IR 05000259/1998006
| ML18039A601 | |
| Person / Time | |
|---|---|
| Site: | Browns Ferry  |
| Issue date: | 11/02/1998 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML18039A599 | List: |
| References | |
| 50-259-98-06, 50-259-98-6, 50-260-98-06, 50-260-98-6, 50-296-98-06, 50-296-98-6, NUDOCS 9811090249 | |
| Download: ML18039A601 (50) | |
Text
e U.S. NUCLEAR REGULATORY COMMISSION
REGION II
Docket Nos:
License Nos:
50-259, 50-260, 50-296 DPR-33, DPR-52, DPR-68 Report Nos:
50-259/98-06, 50-260/98-06, 50-296/98-06
'icensee:
Tennessee Valley Authority Facility:
Browns Ferry Nuclear Plant, Units 1, 2, 8 3 Location:
Corner of Shaw and Browns Ferry Roads Athens, AL 35611 Dates:
August'23 - October 3, 1998 Inspectors:
J. Starefos, Acting Senior Resident Inspector E. DiPaolo, Resident Inspector T. Morrissey, Project Engineer (Section 01.3)
D. Jones, Radiation Specialist (Section R1.1 )
H. Whitener, Reactor Engineer (Sections M3.1, M3.2, M3.3, and M3.4)
Approved by:
H. O. Christensen, Chief Reactor Projects Branch 6 Division of Reactor Projects Enclosure 2 98ii090249 98ii02 PDR ADOCK 05000259
PDR'
EXECUTIVE SUMMARY
Browns Ferry Nuclear Plant, Units 1, 2, & 3 NRC Inspection Report 50-259/98-06, 50-260/98-06, 50-296/98-06 This integrated inspection included aspects of licensee operations, maintenance, engineering, and plant support.
The report covers a 6-week period of resident inspection with assistance from a Project Engineer.
In addition, a Radiation Specialist performed an occupational radiation, exposure inspection and a Reactor Engineer inspected in-service testing (IST).
~Oerations Plant systems responded as designed when an automatic turbine trip and reactor scram occurred on Unit 2. Thorough troubleshooting of the stator cooling water system led to prompt identification of the cause.
The licensee's Incident Investigation Team performed a thorough investigation of the event (Section 01.1).
Licensee management expectations for signing the working copies of clearances in the field were not diligently implemented, as identified by two examples.
The licensee clearly communicated expectations to Operations personnel following identification of the issue (Section 01.2).
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General material conditions of the Unit 2 Core Spray system were considered to be good (Section 01.3).
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The results of an inspection tour of the Unit 3 torus were that material conditions were good.
Plant operators were unaware that the drywell-to-torus vacuum breakers were being propped open with various items (Section 02.1).
Operations personnel inappropriately entered into Technical Specification (TS) Limiting Condition for Operation (LCO) 3;0.3 when tagging out the Containment Atmospheric Dilution (CAD) system to Unit 3 prior to reactor shutdown for the refueling outage.
Although the actual conditions for entry into TS LCO 3.0.3 did not exist, operators involved were not appropriately sensitive to intentional entry into TS LCO 3.0.3 (Section 04.1).
'aintenance
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Thorough troubleshooting of equipment problems was observed during the inspection period. Workers were found to be knowledgeable of their assigned tasks.
Good work
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practices were demonstrated (Section M1.1).
Operators conservatively backed out of testing and consulted engineering support when problems were encountered during core spray logic system functional testing.
Operations personnel performing the test demonstrated an in-depth knowledge of the test and the consequences of potential personnel errors (Section M1.2).
The Program Manual for the second ten-year inservice testing (IST) interval was consistent with the Code requirements (Section M 3.1).
The licensee's IST program scope was satisfactory.
Valves in the flow path for reactor core isolation cooling (RCIC) and residual heat removal systems (RHR) were described and tested in appropriate procedures.
(Section M 3.2).
The licensee has developed and implemented procedures which meet IST program
, requirements as described in the program manual. The procedures contain acceptance criteria which are consistent with ASME Section XI code requirements (Section M 3.3).
~En ineerin
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The licensee's resolution that an Emergency Diesel Generator cooler leak was not a failure was considered to be incorrect. However, the licensee performed an adequate review to determine the cause of the leak on the 1/2C diesel generator cooler (Section E1.1).
Minor problems with security metal detector arrangement and functional testing were identified. The licensee appropriately resolved these issues (Section S2.1).
The licensee was'properly monitoring and controlling personnel radiation exposure during the Unit 3 Cycle 8 refueling outage and posting area radiological conditions in accordance with 10 CFR Part 20. Personnel entering the Radiologically Controlled Area were adequately briefed on radiological hazards and protective measures.
Maximum individual radiation exposures were controlled to levels which were well within the regulatory limits for occupational dose specified in 10 CFR 20.1201(a).
The licensee was generally successful in meeting established ALARAgoals (Section R1.1).
Re ort Details Summa of Plant Status Unit 1 remained in a long-term lay-up condition with the reactor defueled.
Unit 2 operated at or near full power with routine or scheduled power decreases until the unit automatically scrammed on October 1, 1998 (See Section 01.1). The unit was returned to full power on October 5, 1998.
Uriit3 operated at decreasing power levels as preparations were made to shutdown for the Unit 3 Cycle 8 refueling outage.
The outage began at 9:00 a.m. CDT on September 20, 1998.
I. 0 erations
Conduct of Operations 01.1 Unit 2 Reactor Scram on Turbine Tri due to Hi h Stator Coolin Tem erature a.
Ins ection Sco e 71707 37551 62707 The inspector observed and reviewed actions of control room operators following an automatic reactor scram on turbine trip. Troubleshooting, repair, and the licensee's Incident Investigation Team activities were observed.
The Plant Operations Review-Committee (PORC) restart meeting was also observed.
b.
Observations and Findin s At 12:42 a.m., on October.1, 1998, the Unit 2 Control Room received indications of abnormally high temperatures in the main generator stator cooling water system.
At 12:46 a.m. operators received an annunciator indicating that the generator stator cooling water system had failed (i.e., generator high coolant outlet temperature).
Operators placed the spare stator cooling water pump in service in accordance with procedures.
This effort failed to lower stator cooling water temperature.
After 60 seconds with the condition not cleared, a turbine trip and reactor scram occurred at 12:47 a.m., as designed.
The inspector reviewed the plant response to the transient by examination of control room chart recorders and the integrated computer system printout. Due to the transient, reactor vessel level water decreased to a minimum of approximately 1 inch and reactor pressure peaked at approximately 1115 psig. Nine main steam relief valves (MSRV)
opened as a result of the reactor pressure transient associated with the turbine trip. All MSRVs satisfactorily reseated.
