IR 05000259/1991002
| ML20138G076 | |
| Person / Time | |
|---|---|
| Site: | Browns Ferry  |
| Issue date: | 03/18/1991 |
| From: | Patterson C NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20138G073 | List: |
| References | |
| 50-259-91-02, 50-259-91-2, 50-260-91-02, 50-260-91-2, 50-296-91-02, 50-296-91-2, NUDOCS 9610180212 | |
| Download: ML20138G076 (44) | |
Text
.
.
. -
-
.-
.
. - -...
-
. _.
.
.
.
p Og#o UNITED STATES NUCLEAR REGULATORY COMMISSION p
REGION il
,
y
,j 101 MARIETTA STREET. N.W.
ATLANT A, GEORGI A 30323 l
\\...../
Report Nos.:
50-259/91-02, 50-260/91-02, and 50-296/91-02 l
Licensee: Tennessee Valley Authority 6N 38A Lookout Place i
l 1101 Market Street
Chattanooga, TN 37402-2801 Docket Nos.: 50-259, 50-260, and 50-296 License Nos.: DPR-33, DPR-52, and DPR-68 Facility Name: Browns Ferry Units 1, 2, and 3 Inspection at Browns Ferry Site near Decatur, Alabama
,
Inspection Conducted: January 19, 1991 - February 15, 1991 Inspector:
//
4-V
@
3/
ef/
C. A PagA p;'Teis nt Inspector Date / Signed
/L Accompanied by:
E. Christnot, Resident Inspector W. Bearden, Resident Inspector K. Ivey, Resident Inspector G. Humphrey Resident Inspector Approved by:
7/
F/
Pau
- M Ins wun ero y/ar(s nie7
--
Date Signed e
TVA Projects Di%ision SUMMARY Scope:
This routine resident inspection included surveillance observation, maintenance observation, operational safety verification, modifications, post modification testing, Engineered Safety Feature System walkdown, standby liquid control issues, System Preoperability Checklist, local Leak Rate Testing, reportable occurrences, action on previous inspection findings, and site management and organization.
i
'
Results:
i Activities related to preparation for Unit 2 fuel load were the focus of inspections.
Twenty-nine open items were closed.
All fuel load items were
!
9610180212 960318
}
l PDR ADOCK 05000259
l G
PDR S
-.- --.- -
. -
-. - -. -. - -. -. -
. - _. - -. -.
. -. -
=
l l
'
.
,
closed or resolved.
Other items ins Temporary Alteration Change Form log, pected were the hold order log, the and the Unit 2 drywell. Meetings of the Nuclear Safety Review Board and Senior Management Assessment Restart Team
concerning fuel load and restart preparations were attended.
With resolution of the items discussed, activities support Unit 2 fuel load.
.
A Non-cited Violation was identified for failure to maintain Limiting l
Condition for Operation compensatory measures for inoperable Continuous Air Monitor paragraph 4 In each case the licensee took prompt action to correct the problem, conducted an incident investigation and reported the event to the Nuclear Regulatory Commission in Licensee Event Report.
A Non-cited Violation was identified for failure to follow a Surveillance Instruction during Standby Liquid Control testing, paragraph 8.
The licensee
-
conducted an incident investigation and revised the SI to preclude formation i
of any air pockets in the lines under any condition.
An Inspector Followup Item was identified concerning a possible single failure problem with the Standby Gas Treatment system, paragraph 10.
The licensee is reviewing data to determine if acceptable flow rates exist with a single train failure.
If not, a special test is being considered to resolve the issue.
-
,
i
-
,
I n
-, ~ --
, - -,,
,
,r-
,
,
,,.
-
-
-
,N-
--
-
-.
~
..
_
- _. _ -
_..
.
- _..
. - -.
.
.
j
.
REPORT DETAILS d
1.
Persons Contacted
.
!
Licensee Employees:
O. Zeringue, Site Director
.
- L. Myers, Plant Manager i
t
- M. Herrell, Operations Manager
.
- J. Rupert, Project Engineer i
R. Johnson, Modifications Manager
i
- M. Bajestani, Technical Support Manager R. Jones, Operations Superintendent
- A. Sorrell, Maintenance Manager j
G. Turner, Site Quality Assurance Manager
- P. Carier, Site Licensing Manager
- P. Salas, Compliance Supervisor
- J. Corey, Site Radiological Control Manager R. Tuttle, Site Security Manager i
Other licensee employees or contractors contacted included licensed reactor operators, auxiliary operators, craftsmen, technicians, and public safety officers; and quality assurance, design, and engineering personnel.
NRC Personnel:
- C. Patterson, Senior Resident Inspector W. Bearden, Resident Inspector
- E. Christnot, Resident Inspector
- K. Ivey, Resident Inspector
- G. Humphrey, Resident Inspector
- Attended exit interview Acronyms used throughout this report are listed in the last paragraph.
2.
Surveillance Observation (61726)
The inspectors observed and reviewed the performance of selected sis.
The inspections included reviews of the sis for technical adequacy and conformance to TS, verification of test instrument calibration, observations of the conduct of testing, confirmation of proper removal from service and return to service of systems, and reviews of test data.
The inspectors also verified that LCOs were met, testing was accomplished by qualified personnel, and the sis were completed within the required frequency.
The following SI observations and reviews were conducted during this reporting period:
.
-
.
-
.-.
-
-
-
.
-.-
_.-
_
.
.
l
3-SI-4.9.A.2.c(c), Main Bank 3 Battery Discharge Test and 3-SI-a.
4.9.A.2.b-1, Quarterly Check for 250V Main Battery Number 3.
The inspector observed the performance of these sis and reviewed the results.
Main Bank Battery 3 is near the end of life and this SI is being performed once a year.
The system engineer, plant operations personnel, plant maintenance personnel, and a TVA inspector from Quality Monitoring were observed actively participating in the l
performance of this SI.
!
b.
During the previous reporting period, an inspector reported the
!
review of an inadvertent 2D RHR pump start on December 20, 1990. The
,
inspector stated that this event would be followed until a review of the completed incident investigation could be performed.
Report II-8-90-152 was completed on January 24, 1991.
An inspector reviewed the report and concluded that the inadvertent pump start was caused by carelessness during the performance of the SI. A craftsman was performing a continuity check for the pump's auto start logic and accidentally made up the circuit.
The inspector considered this an isolated occurrence.
No further concerns were identified.
!
'
c.
An inspector reviewed activities to perfonn 2-SI-4.2.C-3(B),
Instrumentation That Initiates Rod Blocks / Scrams Intermediate Range Monitor Channel B Calibration. During the performance of this SI the instrumentation did not function as required.
As a result, the SI was discontinued, a test deficiency initiated, and e Work Order (WO i
9125511-00) was initiated to trouble shoot and repair the instrument.
The inspector questioned the IMs about the accuracy of the SI procedure steps. The IMs stated that the only problem identified was that, in step 7.13.26, instructions were not stated for activities when the instrument was found to be out of tolerance.
The IMs stated that actions would be initiated to correct this discrepancy.
d.
Mechanical Maintenance Instruction, MMI-22, R-7, Reactor Core
'
Isolation Cooling System.
The inspector reviewed testing in progress of the RCIC turbine, pump, and turbine / pump lubrication system.
However, during the testing, the turbine electronic overspeed trip did not function.
At this point, the testing was discontinued to establish the corrective actions to be taken to resolve the deficiency.
.
No violations or deviations were identified in the Surveillance Observa-tion area.
l I
l l
l l
. _ -
-
-
.
.
3.
Maintenance Observation (62703)
Plant maintenance activities were observed and reviewed for selected
,
safety-related systems and components to ascertain that they were l
conducted in accordance with requirements.
The following items were considered during these reviews:
LCOs maintained, use of approved procedures, functional testing and/or calibrations were performed prior to returning components or systems to service. QC records maintained, activities accomplished by qualified personnel, use of properly certified parts and materials, proper use of clearance procedures, and implementa-tion of radiological controls as required.
Work documentation (MR, WR, and WO) were reviewed to determine the status of outstanding jobs and to assure that priority was assigned to safety-
related equipment maintenance which might affect plant safety.
The
,
inspectors observed the following maintenance activities during this reporting period:
Special Instrumentation Instruction SII-0-XX-92-051, LPR!i Maintenance a.
and Testing Instruction.
The inspectors reviewed and observed the performance of this instruction.
The purpose of the instruction was to perform maintenance, removal, testing and replacement of LPRM detector assemblies.
The licensee identified a total of 11 LPRM detector assemblies for replacement.
This activity involved the use of the refueling bridge over the reactor vessel cavity. All activities were controlled by the refuel floor SR0s, observed by site quality monitoring personnel and supported by health physics personnel. One item was discussed with licensee personnel involving comunications.
During the replacement of detector number one, the flush was prematurely stopped due to miscomunications between the personnel on the refueling bridge, the refuel floor SRO, and the personnel in the Drywell controlling the flush.
The portions observed and reviewed by the inspectors included initial conditions and prerequisites, shift briefings, operator briefs and training, and electrical checkout of the newly installed assemblies.
Several assemblies failed the voltage breakdown and/or the insulation resistance tests.
All items were repaired.
b.
Technical Instruction 0-TI-235, Secondary Containment Zonal Integrity Test.
The inspector reviewed and observed the performance of this TI. The purpose of this TI was to test the integrity of the secondary containment zonal boundaries.
The 8FN secondary containme it is divided into four zones which may be isolated independently from each other - the refueling zone and Unit 1, Unit 2, and Unit 3 reactor zones.
This instruction tested the integrity of three zones, excluding Unit 3, and two zones, Units 1 and.
. _.
.
.
+
.
The inspector reviewed and observed the test in progress.
The test involved the closing off of boundary doors, ventilation dampers, and i
equipment hatches.
The SBGT system was operated to verify that secondary containment criteria could be met.
Preliminary data indicated that secondary containment criteria for three zones could be met.
The licensee attempted various methods, such as placing a blank over the SBGT inlet suction from the refuel floor to meet the criteria for two zones. The licensee was unsuccessful in meeting the criteria for two zones.
The test was performed according to procedure, the test director was knowledgeable of the system and the SOS exercised control over the plant.
No violations or deviations were identified in the Maintenance Observation area.
Operational Safety Verification (71707)
l The NRC inspectors followed the overall plant status and any significant safety matters related to plant operations.
Daily discussions were held with plant management and various members of the plant operating staff.
The inspectors made routine visits to the control rooms.
Inspection observations included instrument readings, setpoints and recordings, status of operating systems, status and alignments of emergency standby systems, verification of onsite and offsite power supplies, emergency power sources available for automatic operation, the purpose of temporary tags on equipment controls and switches, annunciator alann status, adherence to procedures, adherence to LCOs, nuclear instruments operability, temporary alterations in effect, daily journals and logs, stack monitor recorder traces, and control room manning. This inspection
'ctivity also included numerous informal discussions with operators and v:pervisors.
General plant tours were conducted.
Portions of the turbine buildings, each reactor building, and general plant areas were toured.
Observations included valve position and system alignment, snubber and hanger conditions, containment isolation alignments, instrument readings, housekeeping, power supply and breaker alignments, radiation and contaminated area controls, tag controls on equipment, work activities in progress, and radiological protection controls.
Informal discussions were held with selected plant personnel in their functional areas during these tours.
a.
Drywell Tour On February 13, 1991, an inspector toured the Unit 2 drywell with the Plant Manager and drywell coordinator.
Progress continues to be made toward closure of the drywell.
A punchlist of items was identified
.
.
for correction.
Several of the items were previously identified by the licensee during nrevious inspections.
The drywell coordinator provided a typed Mst of the items from the tour and discussed resolution of the items.
With resolution of the items no concerns were identified that would impact fuel load, b.
Implementation of TS LC0 Compensatory Measures TS Section 3.2.K requires the radioactive gaseous effluent monitoring instruments listed in Table 3.2.K to be operable.
This includes monitors for the reactor, turbine, and radwaste building ventilation systems, among others.
TS 3.2.K also requires that actions be taken whenever the instruments are declared inoperable and effluent releases are being conducted through an affected pathwey.
The required actions include a four hour flow rate estimate, an eight
,
l hour grab sample for noble gases, and continuous sampling for iodine and particulates.
These LCO compensatory requirements are satisfied by the use of a temporary monitor connected to the CAM process lines.
The following events constitute two examples of the failure to meet the requirements of TS 3.2.K.
These events were identified by the licensee during the last two reporting periods.
