IR 05000327/1997006
| ML20141H958 | |
| Person / Time | |
|---|---|
| Site: | Sequoyah  |
| Issue date: | 07/28/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20141H951 | List: |
| References | |
| 50-327-97-06, 50-327-97-6, 50-328-97-06, 50-328-97-6, NUDOCS 9708040130 | |
| Download: ML20141H958 (70) | |
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U.S. NUCLEAR REGULATORY COMISSION
REGION II
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Docket Nos:
50 327, 50 328 License Nos:
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Report Nos:
50 327/97-06, 50 328/97 06 I
I Licensee:
Tennessee Valley Authority (TVA)
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Facility:
Sequoyah Nuclear Plant, Units 1 & 2
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Location:
Sequoyah Access Road
Hamilton County, TN 37379
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l Dates:
May 25 through July 5,1997 i
Inspectors:
M. Shannon, Senior Resident Inspector R. Starkey, Resident Inspector D. Seymour, Resident Inspector
W. Bearden, Region II (RII) Reactor Inspector (Section M4.2 - M4.3)
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a E. Testa, RII Reactor Inspector (Section R1)
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P. Taylor, RII Project Engineer (Section 07.2 07.2)
S. Sparks RII Project Engineer (Section 07.2 07.3)
l J. Starefos, Resident Inspector, Browns Ferry Nuclear
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Plant (Section 07.2 07.5)
i C. Smith, RII Senior Reactor Inspector (Section E2.3 -
E2.4)
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E. Girard, RII Reactor Inspector (Section E1)
T. Scarbrough, Senior Mechanical Engineer, Office of
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Nuclear Reactor Regulation (NRR), (Accompanying i
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Personnel)
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M. Holbrook, INEEL (Accompanying Personnel)
Approved by:
M. Lesser, Chief Reactor Projects Branch 6
Division of Reactor Projects
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Enclosure 2 9708040130 970728 PDR ADOCK 05000327 G
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EXECUTIVE SUMMARY Sequoyah Nuclear Plant, Units 1 & 2 NRC Inspection Report 50 327/97-06, 50 328/97 06 This integrated inspection included aspects of licensee operations, maintenance, engineering, plant support, and effectiveness of licensee controls in identifying, resolving, and preventing problems. The report covers a six week period of resident inspection.
In addition, it includes the results of announced inspections in the areas of engineering, maintenance, corrective action program, and health physics performed by regional and headquarters inspectors.
Operations Operations successfully performed significant power changes on Unit 2 to e
repair a failed letdown isolation valve, to repair a failed sensing line on the 28 main feedweter pump, and due to a main transformer relay actuation; and on Unit 1 to repair a main feedwater pump (Section 01.1).
e A non cited violation was identified for the failure of the licensee to perform steps of a procedure in the correct sequence, resulting in establishing a flow path for essential raw cooling water to enter and contaminate the "A" condensate storage tank (Section 01.3).
A weakness in operator training was identified for the failure of two e
operator trainees to successfully parallel emergency diesel generators to their shutdown boards (Section 05.1).
e A Quality Assurance outage assessment effort was substantial and was effective in the identification of licensee strengths and weaknesses during the Unit 1 Cycle 8 refueling outage (Section 07.1).
The implementation of the Corrective Action Program (CAP) processes e
appeared to have improved since the audit of October 1996. However, the monthly CAP status reports, and weaknesses with Problem Evaluation Reports (PER) identified during this inspection, indicated that improvement may not be continuing. Continued management attention and Nuclear Assurance involvement, along with more effective implementation by the line organization of the CAP process is necessary.
(Section 07.2).
Self assessments by operations resulted in several improvement o
initiatives. The peer review program, in combination with review of PERs and other related material, has been succes.sful in identifying the raw data from which corrective actions can be developed and implemented.
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However, recent issues are evidence that actions in response to self-
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assessments have not resulted in sustained improvements in performance.
(Section 07.3).
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A positive observation was noted for operation's timely identification e
of improper work activities on the excess letdown valve (Section M4.1).
Maintenance
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Self assessments by maintenance provided an accurate picture of the e
performance of the maintenance department. A declining trend in the maintenance area was identified following a more thorough and critical
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review of self assessment and other site information. Corrective actions to address the identified weaknesses have been developed, most notably in the area of personnel accountability, human performance, and i
supervisory oversight.
However, recent issues are evidence that actions in response to self-assessments have not yet been fully effective (Section 07.3).
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I During plant power changes, numerous equipment problems and material e
i condition deficiencies caused challenges to the operations staff (Section 01.2).
A positive observation was noted with the extensive troubleshooting plan e
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and post maintenance testing plan developed by the maintenance manager with the support of engineering (Section M1.2).
- The pre job briefing for the replacement of a Unit 2 Loop 2 steam e
generator level controller was thorough, and the replacement of the controller by instrument maintenance personnel was carefully performed.
