IR 05000259/1990023
| ML18033B494 | |
| Person / Time | |
|---|---|
| Site: | Browns Ferry  |
| Issue date: | 08/15/1990 |
| From: | Carpenter D, Kellogg P, Patterson C NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML18033B492 | List: |
| References | |
| TASK-2.K.3.13, TASK-TM 50-259-90-23, 50-260-90-23, 50-296-90-23, NUDOCS 9008240085 | |
| Download: ML18033B494 (42) | |
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UNITED STATES NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTASTREET, N.W.
ATLANTA,GEORGIA 30323 Report Nos.:
50-259/90-23, 50-260/90-23, and 50-296/90-23 Licensee:
Tennessee Valley Authority 6N 38A Lookout Place 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 1,,2, and
Inspection Con+cted:
June 19 - J ly 2
,
990 I
Insp ctors:
'
D.
R~
Carp ger, N C,Si e
Man ger
~C.
A. Patterson, NRC Restart Coordinator Accompanied by:
E. Christnot, Resident Inspector W. Bearden; Resident Inspector K. Ivey, Resident Inspector G.
Humphrey, sident Inspector 8'.,~ er rd Project Engineer Approved by:
Paul-
'gg-,
ection Chief, Inspect on Programs, TVA Projects Division 8 g/8 Date Signed D te igned
//'ate Signed SUMMARY Scope:
This routine resident inspection included surveillance observation, operational safety verification, modifications,'ower ascension test program, essential calculations, SPOC, reportable occurrences, action on previous inspection findings, and TMI action items.
Results:
A NCV for failure to follow procedure for Interim Order procedure changes was identified, paragraph three.
The licensee took prompt action to correct this administrative proble A NCV was identified for failure to follow an SI, paragraph nine.
The licensee identified this item and took prompt action to correct the issue by conducting an incident investigation of the event.
The omission of some calibration steps during the SI was due to a
communication problem between maintenance shifts and did not affect the operability of the radiation monitor.
The operations section took positive action to improve preparation of hold orders.
The operations work support center has been expanded to include a
quiet area for personnel preparing tagouts.
A 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> review period was established for routine tagouts.
There were inadequate instructions given to the systems engineers involved in the SPOC process, paragraph six.. -There was no QC involvement in the SPOC process.
System engineer knowledge in some cases was weak regarding SMPL items, CCDs, schedules, schedule impacts, and walkdown criteri REPORT DETAILS Persons Contacted Licensee Employees:
"0. Zeringue, Site Director
"L. Myer's, Plant Manager M. Herrell, Plant Operations Manager J.
Hutson, Project Engineer
'R. Jones, Operations Superintendent A. Sorrell, Maintenance Superintendent G. Turner, Site guality Assurance Manager
"P. Carier, Site Licensing Manager P. Salas, Compliance Supervisor J.
Corey, Site Radiological Control Superintendent R. Tuttle, Site Security Manager Other licensee employees or contractors contacted included licensed reactor operators, auxiliary operators, craftsmen, technicians, public safety officers, quality assurance, design, and engineering personnel.
NRC Personnel:
"D. Carpenter, Site Manager
- C. Patterson, Restart Coordinator
"E. Christnot, Resident Inspector
"W. Bearden, Resident Inspector
'K. Ivey, Resident Inspector
"G. Humphrey, Resident Inspector R. Bernhard, Project Engineer
"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 required SIs.
The inspections included reviews of the SIs for technical adequacy'nd 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 SIs were reviewed to determine which logic relays are actuated for the proposed integrated safeguards test:
a.
2-SI-4.2.B-1 (A-B)
Core and Containment Cooling Systems Reactor Low Water Level Instrument Channel A Calibration b.
2-SI-4.2.B-ATU (A-B)
c.
2-SI-4.2.B-40A Core and Containment Cooling Systems Analog Trip Unit Functional Test RCIC System Initiation and Isolation Logic-Functional Test d.
O-SI-4.9.A.3.a e.
2-SI-4.2.B-45A Common Accident Signal Logic Loop I RHR Logic System Functional Test 2-SI-4.2.B-42A HPCI System Initiation and Isolation Logic-Functional Test g.
I/2-SI-4.9.A.3.6.
480V Load Shedding Logic System Functional Test No violations or deviations were identified in the Surveillance Observation area.
The NRC inspectors reviewed 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 alarm 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 activity also included numerous informal discussions with operators and supervisors.
General plant tours were conducted.
Portions of the turbine buildings, each reactor building, and general plant areas were visited.
Observations included valve position and system alignment, snubber and hanger conditions, 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 tour a.
Operations Support Work Center The Operations Section has expanded and improved the Operations Support Work Center located next to the control room.
This area has a specific quiet area for personnel preparing hold orders.
Also, the operations staff has imposed a
24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> review period for preparation of routine hold orders.
b.
Control of Division of Nuclear Engineering Procedures On June 6,
1990, the inspector obtained a
copy of BFEP PI-88-07, System Plant Acceptance Evaluation, Revision 5, August 21, 1989 from Document Control.
Filed behind the PI in the controlled copy was an IO dated December 19, 1989, that included directions for two pen and ink changes, replacement of two attachments, and the addition of one attachment.
Discrepancies noted included:
1.)
The replacement attachments were not annotated to reflect their level of revision 2.)