Plant systems and primary containment isolation equipment performed as designed.
The failure of the stator cooling system to properly cool the main generator was initially believed to be caused by a malfunctioning temperature control valve (TCV). The inspector observed portions of the system troubleshooting.
Troubleshooting personnel concluded that the system failed due to system blockage between the stator cooling
water coolers and the TCV..Troubleshooting activities were then shifted to address causes of flow blockage.
Disassembly of the Stator Cooling Water Cooler A inlet isolation globe valve (2-SHV-035-0865), revealed that the valve disc had separated from the stem.
The valve design was such that the disc was loosely threaded to the valve stem and held in place with a pin. System flow past the valve caused disc vibrations which wore down the locking pin and stem threads.
The locking pin and stem threads had worn sufficiently to fail, allowing the disc to block flowto the system heat exchangers.
Inspection of the similar valve on Unit 1 revealed similar stem thread and locking pin wear. The licensee replaced the valve and performed inspections of the remaining normally-open valves in the system of the same design.
Inspections of those valves did not indicate the wear observed on 2-SHV-035-0865. The licensee planned to inspect similar valves in the Unit 3 Generator Stator Cooling System prior to restart from the refueling outage.
An inspector attended the Plant Operations Review Committee (PORC) restart meeting and reviewed the Incident Investigation Team Event Report 98-010673-000 plant restart recommendations.
A thorough analysis of the event transient had been performed.
The inspector determined that the cause and immediate corrective actions had been appropriately presented by the Incident Investigation Team and addressed by the PORC.
The inspector verified that the scram had been entered into the licensee's maintenance rule database.
The licensee characterized the event as a functional failure. Discussion with the licensee indicated that further review would be performed by the expert panel to determine whether the event was a preventable functional failure and if it was repetitive.
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Conclusions Plant systems responded as designed when an automatic turbine trip and reactor scram occurred on Unit 2. Thorough troubleshooting of the stator cooling water system led to prompt identification of the problem. The Incident Investigation Team performed a thorough investigation of the event transient and causes.
This event was appropriately included in the maintenance rule database.
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Clearance Ta s Not Pro erl Removed Ins ection Sco e 71707 The inspector reviewed the licensee's actions taken when Operations personnel discovered that two components were in their tagged position with the tags attached after the clearance had been released. Subsequently, the inspector observed portions of the tagging of amphenol connectors on hydraulic control units following the shutdown for the Unit 3 refueling outage.
Observations and Findin s On August 31, 1998, the licensee identified two non-safety related components that remained in their tagged positions with red hold order tags attached after the clearance
,
was released and documented as restored.
Problem Evaluation Report (PER) 98-009470-000 was initiated. The inspector discussed this event with plant management.
During a subsequent inspection, on September 20, 1998, the inspector noted that the assistant unit operators did not sign the working copy of the clearance form with first and second party initials, but instead were generally. checking the list as the tags were hung. This clearance was being placed on the control rod drive amphenol connectors.
The inspector discussed this observation with plant management.
PER 98-010101-000 was initiated.
Discussion with Operations management indicated that the licensee considered the potential for clearances being implemented in the field without the appropriate diligence in signing the working copy, but no examples were identified. The inspector noted that management expectations for treating the working copy as if it was the original were clearly communicated at a subsequent shift turnover meeting.
Among the corrective actions for the initial event, an action item was implemented for a 30-day period by which the Shift Support Supervisors would review all working copies of clearance sheets returned from the field for proper verification signature/initials.
c.
Conclusions Licensee management expectations for signing the working copies of clearances in the field were not diligently implemented, as identified by two examples.
The licensee clearly communicated expectations to Operations personnel following identification of the issue.
01.3 Unit 2 Core S ra S stem Walkdown a.
Ins ection Sco e 71707 The inspector performed a detailed walkdown of the Unit 2 Core Spray (CS) system in accordance with Inspection Procedure 71707.
b.
Observations and Findin s Inspection of all accessible valves, piping and pumps showed an overall good material condition. No leakage was noted from system components.
Oil levels in the CS pumps were within tolerance.
Valves appeared to be adequately lubricated with no excessive oil leakage noted. The system lineup was in accordance with licensee procedures.
c.
Conclusions General material conditions of the Unit 2 Core Spray system were considered to be good. '
02 Operational Status of Facilities and Equipment 02.1 Unit 3 Refuelin Outa e Observations a.
Ins ection Sco e 71707 The inspectors inspected portions of Unit 3 which were not accessible during normal operations.
These areas included the drywell, reactor building side of the main steam line vault, and the torus.
b.
Observations and Findin s On September 30, 1998, the inspectors performed a tour of the suppression pool (torus). At the time of the inspection the licensee had completed the replacement of the emergency core cooling suction strainers per NRC Bulletin 96-03. Suppression pool desludging activities were in progress.
The inspectors did not identify any significant foreign material in the suppression pool ~ The licensee planned to perform a foreign material search prior to closeout.
Suppression pool coatings appeared to be in good condition.
During the torus tour the inspectors noted that most of the drywell-to-suppression pool vacuum breakers were propped open with various items (i.e., rolls of tape, shackles,
-and pipe end caps).
The vacuum breakers were apparently propped open in order to allow cooler drywell air to enter the torus. The inspector noted that the vacuum breakers were not required to be operable in the plant mode at the time (Mode 5);
however, control room personnel had not been made aware that this equipment was affected in this manner.
The operators initiated PER 98-010665 based on the inspectors'bservations.
The licensee removed the items blocking the vacuum breakers open and performed an inspection of the drywell side of the vacuum breakers for foreign material.
c.
Conclusions The results of an inspection tour of the Unit 3 torus were that material conditions were good.
Plant operators were unaware that the drywell-to-torus vacuum breakers were being propped open with various items.
Operator Knowledge and Performance 04.1 Unit 3 Reactor Shutdown for Refuelin Outa e
a.
lns ection Sco e 71707 The inspectors observed portions'of the Unit 3 reactor shutdown and the plant cooldown for the'refueling outage.
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Observations and Findin s On September 20, 1998, Unit 3 commenced a reactor shutdown and coo!down for the scheduled refueling outage.
The portions of the shutdown and coo!down observed were well-controlled.
During a review of the control room operators'ogs, the inspectors noted what appeared to be a planned entry into Technical Specification (TS) Limiting Condition for Operation (LCO) 3.0.3 due to both trains of the Unit 3 Containment Atmospheric Dilution (CAD)
system being isolated and tagged.