The entire evolution was well planned and executed (Section M1.3).
A non cited violation was identified for failure to inspect both sides i
e of nine fire barrier penetrations (Section M1.4).
A positive observation was noted with housekeeping improvement in the turbine building (Section M2.1).
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o One non cited violation was identified for failure to follow maintenance i
instructions during repair work on a Unit 2 excess letdown isolation l
valve (Section M4.1).
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e Significant corrective actions were taken, or were in the process of being completed, for the deficiencies identified by the licensee in
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their May 5, 1997, Generic Letter (GL) 96 01 Report. A non cited violation was identified for four examples of inadequate surveillance
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instructions related to the GL 96 01 review.
Required surveillance testing was performed during the March 1997 refueling outage, and prior to reactor startup following the forced outages in June 1996 and
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November 1996 (Section M4.2 and M4.3).
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Enaineerina Implementation of Generic Letter 89-10 at Sequoyah was not sufficiently e
complete to permit closure of the NRC review (Section E1.1).
e Weaknesses were identified in the analyses of stroke time failures of turbine driven auxiliary feedwater trip and throttle valve 1-FCV 151 documented in two PERs (Section E1.1 and E2.2).
The licensee employed personnel who were knowledgeable of industry e
issues and obtained accurate diagnostic measurements in implementing Generic Letter 89 10 (Section E1.1).
A violation was identified for the licensee's failure to implement e
adequate corrective actions to correct the improper setting of the safety injection system relief valves. (Section E2.1).
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Corrective actions developed and implemented for motor cperated valves e
not having "T" drains in their limit switch compartments were consistent with design requirements and NRC's guidance in Generic Letter 91-18 (Sectior.E2.3).
e The overall quality of plant modifications M8779A and M8780A was determined to be good. The broad scope of the plant modifications have achieved the design objective of re-establishing configuration control for Sequoyah's Environmental Qualification Program (Section E2.4).
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Plant Sucoort The inspectors determined that the licensee effectively implemented a e
program for shipping radioactive materials required by the Nuclear Regulatory Commission and Department Of Transportatien regulations (Section R1.2).
Radiological facility controls and housekeeping in radioactive waste e
storage areas were observed to be good. Material was labeled appropriately, and areas were properly posted (Section R1.3).
e Radiation worker internal and external doses were being maintained well below regulatory limits and the licensee was continuing to maintain exposures as low as reasonably achievable (Section R1.3).
One non cited violation was identified for failure of a radiographer to e
follow site procedures (Section R1.3).
e A violation was identified for failure to replace the rubber gasket-seals for railroad tracks required to maintain the auxiliary building at a negative pressure as described by the Updated Final Safety Analysis Report and detailed design documents (Section R1.3).
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The licensee's water chemistry control program for monitoring primary e
and secondary water quality had been implemented, for those parameters reviewed, in accordance with the Technical Specification requirements (Section R1.4).
The Fuel Integrity Assessment team was aerforming the required fuel e
integrity assessments as specified by tie Site Standard Practice (Section R1.4).
The radiological impact from facility operation was less than 1 percent e
of the 40 CFR 190 regulatory limit. The exposures calculated from the 1996 Annual Radioactive Effluent Release Report resultant data were consistent with results from the preoperational monitoring program (Section R1.5).
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Report Details-
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Summary of Plant Status a.
Unit 1 began the inspection period in power operation. The unit operated at 100% power until June 28,'when power was reduced to 62* for maintenance on the
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main feed pumps, Power was restored to 100% on June 30, and the unit operated l
at power for the remainder of the inspection period.
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I Unit-2 began the inspection period in power operation. The. unit operated at l
100% power until~ June 6 when power was reduced to approximately 28% to repair the normal letdown isolation valve.
Power was restored to 100% on June 9 and the unit operated at 100% power until June 18,:when power was reduced to
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approximately 56% to remove and re) air the 2B main feed pump. Power was
restored to 100% on June 19, and t1e unit operated at 100% until July 4, when i
power was reduced to approximately 60% due to a main transformer Bucholtz relay actuation (high combustible gas concentration).
Power was restored to
l 100% on July 5, and operated at 100% for the remainder of the inspection i
period.
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Review of Vodated Final Safety Analysis Reoort (UFSAR) Commitments While performing inspections discussed-in this report, the inspectors reviewed
i the applicable portions of the UFSAR that were related to the areas inspected.
l The inspectors verified that the UFSAR wording was consistent with the j
observed plant practices, procedures, and/or parameters.
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Conduct of Operations (71707)
01.1 General Comments-
Using Inspection Procedure 71707, the inspectors conducted frequent
reviews of ongoing plant operations.
