted good supervision and foreign material exclusion control.
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c.
SW Repair Project
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i The inspectors observed various activities associated with the SW repair project. The licensee initiated the first of six planned 7-day LC0 entries on January 17 in accordance with TS 3.7.4.1.d.
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The work is being performed on Unit 1 piping; however, Unit 2 i
enters the 7-day LCO so that a SW header can be drained for J
welded plug installation. After weld plug installation, the Unit 2 portion of SW is then restored to service until the next LCO
entry is required. The inspectors determined that the licensee
thoroughly planned and managed the time duration within the LCO.
Temporary operating procedure 49.02 was developed to drain a header and operate the system while drained. After entering the
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LC0, the A header draining was accomplished on time and isolation
boundaries due to recently refurbished SW butterfly MOVs were
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acceptable. The area designated for plug installation required i
weld buildup because of pitting corrosion, which was factored into the schedule. Minor problems occurred with final NDE of the
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welded plug but were resolved. The header was then filled and the
plug hydrostatically tested and returned _to servic.e on January 28,
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well within the time limit. The B header LC0 started on January 31 and required less time in the LC0 due to sufficient wall
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thickness in the vicinity of the plug. Upon exiting the LCO, the
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licensee sand blasted and cleaned the piping.
Pitting assessment and repairs are ongoing. The, third LCO will be entered at the end
1 of February for plug relocation. The licensee's repeated use of LCOs to perform this maintenance was evaluated by the NRC staff in
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a safety evaluation report dated December 3,1992.
No violations or deviations were identified.
5.
Surveillance Observation (61726)
I The inspectors observed and reviewed TS required testing and verified that testing was performed in accordance with adequate procedures, that
test instrumentation was calibrated, that LCOs were met and that any
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deficiencies identified were properly reviewed and resolved.
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a.
2J Bus UV Test i
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On February 12, the inspectors observed 2-PT-36.9.1.J, Degraded l
i Voltage / Loss of Voltage functional Test: 2J Bus. The procedure
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tests the 2J bus 74 percent UV and 90 percent degraded voltage
j relays.
A recent PAR required momentarily entering into TS 3.0.3 i
because the test simultaneously renders an outside recirculation
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spray pump and its associated casing cooling pump inoperable.
Using TS 3.0.3 to accomplish this test has been previously
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reviewed and documented in NRC Inspection Report Nos.
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50-338, 339/92-29.
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The test was well controlled; however, the inspectors noted f
inconsistent documentation for simultaneous verification.
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j of the procedure steps were annotated as "SV" indicating SV I
whereas others were not. The craft personnel performing the test contacted procedure writers and suggested that a change be made to
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J make the use of "SV" notation more consistent.
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b.
EDG Load Sequencing Timer Verification Test
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On January 26, the inspectors observed 1-PT-83.3, Load Sequencing
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i Timers Verification.
The test verifies that the EDG load
j sequencing timers are within tolerances shown in TS Table 4.8.1.
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While testing the 62X timer associated with CC pump 1-CC-P-1B,
l personnel performing the test identified a discrepancy between l
drawing 11715-ESK-5Q and the as-built condition.
Specifically,
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the drawing showed a contact off the 62X relay in the circuit,
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however, it could not be verified in the field. The technicians
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appropriately stopped the test and contacted engineering for l
j assistance.
It was later determined that the wiring was modified l
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to remove the contact per E&DCR-PS-923-1, but the drawings were
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not updated. Drawing update request 93-031 and 93-032 were
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submitted to correct the condition.
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The inspectors reviewed the testing accomplished through January
26 and noted 5 timers had drifted outside their TS setpoint
tolerances. Three of the timers were associated with CRDM cooling
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fans, one with a containment air recirculation fan and one with a
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standby primary grade water pump. The licensee documented these i
failures on DRs93-137 and 93-162 and submitted LER 50-338/93-03.
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Setpoint timer drift has been a recurring problem at North Anna.
j Based on the problem, and in part, as a result of EDSFI findings,
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the licensee initiated a program to replace the current Agastat timers with Allen-Bradley SS relays.