The resident inspectors reviewed these events and the results are as follows:
(1) On December 30, 1990, during the performance of Instrument Maintenance 9rocedure 3-SI-4.2.K.2.a.
Reactor Building Ventilation Exhaust Monitor Source Calibration and Functional Test, CAM 3-RM-90-250 was valved out of service several times.
At the time of the SI performance a temporary monitor was installed on the CAM to satisfy the compensatory requirements of TS 3.2.K.
During the SI performance, the temporary monitor was valved out each time the permanent monitor was.
The licensee estimated the aggregate time that the temporary monitor was out of service to be up to 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.
This resulted in the failure to maintain continuous sampling of iodine and particulates.
Upon identification of this condition, the licensee immediately terminated effluent releases via the affected pathway.
This event was reported to the NRC in LER 50-296/90-05 on January 28, 1991.
In IR 90-40, an inspector reported that this issue would be followed until a review of the completed incident investigation report could be performed.
Report II-B-91-002 was completed on January 25, 1991.
The report attributed the event to three causes: a) a design oversight which did not provide a sample point to be used when the monitor's inlet lines are isolated; b) misinterpretation of a TS action which allowed continuous sampling to be suspended for up to four hours; and c) lack of a section review of the SI by the Chemistry department.
-
___
_. _ _ _ _.. _ _
-.
_ _. _ -. _. _. _ _ _ _.. _ _ _ _ _ _. _. _ _. _
.
.
,
l
,
.
As corrective action, the licensee modified the process lines for the ventilation exhaust radiation monitors for the refuel and reactor zones, radwaste building, and turbine building to include sampling taps upstream of the isolation valves. The use of the new sampling taps will ensure that sampling continues i
even if the monitor is isolated. An inspector verified that the
,
!
monitors had been modified with the new sampling taps.
The l'
licensee is also revising the calibration and functional test l
sis for the 10 effluent CAMS to clarify sampling requirements l
when a monitor is inoperable.
In addition, all sis determined to affect chemistry compensatory sampling will be required to be routed to Chemistry for an affected section review when revisions are made.
(2) On February 1,1991, during the performance of 0-SI-4.8.B.2-1, l
Airborne Effluent Analysis - Particulate and Charcoal Filter l
Analysis, a RLA discovered that the filter holder for CAM 1-RM-l 90-250, Reactor Building Ventilation Exhaust Monitor, did not
!
contain any filters.
The analyst notified the CSS of the missing filters.
The CSS determined that the reactor zone ventilation was in-service with an effluent release being monitored at the time.
Based on the performance of the previous analysis, the CSS determined that the reactor zone effluent had j
been unmonitored for iodines and particulates since January 26, 1991. No compensatory measures were in place while the effluent release was being conducted and the monitor was inoperable.
Following identification of - the missing filters, all other effluent. CAMS were checked to verify that required filters were properly installed.
No other deficiencies were identified.
This event will be reported to the NRC in LER 50-259/91-02.
j l
,
,
The licensee initiated an incident investigation _(II-B-91-029),
which was completed on February 11, 1991, to detemine the root cause and corrective actions to be taken.
The cause of the event was attributed to personnel error in that the procedure to change the filters (0-SI-4.8.8.2-1) requires the installer to ensure that the filter holder has been prepared properly.
This step was signed off by the RLA on the assumption that the filter holders had been correctly prepared by the previous shift.
The investigation also concluded that inadequate onshift supervision by the CSS and poor communication between RLAs regarding the status of the filter holders without verification contributed to the failure.
Additional contributing causes were lack of RLA familiarity with the procedure and lack of adequate review prior to performance.
As. corrective actions for this event, the licensee changed the i
chemistry shift turnover policy to allow for a longer turnover
.
>
period and revised the required reading mechanism to keep RLAs i
from performing procedures until they have reviewed and
,
!
l
'
_
_
_
_
.
.
-
-
.
~. -. -,
.
.
.
.
understood any revisions.
In addition, the licensee took personnel action against the individuals involved in the event.
The above given examples constitute a violation for failure to maintain TS 3.2K LC0 requirements and compensatory measures.
This licensee identified violation is not being cited because the criteria specified in Section V.G.1 of the NRC Enforcement Policy were satisfied.
The licensee took immediate actions to meet the TS requirements and further corrective actions to preclude the
'
recurrence of each event.
This violation is identified as NCY 259, 260, 296/91-02-01, Failure to Maintain LC0 Compensatory Measures.
c.
Equipment Clearances The inspectors reviewed the clearances identified below to verify compliance with SDSP-14.9, Equipment Clearance Procedure, and that the clearances contained adequate information to properly isolate the affected portions of the systems being tagged.
Additionally, the
,
inspectors verified, on accessible equipment, that the required H0 tags were installed.
Although some H0s were held open longer than
'
necessary, the documentation was complete and accurate.
No deficiencies were identified during the performance of these reviews.
Clearance Equipment / Purpose
!
86-1171 This H0 located on the 250V DC Battery Board I, Panel 7, Breaker 711, was initiated for the implementation of ECN P0307.
A review of the licensee's documented status of this ECN revealed that it was canceled June 8,1981.
3-90-340-1 This H0 was attached to breaker 802, Panel 8 on 250V DC Battery Board I, which was labeled as a spare. The inspector questioned the hold order attached to a spare breaker.
Operations personnel reviewed the condition and reported that this breaker had been spared under ECN P7161, which was implemented per Work Plan WP
,
0501-90. The work was completed in the latter part of November, 1990.
!
2-89-918-141 No discrepancies noted.
,
2-90-529-130 No discrepancies noted.
2-91-80-1 &
These H0s were attached to breaker 2-91-131-2 710, Panel 7 on the 250V DC Battery Board 2 which was labeled as a spare.
A review of this H0 revealed that the breaker was spared under WP 2013-91.
The H0 was issued on January 18, 1991 l
l
-
.
l
.
.
'
e
.
i to begin the work and will be removed upon full'
completion of this effort.
2-91-133-1 This H0 was attached to breaker 1178, on the 250V DC Battery Board 2 and was labeled as a spare.
l This was found to have been spared per DCN W10617
,
and W10618 that was implemented per WP 2618-90.
The H0 was issued January 26, 1991 and will be removed when all work is completed.
d.
Temporary Alterations The inspector reviewed the system status and temporary alteration files to detennine the extent of licensee progress in this area.
During that review the inspector noted that licensee management has
continued to devote attention to this area as evident by the current number of open TACFs.
At the time of the review there were 10 open Unit 2 TACFs and 20 open Unit 0 TACFs plus a larger number of Unit 1 and Unit 3 TACFs.
The licensee has segregated all active TACFs into two groups:
those that do not impact Unit 2 restart (mostly Unit 1 and 3 TACFs along with some Unit 0 TACFS) and those that potentially j
,
could affect Unit 2 restart (all Unit 2 TACFs and some Unit 0 TACFs).
Licensee technical support personnel responsible for oversight of
'
this program stated that although the goal is still zero open TACFs for Unit 2 the actual commitment is to be below 10 open TACFs before restart.
There are currently 9 TACFs related to Unit 2 restart (which includes some Unit 0 TACFs) that the licensee feels will still be necessary at restart.
Those TACFs are identified as deferrals and each of these has been reviewed by the PORC which has documented concurrence with deferral of these TACFs until after restart.
The inspector reviewed the existing Unit 2 and Unit 0 TACFs and did identify any problem which should affect core reloading of not Unit 2.
The resident staff will continue to follow the licensee progress in this area with another review of all open TACFs prior to restart.
One NCV was identified in the area of Operational Safety Verification.
5.
Modifications (37700, 37828)
The inspectors maintained cognizance of modification activities to support the restart of Unit 2.
This included reviews of scheduling and work control, routine meetings, and observations of field activities.
,
Throughout the observation of modifications being performed in the field l
!
QC inspectors were observed monitoring and documenting verification at work activities.
I a.
Q-List, Electrical Cables
.
-.
.
-
.
l
.
.
l l
.
l The licensee informed the inspector that during previous reviews a number of electrical cables affecting System 31, Control Bay HVAC, were not placed on the initial Q-List.
This error was discovered
!
during the SPAE process.
The licensee also informed the inspector that some of these electrical cables were identified as having possible pull-by, separation, and ampacity failures.
The initial information received by the inspector indicated the following:
(1) Pull-by During a reevaluation of the cable pull-by issue for the cables being added to the Q-List a total of 334 safety related cables were identified that were not previously evaluated for pull-bys.
The application of the screening process previously established for the pull-by analysis identified both V3 and V4 conduits to be evaluated for pull-bys.
The Length-Fill Ratio process
'
applied to these conduits indicated that three of these were
above the previously established cutoff for required walkdowns.
The results of the walkdowns were used to establish the position
!
of these three conduits in the sidewall pressure ranking.
The licensee indicated that the additional cables added to the Q-List did not affect the pull-by hi-pot testing results.
This
.
was verified by the inspector.
(2) Ampacity
'
(a) Existing calculation impact:
31 cables were identified as failures but were not replaced due to not being on the
'
Q-List; 18 of these 31 ca::les were determined to be nonsafety-related; six cables were evaluated further and i
were determined to be acceptable; seven cables were l
evaluated further and confirmed as failures; and DCN W15974 was issued to address this cable ampacity item.
(b) Reconfirmation of Ampacity Scope:
Ampacity data base was
,
'
reconciled against the AC/DC calculation data base and was completed on January 8, 1991; 293 cables were not included in the original ampacity data base; of these, 47 cables were determined to be nonsafety-related; 158 cables were determined to be voltage level 3-V3; 15 cables were identified as being in unanalyzed trays and were scheduled for replacement; 64 cables were determined to be routed in
!
conduit only and the evaluation indicated no failures; and eight cables were found to have been previously replaced by other programs.
.
(3) Cable Separation The program used the Q-List to bound the scope of non-suffixed cable, those that did not indicate what division they are l
l L
-
.
.
_
._ ___._
. _. _ _.
_.
_.
_. - _. _
-
_ _.. _ _ _
..
.
'
l
-
assigned to, such as 2PL2104 I.
All cables evaluated for ampacity which were determined to be safety-related and did not have a suffix, indicating which divisional assignment, were evaluated for compliance to the separation requirements.
A total of 62 cables were identified to be safety-related and without a suffix.
Of this amount: 18 were V4 cables of which i
l five required rerouting and 13 required retagging; and 44 were V3 cables of which 10 required rerouting and 32 require retagging.
DCN W15974 was also issued to address this cable separation item.
The licensee infonned the inspector that many of these items are still under review.
The inspector will monitor the licensee's i
activities involved with DCN 15974.
As part of the inspector's review of this DCN it was noted that this change affected at
.
least two systems; 31, Control Bay HVAC and 39, C02 Storage and Fire Protection.
,
b.
Field Activities The inspector reviewed and observed the licensee's activities for DCNs W15974 and W16097.
These included attending pre-design
!
meetings, review and observation of advanced authorized activities, review and observation of installation activities and review of Post Modification Tests.
(1) DCN W15974 was issued to correct cable ampacity and separation i
deficiencies.
The DCN was issued in four revisions, A thru D,
!
due to scheduling considerations.
Revision C, which dealt with ten cables effecting the Unit 3 Auxiliary Board Room Fans for DGs 3EA and 3EB, was completed first.
This DCN involved i
advanced authorized activities which were approved by the PORC.
The inspector reviewed the PMT for Revision C and noted that fans were bumped for rotation and the dampers were also tested.
,
l Two cables, 3PL 2402 and 3PL 2403, were of special interest due l
to the fact that NE indicted that these cables required replacement under the ampacity/ separation issue.
However, the i
plant system engineer questioned as to why these should be replaced.
These cables are connected to a temporary switch and damper motor associated with the Unit 3 shutdown board rooms.
Infonnation received from the licensee indicated that these cables would be replaced.
(2) DCN 16097 was issued as a result of a 10 CFR 50, Appendix A, Criterion 17, Electrical Power Systems, deficiency.
During the
!
SP0Cing process for System 31, Control Bay HVAC, it was noted that the control bay HVAC did not provide enough cooling to the 3C Level and specifically the relay room.
This room contains
.
the relaying networks affecting the switchyard.
During a
'
postulated Unit 2 accident scenario, the room could overheat and
!
_ _
__
_
_
..
.
_.
_
.
.
h
11
.
risk the loss of offsite power. The licensee was installing an i
additional air handling unit in the 3C relay room to provide additional cooling.
The inspector reviewed and observed the licensee activities involving installation of conduit, water piping and supports.