Attachment I, consisting of 42 pages, did not have the pages numbered to indicate
"page x of xx" or any method of determining the length of the attachment to insure completeness.
Attachments G and J were one page long and were not marked to indicate their length.
3.)
The changes specified in the IO had not been performed to the controlled copy in document control.
In discussions with the licensee, other problems with NE's current method of making procedural changes with IOs were discovered:
IOs were posted in front of the PI per the current instructions.
The level of revision of the PI was not changed nor was any change made to the PI pages to indicate IO status.
Document Control does not make pen and ink changes to procedures, only page for page changes.
Superseded parts of the procedure were not 'marked to prevent use of the old text.
Procedures were not revised within the 90 days required after issuance of an IO.
ONP Standard ONP-STD-4.4.5, Revision O-C, Administration of ONP Division Procedures, and NP Standard SDSP-2. 12, Revision 3,
Controlling Documents, were reviewed.
The ONP was an advance copy and all guidance in the standard had not been adopted by the site.
The lower tier standards do not follow the guidance in the upper tier standards.
The system of IOs was not in compliance with the requi rements of SDSP-2. 12 requiring methods of page accountability and revision level, and requiring identification of superseded pages to prevent inadvertent use.
Changes to the methods of IO issuance and posting were made as a
result of the inquiries.
The inspectors concerns were addressed by changes outlined in conversations with the NE staff, and in a
memorandum issued by the Project Engineer concerning issue and control of interim orders.
The licensee took prompt corrective action to correct the problem.
This violation is not being cited because the criteria specified in Section V.A of the NRC Enforcement Policy were satisfied.
This is identified as NCV 259, 260, 296/90-23-01, Failure to Follow Procedure for Interim Order Procedure Changes.
Restart Review Board On June 28, 1990, the inspectors attended a meeting of the restart review board.
The procedural requirements for the board are specified in SDSP 8. 1, Design Change Requests.
A Change Control Board is established to review and approve Design Change Requests and to determine the required for restart status of various items being tracked onsite.
The Restart Review Board is a
sub-committee of 'the Change Control Board.
Items on tracking lists are evaluated against the restart criteria.
This evaluation fulfills a commitment made in the Nuclear Performance Plan.
Examples of items reviewed are CA(}Rs, ECNs, and Employee Concerns.
Twenty-nine CAgRs were reviewed to determine if the items must be resolved before restart of unit 2.
Fourteen of the items were determined to be restart items by evaluating the CA(}R against the restart requirement criteria.
The inspector observed that the meeting was conducted using the restart criteria and the evaluations were conservatively made.
Presently of 236 open CAgRs, 134 have been determined to be restart items.
4.
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 activitie a.
High Potential Cable jesting (51061, 51063)
The inspectors continued to follow activities associated with the high potential testing of electrical cables in conduit.
This testing was conducted in accordance with ST-90-01, Special Test Procedure for DC High Potential Testing of Low Voltage Cables.
The inspector also observed and reviewed the results of the high potential testing.
As a result of the anomalies identified during testing the electrical cables in conduit ES2052-IB, the licensee conducted inspections of 313 junction boxes for missing conduit bushings.
As of July 18, 1990, all inspections were completed with 11 boxes missing a total of 13 bushings.
The following activities were accomplished.
Test completed - Conduit 3ES1676-IB was completed.
This test consisted of a total of six conductors.
No anomalies were identified.
Field Activities -
The inspector observed portions of the testing performed on 34 conductors in conduit 2ES1313-I.
This test involved FCVs 71-18 and 19 and was performed from the 250 VDC RMOV Board 2C.
The test was completed with no anomalies identified.
Four more tests remain to be completed.
The test of conduit 2ES3342-II, which involves FCV 75-37, was being evaluated to determine if testing was required.
b.
Field Activities The inspector reviewed the licensee activities in the following areas:
DCN W12179A.
This item was initiated because all cables in conduits ES2051-IB and ES2052-IB were cut to isolate and remove cables that failed the DC high potential test, ST-90-01.
A section of conduit approximately 15 feet long was also removed near JB3206 in Unit 1 reactor building, elevation 593'.
The issuance of the DCN resulted in the 'writing of WP 1078-90.
WP 1078-90 was written to,implement OCN 1078-90.
The field activities involved the following: all cables in conduit ES2051-IB were to be spliced using new qualified cable; approximately 15 feet of conduit ES2052-IB previously removed was to be replaced; and all cables in conduit ES2052-IB were to be spliced using new qualified cable
The inspector observed the areas where the work activities occurred.
At the end of thi s reporting period, the WP was still in the field and being worked.
The inspector reviewed six gC inspection reports associated with WP 1078-90.
All items reviewed were satisfactory.
No deviations or violations were identified in the modifications area.
Power Ascension Test Program The inspectors reviewed the proposed testing of ECC and Standby Electrical Power Systems before Restart of Browns Ferry Unit 2 This review included an evaluation to determine if TVA needed to perform an additional integrated LOP/LOCA test in addition to the performance of the required surveillance testing of the ECCS and Standby Electrical Power Systems, prior to the restart of Unit 2.
A concern was derived from problems experienced with Unit 2 interties with Units
and 3.
This condition 'was documented on Condition Adverse to guality Report, CARR BFP880406.
An example was a Unit 1, Division 1 spurious accident signal in core spray followed by a real Unit 2 accident signal resulting in an attempt to start Unit
RHR loads on an already fully loaded DG without load shedding.