A priority listing for relay replacement has been established and the first replacement timers
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are scheduled to be installed this outage.
SS replacement relays i
j include long-time delay loads or critical loads with a drift history A total of eight Agastat relays will be replaced this
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outage. Three relays are associated with the IJ bus and five with
the IH Bus. The inspectors noted that none of the five current
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failures were on the replacement list for this outage and that two
of the current failures were repeat in that they had failed the
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i previous test.
The licensee indicated that these relays would be j
counted as repeat failures and would fall under their program for i
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replacement in future outages. The inspectors discussed these
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failures with regional personnel and considered the actions taken i
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did not adversely affect diesel load group sequencing.
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6.
Licensee Event Report Followup (92700)
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j The following LERs were reviewed and closed.
The inspector verified j
that reporting requirements had been met, that causes had been
identified, that corrective actions appeared appropriate and that i
generic applicability had been considered.
Additionally, the inspectors l
confirmed that unreviewed safety questions were not involved and that violations of regulations or TS conditions had not been identified.
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a.
(0 pen) LER 339/91-06:
Failure to Place Inoperable Degraded
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Voltage Relay in Trip Within One Hour j
On September 5, 1991, a timer actuation relay for an emergency bus j
degraded voltage protection channel failed during testing.
Although TS 3.3.2.1 requires placing an inoperable channel in trip
within one hour, the licensee determined this to be impractical due to the nature of the circuit. Multiple electrical jumpers
were required in complex circuits configurations. The channel was ultimately placed to its safe condition after approximately three hours. Corrective action by the licensee was to evaluate the need
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for a periodic replacement program and to initiate a TS amendment to extend the time required to place F. inoperable channel in
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trip.
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The licensee is continuing to review the TS amendment. The cause of the Westinghouse ARD relay failure was attributed to long term heating due to continuous energization. The licensee does not believe the failure is related to 10 CFR 21 report Part 21 91-10 concerning ARD relay epoxy softening.
Part 21 Westinghouse ARD relay failures occurred in recently installed relays with relatively few hours of operat. ion. The inspectors determined that the licensee incorrectly linked the two failure mechanisms in their review for corrective action, and resolved the Part 21 issue without developing a periodic replacement program as discussed in the LER.
This LER will remain open until the licensee evaluates a replacement program for energized relays and submits its TS amendment.
b.
(Closed) LER 50-338/92-10:
EDG Fuel Oil Transfer Lines Are Not Missile Protected When this inadequate design was initially discovered, the licensee took prompt action to implement compensatory measures, including the following:
e A Justification for Continued Operation was developed and approved to document the adverse condition and establish short and long term compensatory actions.
- An Operations Standing Order was approved to document the actions required in the event of a secondary line break on North Anna Unit 2 that may affect the EDG fuel oil transfer lines.
- Abnormal Procedure 0-AP-41, Severe Weather Conditions, was revised to require a roving watc.. for the EDG fuel oil transfer lines to verify their integrity or to initiate corrective action.
The licensee also promptly initiated a DCP to add missile protection to these oil transfer lines. The inadequate design was discovered on July 14, 1992.
By August 28, 1992, the DCP was fully implemented.
c.
(Closed) LERs 50-339/92-04 and 50-338/92-05:
Emergency Diesel Generator Load Sequencing Timer Setpoint Drift.
The licensee has established a plan to change out the existing Agastat relay load sequencing timers with Allen-Bradley SS relay timers. The licensee grouped the timers into three categories based on function and DR history. The first replacements are scheduled for the ongoing Unit 1 outage with additional replacements in future outages as require.
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Action on Previous Inspection Items (92701, 92702)
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a.
(0 pen) Unresolved Item 50-338/92-32-01: DBD Concerns l
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The licensee discussed their position on the open items that were
questioned in NRC Inspection Report Nos. 50-338,339/92-32.
l Item 24.3.1 concerned the pote'ntial for inadequate ' recirculation sump water inventory and less than full RS flow during the initial
stages of a MSLB accident. The inspectors reviewed section 6.2.2 l
of the Safety Evaluation Report for North Anna, Supplement 8, l
dated December 1977 in which similar concerns were raised for the
LOCA.