The logs indicated that this was performed in preparation for drywell entry scheduled for later in the shift. Entry into LCO 3.0.3 allows 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> to prepare for an orderly shutdown.
At the time that TS LCO 3.0.3 was entered,
,preparations for the reactor shutdown were in progress with plans to scram the reactor in 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />. The inspectors discussed the entry into TS LCO 3.0.3 with the licensee.
The licensee initiated PER 98-010136.
The licensee concluded that TS LCO 3.0.3 was not required to be in effect for this-situation since TS Surveillance Requirement 3.6.3.1.2 bases states that a valve is allowed to be in the nonaccident position provided it can be aligned to the accident
'position within the time assumed in the accident analysis.
The inspectors were concerned that the occurrence demonstrated that the operators involved were not appropriately sensitive to intentional entry into TS LCO 3.0.3. Licensee corrective.
actions to address this concern were not fullydeveloped at the completion of the inspection.
C.
Conclusions Operations personnel inappropriately entered into TS LCO 3.0.3 when tagging out the Unit 3 CAD system prior to reactor shutdown for the refueling outage.
Although the actual conditions for entry into TS LCO 3.0.3 did not exist, operators involved were not appropriately sensitive to intentional entry into TS LCO 3.0.3.
Miscellaneous Operations Issues (92901)
08.1 Closed Unresolved Item URI 50-260/98-01-02, Control Rod Mispositioned During Exercise Test. This item was opened pending completion and NRC review of the licensee's investigation when a control rod was inadvertently withdrawn several notches past its previous position and promptly inserted back to its intended position. The licensee's investigation determined that the cause of the mispositioned control rod was human error and the cause of the re-insertion of the control rod without direction was human error. The licensee performed numerous corrective actions which included:
simulator training on this event during licensed operator requalification training; training on peer checking; and assigning senior members (SROs) of the Operations staff to each shift crew Shift Manager to serve as mentors (after the two-week period, it was determined that this practice would no longer be needed).
In addition, Standing Order 0130 was developed to set forth specific expectations for the performance of the testing.
Specific NRC observations were documented following the event in Inspection Reports 259,260,296/98-01 and 98-0 Abnormal Operating Instruction (AOI) 2-85-7, Mispositioned Control Rod, step 4.2.4, stated that if mispositioning of the control rod is immediately noted, with the concurrerice of the Reactor Engineer and Shift Operations Supervisor (SOS), then insert or withdraw the mispositioned rod to its required position. The licensed operator failed to obtain the concurrence of the Reactor Engineer and SOS prior to inserting the mispositioned control rod. This non-repetitive, licensee-identified and corrected violation is being treated as a Non-Cited Violation, consistent with Section VII.B.1 of the NRC Enforcement Policy. This non-cited violation is identified as NCV 50-260/98-06-01, AOI not Followed for Mispositioned Control Rod. The unresolved item is closed.
G8.2 0 en Unresolved Item URI 50-296/97-10-01, RCIC Steam Trap Piping Flaw. NRC Inspection Report 259,260,296/97-10 describes the licensee's actions taken when a leak was identified on the Unit 3 Reactor Core Isolation Cooling (RCIC) system steam supply piping. The inspectors requested assistance from the NRC technical staff to interpret the applicability of the associated TS. The technical staff responded to the inspectors'uestions in Technical Interface Agreement 97-026, dated August 24, 1998, which was Enclosure 2 of NRC Inspection Report 259,260,296/98-05.
On October 1, 1998, the NRC technical staff was presented with additional information from the licensee in response to the NRC position via teleconference..The NRC requested that the licensee provide the information in writing to the Project Manager for consideration.
This e-mail correspondence was made public on October 20, 1998, via accession ¹ 9810200128.
This unresolved item remains open.
II. Maintenance M1 Conduct of INalntenance M1.1 General Comments a.
Ins ection Sco e 62707 The inspectors observed portions of the'following work activities:
Unit 3 A core spray pump breaker auxiliary switch operator replacement Unit 2 main generator stator water cooler A inlet valve, 2-SHV-035-0865, troubleshooting and repair Unit 2 reactor manual control system timer replacement Unit 3 high pressure coolant injection system steam line drain piping replacement Unit 3 scram valve diaphragm replacement and spring adjustment Unit 3 high pressure coolant injection system turbine exhaust valve, 3-ISV-73-23 repair Unit 2 B recirculation pump speed controller troubleshooting and repair b.
Observations and Findin s The inspectors found the work practices demonstrated under these activities to be good.
'Workers'ere found to be knowledgeable of their assigned tasks.
Good
troubleshooting techniques were observed.
Engineering personnel supporting the activities were knowledgeable of system design and operation.
Appropriate radiation control measures were in place. The inspectors identified a minor issue with post maintenance testing of the 3A core spray pump breaker auxiliary switch operator replacement.
This was discussed with the licensee and properly addressed.
Conclusions Thorough troubleshooting of equipment problems was observed during the inspection period. Workers were found to be knowledgeable of their assigned tasks.
Good work practices were demonstrated.
M1.2 Unit3CoreS ra S stemLo icFunctionalTest a.
Ins ection Sco e 61726 An inspector observed the performance of TS Surveillance Requirement 3-SR-3.3.5.1.6(CSI), Core Spray System Logic Functional Test Loop I. This test demonstrated operability of Core Spray (CS) System logic circuitry.
'b.
Observations and Findin s The inspector observed the performance of 3-SR-3.3.5.1.6(CSI) on August 27, 1998.
This was the first performance of the test since revised to satisfy recently implemented Improved Technical Specification requirements.
The test was lead by Operations personnel specifically designated to perform pre-outage surveillance testing.
The pre-job briefing was well-conducted.
Past problems, relay layout, and proper use of maintenance and test equipment were stressed.
The inspector noted that these expectations were continually re-enforced by the lead performer with the electricians performing certain activities during the surveillance.
Expectations of communications and second party verification performance. were stressed.
During testing the lead performer and a backup performer (both licensed senior reactor operators)
demonstrated good knowledge of the effects of procedural steps and potential consequences of improper performance.
For example, when placing insulating boots over relay contacts, electricians were informed of the consequences of inadvertent contact closure.
C.
During the testing unexpected results were experienced.
The core spray pump breakers did not automatically close when expected.
Operators conservatively backed out of the test and consulted engineering for support.
Following successful troubleshooting, the test was completed satisfactorily.