In general, the conduct of o)erations was good. Operations successfully made significant power
clanges on Unit 2 to repair a failed letdown isolation valve, to repair
a failed sensing line on the 2B main feedwater pump, and due to a main
transformer relay actuation; and on Unit 1 to repair a main feedwater i
pump. Specific events and noteworthy observations are detailed in the
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sections below, i
i 01.2 Operational Challenaes Durina Plant Power Chanaes i
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Inspection Scope
j The' inspectors reviewed the various operational challenges encountered during the four significant unit power reductions to perform plant
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b.
Observation and Findinas The inspectors noted various equipment problems that were being
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encountered during plant power changes. The equipment problems varied during each plant transient: however, the problems were unexpected and resulted in operational challenges. The inspectors observed some of the failures and noted the other failures in the control room logs. The failures were as follows:
Unit 2 Power Reduction to 28% on June 6, and Power Increase to 100% on June 9.
During the initial load decrease:
a feedwater regulating valve caused a 7% level deviation; the letdown heat-excharger outlet flow indicator failed: when removing the #3 heater drain tank pump, the #3 heater drain tank level started oscillating, resulting in LCV 6 105A opening and closing repeatedly: fire protection to the seal oil unit was isolated due to a failure of 2 FCV 26 72 to reset; the pressurizer spray line temperature " low temperature" alarm annunciated, causing the operators to take manual control of the pressurizer spray valve: while removir.g the 2A main feedwater pump from service: the governor valve positioner stopped moving and appeared to be stuck: the Neutral Overcurrent relay for the "B" cooling tower transformer picked up. causing the "B" common station service transformer sup)1y breaker to trip and actuation of the fire protection system: the hig1 pressure gland steam pressure began oscillating and bringing in computer alarms; and the excess letdown valve failed closed.
(Refer to Section M4.1).
During the power increase:
operators had difficulty adjusting the #3 heater drain tank level due to the heater drain tank pump recirc valve leaking through; the main steam reheat warming valves were found closed when they should have been opened per 0-G0 4, Step (16); and operators received a " Computer Alarm Rod Deviation and Power Range Tilts" alarm due to a high upper detector quadrant power tilt ratio.
Unit 2 Power Reduction to 56% on June 18 and Power Increase to 100% on June 19.
During the power decrease: operators received the pressurizer spray line temperature low alarm: operators received a ground alarm on the 250 V DC battery due to a 160 volt ground; the "A" main feedwater pump did not load up as cuickly as expected, resulting in operators reducing turbine load anc taking manual control of the feedwater regulating valve to dampen the level swings and the #2 steam generator level was slower to recover than the other levels; and the axial flux difference (AFD)
went out of the administrative target band.
During the power increase: the 2B condensate booster pump developed excessive seal leakage: and the 2C condensate booster pump recirc valve developed significant leakage.
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- Unit 1 Power Reduction to 62% on June 28 and Power Increase to 100% on
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June 30.
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the C-4 heater level went low and the normal level control valve was found stuck: the 18 B main feedwater pump
' suddenly unicaded almost 1 million pounds mass per hour, the 1A A main feedwater pump _apwared to have overcompensated and feedwater pressure went too high; a )roblem Evaluation Report (PER) was initiated for decreasing power (17% per hour) in excess of the planned 10% per hour:-
the 1A A main feedwater pump had to be taken to manual to settle out steam generator flow swings: and the main transformer phase "A" group #1 fan #10 appeared to be locked up.
Ouring the power increase: the "B" condensate booster pump was already warmed up due to the suction valve leaking through; and the "A" air
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l compressor tripped on high oil temperature, i
Unit 2 Power Reduction to 60% on July 4 and Power Increase to 100% on July 5.
L During the power increase: the 2A condensate booster pump tripped during the start sequence due to an excessive amount of water in the i:
pump's oil system; and the AFD monitor alarm was suspected of being
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inoperable due to the AFD being outside the target band and with no
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alarm reflash capability.
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l The problems, while not all inclusive indicated a need for further
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licensee effort in improving plant equipment reliability. They also appeared to present a high number of challenges to the operations staff, mtentially causing the operators to see these challenges as routine.
Related to this, is a Nuclear Assurance finding (weakness) detailed in-Section 07.1 of this, report that stated, "When abnormal and/or unanticipated actions occurred, control room personnel generally reacted to the conditions as a normal evolution, when a more appropriate response would be to stop and establish a clear understanding of the condition."
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Conclusions Each equipment failure, by itself, did not present a safety significant
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problem however, the collective number of failures during each evolution challenged the operators and indicates material condition weaknesses.
01.3 Essential Raw Coolina Water (ERCW) Enters Condensate Storaae Tank (CST) via Auxiliary Feedwater System (AFW)
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Insoection ScoDe l
The inspectors reviewed the circumstances which resulted in ERCW water
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(river water) entering the "A" CST via the AFW system.