No deficiencies were identified.
All work l
was in accordance with the licensee's modification program.
DCA's, workplans and signoffs were in the field and being utilized.
The inspector's reviews and observations also indicated that due to Q-List equipment interfaces, more activities may be required by the licensee.
These activities could include the upgrading of equipment to safety related status and possible replacement of equipment. The inspector will continue to monitor the licensee's activities in this area.
No violations or deviations were identified in the Modifications area.
6.
Post Modification Testing (37700, 37828)
An inspector observed the performance of PMT BF-3.002, Reactor Vessel
!-
Water Level Tracking, conducted on January 31, 1991.
The PMT was i
performed to verify that control room indications of reactor water level actually tracked changes in the water level in the reactor vessel.
The PMT was written for ECN P7131 which modified the reference sense lines
,
used for reactor water level monitoring.
The PMT consisted of lowering the water level in the reactor vessel and monitoring control room indications to ensure that the reactor water level instruments on each modified reference leg tracked the decrease.
The test was completed satisfactorily and the inspector identified no deficiencies.
No violations or deviations were identified during the review of Post
'
Modification Testing.
i
!
ESF System Walkdowns (71710)
!
The inspector walked down selected portions of System 86, Diesel Air Start System, associated with the Unit 1/2 and Unit 3 DGs. During the walkdown the inspector noted that for each of the eight DGs there are a pair of ball valves (0-86-539A, 0-86-540A, 0-86-5398, 0-86-5408, 0-86-539C,
0-86-540C, 0-86-539D, 0-86-5400, 0-86-650-3A, 0-86-651-3A, 0-86-650-38, 0-86-651-38, 0-86-650-3C, 0-86-651-3C, 0-86-650-30, and 0-86-651-38) used to isolate the left and right banks of starting air from the air operated starting motors.
Each of the ball valves has a small piece of light weight chain and plastic tab which functions as a valve locking device.
These locking devices are not adequate.
This type of valve design only requires a 90 degree movement of the valve handle to completely shut the i
valve. Some of the valve chains are just wrapped around the handle with no actual securing device. The problem is further complicated because the eight valves assc-:iated with the Unit 3 D/Gs are not of the same configuration as t'1e valves associated with the Unit 1/2 D/Gs.
For eight of the 16 valves he low air supply header alarm is located upstream of I
_
--
j
.
.
the valve.
If a valve were inadvertently closed that 0/G would be inoperative and the control room alarm would provide no warning.
The inspector discussed this condition with the plant manager and was informed i
that the condition would be resolved.
The inspectors will continue to follow the licensee's actions in this area during the next reporting period.
8.
Standby liquid Control System Issues Various issues and problems have been identified involving the SLC system during several reporting periods.
discussed below:
The problems and their resolutions are a.
On November 20, 1990, during the performance of 2-SI-4.4.A.2, Standby Liquid Control System Functional Test, SLC pump 2A did not develop flow.
An investigation determined that the pump was air bound following an inadequate flushing process.
Prior to the performance of the SI, the ASOS directed the AVO to flush the test tank and system piping with demineralized water in accordance with steps in the SI.
It was during this flush that air was allowed to collect at
'
the pump suction.
The licensee initiated an incident investigation (II-B-90-134) to determine the root cause of this event and to provide corrective actions.
The NRC inspectors opened URI 260/
90-37-01 pending review of the completed incident investigation report.
Report II-B-90-134 was completed on December 19, 1990.
The report concluded that the root cause of the event was that steps in the SI were performed out of sequence, allowing air into the pump suction piping.
The system engineer stated that the air pocket would not have formed if the SI had been performed in the proper sequence. The report identified that the flushing steps in the SI should be revised
'
to preclude the formation of air pockets in the suction line under any condition.
The inspector verified that the SI had been revised, i
TS Section 6.8.1.1.c requires that written procedures be implemented covering surveillance and test activities of safety related equipment.
The failure to follow SI steps as written is a violation of this requirement.
This licensee identified violation is not being cited because the criteria specified in Section V.G.1 of the NRC Enforcement Policy were satisfied.
The licensee took corrective actions to preclude the recurrence of this event. This violation is identified as NCV 260/91-02-02, Failure to follow SI During SLC Testing.
b.
Report II-B-90-134 also identified that the NPSH provided for the SLC pumps did not conform to the guidelines of the pump manufacturer.
Licensee review of this issue revealed that it was also identified as a concern in 1985 and SCR 8FNMEB8510 was issued at that time.
The SCR concluded that a special test should be conducted. The licensee conducted special test ST-8522, SLC Suction Pressure Detennination,
.
.
.
-
..
_
-,.-
--
. --
--
..
... -.
.
--
c
.
i
.
in 1985 which verified adequate NPSH without cavitation for the SLC
,
l system pumps.
The test involved running a single pump recirculating i
through the test tank at a temperature of 110 degrees F.
This issue is resolved.
During a performance of 2-SI-4.4.A.2 reported in IR 90-37, a packing
<
c.
l leak developed on SLC pump 2A. An inspector examined the old packing l
after its removal from the pump and noted that approximately half cf the components of the multi-piece seal were damaged. New packing was installed and the pump returned to service.
i
'
l During this reporting period, a packing leak again developed on SLC l
pump 2A during performance of the SI.
An inspector discussed SLC i
pump packing problems with the cognizant system engineer and examined i
the pump.
The system engineer indicated that no definite cause had
.
been identified for the packing leaks.
By the end of the reporting
'
period, the 2A pump packing was replaced and the SI ran successfully with no packing problems.
The resident inspectors will follow up on the SLC pump packing problems with the system engineer to determine if a generic problem
,
'
exists.
Findings will be documented in future inspection reports.
d.
During this reporting period, the resident inspectors were made aware
.
of potentici problems with the adequacy of NPSH for SLC system pumps
!
because of events which occurred at the Quad Cities Nuclear Plant.
The resident inspectors discussed this event with cognizant licensee personnel at BFN.
The licensee had performed a special test in 1985
.
(see b above) which verified adequate NPSH for the SLC pumps at 110
!
degrees F.
In addition, the EQ envelope for the SLC pump area is based on a RWCU system line break.
When the line breaks, the area temperature initially increases to 130 decrees F, then decreases steadily to 100 degrees F within 5 minutes.
The area temperature then remains at 100 degrees F.
The plant maintains a control room
,
'
annunciator (2-XA-55-58, window 13) which alarms on abnonnal
!
temperature in the SLC pump area.
The high alarm is set for 95.1
'
degrees F.
The licensee considers the special test and high temperature alarm sufficient to conclude there is no concern with NPSH at elevated temperatures for BFN.
NRC IN 91-12, Potential Loss of NPSH of SLC System Pumps, was issued on February 15, 1991, to alert licensees to the potential NPSH l
problem.
At the exit meeting on February 19, 1991, the inspectors
i noted that the licensee should review the IN accordance with plant procedures, even though a preliminary review had already been conducted.
One NCV was identified during the review of SLC system issues.
.
i
,
. -
_
..
o
.
9.
Inadequate RHR Support.
h January 11, 1991, a licensee engineer performing an analysis for
adequacy to support additional loads from lead shielding used during outages discovered that proper documentation could not be found for one l
support (2478452-H0255).
This discrepancy concerned the existing supports associated with a six inch class II Unit 2 RHR loop I drain line.
The SP0C process for the RHR system had been completed December 3,1990, without identifying this discrepancy.
The licensee initiated an incident investigation and subsequently discovered that qualification and
l documentation of tie-back support 2478452-H0255 modeled in Stress Problem l
No. NI-274-IR does not exist.
This tie-back support was attached to a l
larger section of Class I RHR piping and the above stress problem did not
adequately address piping loads from the seismic class II/I side of the tie-back support.
This analysis was apparently one of a small number of analysis which had not been reperformed when Bechtel Corp. took over l
responsibility for the seismic analysis activities.
Corrective actions performed by the licensee included removal of the tie-back support, installation of one new support, and modification of three existing
,
i supports.
The licensee informed the inspector that the apparent cause of this
,
failure was limitations placed on the review criteria for acceptance of analysis performed by other than TVA personnel.
The inspector reviewed t
the licensee's completed investigation report which was issued on February 11, 1991. The inspector determined that the investigation included identification and review of 14 other calculations created by SWEC and accepted by Bechtel in the turnover process to assure that other similar situations did not exist.
The licensee detennined that the inadequate seismic analysis was an isolated case.
No deficiencies associated with the conditions found in stress problem N1-274-1R were identified in that l
review. The inspector agrees with the licensee's determination that this l
is an isolated case and that the completed corrective actions were adequate.
10. System Pre-Operability Checklist (71707)
Efforts to review the licensee's program and activities to upgrade and modify plant equipment and documentation was continued by the inspectors for the restart of Unit 2.
Systems essential for fuel load have been completed and evaluated with only a few documented deficiencies existing.
A summary of those reviewed during this reporting period are as follows:
a.
System 31, HVAC Control Bay The inspector continued to observe and review the licensee's activities associated with the Control Bay HVAC system.
The procedure TI-35, Air Flow Palance, has been completed.
The inspector was informed that the all flow results of the test were acceptable by NE, with the exception of the Relay Room.
The licensee indicated that a CAQR would be generated documenting the inadequate flow and the CAQR would be dispositioned as Install Additional Cooling. The l
l l
l
.
.
inspector attended a licensee meeting with the Site Director at which the System 31 Relay Room Cooling was discussed.
Several options were presented and the Site Director indicated that the option selected would be to install AHUs in the relay room, use chill water from Unit 3, and tie in a dedicated power supply.
The licensee also indicated that these modifications could be completed within the
'
next four weeks.
The inspector will continue t; follow the licensee's activities in this area.
b.
Sampling and Water Quality System (System 43)
l l
This system includes various equipment located in the Turbine l
Building, Radwaste Building, and Reactor Building that is used by l
licensee personnel to perform either continuous or grab sampling of fluid systems and the Drywell attrosphere.
l The inspector accompanied licensee persoanel during the preliminary
!
system walkdown conducted on January 28, 1991.
During the walkdown l
several minor material deficiencies were identified as follows:
l The system contained a few missing valve ID labels.
Radwaste Floor Drain Filter Outlet, 0-CE-43-25F, had a bent stem and missing handwheel.
Several sample sinks had missing sample valve handwheel nuts.
Although the PASS System is included within the scope of System 43, much of the installation work for the PASS was still ongoing at the time of the preliminary walkdown.
!
Each of the above discrepancies was docuniented by the system engineer on a work request, labeling request form or other suitable form.
The system engineer stated that PASS hardware installation will be field complete prior to restart.
Functional testing will also be complete except for a limited amount of testing required to be performed during the power ascension program, System 65, Standby Gas Treatment System c.
The inspector continued to monitor the licensee's activities involving System 65, SBGT.
The inspector noted in the FSAR the following statements under section 5.3.3.7, Standby Gas Treatment System.
The SBGT design flow for the TS and Chapter 14 analysis is
,
i 18,000 cfm. TS 4.7.B.2.a requires SBGT to operate within +/- 10 percent of the design flow; therefore, the flow from two trains
.
-
--.
-
-
_ = ~ -.
.-
. -- -
-
.
.
.
!
of SBGT must always be equal to or greater than 16,200 cfm (90
!
percent of design flow).
This value is the minimum acceptable i
capacity and is divided into the following parts:
Allowable Surveillance Inleakage 12,000 cfm
-
Design Basis Earthquake Margin
+4,200 cfm
-
Minimum Acceptable Capacity 16,200 cfm
!
Design Flow 18,000 cfm Allowable surveillance inleakage occurs as a result of secondary containment maintenance and/or modifications, siding and roof
l leakage, HVAC damper leakage, airlock door leakage, penetration leakage, and other similar leakages.
The limiting value for the l
allowable surveillance inleakage is specified by TS 4.7.C.1.a.
The DBE margin is the flow required to compensate for the increase in leakage following an earthquake.
The DBE margin is j
based on a calculated value of the increased leakage through the l
secondary containment boundary due to a DBE.
The minimum l
acceptable capacity is the sum of the allowable surveillance
'
inleakage and the design basis earthquake margin.
The minimum
{
acceptable flow rate of two SBGT trains is equal to the flow rate defined by the minimum acceptable capacity.
,
!
During recent testing of the SBGT, as documented in IR 90-02, the I
'
inspector noted that the back draft dampers in all three trains appeared to leak excessively.
!