Remedial corrective action taken by the licensee was:
(1) to disable the Unit
a'nd Unit 3 accident signals where spurious operation could possibly degrade the circuitry required for Unit 2,
(2) disable RHR pumps cross-connected auto start for Units
and 3,
and (3) to disable Core Spray Pumps 4KV circuit breakers for Units 1 and 3.
A second problem was identified when a restart test program test was performed to demonstrate LOP/LOCA with the
"D" diesel generator out of service.
As required, the remaining seven diesel generators started and tied to their respective shutdown boards.
The Unit 3 breakers associated with diesel generators, 3A, 3B, and 3C, tripped within 5 cycles after closing.
This condition left diesel generators 3A, 3B, and 3C in a
locked-out condition which could not be reset from the control room or reset automatically.
This failed the acceptance criteria.
The root cause was determined to be a failure by the system vendor to consider all possible LOP/LOCA logic timing sequences during the system design.
A timer was added to the circuitry to correct the condition.
For both problem areas addressed, above, after implementation of the corrective actions, each was retested and the results were acceptable.
A
CFR 50.59 Safety Evaluation performed by the l.icensee verified that with the deletion of the common accident signal for Units
and 3, the plant logic configuration will only support operation of Unit 2.
The inspectors have reviewed the SIs required by the TS to demonstrate the operability of the ECCS and Standby Emergency DGs.
The CARR, associated Design Change Notice (DCN H2735A),
and applicable drawings were reviewed.
Based on these reviews, the planned Integrated Safeguard Tests are acceptable to support operation of Unit.
System Preoperabi1 ity CheckTi st (71707)
The licensee has implemented 3 major programs to complete and verify operability of the systems required for Unit 2 restart.
The first program is a
System Plant Acceptance Evaluation (SPAE).
Phase I of the SPAE identifies all outstanding work associated with the applicable systems'hase II consists of an engineering preoperabi lity review and Phase III verifies that all work was completed.
A detailed scope for each of the
phases follows:
SPAE System Plant Acceptance Evaluation (PI-88-07)
Phase I:
OUTSTANDING WORK IDENTIFICATION All DD's affecting Primary & Critical Drawings identified All DD's on Secondary Drawings identified All change documents identified All ECN's/DCN's identified per Site Master Punchlist All Punchlist Items associated with ECN's/DCN's identified All essential calculations identified and documented All CARR's identified All EA Action Items identified All Restart Test Documents reviewed for unverified assumptions System Restart Design Criteria evaluated All Primary & Critical Drawings verified Nuclear Performance Plan Special Program Review Phase II: SYSTEM PREOPERABILITY ENGINEERING REVIEW Engineering closure of all DD's All open non U2C5 change documents closed and documented Primary
& Critical Drawings reviewed for technical adequacy including CAD restoration errors All Design Engineering evaluation completed SPAE Package assembled by responsible engineer Phase III:
WORK COMPLETION VERIFICATION SPAE checklist routed for signatures RIMS No.
assigned and SPAE package issued for system return to service The second program, the System Pre-Operability Checklist (SPOC),
was designed to provide a
systematic method to ensure that all open work activities and outstanding programmatic items affecting system operability for restart are complete or dispositioned prior to recommending that a
system is available to support the unit restart.
The criteria specified in this program are:
0
SPOC - System Pre-Operabi 1 ity Checklist The following will be verified complete:
All ECN/DCN'
affecting system operability closed All TACF's that affect system operability removed All Preventative Maintenance identified by the system engineer is in periodicity All Maintenance Requests required for system operability, are closed including Post Maintenance Testing All NRC commitments resolved by Site Licensing All Site Commitments NMRG, INPO, and GE system review items closed All TS changes approved by NRC All CAQR's closed All SI's 8 OI's affecting operability are in periodicity Engineering System Evaluation issued per BFEP PI-88-07 All system hold orders cleared The third program is a
system checklist for miscellaneous systems, which does not involve the depth of detail of the SPOC program.
However, this program is only applied to non-safety related systems The items reviewed in this program are:
ECN/DCNs required to be completed for restart are returned to service in accordance with SDSP-12.4.
System related TACFs required to be removed for restart are removed.
All system related NRC commitments required for restart are completed.
System related MRs, MRs, and PMs required for restart are completed and closed as applicable.
System related CAQRs determined to directly affect system operability for restart are dispositioned.
All Primary and Critical Drawing's have been revised and issued.
All DDs have been reviewed to identify secondary drawing DDs which affect Primary 5 Critical drawings:
Primary and Critical Drawings legible and available in control room.
System status file is up to date and has been reviewed for abnormal status'ny abnormal status has been dispositione System walkdown has been performed in accordance with OSIL-64 and operability issues have been dispositioned.
Outstanding work has been reviewed for overall schedule impact.
The inspectors have monitored the licensee's implementation of the SPOC program during their efforts to evaluate systems required to support unit 2 startup and will continue this activity throughout the completion of turnover of the systems required for restart.
The activities monitored during this reporting period were:
Lube Oil System (System'0).
The inspector performed a walkdown of greater than 70% of this system with the system engineer.
Some discrepancies were noted during the walkdown and the inspector verified that Maintenance Work Requests were issued for the applicable items.
These items in general pertained to labels that were missing, cosmetic deficiencies, and housekeeping.