Conclusions Operators conservatively backed out of testing and consulted engineering for support when problems were encountered during core spray logic system functional testin Operations personnel performing the test demonstrated an in-depth knowledge of the test and the consequences of potential personnel errors.
M3 Maintenance Procedures and Documentation M3.1 Inservice Testin Pro ram The inspectors performed an inspection of the inservice testing (IST) program and reviewed portions of the second ten-year interval Program Manual to verify that components were identified in the program and that the required testing, frequency of testing, test parameters, and justification for deferrals were specified.
b.
Observations and Findin s The licensee's second ten-year interval began September 1, 1992, and was based on the 1986 edition of the ASME Section XI Boiler and Pressure Vessel (B&PV) Code.
However, the licensee may endorse subsequent editions provided all requirements of a subsequent edition are adopted.
The code of record for Browns Ferry Units 1, 2, and 3 isSection XI, Subsection IWP of the ASME B&PVCode 1986 edition for Pumps.
The licensee adopted the 1988 addenda of the ASME Section'XI Code which references ASME/ANSI Operations'and Maintenance (OM) Standard Part 10 for valves, and for pressure relief devices the licensee committed to OM Part 1, 1981. The inspectors found the second ten-year interval program document consistent with ASME Section XI, Subsection IWP 1986 edition and ASME/ANSI OM code standards Part 10 1988 addenda and Part 1 1981.
Elements of the Code and OM standards were incorporated into the Program Manual and into implementing plant procedures.
Required systems
. included in the IST program were identified and pump and valve tables identified the components, type of tests, test frequencies, test procedures, deferral justifications and relief requests.
~ c. Conclusions The Program Manual for the second ten-year IST interval was consistent with the Code requirements.
M3.2 Pro ram Manual Sco e
a.
Ins ection Sco e 73756 The inspectors reviewed certain aspects of the licensee's inservice testing to review the scope of the program manual
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A limited scope review was performed for the Reactor Core Isolation Cooling (RCIC)and the Residual Heat Removal (RHR) System b.
Observations and Findin s S stem Sco e Reviews The inspectors reviewed the Reactor Core Isolation Cooling (RCIC) and Residual Heat Removal (RHR) low pressure injection mode system programs and Piping and Instrumentation Drawings (P8 IDs) to verify that the valves affecting the flow path of these systems were tested in the IST program. These valves were in the program.
In addition, the inspectors reviewed test data and trending data to verify the test frequency for the quarterly tested pumps and valves for 1996 through 1998.
Some valves in RCIC and RHR systems are considered impractical to test at power and adequate cold shutdown or refueling outage justifications were included in the program manual.
Operability of a number of these valves was verified at refueling outages through the valve disassembly method using procedure 2/3-SI-3.2.3, "Testing ASME Section XI Check Valves (Internal Inspection)." Valves for disassembly are classified into 24 groups, with a maximum of 4 valves per group. One valve from each group is tested each operating cycle until all valves are inspected and then the cycle repeats.
Conclusions
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M3.3 ao The licensee's program scope was satisfactory.
Valves in the flow path for RCIC and RHR were described and tested in appropriate procedures.
Im lementin Procedures Ins ection Sco e 73756 The inspectors reviewed selected procedures to determine if code requirements were included.
Observations and Findin s The licensee had developed implementing procedures for the pump and valve tests which are listed in the program manual matrix. The inspectors reviewed a sample of the procedures to verify that the code requirements were incorporated.
The inspectors found that procedural instructions were, in general, clearly stated; the acceptance
. criteria was consistent with code requirements; and data was adequately documented.
The inspectors found that the program is adequately implemented through the plant procedures.
Periodic tests are pre-scheduled for the most part through the work management system.
However, the relief valves and cold shutdown tests are selected and tracked by the IST Engineer.
This selection is forwarded to the scheduling coordinator and work orders are issued for these tests.
The IST Engineer is responsible to see that the required percentage of relief valves are tested and that cold shutdown.
tests are initiated within 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> of plant shutdown.
Changes in test frequency are performed in the same way, The IST Engineer maintains documentation of these activities although there is no formalized procedure.
The IST Engineer must review all test results, transfer the test data to a summary review form, such as 2-SI-3.2.1, and document the data evaluatio The inspectors reviewed these activities and concluded that the IST Engineer had performed and documented the required activities.
However, there were no plant procedures which, in the event of the absence of the IST Engineer, would provide assurance that these activities would be properly performed.
In discussions with management, the licensee stated that this condition is being reviewed and corrective actions are being studied.
Procedures reviewed, in part, or totally included but were not limited to the following:
2-SI-3.2.1, Rev 20, ASME Section XI Valve Performance (Administrative Control).
2-SI-3.1.2, Rev 11, RHR Pump Performance (Performance Data Summary).
2-SI-3.1.13, Rev 3, RCIC System Pump Baseline Data Evaluation (Used to rebaseline the pump).
2-SI-3.1.9, Rev 5, RHR System Baseline Data Evaluation.
2-SR-3.5.1.6(RHR II), Rev 3, Quarterly RHR System Rated Flow Test Loop II 2-SR-3.5.3.3, Rev 2, RCIC System Rated Flow At Normal Operating Pressure.
2-SR-3.3.3.1.4(H1), Rev 0, Verification of Remote Position Indicators For Residual Heat Removal System Valves.
2-SR-3.3.3.1.4(F), Rev 0, Verification of Remote Position Indicators For Reactor Core Isolation Cooling System Valves.
2/3-SI-3.2.3, Revs 13/5, Testing ASME Section XI Check Valves (Internal Inspection)
2-SI-3.2.14, Rev 12, RHR Check Valve Operability Test (Keepfill backflow tests).
2-SR-3.6.1.3.5 (RHR II), Rev 1, RHR System MOV Operability Loop II.
2-SR-3.6.1.3.5, Rev 1, RCIC System MOV Operability.
2-SI-3.2.9, Rev 10, Testing of ASME Section XI Relief Valves.
1-SI-4.5.C.1(3), Rev 21, RHRSW Pump and Header Operability and Flow Test (Unit 1 Test).
The procedures were reviewed for consistency with the OM requirements rather than component manipulation In review of 2-SI-3.2.9 (relief valve testing), the inspectors noted that the tolerance used at Browns Ferry was+/- 6% of the set,pressure, while the code specifies+/- 3%.
NUREG 1482 gives NRC approval for licensee determined tolerances if the values are justified. Engineering calculation MD-Q0999-980119 was performed to analyze the
'ffect of using +/- 6% tolerance at Browns Ferry. This analysis concluded that no problem was created nor has the potential for any problem been identified as a result of the+/- 6% criteria. Site Engineering Drawing Change Notice (DCN) S40433A
'documents this analysis and places the new tolerance in appropriate design output documents.