10 CFR 50 Appendix A, General Design Criteria for Nuclear Power Plants, defines Single Failure. Criterion 41, Containment Atmosphere l
Cleanup, assumes a single failure with the _ three trains of standby l
gas called on to operate.
With one of the train fans failing to start and with leakage though its respective back draft damper more l
than 1800 cfm, the minimum acceptable capacity of 16,200 cfm would
,
l not be met.
This item is identified as an IFI 259, 260, 296/91-02-03, Possible Single Failure Criteria Identified With SBGT.
d.
Reactor Core Isolation Cooling (System 71)
l
The inspector accompanied licensee personnel during the preliminary l
system walkdown conducted on January 21-22, 1991.
During the I
walkdown the following minor material deficiencies were identified:
The inspector noted two conditional release tags installed on RCIC components (Vacuum tank and Turbine Trip and Throttle Valve). The tags referenced CAQR BFP 871089 and were associated with motors not meeting design requirements for ampere ratings.
After discussing this observation with site QA personnel the inspector was informed that the tags were part of Conditional Release 89-0003 which uss not applicable to the referenced CAQR.
,
_
_
_ _ _
.. -_.
.. _.
_
.
.
,
.
'
.
The conditional release had been released on June 15, 1990 with the tags apparently missed.
The licensee further stated that the tags do not represent a current concern and would be removed.
Various gauges located on the RCIC turbine and lube oil system were inoperable with broken faces and/or missing pointers.
'
The licensee representative stated that the new gauges were being procured and would be installed prior to restart.
The inspector followed the licensee's activities associated with testing of the RCIC turbine during the week of February 11-15, 1991.
The licensee conducted a special operational test of the RCIC turbine on low pressure steam supplied by the Auxiliary Steam System.
This test was performed by operating the turbine uncoupled from the pump using low pressure steam supplied via a special spool piece that crosstied the Auxiliary Steam System and the RCIC turbine steam supply piping.
The inspector did not identify any discrepancies associated with the preparations for this special test, however one problem with the turbine oil system was identified during the test.
A local temperature
'
indicator installed in an oil line caused a restriction in the oil flow during turbine operation.
This resulted in licensee personnel suspending the testing until a design change could be issued to resolve this problem.
The inspectors will follow the
licensee's activities in this area during the next reporting period.
High Pressure Coolant Injection (System 73)
e.
The inspector accompanied licensee personnel during the preliminary system walkdown conducted on January 21-22, 1991.
During the walkdown the following minor material deficiencies were identified-During the walkdown the inspector noted a clearance tag attached to a relatively long section of one inch piping.
This section of piping did not contain a valve or other component that could be operated.
After discussing this observation with operations i
personnel the inspector was informed that the clearance tag was
'
originally for manual valve 2-HCV-73-617 associated with Hold Order 2-89-987-67 That hold order had been released during 1990 and the tag had apparently missed due to being in the wrong location.
The licensee removed the clearance tag.
The HPCI Steam Line Trap Bypass Valve, 2-FCV-73-5, had recently had a hanger removed.
The anchor bolt holes had been regrouted and the job appeared to be complete.
The valve did not appear to be adequately supported.
The System Engineer informed the inspector that he would pursue this issue with NE to resolve the inspector's concern about adequate supporting of the valv._
_
_
.
_.
.
.
l
.
.
l
i
f.
Buildings and Structures (System 303)
i
!
The inspector accompanied licensee personnel during portions of the preliminary system walkdown conducted on January 14-18, 1991. During the walkdown no significant deficiencies were identified, i
g.
Flood Protection (System 327)
This system consists of various design features intended to mitigate the effects of flooding in the Reactor Building, Diesel Generator Buildings, Intake Pumping Station, Radwaste Building, Offgas Building, and RHRSW Intake Building due to natural phenomena, i.e.
sources external to the buildings.
l
~
The inspector accompanied licensee personnel during the final system walkdown conducted on January 14-18, 1991.
During the walkdown the following minor material deficiencies were identified:
Several penetrations located in the Intake Pumping Station
,
l require repairs to prevent inleakage of groundwater.
Some of these have apparently been long tenn problems as evidenced by
,
l
!
the presence of a large buildup of mineral deposits below the l
l
'
The exterior doors to the Unit 1/2 Diesel Generator Building are designed as flood doors.
Each of these doors has a security
!
card reader.
The electrical conduit penetrations associated j
'
with each card reader did not appear to be adequately sealed.
The system checklist was completed on January 18, 1991.
The inspector reviewed the SP0C package with the system engineer on i
January 24, 1991.
The SP0C package did not include any deferrals or exceptions.
l No violations or deviations were identified during the review of System Pre-Operability Checklists.
i l
!
11. Local Leak Rate Testing (61720)
An inspector continued to follow the progress of the licensee's LLRT program.
As of February 15,1991, 63 of 77 identified individual LLRT tests required to be performed prior to performance of the ILRT had been completed.
The ILRT is presently scheduled to be performed on March 15,
'
1991.
An inspector monitored portions of LLRT testing associated with four of
'
the eight MSIVs performed on January 31, 1991. This testing was performed
.
in accordance with 2-SI-4.7.A.2.1-3/lc,
"C" Main Steam Line LLRT, and
'
2-SI-4.7.A.2.1-3/1d,
"D" Main Steam I ine LLRT.
This testing is intended to satisfy ASME Section XI testing for leak tightness in accordance with T.S. 4.6.G and T.S. Definition 1.0.MM along with verification of primary containment operability per T.S. 4.7.A.2.1.
The stated acceptance criteria shown in the sis is 11.5 SCFM while maintaining a minimum
.
.
-
-
._,
.
-
- - - -
-
---
- - -
.-
.
.
-
pressure of 26 psi.
The two sis observed by the inspector passed the above acceptance criteria with both MSLs having less than 1.0 SCFM.
The inboard MSIVs in both MSLs had been recently disassembled for performing maintenance on the valve seating surfaces.
l 12. Reportable Occurrences (92700)
l I
The LERs listed below were reviewed to determine if the information i
provided met NRC requirements.
The determinations included the verifica-
,
tion of compliance with TS and regulatory requirements, and addressed the l
adequacy of the event description, the corrective actions taken, the existence of potential generic problems, compliance with reporting requirements, and the relative safety significance of each event.
Additional in-plant reviews and discussions with plant personnel, as appropriate, were conducted.
i a.
(CLOSED) LER 259/85-52, Status of Fuse Identification Program.
!
This item was initiated by the licensee in response to IR 83-27.
TVA committed to establish a fuse identification program for all
!
plant equipment, 600 volt fuses or less.
The fuse labeling program at Browns Ferry identifies fuses with an adhesive label located near
'
each fuse.
This label contains a unique identifier, indicating the unit, the function code, the number of fuses in the set, the TVA system number, the load, and the manufacturer model number.
During the SP0C process for System 57, Auxiliary Electrical, the inspector noted and reviewed numerous adhesive labels near fuses when
various electrical panels were opened for inspection. Although this LER is considered closed based on the licensee's activities to date, i
the fuse program at BFN is also a Volume 3 NPP item. The closure of this LER does not close the NPP item as TVA must notify the NRC of completion of the program.
b.
(CLOSED)LER 296/85-17, Failed Supports on the Residual Heat Removal System - Unit 2 Impact.
This item was initially identified in Unit 3 on July 16, 1985.
Loop 1 of the RHR system was declared inoperable after a broken hanger and
>
i
-
a damaged snubber on the torus return line were discovered by personnel working in the vicinity.
Prior to discovery of the broken hanger, Loop I of the RHR system had been in shutdown cooling.
The
,
i hanger, designated H3, and the snubber, designated R41, provide vertical support for the 18-inch torus return line.
These devices
!
had been inspected in June of 1985 as part of the torus attached
'
piping supports reinspection program.
At the time of this reinspec-tion, no problems with these devices were reported.
A small broken hanger was also found on July 12, 1985, on the one-inch vent line that comes off 3-HCV 74-55.
The small hanger attached to the one-inch vent line to 3-HCV 74-55 was modified and returned to
service on August 2, 1985.
The support for the 18-i.,ch test return line was repaired and returned to service on July 27, 198, -.- - - - - -.
.. -. - - -
-.~
- -. -..
- -.. _
--
..
.
s
.
.
I,
This item was reviewed for impact on Unit 2 RHR and was documented in
,
j 1R 88-21.
The report indicated that a modification to RHR had been i
completed.. The items were not closed in IR 88-21 due to additional i
information being required involving vibration testing,
j i
'
The' licensee performed PMT-39, for ECN L2107, Replacement of RHR
'
Valve with V Notch Disc. The inspector reviewed PMT-139 and noted.no deficiencies.
c.
C D LER 259/86-04, Residual Heat Removal System Heat Exchanger On November 28, 1985, during routine sampling of the Unit 1 RHR System water, on the licensee noticed abnormal levels of conductivity, chloride concentrations, nitrite and sulfate.
,
Following an investigation, the licensee concluded that the existing Perfex Corporation gasket material located on the RHR heat exchangers was the major contributor to the identified problem.
The inspector reviewed the LER and the information provided in the closure package.
The licensee has written DCR 2863 to replace the existing gaskets, which are soft iron, double-jacketed asbestos, with i
new gaskets.
The new gaskets are silver plated solid stainless steel ring type.
Documentation 11dicates that new gaskets have been installed on the 2B and 20 RHR heat exchangers.
Per ' licensee memorandum R53-871013-855, dated October 13, 1985, the new ~ gaskets will be evaluated under operational conditions by the Mechanical Technical Section and Plant Operations to determine suitability.
,
d.
(CLOSED) LER 259/86-24, Loss of Secondary Containment Caused by Design Oversight.
On August 22, 1986, the licensee determined that various non-safety related piping systems penetrating the reactor building / turbine building wall were not supported to seismic Class I criteria.
The systems involved were Auxiliary Boiler (System 12), RCW (System 24),
and Fire Protection (System 26).
Because of this, the licensee declared secondary contain. Tent inoperable.
The cause was attributed to inadequate design oversight, which allowed drawings to be issued without requirements to seismically qualify secondary containment penetrations as described in the FSAR.
This LER was submitted on September 19, 1986.
The LER stated that long term corrective action proposals were under evaluation and an updated report would be submitted later.
Revision 1 to the LER was
,
submitted on February 4, 1987, to provide alternatives for permanent resolution of the problem.
Revision 2 was submitted on April 22, 1988, to provide the licensee's final actions to resolve the problem.
The inspector reviewed the three revisions of the LER and determined that they satisfied the reporting requirements of 10 CFR 50.73. A program for resolving FSAR discrepancies regarding seismic qualification of secondary containment penetrations was submitted to
.
.
.
-
l
-
the NRC on March 16, 1988.
NRC safety evaluation was issued on April 11,1988.
The resolution required that BFN demonstrate prior to Unit 2 restart that the plant would be capable of maintaining a negative pressure of 1/4-inch of water in secondary containment following a design basis earthquake.
By letter, dated October 6,1989, the licensee informed the staff that design, testing and modifications required to resolve the
!
discrepancy had been completed.
The inspector reviewed various ECN and DCN's closure packages and found the results to be acceptable. -
!
This item is closed based on the corrective actions listed above.
>
e.
(CLOSED) LER 260/88-09, Unplanned ESF Actuation Due to Loss of RPS Power Caused by Lack of PM in 480 Volt Switchgear Breakers.
This LER was associated with three separate but related events on Unit 2 which involved the unplanned initiations of a RPS half scram, partial primary containment isolation, secondary containment isolation, and actuation of the CREV system and SBGT system. The events occurred on September 10,1988, at 1340 hours0.0155 days <br />0.372 hours <br />0.00222 weeks <br />5.0987e-4 months <br />, October 2, l
1988, at 0420 hours0.00486 days <br />0.117 hours <br />6.944444e-4 weeks <br />1.5981e-4 months <br />, and again on October 2,1988, at 0442 hours0.00512 days <br />0.123 hours <br />7.308201e-4 weeks <br />1.68181e-4 months <br /> during switching operations when the normal supply breaker on a 480 volt board failed to close because of the dirty condition of the
!
sliding secondary disconnects in the breaker control logic.
This deenergized the 480 volt board and the RPS bus which it supplies.
Loss of power to a RPS bus causes the ESF actuation listed above.
'
The licensee determined that the root cause of the breaker failures
!
was the lack of preventive maintenance on the breaker and board compartment.
PM on the breakers had not been done during the last two years because the Units have been shutdown for a long time and the PM frequency on these breakers is tied to the refueling outages.