One drawing discrepancy was noted and a follow-up has been initiated.
In addition, four Design Change Notices were found to be outstanding against the system and the field work had not begun.
b.
The inspector determined that the system did not appear ready for a final walkdown at the time that this walkdown was performed.
Raw Cooling Water (System 24).
The inspector reviewed the SMPL for the RCW system with the system engineer.
The engineer was not fully knowledgeable of all items on the list.
In particular, the status of CAQR 89024 was not known.
This CAQR was that some components were designed, purchased and fabricated to pressures that were less than the design pressure specified in the FSAR.
The inspector also walked down portions of the system in the turbine building and reactor building with the system engineer, a planner, and a plant operator.
Twenty-six deficiencies were identified.
On the RCW supply to the CRD pump 1B, a straight section of 3/4" pipe was disassembled and a
new section of pipe was laying next to the pump.
The pipe was being replaced because of MIC.
This condition has occurred in small diameter piping during low flow conditions.
This was thought to be one of the major items of concern with the system.
During the walkdown in the reactor building, some piping and valves were located in a CSCA.
The system engineer did not enter this area and stated the walkdowns did not have to be 100K.
Although numerous deficiencies had been identified in other areas, this area in the CSCA would not be inspected.
Some flow drawings for RCW were CCD and others were as-constructed.
The system engineer did not understand what a
CCD wa The inspector noted on one schedule that RCW was due for SPOC on August 10, 1990, and another scheduling book showed the SPOC date as August 25, 1990.
The system engineer.could not explain the reasons why the dates were different.
Potable Water System (System 29).
The inspector reviewed the SMPL with the system engineer.
The inspector noted that TACF 0-87-006-28, which provided cooling water to a temporary air conditioning unit, was not included on the SMPL.
The licensee stated that the TACF had originally been written incorrectly for System
rather than System 29.
System 28 no longer exists.
Although this TACF is of no safety significance, the inspectors are concerned that this error may indicate a potential generic problem with the accuracy of the SMPL.
Gland Seal Water (System 37).
A system checklist was performed on this system.
The inspector reviewed the completed checklist package and SMPL.
One electrical drawing, 2-47E610-37-1, and three mechanical drawings, 2-47E841-1, 1-47E818-1, and 2-47E818-1, were rev'.ewed.
Two of the mechanical drawings were designated as CCDs.
The inspector questioned why these were CCDs.
The system engineer did not know and was not knowledgeable of CCDs.
Two other system engineers were also questioned concerning CCDs and were also not knowledgeable of CCDs.
The system was being evaluated only for its, primary and secondary containment penetrations.
The inspector also reviewed the walkdown items and no significant issues were identified.
No other issues that could affect system operability were identified.
Demineralized Backwash Air (System 53).
The inspector reviewed the completed system checklist for this system.
All outstanding work against this minor plant system had been, reviewed by the licensee.
Work required for operation was evaluated and dispositioned to support system status and configuration control.
Two MRs outstanding on this system were reviewed by the inspector and found to be minor leakage items.
No other outstanding issues remained for this system.
Temperature Monitoring (System 56).
The inspector reviewed the SMPL for'his system with the system engineer.
This system consists of various thermocouples on the reactor vessel with associated chart recorders in the control room.
One ECN on the SMPL referenced several systems.
After the work associated with System
was completed the DCN would not be closed until all the work was complete on each system.
This would result in a
SPOC deferral item, even though all work was complete for this syste,
The inspector conducted an inspection of the visible sections of the system in the Unit 2 drywell.
The walkdown in the drywell had not been previously performed by the system engineer.
No deficiencies with the system were noted during the tour.
g.
,Off Gas System (System 66).
The system was walked down in part as the preliminary function prior to beginning the SPOC determination.
However, a
more detailed walkdown will be performed at a later date.
h.
Core Spray System (System 75).
Major portions of this system were walked down by the system engineer and the inspector.
During this walkdown, it was noted that some work remained which consisted of replacing electrical power cables to the 2C Core Spray Pump as required for EQ.
Some system deficiencies were noted.
These consisted of four limitorque operator compartment covers found either loose or to have bolts missing; identification tags were missing on four valves; and one junction box cover did not meet EQ requirements.
A Maintenance Work Request was initiated for each of the identified discrepancies.
A final walkdown of the system will be performed at a later date to verify corrective actions have been performed.
i.
Raw Water Chlorination (System 51).
This Raw Water Treatment System has been evaluated to be acceptable through the SPOC process.
The inspector reviewed the completed SPOC package and associated open items.
No discrepancies were noted.
In conclusion, for the systems reviewed, the inspectors noted the following:
1)
No QC involvement in the SPOC process 2)
System engineers need training on CCDs 3)
System engineers knowledge of SMPL items was weak 4)
Schedules contained conflicting dates 5)
System engineers knowledge of schedule impact was weak 6)
Inconsistent quality of walkdowns by system engineers 7)
Unclear guidelines on whether walkdowns were partial or 100%
8)
System engineers seemed unclear of management expectations regarding the SPOC process.
These conclusions were discussed with the Site Director, Plant Manager, and Technical Support Superintendent on July 20, 1990.
Management was receptive to the inspectors conclusions.
7.
Essential Design Calculations (37700)
Past audits by organizations both internal and external to TVA have shown that calculations supporting the design basis for TVA's nuclear power plants have not been adequately documented.