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Observation and Findinas On April 29, 1997, with Unit 1 in Mode 5, during performance of
Surveillance Instruction (SI) 1-SI 0PS 003-118.0, Auxiliary Feedwater Pump and Valve Automatic Actuation, Revision 3, the ERCW flow control valves (FCV) to the turbine driven auxiliary feedwater (TDAFW) pump opened unex>ectedly. The valves were o)en for approximately two minutes during whic1 time a flow path existed w11ch allowed ERCW water to go to the TDAFW pump suction, out the common recirculation line, and then to the CSTs.
Prior to this occurrerce, the 1 SI 0PS 003 118.0 lineup had isolated the steam generators to prevent flow from the AFW system. On the following day, April 30, the chemistry laboratory re)orted that CST
"A" had elevated chloride levels.
It was at that time t1at the flow path from the TDAFW was identified as the source of the elevated chloride levels.
Prior to the performance of 1 SI 0PS-003-118.0 TDAFW CST suction valve 1-VLV 003-809 was tagged closed due to concern for excessive leakage out of the pump outboard seal. The ERCW FCVs were already tagged closed as required by General Operating procedure 0 G0-7 Unit Shutdown From Hot Standby to Cold Shutdown. The TDAFW pump suction pressure switches for Wap over to ERCW are located between the CST suction valve and the pump. Due to the location of the pressure switches, with the CST suction valve closed, the low suction pressure switches for the swap-l over to ERCW were in the " actuate" position. This low pressure condition caused the " low suction pressure to the AFWPs" alarm window to be illuminated. However, the presence of this alarm was not addressed in the pre job briefing, nor was it questioned by the operators or the test director during the briefing. With the TDAFW low suction pressure input present, only the TDAFW trip and throttle valve being greater than 50% open was needed, once power was restored, to cause the ERCW FCVs to open.
In preparation for 1-SI 0PS-003 118.0, the Test Director released the hold order on the ERCW FCVs to all three Unit 1 AFW pumps, which placed power on all ERCW FCVs. The lifting of the hold order took place prior to Section 6.1 of 1 SI 0PS-003118.0, but was not directed by the procedure until Sections 6.5 and 6.7.
During aerformance of Section 6.2 of the SI, an actuation signal was initiated w11ch resulted in the TDAFW trip and throttle valve opening. When the trip and throttle valve opened, the logic was completed (low suction pressure from the CST and trip and throttle valve being greater than 50% open) and the ERCW FCVs opened.
Steps in Sections 6.5 and 6.7 would have prevented the FCVs from opening if the hold order had been released in the correct sequence. The test director, who was in the control room, noticed the i
ERCW valves going open. Operators promptly closed the valves. Actual l
open time was approximately two minutes from the TDAFW start signal to closure of the valves by operators.
The inspector reviewed the licensee's corrective actions, as detailed in PER No. SQ971275PER, and concluded that they were appropriate to prevent recurrence of this event.
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l The licensee failed to perform steps of procedure 1 SI 0PS-003118.0 in l
the correct sequence which resulted in establishing a flow path for ERCW to enter and contaminate the "A" CST. This licensee identified and corrected violation is being treated as a non cited violation (NCV),
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l consistent with Section VII.B.1 of the NRC Enforcement Policy (NCV 50 328/97 06 01).
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Observations One NCV was identified for failure to follow procedure steps in sequence.
Operator Training and Qualification 05.1 Emeroency Diesel Generator (EDG) Testina a.
Inspection Scong The inspectors reviewed the circumstances of two EDG output breakers tripping open while paralleling the EDGs to their shutdown boards during two consecutive weekly surveillance tests.
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Observations and Findinas On June 6 and June 12, while performing 2 SI 0PS 082-007.A. Electrical Power System Diesel Generator 2A A, and 2-SI 0PS-082 007.B. Electrical Power System Diesel Generator 2B-B, the output breakers for the 2A-A and 2B B EDGs, respectively, tripped open while the EDGs were being parallelled to their shutdown boards.
In each case, the generator output breaker tripped on instantaneous overcurrent. On June 6 the instantaneous overcurrent relay was reset and the diesel was successfully synchronized to the shutdown board. On June 12. the instantaneous relay was checked and reset, the generator tested, and the EDG successfully rerun and synchronized to the shutdown board.
The licensee determined the cause of the output breakers tripping was inexperience of the operators (trainees) in synchronizing the EDGs to their shutdown boards. The 3rocedure requires the operator to adjust the synchronizing scope to o)tain an indication of slowly rotating in the fast direction, and to close the breaker when the synchroscope indicates between the five minutes till and 12 o' clock position, which the trainees did.