The licensee instituted a comprehensive FM program for circuit breakers.
The observations and reviews of this program were documented in previous inspections, f.
(CLOSED) LER 259/88-36, Unanalyzed Electrical Loading on Safety Related Electrical System Due to an Inadequate Design and Review Program.
This LER was associated with the licensee's evaluation of restart tests performed in 1988 that identified two possible unanalyzed conditions concerning loading and sequencing of loads on the safety-related electrical distribution system.
The first condition involved
!
possible overloading of the DGs supplying the 4160V shutdown boards
,
during accident conditions with loss of offsite power if a spurious accident signal were concurrently generated from another unit.
The second condition involved possible violation of 10 CFR 50, Appendix X analysis time sequence assumptions on availability of power to the 2D and 2E 480V RMOV boards which supply power to the RHR, LPCI valve motors.
This LER also involved the licensee's initiation of CAQRs BFP 880406, and BFP 88053.
- -.
..
-.. - - - -. ~.
.
.
._-.--.- - - -- --.
_ -
.
.
.
l
.
.
The licensee determined that the root cause of these conditions was an inadequate design control and review program at the time of the original design and during LPCI modifications made in 1977.
The original design of the Standby AC Auxiliary Power System did not document or failed to consider the transit.nt load increase encountered when starting motors on a previously loaded board, as would be the case of a common accident signal. Also, the 10 CFR 50, l
Appendix K analysis failed to properly include all time delays into l
the analysis assumptions of power availability.
CAQR BFP 880406, dealt with the overloading of the DGs by a spurious actuation of
accident signals from the non-operating Units during a LOCA condition in Unit 2.
The licensee issued DCN 2735A.
!
This DCN consisted of disabling the automatic actuation signals from
!
Unit 1 and 3 initiated by a single credible spurious accident signal, which would adversely influence Unit 2 systems performance.
The Units 1 & 3 initiation signals as originally designed started the Units 1, 2, and 3 DGs, the Units CS pump and RHR pumps. The start-up of Units 1 and 3 ECCS pumps could unnecessarily subject the Unit 2 DGs, in the event of Unit 2 LOCA, to large loading conditions which could reduce their reliability.
i
The lifting of wires in panels 9-32 and 9-33 of Units 1 and 3
isolated any spurious accident scenarios from influencing Unit 2 operation and safe shutdown equipment performance.
The effects of
the change prevented automatic initiation of the Unit 1 pumps
!
blocking and tripping the Unit 2 CS and RHR pumps on a Unit 1 spurious accident signal.
The change did not affect the response of Unit 2 ECCS equipment and 480V load shedding buses to a Unit 2 real accident signal.
The inspector reviewed the DCN and noted that the change was made and tested by PMT-BF-82.001.
No deficiencies or exceptions were observed.
CAQR BFP 880537 dealt with effects of extending the DG ready-to-load times and the transfer times of the 480V RMOV boards 2D and 2E. The licensee contracted with a vendor to perform and evaluation of the above effects.
The inspector reviewed the evaluation and noted that
'
the limiting events were:
recirculation discharge line break with LPCI injection valve failure.
This event results in the highest PCT for BFNP
'
l recirculation discharge line break with diesel generator
failure.
l
'
recirculation suction line break with a false LOCA signal.
The evaluation compared the sequence of events and the time of ECCS
,
injection for these events, it was concluded that the maximum
'
extended ready-to-load time for the diesel generator was 21 seconds l
_
.
.
.
and the maximum transfer time was 22 seconds.
These extended times l
would not change the limiting PCT results documented in the Safety Evaluation in Support of Extended Valve Stroke Times for Brown Ferry Nuclear Plant Units 1, 2, and 3, General Electric Company, NEDC-31580P, dated May 1988.
g.
(CLOSED) LER 259/88-38, Failure to Identify and Maintain Minimum Set of Electrical Calculations by Design Results in Conditions That Could Degrade Plant Perfonnance.
This item is associated with reviews performed by the licensee.
On October 17, 1988, a review of open CAQRs was initiated using a more
,
'
conservative reporting philosophy.
This review was designed to
ensure that all conditions as defined by 10 CFR 50.72 and 50.73 had
!
been properly reported.
This review discovered a condition that I
'
affected all three units.
This condition was discovered with all three units shutdown and defueled.
During the review of plant
'
electrical design for technical adequacy and compliance with regulatory requirements, the lack of a minimum set of design
!
a calculations was discovered.
Discovery of this condition prompted j
the perfortnance of a design baseline calculation.
The calculation
!
identified potential problems in areas such as:
some 480V motors did i
not have adequate starting voltage when the 480V distribution board i
,
had a minimum voltage of 432V; some control circuits operating
,
t voltage was less than minimum when the distribution bus was at minimum voltage; the minimum operating voltage of some components in the instrument and control bus had not been met; maximum voltage
.
rating of DC components may have been exceeded when the associated
{
,
,
battery was on equalizing charge; overcurrent protection for Drywell
'
blowers 2A-1 and 2A-2 was not adequate; operating voltage for some DC
1 motors may have been below minimum voltage requirements; and maximum
,
I voltage rating of some DC motors may have been exceeded.
The licensee determined that this condition was caused by a failure
!
of design to identify and maintain a minimum set of electrical
calculations.
The lack of clearly defined design requirements and criteria for electrical systems at the time of the plant design was a l
contributing factor in the design error.
The inspector reviewed, observed, and documented in previous irs the licensee's activities in correcting electrical design issues.
These activities included issuing and installing ECN/DCNs such as P7161 which installed regulating transformers for all three units I&C buses; change transformer tap settings to adjust 4160/480V swithchgear; and replacing undersized electrical cable.
h.
(CLOSED) LER 260/89-02, Rev. 1, ADS Accumulator Pressure Switch Supports Not Seismically Qualifie..
-
_.
.
.
l
.
This LER was preceded by CAQR BFP 890010 which was initiated by the licensee on January 9, 1989.
The CAQR identified pressure switches
!
2-PS-32-31A,B,C,D, and F as being improperly mounted with loose and missing bolts, brackets missing, and a mounting on one housing was broken. It was further stated that the condition created the
,
l potential for failure of the pressure boundary of the switches l
following a seismic event.
t DCN H1034A, later superseded by DCN H6084, was issued to correct the deficiency by modifying the pressure switch mountings to meet seismic criteria, replace the existing Meletrol Pressure Switches with Static-0-Ring Pressure Switches, and to add a shutoff valve and test tee to the pressure switch configuration.
This DCN was implemented on Unit 2 per WPs 2370-89 and 2455-89 and was documented as completed on September 21, 1989 and September 29, 1989 respectively.
i NUREG-1232, Vol. 3, Supp. 2, SER, dated January,1991 was issued by
'
the NRC Staff which closed the issue for restart.
i.
(CLOSED FOR UNITS 1 AND 2 ONLY) LER 259/89-11, Design Error in EECW Anti-Siphon Check Valves.
On May 3, 1989, the licensee determined that the EECW anti-siphon check valves had the potential for drawing uncontrolled and unfiltered air from secondary containment and releasing it to the environment through the EECW discharge line which is a nonelevated
,
!
path.
The cause of this problem was an error in the original design of the EECW system which did not consider the effects on secondary containment integrity.
This LER was submitted on June 6, 1989. The inspector verified that the LER met the reporting recuirements of 10 CFR 50.73.
The
!
inspector noted that the LER was submitted 4 days past the 30 day requirement.
The timeliness of LERs has been addressed in previous
!
inspection reports.
As a corrective action the licensee committed to a review of design criteria documents for systems penetrating secondary containment to verify that secondary containment interfaces are adequately identified.
The licensee also connitted to perform necessary design changes and modifications resulting from the reviews.
DNE reviewed the system design criteria and concluded that secondary containment isolation requirements were addressed in each one.
For systems not having a specific design criteria, design documents contain the detailed requirements for secondary containment design.
The specific action taken for the anti-siphon check valves was to reroute the vent lines to draw air from outside of secondary containment.
The modifications were performed under DCNs W7300A,
'
W7301A, and W7302A.
The work was completed for all four vent lines in Units 1 and 2.
Only one of the two Unit 3 check valve vent lines
{
__.
_
_
--
_
. _ _.
._
._
l
.
.
'
i had been modified.
The remaining vent line was isolated and CAQR BFP880735 was issued to track the completion of the rodification.
Special Requirement / Compensatory Measure 89-67-3-015 was written to track the CAQR for operations and to ensure that it is resolved prior to bolting on the Unit 3 reactor vessel head.
The inspector reviewed the closed DCNs and walked down the modifica-tions in the plant.
The inspector also reviewed the Special Requirement / Compensatory Measures book to ensure that the CAQR for Unit 3 was still being tracked.
No deficiencies were identified.
This item is closed for Units 1 and 2 only.
This item will remain open for Unit 3 until the modification of the remaining vent line is completed.
j.
(CLOSED) LER 259/89-14, Unplanned DG Starts, an ESF Actuation Caused by Personnel Error and Procedural Inadequacy.
These items were identified when on June 6,1989, DGs 18 and 10 auto-started during the performance of 0-SI-4.9. A.3.a.
The DGs started because a utility craftsman inadvertently allowed a wire he was attempting to reland on terminal 13 of the CAS A-2, CAS A-2, relay to come into contact with terminal 11, which was energized.
This energized relay CAS A-1, which in turn energized CAS A-5 and CAS A-6 relays resulting in the auto-start of the DGs.
The DGs were immediately shutdown.and placed in standby readiness.
!
The licensee detennined that this event was caused by personnel Contributing factors to the event were a congested work area, error.
poor lighting, and an inadequate ptocedure.
The inspector reviewed the licensee's corrective action which included procedure changes allowing adjacent terminals to be covered with insulating electrical tape'when lifting and landing leads. The inspector noted that the license also issued and installed a modification which affixed pemanent Banana Jacks in relay panels to prevent inadvertent shorting of electrical circuits.
k.
(CLOSED) LER 259/89-18, Low Flow Through Area Coolers Due to Inadequate Surveillance.
Area coolers for the RHR and CS pumps may have operated with degraded flow rates during previous plant operations.
The air flows from the room coolers were less than design flows.
These were corrected by motor pulley sheave adjustment, directional vane repair, and the
.
cleaning of cooling coils.
The root cause of this condition was
!
determined to be a lack of a procedure or program to periodically l
measure flow rates through the room coolers. The inspector reviewed i
the licensee's closure package for this item. A TI was developed for i
measurement of air flows.
TI-134, CS and RHR Room Cooler Air Flow Verifications, requires the instruction to be perfomed once every
l
i
_
... _.__ _ _ _..
- _. _ -. - -.. - _ _ _ _ _ _.
_ _ _ _ _ _- _
,
.
.
d
'
'
.
l'
six months.
MMI-178 was also revised to include a statement that i
following any replacement or adjustments on variable pitch sheaves, air flows should be measured to verify design flows. are met.
The
,
'
inspector concluded that performance of the TI and MMI should j
preclude undetected degradation of the air flows.
i i
1.
(Closed) LER 259/89-20, Core Spray System Minimum Flow Bypass Valves l
Not Qualified Due. to Design Error in Original Analysis for Torus l
Hydrodynamic Motions
During engineering analysis licensee personnel identified that the
l'
valve yokes for the CS system minimum flow bypass valves for all three units could exceed the allowable yield stress when subjected to loadings from torus hydrodynamic motions.
Failure of these valves could prevent the CS systems from performing their intended function.
,
l
)
The licensee performed additional review and analysis associated with l
the above problem determination.
The root cause was determined to be
'
a design error in the original analysis used to qualify the valves, i
Field inspection showed that the valve yoke dimensions for
2-FCV-75-37 were smaller than those used in the 1984 analysis.
The
}
licensee further evaluated the problem and determined that the
!
condition also applied to both loops of CS on each of-the three
!
' units.
Additionally 10 other safety related valves made by Velan, Inc. that could have a similar problem were identified on Unit 2.
,
.
.
The inspector reviewed selected documentation provided by the
!
licensee and determined that six of the above ten additional Unit 2
!
valves had yokes that were substantially stronger than the subject CS
'.
valves.
The inspector was informed by the licensee that the remaining four valves would require modification of related supports.
}
The inspector reviewed portions of Essential Calculation, l
CD-Q0075-894658, which provides the licensee's justification for
!
qualification of 2-FCV-75-9 and 2-FCV-75-37 by reinforcing the yoke.
!
- Additionally the inspector examined documentation to verify that the
following modifications were field complete:
.