These audits were conducted by Gilbert Commonwealth, TVA's Quality Assurance organizations, the NRC,
and INPO.
Calculations were identified in these reviews as being missing, incomplete, or not updated.
While these weaknesses were initially defined in the electrical area, subsequent assessment of the condition by TVA management concluded that a
review of design calculations should be conducted by the other engineering departments.
The calculation regeneration/revision effort was further complicated by the additional effort needed to support other programs such as seismic, 79-14, small bore piping, etc.,
which resulted in other new and revised calculations.
In response to this concern, TVA NE initiated a review of the engineering calculations in the electrical, nuclear, mechanical, and civil areas to resolve these previous audit findings and their generic implications in the Unit 2 restart effort.
These calculation activities apply to all four engineering discipline departments in NE.
Each discipline was tasked with performing a review to assess the extent of this condition and adequacy of the calculations.
Although civi 1 calculations represent the majority of the total calculations, electrical calculations also comprised a large portion of the actual work effort.
Program integration is being achieved through a
calculation status tracking control log.
This system is titled the CCRIS.
The CCRIS is tracking calculations supporting engineering changes and'nteractions between calculations and modifications.
Features of the CCRIS include integration of the calculations from the four NE technical departments, identification of analyses required to support design changes, and identification of interface links between calculations.
The CCRIS is in place and will be used to track the status of essential calculations to support Unit 2 restart.
The essential calculations effort is tied directly to the DBVP which verified that essential calculations exist for the safety related systems being reviewed and that the calculations support system "functionality.
"Essential Calculations" are defined as calculations which address existing plant systems or features or portions thereof whose failure could:
1)
Result in a loss of reactor coolant system integrity 2)
Result in loss of ability to achieve safe shutdown; or 3)
Result in a
release of radioactivity offsite in excess of the
CFR 100 guidelines.
In the electrical and mechanical areas, every calculation will be reviewed.
The civil and nuclear 'alculations will be sampled in accordance with nationally accepted sampling criteria (Nuclear Construction Issues Group, NCIG02).
The inspector noted that 'he calculation regeneration effort is not complete, i.e.
some new, calculations and revisions to calculations are pending.
The status as of July 17, 1990 is as follows:
Engineering
~Disci line Wor k
~Cnm late Work
~Remainin Scheduled Com letion Date Electrical 271 new CALCS 4 new CALCS 9/17/90 approx 380 111 revised CALCS revised CALCS Nuclear Approx 30 2 new CALCS new CALCS 5 revised CALCS ll revised CALCS 8/31/90 Mechanical Approx 250 new CALCS Approx 60 revised CALCS
new CALCS 25 revised CALCS 9/17/90 Civi 1
new CALCS
new CALCS 72 revised CALCS Approx 3000 revised CALCS 9/28/90 Above numbers are not based entirely on essential calculation regeneration/revision program.
Many new and revised calculations have resulted from other programs such as AC and DC calculations, 79-14, small bore piping, seismic, and ampacity.
8.
Reportable Occurrences (92700)
The LERs listed below were reviewed to determine if the information provided met NRC requirements.
The determinations included the verification of compliance with TS and regulatory requirements, and addressed the 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 i'-plant reviews and discussions with plant personnel, as appropriate, were conducted.
a.
(CLOSED)
LER 259/86-07, Control Rod Drive Insert and Withdraw Lines not Seismically gualified.
This LER was resolved by closure of URI 259, 260, 296/86-06-01, closed in this report (Item 9e).
b.
(CLOSED)
LER 296/87-01, Momentary Loss of Secondary Containment Due to Personnel Airlock Failure Due to Fatigu o
This failure allowed the reactor building and turbine building personnel airlock doors to be opened at the same time, thus breaching secondary containment.
A failed electric strike device was replaced.
The long term. corrective action was to replace the original design with an electric dead bolt. device.
This modification was completed on doors
¹221 and" 244 under ECN P0897, MP 2068-87.
In addition to the new electric striker, an internal position limit switch was added to the interlock circuits under ECNs P07052 and P07053.
The inspector has reviewed the" modification documentation package and observed the operation to the airlock doors.
(CLOSED)
LER 259/88-10, Personnel Error in Procedure Preparation Causes Engineered Safety Features Actuation.
This LER was closed in IR 88-32 for Unit 2 and should have been closed for Unit 1.
(CLOSED)
LER 260/89-07, Cable Deterioration Causes Inoperability of Neutron Monitoring System.
IR 89-11 identi fi ed thi s event as IFI 89-11-03, which was subsequently closed out in IR 90-03.
The only remaining action was verification of field work completion.
The inspector has reviewed CARR BFP89-0291 and its closure which documented these conditions.
The licensee has completed all rewiring of affected panels in Unit 2 and those support systems in Units 1 and 3 required for operation of Unit 2.
The remaining work to support Units
and 3 operation has been punchlisted for the respective units and will be integrated in their return to service work schedule.
040 in response to this failure.
(CLOSED)
LER 259/89-013, Seismic Reanalysis of the Reactor Pressure Vessel.
Sei smic r eanalysi s of the BFN reactor pressur e vessel s calculated that the control rod drive housings would exceed the stress limits specified in the BFN FSAR during normal power operation combined with a
seismic event.
The reanalysis was performed using an updated RPV model and FSAR specified damping factors.