If the synchronizing scope is rotating too slowly in the fast direction, and/or the breaker is closed at a slightly greater than five minutes to 12 o' clock >osition, an overcurrent condition can result, tripping the EDG output areaker. The licensee concluded that the operator trainees were acting in an overly cautious manner by l
adjusting the synchronizing scope to travel too slowly in the fast l
direction, and by closing the breaker at that slow speed at five minutes to the 12 o' clock position. The licensee implemented procedure change forms to revise the procedures for both units to require closing the l
breaker when the indication is at 12 o' clock.
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c. ' Conclusions
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The inspectors considered the failure of the two operator trainees to successfully parallel the EDGs to their shutdown boards to be weakness in operator training.
Quality Assurance in Operations (40500)
07.1 Review of the Unit 1 Cycle 8 Quality Assurance (0A) Outaae Assessment a.
Inspection Scope l
The inspector reviewed the Unit 1 Cycle 8 outage oversight assessment (NA-SQ 97 43) to gain an independent review of licensee performance during the refueling outage.
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Observations and Findinas l
The inspector noted that the Nuclear Assurance assessment team (13 members) initiated 125 PERs during the outage. The team reached the following global conclusions which were documented in the assessment i
report, "The report identified numerous recurring human performance i
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and line verification due to procedure noncompliance and conflicting
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work standards. Overall, the self-assessment process appears to be less than fully effective in monitoring / enforcing / correcting problems at the first level of supervision."
The nuclear assurance team noted the following weaknesses:
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Apparent varying (conflicting) operations performance standards, e
and operators not performing daily and frequently performed tasks
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with the same accountability as sensitive work activities,
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Critical evolutions not recorded in operator logs, and log entries j
that were either inaccurate or insufficiently documented, The conduct of event critiques needed improvement, o
e Observation of the residual heat removal xamp cavitation
[defueled] and reactor coolant system leac during restoration indicated an area for improvement. When abnormal and/or unanticipated actions occurred, control room personnel generally reacted to the conditions as a normal evolution. A more appropriate response would have been to stop and establish a clear understanding of the condition, The conduct of the Plant Operations Review Committee (PORC)
e continued to be a weakness: PORC scheduling and formality needed
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to improve,
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The plant's response to QA identified issues concerning the e
l January adverse trend PER on procedural adherence, and the
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l November PER on wrong unit / wrong train / wrong component was not prompt and resulted in a missed opportunity to improve the areas l
prior to the outage.
l The nuclear assurance team noted the following strengths:
Overall planning and prioritization of outage activities were e
focused toward improvement of plant material conditions, Positive management improvement initiatives were being e
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l implemented, The conduct of complex and infrequently performed test pre-job e
briefings was good.
e Site engineering support improved significantly, Improvement initiatives were implemented to capture lessons
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l learned from Watts Bar and Browns Ferry, The goals and objectives for improving plant material condition o
were fully accomplished, The management oversight / observation process was expanded to e
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include medium risks evolutions.
l The inspector noted that the assessment included extensive documentation l
of these findings. The inspector also noted that three of the weaknesses l
were related to and/or supported previously documented NRC inspection report (IR) findings.
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Conclusions l
The inspector concluded that the QA outage assessment effort was i
substantial and was effective in the identification of licensee i
strengths and weaknesses during the Unit 1 Cycle 8 refueling outage.
l 07.2 Corrective Action Program a.
Inspection ScoDe Using the guidance of Inspection Procedure 40500. Effectiveness of Licensee Controls in Identifying, Resolving, and Preventing Problems, the inspector reviewed licensee's corrective action program (CAP) as delineated in SSP 3.4, Corrective Actions. The review included an evaluation of the quality of PERs, an assessment of Management Review Committee (MRC) involvement in the CAP process and whether the CAP
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requirements are being effectively implemented.
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Observations and Findinas The inspector reviewed corporate NA&L audit report SSA 9509, dated l
July 31,1995. This audit identified significant weaknesses concerning i
the CAP implementation and PER No. SQ950563PER was issued to address the i
audit finds, which were:
Inadequate or incomplete root cause analysis.
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Some identified adverse conditions were not being documented in the corrective action program as required.
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Examples of tardiness in the developing (20 working days) and l
e implementing (60 working days) of PER corrective actions.
Examples of inadequate root cause determinations leading to high e
levels of recurrence.
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e Examples of no interim actions being assigned to PERs, nor
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reviewed by management.
A subsequent NA&L audit of the CAP (SSA 9613 dated November 4, 1996)
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occur. An NA&L Escalation Report was presented to site management on October 17, 1996, to demonstrate that previous corrective actions had not been thorough and that apparent cause analysis and extent of condition did not probe dee ly enough, resulting in incomplete resolution of CAP issues.
he licensee issued PER No. SQ962389PER to address the SSA 96013 audit finding.
The inspector reviewed the implementation of corrective actions associated with several PERs, including PER No. SQ962389PER, and also
observed MRC meetings. The following observations resulted from these l
reviews:
The site QA organization has initiated continuous oversight of the CAP processes.