DCN W8022A, which modified yoke on 2-FCV-75-9.
,
t DCN W8023A, which modified yoke on 2-FCV-75-37.
.
DCN W7636A, which modified supports for 2-FCV-77-2A, 2-FCV-77-28, 2-
!
FCV-77-15A, and 2-FCV-77-15B.
'
In addition, the inspector verified that the licensee had committed
to complete these corrective actions for similar valves on the other
}
two units prior to restart of those units.
j Based on the above review the inspector determined that the licensee
has taken adequate corrective action for this issue.
i
!
!
,
s
,. -
-,,-y
---g
p
,
,,,, -
T
-
.
-
_. _ _ _ _ _ _ _.. - _.. _. _.. -
.
.
.
l
.
!
- m.
(CLOSED)LER 296/90-05, Reactor Building Vent Exhaust Monitor Removed t
j From Service Causing A TS Compensatory Sample To Be_ Isolated, e
This LER was submitted on January 28, 1991.
An inspector reviewed
[
the LER and verified that it met the requirements of 10 CFR 50.73.
l The event involved is discussed in detail in paragraph 4 of this
.
report and a NCY is being issued.
An inspector verified that the
!
corrective actions had been implemented or were in process.
j 13. Action on Previous Inspection Findings
!
a.
(CLOSED) IFI 259, 260, 296/84-14-01, Regulating Transformers on i
Instrument Bus B.
,
A previous electrical maintenance inspection noted that the licensee
identified a problem with the regulating transformer for Instrument
Bus B.
The problem was traced to a phase load unbalance that i
exceeded 10%.
This exceeded the design of the transformer which (
allows for a maximum of 10% unbalance.
The licensee used a temporary f
alteration and bypassed the regulating transformers.
During the i
extended outage the licensee issued and installed ECN/DCN 7161 which replaced all six Instrumentation Buses' regulating transformers.
b.
(CLOSED) IFI 259, 260, 296/86-05-07, Reactor Building Radiation
Isolation Monitor.
This item was reviewed in IR 89-19 and IR 90-33 and the only open was clarification of the notes in TS Table 4.2.A and 3.2.A.
Note 11 to Table 3.2.A applied to all the instruments in the table and allowed up to four hours for the instruments to be inoperable for surveil-lance testing.
Table 4.2.A, Note 22, which applied for the specific radiation monitor allowed -24 hours for functional testing and calibration.
The inspector reviewed the licensees's closure package-for this item.
The licensee submitted a TS change number 228 on March 3,1988 to correct this problem along with other clarifica-tions.
After further discussions, it was determined that Note 22 provided the allowed time of the instrument. The licensee agreed to this TS revision in a letter dated January 22, 1989.
The concern would be resolved a procedure revision.
This item was reviewed and resolved by a procedure revision.
c.
(CLOSED for Unit 2 only) IFI 260/86-28-05, Addition of EECW/RBCCW Cross-Connect Valves to the ISI program.
During the performance of a surveillance, difficulty was experienced in opening the EECW/RBCCW cross-connect valves.
These valves were not part of the ASME Section XI Pump and Valve Test Program and had not been tested before.
The EECW/RBCCW cross-connect valves are described in the FSAR, Section 10.10.3.
These valves are hydraulically operated back pressure valves using EECW header pressure and water as the hydraulic medium.
This arrangement prevented the repeatability of stroke time testing required by the
l
...
--
.
-
_=
.
. - _ -
--- - -.
-
---
. -
.
.
.
-
,
ASME Section XI Pump and Valve Program.
ECN P-7194 changes these
valves to air operated.
These valves were in the revised program j
'
submitted by TVA in March 1988.
In May 1989, the NRC issued a SER
'
approving BFN revised program.
The licensee revised 2-SI-3.2.10, Verification of Remote Position Indication for ASME Section XI Valve and 2-SI-3.2.10.C, Verification of Remote Position Indicator for
,
!
Emergency Equipment Cooling Water Valves, to include the EECW/RBCCW l
cross connect valves.
The Unit 2 valves and procedures are complete and Units 1 and 3 are scheduled for work and implementation with the recovery efforts for those units.
The inspection has reviewed all of the above documentation and found it acceptable.
The FSAR still reflects these valves as hydraulically operated and the next update should reflect the change to air operated.
d.
(CLOSED) IFI 259, 260, 296/90-27-05, Resolution of Undocumented and Uninspectable Slices in Safety Related Panels Identified During SP0C.
!
These items were identified when splices that were covered with electrical tape were observed in vendor supplied equipment.
The licensee contacted the vendor for the specific equipment.
The vendor responded by letter that the practice of covering internal electrical splices with electrical tape was discontinued approximately 12 years ago.
The licensee stated that this specific equipment was qualified as a unit, therefore it was still capable of performing its safety function.
The inspector reviewed the vendor's letter.
Additional walkdowns of safety related electrical panels by the inspector did t
!
not indicate the existence of other splices of this type.
!
e.
(0 pen) IFI 260/87-09-05, Final Resolution of Unverified Portions of CCD Drawings.
In IR 87-09, an inspector identified that operational boundaries were not clearly defined on the CCDs ar.d numerous CCDs included portions l
which were not verified in the plant.
The inspector also noted the there was no apparent plan for removing the unverified portions from the drawings.
Specific concerns were identified on the CCDs for System 23, RHRSW, and System 86, Diesel Starting Air.
In IR 88-33, an inspector reviewed this item further.
At that time the inspector concluded that the program and schedule for completion of CCDs was acceptable for fuel load.
However, the inspector noted that further review was required for Unit 2 restart.
The inspector
stated that NRC review of audit reports, CAQRs, and schedules for CCD l
implementation would be required to close this item.
During this reporting period, an inspector reviewed the licensee's closure package for this item and held discussions with licensee personnel on the status and scheduling of CCD completion.
r
!
,
_ _ _
__m
__
m. _. _ _ _.. _ _ _ _ _ _ _
- - _ _ _ _ _
-
.
.
I
,
.
d
l
!
As part of the DBVP, the licensee issues CCDs to document the i
evaluated plant configuration.
The pre-start phase of the program i
only includes evaluation of portions of systems within the safe shutdown boundaries.
The post-restart phase of the DBVP will complete the CCD evaluation. Therefore, CCDs will include unverified portions until final completion of the DBVP.
i i
In response to the original inspector's concerns, the licensee revised BFEP PI 87-27, Origination of CCDs, to provide for the
'
definition of system boundaries and removal of unverified porticas of the CCDs required for Unit 2 restart. The licensee also revised BFEP
!
PI 87-48, Revision and Controlling CCDs, to ensure that operational boundaries are defined and to remove unverified portions from the j
drawings.
i'
The-inspector reviewed the CCDs and design baseline documentation for i
System 23 and System 86.
The System 86 SP0C was completed on September 7, 1990, and the System 23 SP0C was completed on
'
j December 5, 1990.
The SP0C process included a complete review of i
DBVP items to ensure they are completed.. No deficiencies were
{
identified.
The inspector discussed the schedule for completion of i
CCDs with cognizant licensee personnel.
The inspector noted that the licensee had 372 CCDs remaining to be created on January 14, 1991.
The licensee had scheduled the completion of the CCDs by March 1,
!
1991.
-This schedule can be impacted by new work activities and i-changes in the schedule for Unit 2 restart.
!_
The inspector concluded that this item was resolved for fuel load; 1:
however, it will remain open pending the NRC review of CAQRs and j
audits on CCDs in accordance with IR 88-33.
4-l f.
(CLOSED) IFI 259, 260, 296/90-18-01, Interaction of ATUs and Seismic
'
Gap.
i
This item was identified on June 1,1990 when an unplanned ESF i
actuation occurred due to spurious operations of circuit cards in the i
ECCS ATU located in the Unit 2 Auxiliary Instrument Room.
During a i
test of the fire protection system in the Cable Spreader Room located
above the Auxiliary Instrument Room, water ran through a seismic gap j
and onto the top of the ATU cabinets.
'
.
f The licensee issued DCN W14093A which provided a water tight seal for i
the building expansion joints on elevation 606.0 floor slab in the j
control bay.
The expansion joints were located in the two Cable
,
Spreading Rooms between Units 1 & 2 and 2 & 3.
These water tight
!
i i
seals were required to prevent any water in the Cable Spreading Room, due to fire protection sprinkler or hose stream discharge, from i
leaking into the Unit 2 Auxiliary Instrument Room and Comunication i
Room below the slab.
This DCN resulted from a recomendation made in
]
the incident investigation of inadvertent water discharge into the i
Cable Spreading Room.
i
,
.
-.
- --
. -.
.
.
-.
.
--
.
-. -.
.
.
.
.
..
-
-
.
.
- -
..
.-
.
.
,
l
-
This DCN required a Belzona Lag Seal to be applied ove'r the expansion joints in Cable Spreading Rooms A and B.
This was intended to completely seal the joints and prevent any water leakage into the rooms below.
The Belzona Lag seal is a molecular membrane which is completely fire resistant.
The inspector reviewed the DCN and it's associated WP 2675.90.
The WP was closed on December 3,1990.
The inspector also reviewed DCAs W14093-1, 4, 5, and 7 contained within the DCN.
The inspector observed the completed work and all installations were in accordance with the DCAs.
>
No deficiencies were identified.
g.
(CLOSED) IFI 259,260,296/90-29-03, Inadequately Identified and
- Trained Conductors in Safety Related Panels.
This open item is related to discrepancies noted during the inspector's observance of a preliminary walkdown of the DGs. During the inspection of the control cabinets, several unterminated cable conductors were noted that were not labeled spare or abandoned.
In addition, Time Delay Relay TD 0-02-211-1822A in Shutdown Board B had broken conductors.
To remove the unterminated cables in the DG electrical control cabinets, TVA issued the following W0s: (a) DG A: W0f 90-19005-00, (b) DG B: WO# 90-19005-01, (c) DG C: W0# 90-19005-02, and (d) DG D:
WO# 90-19005-03.
The broken conductors to Time Delay Relay TD 0-02-211-1822A in Shutdown Board B were repaired via W0 #90-19037-00. W0
- 90-19044-00 was performed to retrain / replace internal wire to Time Delay Relay TD 0-02-211-1812A in Shutdown Board C.
A field verification followup of the above corrective action was performed by the inspector on February 5,1991 in the company of the cognizant licensee system engineer.
Various discrepancies were still evident.
These deficiencies and the work orders initiated by the system engineer for their correction are included in the following tables:
Shutdown Board Breaker Closing Remarks Time Delay Relay Number E E E E E E ME = E E E E = 3 E E E E = 3 E E3 33 3 3 3 3 3 E = 3 E E E E E EE = E = E = 3 E E E 33 EE E EE EE E E E 2A 0-02-211-1818A Appeared OK.
2B 0-02-211-1822A WR #C038882 submitted 2/5/91 after NRC walkdown by SE to add slack to top wires on relay.
2C 0-02-211-1812A Appeared OK.
0-02-211-1816A Appeared OK.
5 EE E E 3 E E E 3 BRE =EEE E E EE E= E E33 E BEE E = 3 2 3 3E333EEE233EEEE EEBEE 33E333333333
_. _
_
_. _. _..
. _ _.
.. __ _ _. _ _ _ _ _ _. __
_
._
.
.
.
.
33 3 3333333 3 33n33 3 3333 333 3 3 3 33 3 3 333333333333333333333 333 3 3 3 333 3333333 Diesel Generator Remarks
.
!
Elec. Control Cabinet 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 = 3 3 3 3 3 3 3 3 3 3 3 3 3 3 313 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 2A Appeared OK.
2B WR #C038881 submitted 2/5/91 after NRC walkdown by SE to identify several untagged and unterminated wires entering cabinet. at top of right hand panel.
2C WR #C038880 submitted 2/5/91 after NRC walkdown by SE to identify several untagged and unterminated wires entering cabinet through conduits at top of panel.
WR #C038883 submitted 2/5/91 after NRC walkdown by SE to identify several untagged and unterminated wires.
33333333333333333333333333333333333333333333333333333333333333333333 The inspector reviewed W0s 91-26394:00, 91-26492-00, 91-26493-00 and 91-26498-00. All activities were documented as completed.
h.
(CLOSED) URI 259, 260, 296/87-09-02, Inadequate Evaluation of the Threat to the plar.t From a Barge Shipment of Explosives.
The item was reviewed in IR 89-01 and left open pending technical justification for the assumptions used in the calculation for TNT equivalents for barge explosions.