E Procedure 1-SI-4.5.C.1 (3) was reviewed in conjunction with the observation of a stroke timing test on the Unit 1 RHR heat exchanger outlet valves 1-FCV-23-46 and 52.
Timing of 1-FCV-23-46 was observed from the control room and 1-FCV-23-52 was observed from the field. Valve stroke times were in the acceptable range for both valves. The inspectors had no concerns with the licensee's performance.
C.
Conclusions The licensee has developed and implemented procedures which meet IST program requirements as described in the program manual.
The procedures contain acceptance criteria which are consistent with ASME Section XI code requirements.
M3.4 Problem Evaluation Re orts PERs The inspectors'reviewed samples (24)of the problem evaluation reports (PERs) for the IST program over a span of 1996 through 1998. The problems were varied and
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included areas such as personnel knowledge, instrument locations and accuracies, actions on failed components, evaluations of program anomalies, program scope, relief valve testing, preconditioning of equipment, etc. The reports were generally clear and complete.
Tracking the resolution of problems was evident and engineering involvement in solutions was strong.
In addition the inspectors also reviewed certain operability evaluations performed by the licensee as a result of a component falling into the alert range and concluded that the IST Engineer was performing the required evaluations.
M8 Miscellaneous Maintenance Issues (62707, 92902)
M8.1 Closed Violation VIO 50-260/97-09-02, Scaffolding Controls Not Properly Implemented.
Numerous examples of noncompliance with procedural controls were identified. The licensee attributed the noncompliances to ineffective oversight by maintenance supervision of scaffolding activities. Also,'the licensee found that the governing procedure, O-TI-264, Scaffold and Temporary Platforms, was cumbersome and contributed to the failures to followprocedure.
The inspector verified that the licensee's corrective actions were reasonable and complete.
The licensee revised the governing procedure to simplify the requirements for erecting scaffolding. For example, the 17 appendices of the procedure were simplified and consolidated into 6. The inspector verified that the examples of the violation and
corrective actions were incorporated into indoctrination training for.scaffolding workers.
On September 16, 1998, the inspector completed a walkdown of approximately 25 scaffolds/platforms erected in the Unit 3 Reactor Building which were pre-staged for the refueling outage which began on September 20, 1998. The inspector found that all scaffolding which did not meet the plant equipment clearance requirements had supporting checklists and engineering evaluations as specified by 0-Tl-264. Minor discrepancies found by the inspector were promptly corrected by the licensee.
Appendix A of 0-Tl-264 listed areas of the site which require seismically qualified scaffolding. The inspector found that the reactor building air intake structures were not listed although these areas contained safety-related plant operating equipment.
The licensee initiated PER 98-009948 and promptly performed a review of all site areas for safety-related or seismically-qualified equipment.
The licensee found one additional area of the site, cooling water gate structure P3, which should have been listed in the appendix due to its seismic qualifications.
The licensee concluded that past scaffolding erected in reactor building air intake structures did have seismic qualifications. The inspectors concluded that other-steps in the appendix which required Operations department contact prior to erecting and the seismic qualification of scaffolding in areas with safety-related equipment were sufficient to ensure that proper controls were implemented in the reactor building intake structures.
The licensee planned to clarify the procedure by listing the additional areas in the appendix.
This violation is closed.
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Conduct of Engineering III. En ineerin E1.1 ao Emer enc Diesel Generator Cooler Failure h
Ins ection Sco e 37551 The inspector reviewed the requirements for evaluation of the replacement Emergency Equipment Cooling Water Heat Exchanger associated with the 1/2C Emergency Diesel Generator (EDG). The inspector reviewed related documentation, discQssed American Society of Mechanical Engineers (ASME) Code,Section XI requirements and program procedure documentation with the licensee, and received technical assistance from NRC ASME Code experts.
Observations and Findin s In August 1997, the licensee identified that the 1/2C Emergency Diesel Generator had a tube leak in the emergency equipment cooling water (EECW) heat exchangers.
This was identified by a level increase in the jacket water cooling system.
Discussions with the licensee indicated that they replaced the EECW heat exchangers instead of repairing the leak in order to minimize the out of service time of the affected diesel.
Subsequent testing revealed that the leaking tube was leaking in the tube roll, slightly in front of the roll transition on the 1C1-heat exchanger.
The 1C2 heat exchanger exhibited no leak The licensee's corrective action program developed a root cause analysis which stated,
"This was most likely cause'd by Stress Corrosion Cracking and/or erosion, both characteristics of these coolers'in their application, aggravated by general thinning.
Without metallurgical evaluation, it is not possible to positively determine the mode of tube failure, and because of the age of the coolers and the cost of the evaluation fhere would be little benefit to having this information, therefore there is no plan to perform a metallurgical evaluation.
Based on Inservice Organization inspection records, these coolers were placed in service in 9/87. The original tube bundles lasted for approximately fourteen years, therefore the recently replaced coolers are at or nearing their end of life. Therefore the root cause of the failure of this component, for its application and use, is component aging.".
ASME Section XI 1989-Division I, Section IWA-7220, states, in part, that if a.
replacement is required because of failure of an item, the evaluation shall consider cause(s) of failure of the existing item to ensure that the selected item is suitable.
If cause of failure appears to be a deficiency in the specification for the existing item, the specification for the item to be used for replacement shall reflect appropriate corrective provisions.
Although the ASME Code does not specifically define the term failure, the licensee's procedure for ASME Code,Section XI, implementation defines a failure as any unanticipated condition that renders an item less fitfor further use or the item can no longer perform its intended function.
The NRC staff reviewed this matter and determined that because Section XI is a component'code, it is inappropriate to take a systems approach to the question.
The pressure boundary integrity of the tube was lost, which constituted a failure. Therefore, an evaluation should have been performed to ensure that the replacement items were suitable.
The inspector noted that the licensee had performed a root cause analysis and documented it in their corrective action program. The inspector could not conclude that the ASME Code specifically required metallurgical evaluation as part of the Code.-
required evaluation.
January 1998 eddy current data from the 3B Emergency Diesel Generator coolers described indications representing a 92% through wall outer diameter (OD) damage and a 67% through wall damage.
These appear to be isolated.
Discussions with the licensee did not identify any other indications of problems.
The licensee also documented in PER 98-08927 that these indications were identified using a new type of probe and new inspection techniques including higher gain settings.
It also states that because of the size of the indications and the new inspection methods there is a good probability that the indications existed previously but were not detected.