The inspectors determined that the NRC was aware of the i
potential for inadequate NPSH and aware of the RS pump i
manufacturer s statement that no pump damage would be expected with inadequate NPSH for up to 30 minutes. At the time, the NRC-raised concerns with the effects of reduced RS on the containment
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depressurization analysis.
These concerns were resolved with the j
addition of the Casing Cooling System (amendment 5 to the license
and associated SER dated May 19,1978) which provided additional
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NPSH. The SER indicated that a postulated hot leg double-ended
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I rupture was calculated to result in the lowest available NPSH.
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The SER indicated that with Casing Cooling the available NPSH j
would be adequate.
In 1990, the DBD open item noted that the
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i available sump water volume would not support full RS flow until i
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420 seconds after a MSLB.
PPR 90-006 was written to address
operability. The licensee concluded in a May 2, 1990, memo, based
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upon engineering judgment, that a delay in full RS flow during the MSLB would not result in a violation of the design basis criteria.
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i This was because the peak containment pressure would not be
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affected by RS since the peak occurs well before the RS pumps-
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start. The consequences would be to extend containment.
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depressurizaion time by 120 seconds and would not contribute
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significantly to a radiological dose. A potential inadequate sump
inventory, which could result in broken suction to'the RS pumps,
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l was judged to be acceptable based upon the manufacturer's
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statement.
Although not stated in the UFSAR, it is considered
that this was evaluated in the NRC's SER. The licensee's DBD i
I program will continue to determine the extent to which
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calculations will be refined to close the item.
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Item 24.2.4 was concerned with a potential non-conservative assumption that the site boundary dose analysis assumed 100 percent containment coverage with spray flow for iodine removal j
although QS and RS actually cover only 85 percent. The inspectors i
reviewed the North Anna SER Table 15.2 and 15.3 which documented i
the NRC's review of the site boundary dose analysis.
The model
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assumed a sprayed volume of 540,000 ft. This corresponds approximately to a QS coverage of 30 percent.
This resulted in an Exclusion Area boundary dose of 116 Rem thyroid. The licensee's
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i judgment is that any non-conservatism in their analysis would be
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i bounded by this review.
Further, the licensee's more recent analysis (not yet submitted) with.currenk standard review plan
i assumptions, remains bounded by the above results. The inspectors i
concluded that enough evidence exists to suggest that this open
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item does not represent an unreviewed safety question.
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Item 24.14.135 determined that,the Casing Cooling Tank low level
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setpoint was below the usable water volume and in the range at l
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which pump vortexing would occur. The inspectors questioned the i
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ability of the low level actuation to function (isolate Casing Cooling pump discharge valve RS-MOV-100A(B)). The licensee's
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position was documented in a January 26, 1993, memorandum. The l
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low level setpoint is 20 inches above the pipe suction. The i
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licensee's calculations are based on suction velocity and use guidance which suggests a minimum submergence of 3.3 feet in order
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to prevent vortexing. The licensee's judgment is that the tank
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diameter and horizontal pipe run tend to make vortexing less
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likely.
Further, the centrifugal single stage horizontally j
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mounted Casing Cooling Pumps could pass any void fractions of 5 I
i percent without noticeable degradation. The inspectors also l
determined that the licensee's E0Ps have steps to verify the j
Casing Cooling discharge valves have isolated on low tank level.
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- j Based upon this, it is reasonable to expect that the containment
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isolation function would be met. However, the inspectors
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considered it a weakness that the licensee had not evaluated this i
i until prompted.
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Based upon the small sampling, the inspectors were unable to
conclude that the licensee's open item tracking system was
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adequate.
The licensee has not prioritized or scheduled items for i
I closure. The licensee indicated that the first revision of DBDs i
(due shortly) would close many items and that the remaining items i
s will be prioritized.
This will also apply to new DBDs. This URI i
will remain open pending continued review of the licensee's
.
I proposed enhancements.
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j b.