Since the last review, the licensee has performed a PRA for explosive barge shipments.
The frequency of a gasoline explosive occurring within the critical exposure distar.ce alcng the shipping channel was determined to be 7.7E-8 events per year.
The critical exposure distance along the shipping channel is defined as the zone within which the worst-case gasoline barge explosion could create incident overpressure greater than 1 psi, which is postulated to resulted in significant damage to safety-related structures.
The calculated barge explosion frequence is lower than the established acceptability criterion of IE-7 per year given in NRC Regulatory Guide 1.91.
The inspector reviewed the licensee's closure package for this item.
The PRA was performed by calculation XD-Q0000-900001, dated February 23, 1990.
The inspector discussed this item and the new methodology of using a PRA with NRR.
This method was determined to
,
.
.
be acceptable and is in accordance with Regulatory Guide 1.91.
A similar type justification was accepted for chlorine barge shipments which pass the site.
The inspector concluded this issue had been reviewed and the issue resolved.
1.
(CLOSED) URI 296/87-45-02, Layup Procedures and Implementation Inadequacies.
These items were identified when the General Operating Instruction, G01-100-13.0, Rev.
1 and implementing procedures were reviewed to determine the requirement for reporting deficiencies associated with the layup surveillance of major rotating equipment.
It was noted that motor and pump rotations were not always being performed in the time frames required by the procedure, and that surveillance of some equipment could not be performed per the procedure.
It was further noted that no procedural requirement existed such as deficiency reports, requiring disposition by upper manag,ement of surveillance that are overdue, inadequate procedures, or of deficiencies found during the performance of surveillance.
The inspector reviewed procedures involved in the layup program which included:
PMI-24.5, Plant Layup and Equipment Preservation; SDSP 6.3, Preventative Maintenance Scheduling and Tracking; EPI-0-000-TST001, EPI Bridge, Megger, and High Potential Testing of Electrical Equipment, and EMI-121, EMI for Recirculation MG Set and Pump Motor.
In addition, the inspector reviewed a licensee printcut which indicated that various electrical equipment, including the recirc MG set and pumps, the RCW pumps and CCW pumps were scheduled for PMs and had PMs performed.
These reviews indicated that the licensee has a PM progran that addresses all units and PMs are scheduled, and trended, anti tracked.
The licensee produces graphs on a monthly bases which indicates those PMs that are late.
J.
(CLOSED) URI 296/88-24-07, Secondary Containment Relief Panels This item had been opened to track the disposition of an identified deficient condition associated with a partial obstruction of a relief (blowout) panel section due to the presence of a welded plate and a pipe penecration through the panel.
The relief panels are constructed of sheetmetal and held in place with special breakable (explosive) bolts and designed to relieve pressure to the turbine building piping tunnel if a high energy line rupture in the Main Steam Vault.
The inspector reviewed selected documentation provided by the licensee to verify adequacy of licensee actions in this area. During this review the inspector determined the following:
l i
CAQR BFP880293, which identified the original problem with excessive caulking and improperly installed explosive bolts, has been closed.
Closure was based on completion of ECN P7197 for Unit 2 which was
=.
-..-
.. _.
-.- __
-
-
--
. - _ -
- -
-
l c
.
,
l perfonned as maintenance on the secondary containment pressure boundary to remove the excess caulking, clean the panel gasket
,
surfaces, reinstall the gaskets, and install the new explosive bolts i
where needed.
CAQR BFP880455 will remain open to track the issue for the relief panel obstruction.
This issue is only related to Unit 3 and does not affect Unit 2 restart.
Additionally NE has evaluated the condition and determined that the inoperable section of this single relief panel will have minimal effect on the ability of the relief panels to perform their intended function.
This determination is based on the relative small area compared to the overall relief panel surface area.
'
,
CAQRs BFP900062 and BFP900063 were written to disposition the deficiencies identified under BFP880293 for Units 1 and 3.
These CAQRs must be closed prior to restart of those units.
The inspector reviewed documentation to verify that ECN F7197 was
'
field complete, which allows the Unit 2 relief panels to be considered operable.
During a previous tour of the Unit 3 Main Steam Vault, the inspector had observed the obstructed relief panel and work associated with the removal of excessive caulking and verification of proper bolting.
Based on the above reviews the inspector determined that the licensee has taken adequate corrective action for this concern.
k.
(CLOSED) URI 90-33-02, Failure to Maintain Configuration Control on Core Spray System After System SP0C.
The inspector had identified 2 disconnected or broken wires from a limit switch on CS system valve 2-FCV-75-54 Further review of the condition revealed that the deficiency was not documented by the licensee. The CS system had undergone a SP0C and therefore all deficiencies should have been identified and corr,ected or addressed.
The condition was brought to the attention of the licensee, and as a result, the licensee completed an incident investigation, and corrected the condition.
Although the exact cause for the loose or broken electrical leads was not determined, it appeared tnat the conduit had been stepped on by an individual.
>
The licensee's actions to correct the condition and to issue warnings to it's employees on protective measures to avoid similar incidents
appeared to be acceptable.
Based on the above, this item is closed.
1.
(CLOSED) URI 260/90-37-01, Problems Encountered During SLC Surveil-lanc,-...
.
---
.. _. - - _ _ -. _ -
_
--..
,
_
l l
j
'
-
l
-
!
l This item was opened for an event in which the 2A SLC pump did not develop any flow during performance of the system SI.
This URI is discussed in paragraph 8 of this report and a NCV is being issued.
(CLOSED) V10 259,260,196/87-09-01, Failure to follow Procedure -
m.
Three Examples.
This NOV consisted of the following three examples of failure to follow existing plant procedures:
Example #1: MMI-29, RHRSW Pump Inspection and Maintenance, was not fully adhered to on 11/24/86 in that one of the RHRSW Pump
,
'
baseplate nuts was found outside of the required torquing adjustment range.
Example #2: Standard Practice BF-15.2, licensee Event Report, was not fully adhered to in that reportability based on the generic applicability of a problem associated with a CAM that failed a low flow alarm test during performance of SI-4.8.8.4-3A, was not adequately determined within the required timeframe during the processing of LRED 87-1-035, originated on 1/16/87.
Example #3: MMI-157, " Inspection, Lubrication and Replacement of the LPCI MG-Set Couplings and Bearings," was revised to clarify coupling alignment criteria which was a LER 296/86-11 commit-ment, but did not note that commitment within the procedure as required by Site Standard Practice 2.11, " Review and Approval of
,
'
Site Generated Procedures / Instructions".
A response to this violation was provi _d by TVA on May 18, 1987.
Personnel error was identified as the reason for each of the three examples in the violation.
.
For example #1, the licensee retorqued the base-plate bolts of the RHRSW pump with the noted discrepancy and all the other RHRSW pumps.
This was done under the following maintenance requests:
Pump #
MR#
Date Written A1 762101 2-18-87 A2 776387 2-03-87 A3 778534 3-10-87 B1 778726 3-09-87
B2 778532 3-10-87 B3 778535 3-10-87 C1 776441 3-06-87 C2 778533 3-10-87 j
C3 778536 3-10-87 t
778537 3-10-87
!
D2 778538 3-10-87
,
!
D3 778539 3-10-87 I
,.
_
_ _. -
..
_..._
_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
___ __
_
._ _.
.
.
.
I Since the violation, MMI-29, has been replaced by MCI-0-023-PMP002,
" Emergency Equipment Cooling Water and Residual Heat Removal Service Water Pump Disassembly, Inspection, Rework and Reassembly".
The inspector reviewed a current copy of this procedure (Revision 10) and found several steps associated with the torquing of foundation plate i
fasteners which are not clear.
This was discussed with the cognizant
!
!
system engineer who agreed to process a procedure change that would clarify the requirerrents.
i Example #2 centered around a problem associated with the 90-250 CAM that failed a low flow alann test during the performance of a surveillance test.
This particular CAM draws air samples from the Reactor Building, Turbine, and refuel zone exhaust ducts of each unit. In their response to the violation, the licensee indicated thai.
the long-tenn plans were to either order new CAMS or to modify the present CAMS for dependability.
Safety Evaluation No. SEBFDCN900030 R1 was approved _ by TVA on 3/27/90 for DCN No. W10738.
On 8/14/90, Plant Manager approval was granted for the implementation of DCN No.
W1073 for the replacement of the following continuous air monitors of the Plant Ventilation Exhaust Radiation Monitoring System (PVERMS)
and their associated recorders with microprocessor based Eberline CAMS:
MONITORS RECORDERS 0-RE-90-252 Radwaste Exhaust 0-RR-90-252 1-RE-90-250 Reactor Building Exhaust 1-RR-90-250 2-RE-90-250 Reactor Building Exhaust 2-RR-90-250 3-RE-90-250 Reactor Building Exhaust 3-RR-90-250 1-RE-90-249/251 Turbine Building Roof Vents 1-RR-90-249/250 2-RE-90-249/251 Turbine Building Roof Vents 2-RR-90-249/250 3-RE-90-249/251 Turbine Building Roof Vents 3-RR-90-249/250 The above listed CAMS have been installed and their calibration and functional testing was satisfactorily completed on 1/6/91 as certified by the 1/7/91 cognizant s l
Retest Control Form (Form SDSP-417) ystem engineer's signature on the for DCN No. W10738.
The new Eberline CAMS will monitor the various exhaust vents in the listed buildings for noble gas, iodine, and particulate activity and record this activity.
In the case of example #3 for the above referenced violation, the
l licensee's response states that the violation occurred as a result of
'
inadequate communication between the LER writer and the maintenance procedure coordinator.
Although the revision to MMI-157 was already underway at the time of the event associated with LER 296/86-11, the LER writer did not inform the MMI-157 procedure coordinator that the LER write-up would
.
reflect that the procedure revision was in process.
The procedure l
-
___
. - -
- - -
.
.
.
coordinator's unawareness of the LER reference to the active procedure revision led to the omission of the commitment reference required by SDSP 2.11, " Review and Approval of Site Generated Procedures / Instructions".
Based on a later review, the licensee considered the omitted reference as programatically valid in that in the context of SOSP
'
2.11, the reference to the procedure revision in progress was a
" statement of fact" rather than an "NRC commitment".
Nevertheless, based on these circumstances, SDSP 15.6, " Commitment / Action Item Tracking" was revised to clarify what TVA considers statements of
'1 facts and descriptions of existing programs versus NRC commitments.
The inspector determined that the concerns associated with the referenced violation have been adequately addressed.
n.
(OPEN) VIO 259, 260, 296/88-04-03, Failure to Correctly Translate Design Requirements into Drawings.
This violation was issued for failure to maintain the design control requirements of 10 CFR 50, Appendix B, Criterion III.
The licensee i
identified that the design basis for Class I buried piping at i
penetrations into secondary containment and at entry points into the
intake structure as described in the FSAR was not correctly translated into specifications and drawings.
The deficiencies were:
1) hanger M-30 on the A train RHRSW/EECW piping, which provided the only axial restraint for certain couplings, was underdesigned and could not withstand the required thrust loading; 2) the original j
l design function of Dresser couplings was defeated by the installation of tie-rod harnesses; and 3) the design evaluation of the as-found i
I condition of the couplings was erroneous.
'
The licensee responded to and admitted this violation by letter, I
dated May 23, 1988.
The response attributed the root cause to a i
failure to clearly document the design basis of flexible couplings
'
used for Class I piping.
The response further stated that this violation was an example of a previously recognized weakness which was documented in the NPP Volume 3.
An inspector reviewed the violation, the licensee's response, and the licensing closure package for the violation.
The inspector noted that problems with Class I buried piping at penetrations into secondary containment and entry points into the intake structure were
,
also addressed in CAQR BFP871126.
Review of the CAQR indicated that the issue constituted an unanalyzed condition which was reportable to i
the NRC in accordance with 10 CFR 50.73; however, the inspector noted that no LER had been issued for this item.
'
The inspector reviewed completed work packages and documentation to I
verify that the licensee had performed modifications and other
___
_
. _ _ _ _
__
_
.
.
.
I
.
corrective actions required for Unit 2.
The corrective actions taken to resolve the violation included:
Replacement of couplings with hard pipe and supports for
-
selected RHRSW/EECW pump supply and discharge lines and RHR supply lines.
ECN P0289 implemented these modifications.
A total of 37 Dresser couplings were replaced.
To limit the scope of work for Unit 2 restart, the licensee placed blind flanges on the 1A,1C, 3A, 38, 3C, and 3D RHRSW lines.