The original BFN RPV analysis was performed in the late 1960's by General Electrics The original calculations could not be located, but the analysis results were documented in the BFN FSAR showing that the existing CRD housing arrangement was in compliance with the original FSAR licensing basis.
Although the stress limits are now shown to be exceeded by the new analysis, there were no indications that the CRD housings would have failed during a seismic event.
TVA has refined the seismic model of the RPV and has upgraded the actual plant configuration by adding lateral restraints to the CRD housings for Unit 2.
Concerns and resolutions on these issues have been addressed in IRs 89-20, 89-39, 89-62, and 90-08.
The seismic upgrade of the control rod drive
housings to provide lateral restr'aint have been completed on Unit 2 per DCN W7792B.
The NRC-Hg staff has verified acceptable completion of this activity.
This inspection has verified that this item is carried on the Corporate Commitment Tracking System as required for both Unit 1 and 3 before to restart of the affected unit.
(CLOSED)
LER 260/89-27, Failure to Neet Technical Specifications Due to Loss of Sump Pump.
RHRSW Pump room sump pump Bl became inoperable when a temporary power cable to a
space heater fell in the sump and became entangled in the impeller.
The B2 sump pump was being replaced at the time under a
modification workplan and was unavailable for service.
The sump was dewatered and cleaned, Pump Bl was removed, refurbished, and reinstalled.
The root cause of this event was carelessness and poor housekeeping on the part of the modifications group.
As corrective action, the event investigation was discussed at safety meetings with all modification personnel.
Also, a modification supervisor must tour all areas where modification work is being performed at least once per shift.
The inspector reviewed the investigation report, safety meeting attendance sheets, and also toured the RHRSW rooms.
The housekeeping at that time was acceptable.
(CLOSED)
LER 260/90-01, Unplanned Engineered Safety Feature Actuation Due to a Failed Radiation Detector Caused by Frequent Disconnection of the Detector Connector.
This event was caused by a failed detector connector damaged by frequent disconnecting of the detector for unit calibration.
Contributing to this event was isolation logic which required only a single radiation monitor to fail to actuate an ESF.
As a corrective action to a similar event, LER 296/89-005, the licensee has committed to replace the radiation monitor with a design that requires less frequent calibration.
The trip logic will be changed to a one out of two taken twice configuration.
This work is to be completed before Unit 2 restart.
Since the corrective action is to be completed under LER 296/89-005, LER 260/90-001 is closed and the corrective action will be tracked for closure under LER 296/89-005.
(CLOSED)
LER 259/90-02, Engineered Safety Features Actuations During Shutdown Board Transfer Due to Inadequate Procedure.
This LER involved an ESF actuation caused by failure to fully rack in a
480 Volt breaker
. It occurred while performing a manual transfer of power supplies during a diesel generator test.
The alternate power supply breaker failed to close.
The root cause was attributed to an inadequate procedure that failed to follow the vendor manual instructions.
The procedure, GOI-300-2, Electrical General Operating Instruction, was revised to include appropriate vendor manual
e
instructions.
The event investigation was placed on the operator required reading list.
The inspector has reviewed the revised GOI-300-2 and the required reading signoff sheets, and has found the licensee actions acceptable.
(CLOSED)
LER 259/90-04, Failure to Comply With Technical Specifications Due to Loss of All Three Reactor Building Hose Stations.
This item is the same issue as VIO 259, 260, 296/90-05-02, closed in this report.
This LER was reviewed and no additional items were found that were not,addressed in the closure of the violation in item 9h.
9.
Action on Previous Inspection Findings (92701, 92702)
(CLOSED) IFI 259, 260, 296/86-02-04, Determination of Design Adequacy for Typical Pipe Supports That Were Utilized in Field-Routed Piping.
IR 50-259, 260, 296/86-02, identified that significant condition report (SCR)
8543RO was issued on December 24, 1985.
This SCR stated that existing field routed tubing and small diameter piping which require seismic installation may not be adequately installed.
The inspection report noted that the design criteria for tubing, BFN-50-713, did not address thermal loads.
The licensee developed separate programs to address concerns with small bore piping and concerns with instrument tubing.
The licensee's implementation of these programs was reviewed during an NRC inspection and the results documented in IR 50-260/89-36.
The review included the concerns identified in previous SCRs including SCR BFNEEB 8543 Rl.
Report 89-36 concluded that the concerns identified in the SCRs were adequately addressed by the TVA programs.
b.
(CLOSED) IFI 259, 260, 296/90-05-04, Qualification of System Engineer to Maintain Fire Protection System.
This item was initially identified during a review of the licensee's activities to meet specific requirements in
CFR 50, Appendix R.
During discussions with the licensee, a fire protection engineering section organization chart was presented.
This chart outlined the system engineering responsibilities for various subsystems and hardware involved with fire protection.
These included High Pressure Fire Protection (System 26),
C02 (System 39), Penetrations, barriers, doors, Appendix R, fire protection equipment, Halon Systems, dampers, smoke detectors, instrumentation and heat detectors.
This section consists of an engineering supervisor, Fire Protection Lead Engineer, and six additional engineers.
Based on the organization and expertise, the system engineer group is qualified to maintain the fire protection syste P
, (CLOSED) IFI 259, 260, 296/90-14-03, Effects of Phase Unbalance on Safety Related Electrical Systems.