(Closed) IFI 50-338/92-15-01:
Iodine Filter Heater Automatic t
Function
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l The iodine filter banks are equipped with automatically operated
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i heaters for the purpose of minimizing humidity effects on the l
j charcoal. The heaters are energized by a pressure switch which i
senses flow.
During a previras inspection, the inspectors opened
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this IFI concerning the flot rate at which the heaters operate.
Excessive flow was required to energize the heaters which was
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inconsistent with the UFSAP,.
Since that time, the licensee has
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l completed a DCP to ensure heater operation with only the j
safeguards ventilation fans running through the filter bank.
Each
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safeguards fan supplies 6300 SCFM and is the smallest fan directed l
l through the filters.
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l c.
(Closed) Unresolved Item 50-338/91-27-01:
High Failure Rate of l
l Emergency Lights
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i The licensee determined that emergency lighting failures were l
primarily a result of bad or leaking batteries due to high ambient I
temperature. The licensee reviewed work history and identified j
the average battery lifetime of each emergency light in the plant.
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Areas in the plant with lowest lifetimes (less than 3.6 years
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compared to a published service life of 15 years) were identified
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to be in the MSVH, turbine building, EDG rooms, fuel building and i'
auxiliary building. ADM 16.2, Special Reports for Inoperable Appendix R Equipment, adequately provides the minimum lighting j
requirements for a particular area of the plant and requires
action to restore inoperable lights within 14 days or submit a i
special report to the NRC.
In recent history the licensee has not i
been required to submit a report.
j i
The licensee has proposed short term corrective action to replace
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batteries every year in those locations with the worst i
performance.
In the longer term, the licensee will continue to
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track and identify lights with high failure rates, review the
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results of the ongoing emergency lighting study at tne Surry l
Nuclear Station for the most cost effective resolution and i
evaluate candidates for replacement with new lighting units.
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8.
Exit (30703)
i The inspection scope and findings were summarized on February 22, 1993, with those persons indicated in paragraph 1.
The inspectors described
the areas inspected and discussed in detail the inspection results
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listed below. The licensee did not identify as proprietary any of the (
material provided to or reviewed by the inspectors during this
inspection.
Dissenting comments were not received from the licensee.
l Item Number Descriotion and Reference
50-338/93-08-01 (VIO) Failure to Maintain Containment
Penetrations During Refueling (para 3.a)
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50-339/93-08-02 (IFI) SG Shell Unqualified Coating (para 3.c)
t 50-338/93-08-03 (URI) Containment Gaseous and Particulate Rad
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Monitor Operability During Refueling (para 3.f)
t 9.
Acronyms and Initialisms f
ADM Administrative Procedure CC Component Cooling CFR Code of Federal Regulations
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CRDM Control Rod Drive Mechanism i
DBD Design-Basis Document DCP Design Change Package
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DR Deviation Report
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E&DCR Engineering and Design Change _ Request,
ECCS Emergency Core Cooling System EDG Emergency-Diesel Generator EDSFI Electrical Distribution System Functional Inspe'ction
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E0P Emergency Operating Procedure FRV Feedwater Reculating Valve
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ICP Instrument Calibration Procedure
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IFI Inspector Follow-up Item
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LCO Limiting Condition for Operation i
LER Licensee Event Report
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LOCA Loss of Coolant Accident
~l MOV Motor-0perated Valve
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MSLB Main Steam Line Break MSVH Main Steam Valve House NCV Non-Cited Violation i
NDE Nondestructive Examination l
NPSH Net Positive Suction Head
NRC Nuclear Regulatory Connission PAR Procedure Action Request
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PPR Potential Problem Report
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PT Periodic Test-i QA Quality Assurance
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QS Quench Spray
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RCC Rod Control Cluster-I REM Roentgen Equivalent Man
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RS Recirculation Spray
SCFM Standard Cubic Feet Per Minute l
SER Safety Evaluation Report
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SGRP Steam Generator Replacement Project
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SRO Senior Reactor Operator SS Solid State l
SV Simultaneous Verification f
SW Service Water TS Technical Specification UFSAR Updated Final Safety Analysis Report
URI Unresolved Item UV Undervoltage VIO Violation WR Work Request
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