Indicators are established to monitor CAP implementation with a status report being issued monthly. The status report identifies problem areas which require management attention. The ins)ector's assessment of the data from these monthly status reports (iovember 1996 May 1997) indicated that CAP implementation improvement is not l
continuing.
Repetitive issues that continue to appear in these status
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reports were:
tardiness in the development and implementation of PER corrective actions: the quality of tP corrective action plans and the PER closure packages: weak similar ever.. and extent of condition searches; and improvement in the line organizations ability to identify
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deficiencies during their self assessments of the CAP process implementation.
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The inspector reviewed some PERs written on the auxiliary feedwater
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system (AFW) and PER No. SQ962526PER, which identified that NA&L had not established effective oversight of the CAP for an approximate 18 month l
period (April 1995 - September 1996).
l The inspector noted that Block 4 of PER No. SQ962526PER, "Immediate l
Actions Taken," had no assigned actions.
Block 9 of the PER,
" Corrective Action," had no specific corrective actions identified, l
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program implementation would be conducted in June 1997.
In discussing l
these concerns with QA personnel, the inspector determined that multiple
immediate actions and other corrective actions had been taken by the
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licensee, but had not been documented on the PER. Subsequently, PER No.
SQ962526PER was revised to reflect corrective actions taken and planned.
l The inspector noted that many PERs selected for review on the AFW system
had previously been evaluated by NA&L. NA&L had identified deficiencies l
with most of these PERs which were corrected. No additional
l deficiencies were identified.
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During a walkdown of the Unit 110AFW system it was noted that two steam
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traps in parallel drain piping were covered with insulation. The-inspector questioned whether the insulation could affect the ability of J
the steam traps to perform their function.
During a subsequent
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l walkdown, the ins)ector observed that insulators were removing the insulation from t1e Unit 1 steam traps. The inspector brought to the
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licensee management's attention that a PER was not immediately initiated, and subsequently PER No.
SQ971512PER was written. The PER l
indicated that an inspection of Unit 2 TDAFW system revealed that there
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was no insulation on the drain piping or steam traps, as per drawing requirements, and that the Unit 1 drawings were not clear on insulation i
requirements.
In a subsequent telephone call with a Licensing Department contact, the inspector was informed that the licensee had l
contacted the steam trap vendor and concluded that the steam trap will still perform its function if insulated.
The licensee made changes (memorandum October 4, 1996, and April 28, l
1997) to MRC activities in order to strengthen line manager's ownership l
of the CAP process. Changes made included the deletion of the PER Review Subcommittee functions and the establishment of requirements for the HRC to review the corrective action plans for all Level A and B PERs i
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as well as selected Level C PERs.
The inspector observed MRC meetings on June 3-6, 1997, and noted that discussions were on PERs which were returned to the MRC for review of proposed corrective actions. The PER evaluation summaries returned to
the MRC, in general, addressed a description of the condition, immediate action taken, interim action, previous similar events, extent of condition, apparent cause, and corrective action. The inspector noted that the MRC did not accept all PER corrective action plans as presented to the MRC. For example, PER No. SQ971036PER's corrective action plan,
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which was discussed at the HRC meeting on June 5, 1997, was returned to the preparer to address aspects.
The MRC actions taken during the meetings appeared to be consistent with their charter, c.
Conclusion The implementation of CAP processes appeared to have improved since the audit (SSA 96013) of October 1996.
However, the monthly CAP status reports, along with weaknesses with PERs identified during this inspection, indicated that improvements in implementing the CAP processes may not be continuing and has leveled off.
Continued management attention along with more critical self assessment by the line organization and more effective implementation of the CAP 3rocess is necessary. This is of particular importance as the site NA&_ plans to stop the continuous oversight of the CAP in the very near future.
07.3 Line Oroanization Self-Assessment a.
Inspection Scope
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The licensee's self-assessment of operations was reviewed and evaluated,
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which included the program as described in Operations Directive Manual i
ODM 0.5, and the observation / peer checks of job and training performance as described in ODM 0.6.
In addition, the licensee's self assessment of maintenance was reviewed
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and evaluated, which included a review of the Site Trend Analysis Committee reports, quarterly maintenance and modifications self-assessments, and the peer evaluation program and reports.
b.1 Observation and Findinas - Operations Self Assessment The inspectors reviewed the following self assessment information, and other data provided by the licensee:
The operation's self assessment program as described in ODM 0.5. The program consists of analyzing trends using performance indicators. A major source of data is provided by the Observations Sheets from ODH-0.6, PERs, and a monthly activity report provided by NA&L.