This item was originally identified when a radwaste pump tripped on thermal overload after running for approximately 75 minutes.
The licensee determined that this was due to an improper tap setting on Phase C of the main transformer bank 1.
Phase A is normally set at 5,
Phase B is normally set at 5, and Phase C is normally set at 2.
Due to personnel error, Phase C
was also set at 5.
At this tap setting, Phase C was at a higher voltage.
During this event, all safety related loads were being fed from on main transformer bank 2, and were not affected.
(CLOSED) URI 50-259, 260, 296/85-21-03, Frequency/Deflection Criteria Used for Pipe Support Analysis.
IR 50-259, 260, 296/85-21, identified that Browns Ferry Design Criteria No.
BFN-SO-D707, Rev.
2 did not contain frequency/deflection criteria for the design
'of pipe supports.
BFN-50-D707 has been superseded by new criteria documents for the design of Class I
seismic pipe and tubing supports.
This criteria document was reviewed during two NRC team inspections and the results documented in Inspection Reports 50-260/89-15 and 50-260/89-44.
Although BFN-SO-C-7107, Revision 3,
contained criteria for checking the deflection of pipe supports, IR 50-260/89-44 identified an unresolved item (URI EMG-037) with its application for gang hanger supports.
The licensee responded to the unresolved item (TYA letter dated March 16, 1990). and committed to revise the criteria applied to gang hanger supports.
The licensee's proposed revision is considered acceptable.
(CLOSED)
URI 50-259, 260, 296/86-06-01, CRD Lines Not Seismically Qualified.
The licensee developed a special program to address the concern with the seismic qualification of the CRD insert and withdrawal lines.
The licensee's criteria for the seismic analysis of these lines were
~ reviewed during an NRC team inspection and the results documented in IR 50-260/89-44.
The inspection report concluded that the licensee's criteria for the seismic qualification were acceptable.
Seismic issues were part of the licensee's corrective action program in the Nuclear Performance Plan.
(CLOSED) URI 260/88-24-01, Piping Support Adequacy.
This item involved the adequacy of pipe support R-26 in the Unit 2 HPCI System.
Separately, the NRC-HQ Seismic staff open Unresolved Item EMG-024, Base Pate and Anchor Bolt Configuration.
This item was closed out in IR 50-260/89-44 by the staff review and acceptance of calculation CD-Q2073-882189, Revision 1.
The base plate for support R-26 was acceptabl g.
(CLOSED) URI 259, 260, 296/90-14-02, Failure to Follow SI Radiation monitor 3-RM-90-249 was returned to service following layup for the winter and declared operable on May ll, 1990.
However, during review of 3-SI-4.2.K.3A, Turbine Building Vent Exhaust Monitor (3-RM-90-249) Calibration, TVA discovered that calibration steps for a
Magnehelic type flow indicating controller (SI steps 7.8.9 thru 7.8. 12.22)
on the radiation monitor had not been performed, and the radiation monitor should not have been considered operable.
The SOS declared the monitor inoperable and notified the chemistry group to begin compensatory sampling as required by TS Table 3.2.K.
Incident investigation II-B-90-057 was conducted to determine the root cause of this event and identify corrective actions to be taken to prevent recurrence of the event.
The inspector reviewed the licensee's incident investigation and held discussions with licensee personnel to determine the following:
FIC-90-249 (Magnehelic type FIC)
was found to be defective during the performance of the SI, and was replaced using an approved work order (WO ¹90-04906-00).
A functional calibration (bench test)
was performed on the FIC prior to replacing it on the radiation monitor.
I Several crews were involved in the performance of the SI over several days.
The steps for calibration are not SI acceptance criteria and have no effect on the operability of the radiation monitor.
The licensee's investigation determined that the cause of this event was a communications breakdown between the various shifts attributed to both oral and written turnovers.
After the 1st shift (midnight shift)
bench tested and installed the new,FIC on the radiation monitor, the 2nd shift (day shift) continued with the SI.
The midnight crew input on the maintenance activity logsheet for WO
¹90-04906-00 stated that a
"bench calibration" of the new FIC had been completed.
This led the 2nd shift to believe that the steps in the SI had been performed.
The 2nd shift craftsmen and foreman noted that the FIC calibrations steps in the SI were not signed off, but, after discussions, review of the activity logsheet, and review of the condition of the monitor, both were convinced that the calibration steps had been completed and were just not signed off by the 1st shift.
Therefore, they did not perform the calibration steps given in the SI.
After two days lapsed, it was determined that the SI calibration steps had not been complete,
Technical Specification (TS) 6.8.1, Procedures, requires that written procedures be established, implemented, and maintained covering surveillance and test activities of safety-related systems.
The failure to follow a surveillance instruction is a violation of TS 6.8. 1.
However, this licensee identified violation is not being cited because the criteria specified in Section V.G. 1 of the NRC Enforcement Policy were satisfied.
No further actions are required.
This violation is identified as NCV 259, 260, 296/90-23-02, Failure to Follow SI.
(CLOSEO)
VIO 259, 260, 296/90-05-02, Inadequate Compensatory Fire Protection Measures.
This violation was for failure to comply with TS regarding compensatory fire protection measures when fire protection equipment was removed from service.
The violation had two examples.
The first example was for inadequate compensatory measures for inoperable fire hose stations.
The second example was for removing all fire hose stations from service in all three reactor buildings.