There has been no general degradation mechanism identified in the tube outer diameter.
PER 98-08927 documentation stated that eddy current inspections have been performed on the heat exchangers on an approximate two-year frequency.
Therefore, the inner diameter (ID) erosion mechanism is well-monitored and presents no imminent concerns.
It is also apparent that trending is performed within the eddy current
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examination report which addressed years in service of previous versus present EDG cooler sets.
The licensee retubed the heat exchangers associated with the 1/2C and 1/2D
.
During the retubing maintenance, the NRC questioned a buildup of residue on the outside of the heat exchanger tubes, the side exposed to the jacket water system.
The licensee performed a chemical analysis of the material and
'nformed the inspector that the residue was composed of dried rust inhibitor and brass.
The inspector r'eviewed data from the most recent 24-hour run prior to the 1/2C and 1/2D diesel generator coolers being replaced.
The data indicated that the engine cooling water outlet temperature was generally steady and was within the acceptable temperature range throughout the tests.
The licensee determined that the expected life of the heat exchanger is 10 to 12 years based on past performance of the heat exchangers and a specific Certificate of Conformance which documented the Qualified Life as 12 years.
In addition, the licensee described the comprehensive chemical treatment process used to control microbiologically-'induced corrosion (MIC) on the EECW heat exchangers.
The licensee indicated that a biocide, dispersant, and corrosion inhibitor were used to killthe microorganisms, keep the particles in the flow stream, and suppress the
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corrosion reactions.
In the case of the EECW heat exchanger, the copper in the brass tubes is toxic to the microorganisms, inhibiting formation.
In addition, the faster flow retards MIC initiation. The inspector questioned MIC initiation in the residual heat removal service water system considering that system is often in a standby, stagnant condition. The licensee indicated that a different biocide is used and the tubes are not made of the same material. The component engineer indicated that he had not identified cases of MIC corrosion in the RHR system and that the chemical treatment is apparently effective.
c.
Conclusions The licensee's resolution that an Emergency Diesel Generator cooler leak was not a failure was considered to be incorrect.
However, the licensee performed an adequate review to determine the cause of the leak on the 1/2C diesel generator cooler.
ES Miscellaneous Engineering Issues (92903)
E8.1 Closed A
arent Violation EEI 50-260 296/98-05-03 Inadequate RHR Valve Logic and Interlocks Surveillance.
During closeout of LER 50-260/97-002 in NRC Inspection Report 50-259,260,296/98-05, the inspector identified that the procedures used to perform functional testing of RHR loop I/IIvalve logic and interlocks did not adequately test relay contacts 3-4 of relays 10A-K90A, -K91A, -K90B, and -K91B when testing was performed at reactor pressures greater than 230 psig. This condition existed for Units 2 and 3. This was an apparent violation of TS 5.4.1.a, which requires written pr'ocedures
A
to be established, implemented, and maintained for TS-required surveillances. The issue remained open for a reasonable time to allow the licensee to develop its corrective actions.
The license'e's corrective action plan was finalized on September 10, 1998.
The licensee determined that the cause of the inadequate procedure was miscommunication between the personnel who originally identified that the surveillances did not properly test all relay contacts in the circuitry'and the personnel implementing the procedure change.
The procedure could be performed at reactor pressures greater than or less than 230 psig. The original procedural problem was identified as inadequate testing of the low pressure inputs (i.e., <230 psig) to the recirculation discharge valve circuitry. Personnel performing the procedure change believed that this meant that only the portion of the test which performs testing at reactor pressures less than 230 psig needed to be revised.
However, both portions of the test (i.e., at reactor pressures greater, than as well as those less than 230 psig) needed to be revised.
The licensee subsequently revised 2/3-SR-3.3.5.1.6 (CI and Cll) to correctly test relay contacts 3-4 of relays 10A-K90A, -K91A, -K90B, and K91B when testing is performed
.above a reactor pressure of 230 psig. These actions were completed on August 28, 1998. The licensee performed a work order on September 9, 1998, to test the associated relay contacts for Unit 2. This was necessary in order to ensure that the equipment was maintained within the TS-required periodicity prior to the next scheduled performance of the surveillance.
Performance of the surveillance per the revised surveillance procedures was completed on Unit 3 on September 11, 1998. The licensee confirmed that procedure changes for other testing deficiencies identified during review'f NRC Generic Letter 96-01 were properly implemented (see NRC closeout of LER 50-259/97-002-00 in IR 98-03).
In addition, system engineers will receive training on the causes and corrective actions of the occurrence. The inspector verified that the revised procedures and work orders performed on Unit 2 correctly tested the relay contacts.
This issue is identified as VIO 50-260,296/98-06-02, Inadequate RHR Valve Logic and Interlock Surveillance.
The inspector concluded that information regarding the reason for the violation, and the corrective actions taken and planned to correct the violation
'and prevent recurrence was adequately addressed.
This apparent violation is close'd.
Closed Unresolved Item URI 50-260/98-05-04, Rod Block Monitor Inoperable.
On August 16, 1998, during Unit 2 control rod drive exercise testing, control room operators identified that the rod block monitor remained bypassed when an internal rod was, selected following the selection of an edge rod in the same'rod group. Control rod testing was stopped and the problem was investigated.
Additional troubleshooting determined that the rod block monitor system was failing to perform a null sequence for rods that were selected within the same rod group.
Detailed testing was performed by the licensee on the available Unit 3 mockup which was planned for installation during the Fall 1998 outage.
The equipment vendor was also contacted for support.
The licensee concluded that the setting of a potentiometer within the rod block monitor interface module was the cause of the problem.
The licensee's corrective action involved extensive testing using the Unit 3 mockup to determine the root cause of the symptoms identified. On August 20, 1998, the potentiometer was adjusted'on Unit 2 to ensure that all control rod selects would initiate
a null sequence.
In addition, the post modification test package was revised for the Unit 3 work. The licensee performed a review of the vendor manual and design drawing documentation to identify all potential analog adjustments.
The review also included a visual inspection of the available chassis and modules to verify that all potential analog
'djustments have been identified. Several analog adjustments were identified.
Technical Specification 3.3.2.1 states that with two Rod Block Monitor (RBM) channels inoperable, place one RBM channel in trip in one hour. The failure to identify the inoperable RBM channels and take the actions specified by the TS is identified as Non-Cited Violation 50-260/98-06-03, Inoperable RBM. This non-repetitive, licensee-identified and corrected violation is being treated as a Non-Cited Violation, consistent with Section VII.B.1 of the NRC Enforcement Policy. This unresolved item is closed.