ODM 0.6, Observationheer checks of job and training performance. This program is based on lip 0 guidelines, and participation of the operations department has been good. Current improvement initiatives included sending operating crews to other plants to identify good operating practices, continuing to stress improvement in plant material condition such as operator work-arounds, main control room disabled functions, the creation of a mentoring program by assigning a supervisor to each operator, emphasis on procedural compliance, and pre job briefs. The peer review pre-am has also resulted in the generation of many PERs.
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l The most recent quarterly review, which w, completed for the period January 1 to March 31, 1997, and identifieu satisfactory or good performance in all areas except fire arotection systems, which was
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identified as needing improvement. T1e inspector noted that performanca in plant status controls had changed from "needing improvement" to
" satisfactory" since the previous quarter.
ODM 1.4, Operations Top Ten Concerns.
Some of the concerns included establishing a "mentoring" program within operations crews, assistant unit operator (AU0) watchstanding practices / visits at other sites, operator work arounds, reduction of procedural adherence events by operators, and inter / intra department communications.
Level B PER No. SQ970199PER, initiated by Industry Affairs in late January 1997, due to an adverse trend in procedural compliance for the
period of July December 1996.
Minutes of a recent Nuclear Safety Review Board Operations Subcommittee meeting, held in March 1997, where several opportunities for improvement
were noted in the area of operations self-assessments. These included i
additional management observations of the AVO staff, training of the shift management personnel in observation skills, and inclusion of
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cross discipline activities in the self assessment 3rogram. A concern was expressed by operations shift management that t1e self-assessment program focused too much on quantity and not quality. The inspector discussed these observations with operations management, who indicated that actions were being taken or developed to address these concerns.
The inspector agreed that a substantial quantity of data was being generated as a result of the operations self assessments. This was due
i to the increase in the number of PERs from prior years, and the peer j
review program.
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'Recent problems and events associated with plant operations. These problems include control room communications and oversight, control room
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logs, and corrective actions as discussed in NRC irs 50-327, 328/97 04 and 97 05.
In addition, recent NA&L assessments and/or PERs have also identified continuing concerns in procedural compliance and status control, and other human performance problems. These issues indicate that operation's self asse: sments have not resulted in substantive improvements in the operations area.
b.2 Observations and Findinas Maintenance Self Assessment The inspectors reviewed and discussed the peer evaluation program with maintenance personnel.
For calendar year 1996, over 1500 peer evaluations were conducted, with a similar number on schedule for 1997.
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This information is reviewed monthly for strengths or weaknesses, and
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the information is sent to the training center to review for potential training issues. The inspector's review of the peer evaluation cards indicated that substantive information and feedback was being
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identified. The inspectors consider the participation in the peer
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Based on the peer evaluation program and NA&L monthly trends, the j
maintenance self assessment identified that performance had declined in
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several areas.
These areas included plant material condition, conduct of maintenance, maintenance procedures and documentation.
In addition, switchyard activities were noted as still needing improvement, and maintenance history was identified as unsatisfactory.
Based on this declining trend, maintenance concluded that the standards and accountability of maintenance personnel at all levels needed to be improved, and several corrective actions were taken. An outside contractor was brought in to help ~ focus on supervisor and general foreman performance, and each was re evaluated for their individual performance. Supervisory training was conducted, and included the development of a guideline book describing management expectations.
Performance criteria for each supervisor was re written to reinforce performance expectations. Scenario training was used to reinforce and coach administrative and procedure adherence skills with craft personnel. The threshold for technical training grade level acceptance was changed from 70% to 80%.
The inspectors also reviewed a site wide common cause assessment, conducted in March 1997. This effort reviewed data from the last six months of 1996, and was the third such assessment-to be conducted by the site. The assessment noted that corrective actions were already in
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place to improve problems associated with attention to detail, inadequate job skill and work practices, and these efforts were partially effective. However, as discussed earlier, a Level A PER No.
SQ971488PER was initiated June 2, 1997, by NA&L due to an adverse trend identified for human performance during the Unit 1 Cycle 8 refueling outage for conduct of maintenance and operations.
c.
Conclusions Self assessments by operations resulted in several improvement initiatives. The peer review program, in combination with review of PERs and other related material, has been successful at. identifying the raw data from which corrective actions can be developed and implemented.
However, recent issues are evidence that actions in response to self-assessments have not resulted in substantive improvements.
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Self assessments by maintenance, in conjunction with other site information, have provided an accurate picture of the performance of the maintenance department. A declining trend in the maintenance area was identified following a more thorough and critical review of self-assessment and other site information. Corrective actions to address the identified weaknesses have been developed, most notably in the area of personnel accountability, human performance, and supervisory
oversight.
However, recent issues are evidence that actions in response
to self assessments have not been fully effective.
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08 Miscellaneous Operations Issues (92901)
08.1 (Closed) Licensee Event Report (LER) 50 328/96-007:
Enaineered Safety I
Feature (ESF) Actuation. Start of the Auxiliary Feedwater System. As a
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Result of Inadeauate Return of Eauipment to Service. This event was discussed in IR ~50 327, 3 N /96 14.