The inspector reviewed the licensee actions following this event and the licensee's closure package.
The immediate action taken was to restore Unit 3 fire protection and establish compensatory measures that comply with TSs.
E The root cause of this event was attributed to personnel error.
The personnel involved in the event were counseled.
Plant management discussed this event with the operations supervision and cognizant fire protection personnel.,
A SRO has been assigned to 'the fire protection staff for day to day supervision and coordination with the shift SOS.
The shift SOS has direct supervision of the fire brigade and is responsible for ensuring all TS requirements are met prior to implementation fire system impairment permits.
This condition occurred in the plant due to major maintenance on the high pressure fire protection system.
Leaking between boundary isolation valves required isolation of the entire system to allow the system to be drained.
A review of the failure hi.story of the major boundary valves attributed their failure to a lack of valve cycling.
A valve cycling surveillance, 0-SI-4. 11.B. 1.c, was instituted to require yearly cycling of the principal header and component isolation valves on the high pressure fire protection system.
Ouring routine tours of the plant since this event the inspector has
.checked the operators awareness of compensatory fire protecti'on measures.
Compensatory
" measures in the reactor building were reviewed.
No further problems have been identifie.
TMI Actions Items (CLOSED)
260/TMI Action Item II.K.3.13, Separation of High Pressure Coolant Injection and Reactor Core Isolation Cooling System Initiation Levels.
This item involved two separate issues.
The first item was separation of HPCI and RCIC system initiation levels.
The second item was modification of the RCIC initiation 1'ogic to cause automatic RCIC restart on low reactor vessel water level.
For the first item, TVA endorsed the BMR Owner's Group evaluation that the separation of HPCI and RCIC initiation levels would be of negligible safety benefit.
In a letter from the NRC to TVA dated March 16, 1983, the NRC concurred with this evaluation.
For the second item, TVA notified the NRC that the modifications had been completed for Unit 2 in a letter dated August 9, 1989.
The work for this modification was completed under ECN P0478.
This modification to RCIC was accomplished by changing the valve that closes on a high level condition.
Before the modification, the turbine trip valve FCV-71-9 would close to shut off the steam supply due to high level.
Now steam supply valve FCV-71-8 will receive the close signal on a high level trip condition.
Like HPCI, RCIC will now automatically restart on low reactor level if it was previously tripped on high level.
The other RCIC trip parameters will still close the turbine trip valve FCV-71-9.
Closure of the steam supply valve FCV-71-8 'also resets the ramp generator and opens the appropriate drain valves.
TS amendments 173, 176, 144 were approved on August 24, 1989 and incorporated this change.
The inspector reviewed the TS change, OI, and operator training lesson plan.
Reactor Core Isolation Cooling System Operating Instruction, 20I 71, Revision
dated January 12, 1990, addressed the TS change and automatic initiation features'o violations or deviations were identified during the Followup of TMI Action Items.
= 11.
Exit Interview (30703)
The inspection scope and findings were summarized on July 20, 1990, with those 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 comments were not received from the licensee.
Item Number Descri tion and Reference 259, 260, 296/90-23-01 NCV, Failure to Follow Procedures for Interim Order Procedure Changes, paragraph,
260, 296/90-23-02 NCV, Failure to Follow SI, paragraph 9.
Licensee management were informed that a previous violation, four URIs, three IFIs, Nine LERs, and one TMI action item, as discussed in paragraph 8, 9, and 10 were closed during this inspection.
12.
Acronyms AC ATU BFEP BFNP BWR CALCS CAQR CCD CCRIS CFR CRD CSCA DBVP DC DCN DD DEY ECCS ECN ESF FSAR GE HPCI HQ IES IFI INPO IO KV LER LCO LOP/LOCA MR NCV NE NMRG NP NRC ONP PI QC Alternating Current Analog Trip Unit Browns Ferry Engineering Procedure Browns Ferry Nuclear Plant Boiling Water Reactor Ca 1 cul ati ons Condition Adverse to Quality Report Configuration Control Drawing, Calculation Cross Reference Information System Code, of Federal Regulations Control Rod Drive Controlled Surface Contamination Area Design Baseline Verification Program Direct Current Design Change Notice Drawing Discrepancies Deviation Emergency Core Cooling System Engineering Change Notice Engineered Safety Feature Final Safety Analysis Report General Electric High Pressure Coolant Inspection Headquarters Impact Evaluation Sheets Inspector Followup Item Institute o'f Nuclear Power Operations Interim Order Kilovolt Licensee Event Report Limiting Condition for Operation Loss of Power/Loss of Cooling Accident Maintenance Request Non-Cited Violation Nuclear Engineering Nuclear Managers Review Group Nuclear. Power Nuclear Regulatory Commission Office of Nuclear'Power Project Instruction Quality Control
r Q
~
'H,
RCIC RHR RHRSW RPV RTP SDSP SMPL SOS SPAE SPOC SRO SSQE ST TVA TS VIO WO WP WR Reactor Core Isolation Cooling Residual Heat Removal Residual Heat Removal Service Water Reactor Pressure Vessel Restart Test Program Site Director Standard Practice Site Master Punch List Shift Operation Supervisor System Plant Acceptance Evaluation System Pre-Operation Checklist Senior Reactor Operator Safety System equality Evaluation Special Test Tennessee Valley Authority Technical Specification Violati on Work Order Work Pl an Work Request
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