IV. Plant Su ort R1 R1.1 Radiological Protection and Chemistry (RP&C) Controls Occu ational Radiation Ex osure Control Pro ram a(
Ins ection Sco e 83750 The inspectors reviewed implementation of selected elements of the licensee's radiation protection program during the Unit 3 Cycle 8 (U3C8) Refueling Outage (RFO). The review entailed observation of radiological protection activities including personnel exposure monitoring, radiological postings, and verification of posted radiation dose rates and contamination levels within the Radiologically Controlled Area (RCA). Those activities were evaluated for consistency with the programmatic requirements, personnel monitoring requirements, occupational dose limits, radiological posting requirements, and survey requirements specified in Subparts B, C, F, 8, and J of 10 CFR 20.
b.
Observations and Findin s The inspectors conducted frequent tours of the RCA to observe radiation protection activities and practices.
Personnel preparing for routine entries into the RCA and for, entries into the drywell were observed being briefed on the radiological conditions in the areas to be entered.
The briefings were given by radiation control personnel before access was granted and covered the dosimetry and the. protective clothing and equipment re'quired by the Radiation Work Permit (RWP) for the entry. The administrative limits for the allowed dose and dose rate for the entry were emphasized during the briefings. The briefings provided thorough descriptions of the existing dose rates which could be encountered during the entry. The inspectors determined that personnel entering the RCA were adequately briefed on the radiological hazards which could be encountered while in the RCA and the radiological protective measures required to be taken during the entry. Individuals at selected job sites were interviewed and it was determined that the workers were aware of their administrative dose and dose rate limits, the work area dose rates, the proximate low-dose waiting areas, areas of high contamination, and protective clothing required by the RW dose rate limits, the work area dose rates, the proximate low-dose waiting areas, areas of high contamination, and protective clothing required by the RWP.
The inspectors observed the use of personal radiation exposure monitoring devices by personnel entering and exiting the RCA. Thermoluminescent dosimeters (TLDs) were used as the primary device for monitoring personnel radiation exposure.
In addition, digital alarming electronic dosimeters (EDs) were used for monitoring the accumulated dose and the encountered dose rates during each RCA entry. The EDs were set to alarm at administrative limits established for the specific RWP under which the RCA entry was being made.
As the individuals exited the RCA the accumulated dose and encountered dose rate information was transferred from the EDs to the Radiation Exposure System (REXS) data base in order to track individual exposures.
During tours of the RCA the inspectors noted that the required dosimetry was being properly worn by personnel when entering and while in the RCA. The inspectors also noted that personnel exiting the RCA routinely surveyed themselves for contamination using personal contamination monitors (PCMs).
During tours of the RCA, -the inspectors noted that general areas and individual rooms
.
were properly posted for radiological conditions.
Survey maps indicating dose rates and contamination levels at specific locations within the RCA were posted at the entrance to the RCA. Radiological postings were also conspicuously displayed at individual contaminated and high radiation areas.
'At the inspectors'equest, a licensee Health Physics Technician performed dose rate and contamination surveys in several rooms and locations. The inspectors verified that the survey instrument readings were consistent with the posted area dose rates.
Contact dose rates from several radioactive material-bearing containers were also verified to be consistent with the dose rates recorded on container labels.
Independent contamination surveys performed around several posted contaminated areas indicated that contamination was not being tracked out of the contaminated areas.
The inspectors compiled the annual and outage collective dose data, presented in the table below from the licensee's REXS and As Low As Reasonably Achievable (ALARA)
reports. The REXS tracks the cumulative dose on a fiscal, rather than a calendar, year basis and therefore the annual ALARAgoals were also established on a fiscal year basis.
The outage doses were listed in the table by the calendar year in which they occurred and in some cases the outage periods crossed fiscal year ends.
Collective Dose (Man-Rem)
Fiscal Year Annual Dose Actual Goal
Year Mean Unit/
Cycle Outage Dose Actual Goal Days 1994 426 500 588 U2C7'24'80
1995 850'95,717
Collective Dose (Man-Rem)
1996 1997 1998 432'83'49'10 360 489
- 569 522 U2CS U3C7'2C9 U3CS 241 56'77'
350 180 342 110
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23'
's of 10/1/98 RFO
'cheduled for 23 days beginning 9/20/98 As indicated in the table, the licensee was usually successful at meeting established ALARAgoals.
Based on the scope of work, the licensee's ALARACommittee established an officialALARAgoal of 158 man-rem for the U3C8 outage and a challenge goal of 110 man-rem.
The challenge goal was exceeded twelve days into the scheduled 23-day outage, which began on 9/20/98, but the licensee indicated that the official 158 man-rem goal was still achievable.
The licensee also provided the inspectors with data from the REXS data base pertaining to maximum individual radiation exposures for years 1994 through 1997 and year-to-date 1998. The inspectors verified that the data were consistent with the REXS data base and tabulated the data in the table below.
Maximum Individual Radiation Doses Rem Year 1994 1995 1996 1997 1998'EDE 2.949 1.131 1.813 2.176 2.419 Skin 7.383 1.876 2.160 2.239 2.478 Extremi 3.620 10.493 2.289 2.595 2.478 E e Lens 2.969 1.139 1.844 2.213 2.444 Re ulato and Administrative Limits 10 CFR 20 Admin.
5.000 50.000
.1.000 None 50.000 None 15.000 None
'ear-to-date as of 9/28/98
The administrative annual dose limits established by the licensee were delineated in section 3.4.1.6 and Table 1 of procedure SPP-5.1, Radiological Controls. The procedure specified that the 1.0 rem administrative limitcould be exceeded only if authorized by the Site Radiological and Chemistry Control Manager, and that exposures exceeding 5.0 rem required authorization by the Site Radiological and Chemistry Control Manager, the Plant Manager, and the Site Vice president.
As indicated in the table, the maximum individual radiation exposures during the years 1994 through 1997 and year-to-date 1998 were well within the regulatory limits for occupational dose specified in 10 CFR 20.1201 (a).
The inspectors reviewed the licensee's procedures for follow-up actions to,Personnel Contamination Events (PCEs) and reviewed selected records for those events which occurred during 1998. Procedure FO-IP-1 Personnel Decontamination, indicated that the threshold for initiating follow-up actions was skin or personal clothing contamination in excess of 100 net counts per minute (ncpm), as measured by a hand-held frisker.
(Contamination on licensee-provided modesty garments and contamination from noble gas were not counted as.PCEs.)
The licensee's records indicated that 63. PCEs occurred prior to the start of the U3CB outage and that 91 occurred during the first eleven days of the outage.