These lines will be modified for Unit 3 and Unit I restart.
Establishment of requirements and guidelines fo.
- sign and
-
analysis of flexible joints.
The Civil Engineering Branch's
" Rigorous Analysis Handbook" was revised to add guidelines for flexible joints.
Evaluation and modification of other Class I piping with Dresser
-
This included remaining piping in the RHRSW tunnels and buried piping outside of the Unit 1/2 DG Building.
ECN P0289, DCN W8435A, and DCN W8436A implemented these modifica-tions.
I FSAR revisions to reflect the analyses and modifications.
The
-
licensee committed to make the FSAR revisions as part of the update to be completed on July 22, 1989.
The inspector not that the FSAR had not been updated to include the analyses a?
modi fica tions.
The inspector also noted that the licensee issued an upgraded FSAR in 1990 but did not include changes required by this issue.
,
The inspector discussed the lack of a LER and the failure to revise the FSAR with site management at the exit meeting conducted on February 19, 1991.
The Plant Manager stated that they would review their information on these issues.
The inspector concluded that all activities required for Unit 2 fuel load had been completed; however, this item will remain open for Unit 2 pending further review. This item will remain open for Units 1 and 3 until completion of required modifications on Safety Related Electrical Circuit Breakers.
o.
(CLOSED) VIO 259, 260, 296/VIO 88-24-08, Failure to Perform PMs on Safety Related Electrical Circuit Breakers.
This violation was identified on July 23, 1988, when during the performance of the Restart Test Procedure 2-BFN-RTP-L/L-C Retest, RHR pump 2A did not start on demand.
Initially, the licensee considered this failure inconsequential since the pump breaker, 2BXR-074-0005,
,
l had functioned on past occasions.
At the request of the NRC l
inspector, the PM record sheets for this breaker were pulled.
The
inspector was informed by a maintenance representative that the
'
annual PMs had not been completed in 3 years, missed the first year, unable to PM the second and not done yet in 1988.
Further review
'
indicated that the required 5 year major tear down PM, procedure
. _ _.._.___. _.. _ _ _ _ _ _ _
.
.
.
.
EMI-7.3 Rev.1, had never been performed. Additionally, there were a total of 78 Magne-Blast Circuit Breakers, type AMH-4.76-250-00, AMH-4.76-250-1D, and Av.H-4.76-250-20, in 4.16 KV safety-related systems that had never, in 15 years, had the required 5 year PM performed despite the requirements of the vendor information manual.
No engineering evaluation had been performed to justify deferral of the preventive maintenance.
The inspector reviewed the licensee's response dated January 20, 1989, which stated all 4.16KV safety-related breakers required to support-Unit 2 startup will receive a general overhaul before res tart.
All safety-related PMs required for Unit 2 startup will be current at the time of restart. Management attention will be further enhanced by changing PMI 6.8, Preventive Maintenance Program Assessment.
This instruction will be revised to provide monthly graphs for those PM tasks required for equ pment needed to support Unit 2 restart and operation, i.e.,
Unit 2 and common PMs, and PM tasks required for all other plant equipment in Units 1 and 3.
Since Units 1 and 3 do not require as much equipment to be operational in the present layup condition this will allow the scheduled performance to be more closely monitored on each of these units. Separate graphs will be produced for safety and nonsafety-related PM items.
This will al'cw management to further focus on the safety-related items.
The inspector observed and reviewed the licensee's activities in this area over an extended period of time and documented these observa-tions and reviews in :revious inspection reports.
The inspector reviewed the status of PMs as part of the SP0Cing process for System 57, Auxiliary Electrical, and no deficiencies were identified.
p.
(CLOSED) VIO 259, 260, 296/90-25-01, Inadequate Fire Protection
.
Surveillance.
This violation was for an inadequate SI. The SI did not incorporate a TS change to verify that system pressure be greater than 120 psig after sequential start of the fire pumps. The inspector reviewed the licensee's closure package for this item.
The licensee revised the SI to check the setting of the pressure switch.
The failure to implement the TS change was found to be an isolated case.
The inspector reviewed the SI and the change had been made.
The requirements of.TS 4.11.8.1.f are to perform a system functional test which includes simulated actuation of the system throughout its cperating sequence.
The licensee fulfills 4.11.B.1.f.4 by SI 4.11. B. I. f.
This SI verifies that automatic start relays close and fire pumps start in the correct sequence within their allowed times based on system pressure.
The allowed times are 15, 30, and 45 seconds.
The inspector concluded the TS requirement was met by simulated actuation of the control timing and logic circuitry.
i
__
-
__. -
. - _
-
- _ - - -
-
-
-
.
.
..
.
.
.
q.
(CLOSED) DEV 260/89-06-03, Failure to Implement a Commitment to the US-NRC Concerning the Procedure Upgrade Program.
This item was identified during an inspection of the licensee's program involving safety-related instrumentation calibration, maintenance, and configuration control.
The licensee committed to
!
assure the adequacy of appropriate sis by conducting a review process
,
'
which included procedure verification, review, walkdown, and validation.
This commitment was documented in BFP, NPP, Volume 3, Revision 1.
The problems noted during the inspection were observed during the SI even though the SI had been validated by the licensee
'
and was tracked as being validated on a computer print out titled. SI
)
Status List.
The failure to adequately validate 2-SI-4.18-6(A) was l
and example of the deviation.
The inspector reviewed the licensee's response dated, July 7,1989.
The inspector noted that the licensee
revised applicable procedures.
After the deviation the licensee was given a Level III, no civil penalty violation for a programmatic breakdown.
The licensee's corrective action for the violation is ongoing and is to be completed prior to restart. Based on the Level III Violation 259,260,296/89-43-01, this item is closed, r.
(CLOSED) DEV 260/90-18-02, Failure to Correct Drawing Discrepancies.
This item was that corrective action for NOV 260/88-28-01 to update i
primary and critical drawings had not been completed. The deviation occurred due to ineffective handling of drawing deficiencies.
The licensee revised the DD process in SDSP 9.1, " Processing Drawing Discrepancies".
This changed the focal point for processing DDs from design engineering to system engineering. Old DD were closed as part of the SP0C and SPAE process.
DDs are tracked by system and closure monitored in the POD meetings.
After September 15, 1990, DD were processed as PDDs by the system engineer.
PPDs are assigned a priority for resolution.
The inspector reviewed the licensee's closure package for this item.
SDSP 9.1 provides the method for resolution of PDDs. The process of resolution of nearly 2000 DDs has
been routinely monitored by the inspector and recently the number was j
!
less than 200 DDs.
Each system DDs are reviewed as part of the SP0C i
and SPAE process.
These actions have essentially resolved the DDs problem for primary, critical, and important secondary drawings.
<
14. Site Management and Organization a.
SMART Meeting On February 7,1991, the inspector attended a portion of the SMART meeting.
This was the fourth full meeting of SMART.
An extensive discussion on readiness of Unit 2 for fuel load was conducted.
l SMART i
required confirmation that all Volume 3 commitments of the NPP, i
Employee Concerns Special Program, and Independent reviews that were l
i i
!
I
. _.
-
-
- - - -
- -.
- -
__._- -.-
_.
-_-.
.
.
.-.
.
.
B
'
.
required for fuel load were complete.
Additional discussions were held on the status of the SBGT system and the pliers which had been dropped into the reactor vessel. SMART concurred with fuel load when the problems identified were adequately resolved.
Special
,
presentations were provided on Watts Bar stop-work applicability to BFN and on the Independent Operational Readiness / Nuclear Safety Review Board evaluations of BFN.
The next scheduled meeting was set l
for_ March 7, 1991.
b.
Nuclear Safety Review Board (40500)
An inspector attended a portion of the NSRB meeting held at the BFN Training Center on January 31, 1991. The inspector noted that all of
,
!
the BFN upper level managers were in attendance and participated in the presentations and discussions. The meeting focused on the status
'
of BFN Unit 2, the schedule for Unit 2 restart, and action items from previous NSRB meetings.
The inspector noted that the presentations
,
,
and discussions were - thorough and the board members appeared l
knowledgeable of each issue.
The inspector observed presentations given by the Site Director, Plant Manager, Site Quality, Site Licensing, Engineering, and Independent Se.fety Engineering.
No concerns were identified.
15. Exit Interview (30703)
,
The inspection scope and findings were summarized on February 19, 1991, with other persons indicated in paragraph 1 above.
The inspectors
,
described the areas inspected and discussed in detail the inspection findings listed below.
The licensee did not identify as proprietary any of the material provided to or reviewed by the inspectors during this inspection. Dissenting coninents were not received from the licensee.
-
Item Number Description and Reference
!
259, ?60, 296/91-02-01 NCV, Failure to Maintain LC0 Compensatory Measures, paragraph 4.
,
260/91-02-02 NCV, Failure to Follow SI During SLC
,
Testing, paragraph 8,
259, 260, 296/91-02-03 IFI, Possible Single Failure Criteria Identified with SSGT, paragraph 10.
Licensee management was informed that 13 LERs, 6 IFIs, 5 URIs, 3 V10s, and 2 DEVs were closed.
16. Acronyms ADS Automatic Depressurization System j
AHU Air Handling Unit ASME American Society of Mechanical Engineers
,
ASOS Assistant Shif t Operations Supervisor a
.. -.
_
_
-
-
-
.
.
,,
-
.
!
ATV Analog Trip Units AVO Auxiliary Unit Operators BFNP Browns Ferry Nuclear Power Plant i
CAM Continous Air Monitor CAQR Condition Adverse to Quality Report
CCD Configuration Control Drawing CFM Cubic Feet Per Minute CFR Code Federal Regulation i
CREVS Control Room Emergency Ventilation System CS Core Spray CSS Chemistry Shift Supervisor DBE Design Basis Earthquake
DBVP Design Baseline and Verification Program DCA Design Change Authorization DCN Design Change Notice DCR Design Change Request
-
DD Drawing Discrepancy i
DEV Deviation DG Diesel Generator DNE Division of Nuclear Engineering ECCS Emergency Core Cooling System ECN Engineering Change Notice EECW Emergency Equipment Cooling Water EMI Electrical Maintenance Instruction
-
EQ Environmental Qualification ESF Engineered Safety Feature FCV Flow Control Valve FDCN Field Design Change Notice FSAR Final Safety Analysis Report HCV Hand Control Valve H0 Hold Order HPCI High Pressure Coolant Injection HVAC Heating, Ventilation, and Air Conditioning IFI Inspector Followup Item ILRT Integrated Leak Rate Testing IM Instrument Mechanics IR
Inspection Report
Inservice Inspection
KV
Kilovolt
LC0
Limiting Condition for Operation
LER
Licensee Event Report
Loss of Coolant Accident
Low Pressure Coolant Injection
Local Power Range Monitor
LRED
Licensee Reportable Event Determination
MMI
Mechanical Maintenance Instruction
Maintenance Request
Non-cited Violation
__ ___
_
.-
_
_
_.
.
._.
.
_
-,...
l
,
l
.
NE
Nuclear Engineering
Net Position Suction Head
NRC
Nuclear Regulatory Commission
l
Nuclear Reactor Regulation
Nuclear Safety Review board
Operational Readiness Assessment Team
Post Accident Sampling System
Peak Cladding Temperature
PDD
Potential Drawing Of screpancy
Preventive Maintenance
Post Maintenance / Modification Test
Probalistic Risk Assessment
Psig
Pounds Per Square Inch Guage
PVERMS
Plant Ventilation Exhaust Radiation Monitor System
Quality Assurance
Quality Control
Reactor Building Closed Cooling Water
Reactor Core Isolation Cooling
Residual Heat Removal Service Water
Radiochemistry Laboratory Analyst
RMOV
Reactor Motor Operated Valve
.
i
Standard Cubic Feet Per Minute
Significant Condition Report
SDSP
Site Director Standard Practice
Safety Evaluation Report
Surveillance Instruction
SII
Special Instrument Instruction
Standby Liquid Contro1 #crpsr'
Senior Management Assessment Restart Team
SOS
Shift Operations Supervisor
SPAE
System Plant Acceptance Evaluation
SP0C
System Pre-operational Checklist
Senior Reactor Operator
Stone and Webster Engineering Corporation
TACF
Temporary Alteration Change Form
TD
Test Deficiency
TI
Technical Instruction
TS
Technical Specification
Tennessee Valley Authority
Unresolved Item
V
Volt
l
V10
Violation
i
W0
Work Order
l
WP
Work Plan
l
Work Request
..