Procedure DOS-IP-7, Skin Dose Assessment and Calculation, specified that dose assessments were to be initiated whenever an individual may have received a shallow dose to the skin of the whole body or to the extremities in excess of 100 millirem (mrem) from skin or personal clothing contamination.
As of October 2, 1998, skin dose assessments had been initiated for one PCE which occurred prior to the U3C8 outage and for one after the start of the outage.
The inspectors reviewed the dose calculations for those two events and noted that the assigned doses were less than 500 mrem to the extremities for both events.
Procedure SPP-5.1, Radiological Controls, specified that internal dose assessments were to be initiated
~whenever bioassay results indicate that an individual may have had an uptake of radioactive material in excess of one percent of the Annual Limiton Intake (ALI). The licensee's records indicated that internal dose assessments were initiated for three uptakes which occurred prior to the U3C8 outage and for seven uptakes which occurred during the first twelve days of the outage.
The inspectors reviewed the dose calculations for the three uptakes which occurred prior to the outage and noted that the assigned internal doses were less than 25 mrem. The preliminary results from the dose calculations for the uptakes which occurred during the outage indicated that the internal doses were less than 50 mrem.
No regulatory dose limits were exceeded.
The inspectors also reviewed the licensee's records for contaminated floor space within the RCA. Radiological Control personnel maintained records of the areas within the RCA, excluding the drywells, which had contamination levels in excess of 1000 disintegrations per minute per 100 square centimeters (dpm/100 cm'). Contaminated areas were categorized as either temporarily contaminated areas (c-zone) or non-recoverable/exempt areas.
The c-zone square footage was tracked on a daily basis and monthly averages were calculated.
The inspectors noted that during non-outage periods the monthly averages for c-zone square footage during 1998 (year-to-date)
were less than one half of one percent of the RCA floor space and the non-recoverable/exempt areas were 15 percent of the RC Conclusions S2 Based on the above reviews and observations, the inspectors concluded that the licensee was properly monitoring and controlling personnel radiation exposure during the Unit 3 Cycle 8 refueling outage and posting area radiological conditions in accordance with 10 CFR Part 20. Personnel entering the RCA were adequately briefed on radiological hazards'and protective measures.
Maximum individual radiation exposures were controlled to levels which were well within the regulatory limits for occupational dose specified in 10 CFR 20;1201(a).
The licensee was generally successful in meeting established ALARAgoals.
Status of Security Facilities and Equipment S2.1 Securit Metal Detector Preventive Maintenance and Functional Test ao Sco e 71750 An inspector observed the performance of quarterly security metal detector preventive maintenance.
Detector arrangement was compared with vendor recommendations.
Performance of the functional test when the detectors were returned to service was also observed.
Observations and Findin s On September 9, 1998, the inspector observed the performance of preventive maintenance on the security metal detectors in the West Gate Access to the plant protected area.
This maintenance was performed by plant instrument and controls (ILC) maintenance personnel.
The maintenance performs a periodic cleaning and inspection of the detectors.
The l&Cworkers performed this maintenance with no problems noted.
The inspector found that placement of some of the detectors did not correspond with guidance in the vendor manual. The licensee determined that the arrangement of the detectors had not affected their operation.
The licensee subsequently instituted measures to ensure consistent detector placement in the future.
.The inspector observed a functional test of the detectors by security personnel.
The inspector identified a minor issue associated with the performance of the test which was determined to not affect test results.
The licensee was informed of the inspector's findings and appropriate corrective actions were taken.
Conclusions Minor problems with security metal detector arrangement and functional testing were identified. The licensee appropriately resolved these issue V. Mana ement Meetin s X1 Exit Meeting Summary The resident inspectors presented inspection findings and results to licensee management on October 9, 1998. Additional formal. meetings to discuss inspection findings were conducted on September 11 and October 2, 1998.
PARTIALLIST OF PERSONS CONTACTED Licensee T. Abney, Licensing Manager.
J. Brazell, Site Security Manager R. Coleman, Radiological Control Manager R. Greenman, Training Manager J. Johnson, Site Quality Assurance Manager R. Jones, Acting Plant Manager R. Moll, System Engineering Manager G. Little, Operations Manager D. Nye, Site Support Manager D. Olive, Operations Superintendent R. Ryan, Engineering Manager J. Shaw, Design Engineering Manager K. Singer, Site Vice President J. Schlessel, Maintenance Manager INSPECTION PROCEDURES USED IP 37551:
IP 62707:
IP 61726:
'IP 71707:
IP 71750:
IP 73756:
IP 83750:
IP 92901:
IP 92902:
IP 92903:
Onsite Engineering Maintenance Observations Surveillance Observations Plant Operations Plant Support Activities Inservice Testing of Pumps and Valves Occupational Radiation Exposure Follow-up-Plant Operations Follow-up Maintenance Follow-up-Engineering ITEMS OPENED DISCUSSED AND CLOSED OPENED
~Te Item Number NCV 50-260/98-06-01 Status
'Closed Descri tion and Reference AOI not Followed for Mispositioned Control Rod (Section 08.1)
NCV 50-260/98-06-03 Discussed
~Te Item Number URI 50-296/97-10-01 CLOSED
~Te Item Number VIO 50-260/97-09-02 EEI 50-260,296/98-05-03 Open Closed Status Open Status Closed Closed Inadequate RHR Valve Logic and Interlock Surveillance (Section E8.1)
Inoperable Rod Block Monitor (Section E8.2)
Descri tion and Reference RCIC Steam Trap Piping Flaw (Section 08.2)
Descri tion and Reference Scaffolding Controls Not Properly
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Implemented (Section M8.1)
Inadequate RHR Valve Logic and Interlocks Surveillance (Section E8.1)
URI 50-260/98-01-02
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Closed Control Rod Mispositioned During Exercise Test (Section 08.1)
Closed Rod Block Monitor Inoperable (Section E8.2)
SYNOPSIS The U.S. Nuclear Regulatory Commission (NRC), Office of Investigations, initiated this investigation on Harch 5, l998, based on a Tennessee Valley Authority incident investigation report which provided details about a
mispositioned control rod at the Browns Ferry Nuclear Plant.
The report did not contain sufficient information in statements taken from shift personnel involved.
There were concerns'ith the NRC staff. that the log entry was misleading and there was a possible deliberate procedure violation.
The evidence developed in this investigation did not substantiate the NRC staff concern that a false log book entry was made or that there was a
deliberate violation of procedure.
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pg8 Gase No. 2-1998-00?
Ehclosure 3