No new issues were revealed by the LER.
08.2 (Closed) LER 50 327/96 006: A Failed Couoled Capacitor Potential Device i
Caused Actuation of the Generator Backue/ Transformer Feeder Relav Triooina the Turbine and the Reactor. This event was discussed in IR 50 327, 328/96 08.
The LER concluded that the most probable cause of
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the coupled capacitor failure was that the lower capacitor module began to conduct current because of internal degradation. The corrective
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actions described in the LER were reasonable and complete. With the exception of the arobable cause of the failure, no new issues were revealed by the LER.
l 08.3 (Closed) IFI 50 328/97-01 05:
Review Root Cause Which Led to Notice of Enforcement Discretion (N0ED) on EDG, The inspectors monitored the repair of the 2A A EDG governor actuator as it occurred on February 13-
l 15, 1997, and concluded that the failure was not related to any l
maintenance activities performed on the actuator and the licensee could i
l not have predicted the failure. Once the failure was identified, the i
licensee worked expeditiously to replace the actuator and subsequently l
used approximately 20 of the 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> which the NRC had approved in the
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extension of the Technical Specification (TS) allowed outage time. The i
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actual failure mechanism of the actuator is described in LER 50 327/97-002.
l (Closed) LER 50 327/97 002: Enforcement Discretion Granted When i
Problems With the 2A A Diesel Generator Actuator Was Identified. The l
request and approval for enforcement discretion was discussed in IR 50-
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327, 328/97 01. As stattd in the IR, the inswctors verified the licensee's compensatory actions which were tacen during the additional allowed outage time of the 2A A EDG. The inspectors reviewed the root causes and the corrective actions related to the governor actuator l
failure, as described in the LER, and determined that they were
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reasonable and complete.
No similar problems were identified.
l-II. Maintenance M1 Conduct of Maintenance (61700, 61726, 62703, 62707, 64704)
M1.1 General Comments a.
Inspection Scope
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The inspectors observed and/or reviewed all or portions of the following work activities and/or surveillances:
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e 2 SI ICC 003 039.3 Channel Calibration of Steam Generator 1 Level Channel III Rack 11 Loop L 3-39
(L518)
e WO 97 008251 000 Replace Eagle Input /0utput Card e
0 SI 0PS 082 007.M Diesel Generator Surveillance Frequency
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e 2-SI 0PS 082 007.B Electrical Power System Diesel Generator 2B B
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e 0 SI SXV-003 243.0 Full Stroke Testing of Check Valves 0 3-
894 and 0 3 895
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e 1 SI-SXP 003-201.B Motor Driven Auxiliary Feed Water Pump j
1B B Performance Test
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e 1-SI-0PS 082-007.B Electrical Power System Diesel Generator 1B B e
SI-102 M/M Diesel Generator Monthly Mechanical Inspections e
0 PI-SXP 018 007.4 Diesel Generator 18 B Fuel Oil transfer Pump Performance Test e
0-SI CPS 067-682.H ERCW Flow Balance Valve Position Verification e
0 SI-SXV 067 245.3 Full Stroking of the 1B B DG ERCW Check Valves e
1-S0 2/3 1 Condensate and Feedwater System e
1 SI-SXV 000 004.0 Remote Valve Position Indication Verification e
0 SI SXV-001 266.0 ASME Section XI Testing (TDAFW Trip and Throttle Valve)
e 1 SI 0PS 082 007.A Electrical Power System Diesel Generator 1A A e
0 SI-SXV 062 266.0 ASME Section XI Testing (Letdown Isolation Valve)
b.
Observations and Findinos The inspectors noted that the work activities and the 3erformance of surveillance activities were adequately performed, wit 1 the exception of the TDAFW surveillances documented in Section E2.2.
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M1.2 Failure of EDG 2A A a.
Inspection Scope The inspector reviewed the engineering, maintenance and testing
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activities associated with the repair of the 2A A EDG following a i
generator fault during the monthly surveillance test.
b.
Observations and Findinas
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During the monthly surveillance test of the 2A A EDG, the 2A A EDG
tripped and the instantaneous overcurrent and differential current arotective relays picked up.
Observers in the diesel generator room 1eard a " boom," felt the air compression, and noted a puff of smoke from the diesel generator.
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Subsequently, the licensee developed an extensive troubleshooting plan to identify the generator fault.
Initial meggaring and testing failed to identify any problem, so the generator housing was disassembled for i
visual inspections. The fault was eventually identified as a phase to
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phase short as a result of previous maintenance activities.
It was swculated that during cable replacement activities in February 1997, tlat the stator insulation was cracked leading to the fault.
In addition, the fault occurred at a point where a tie wrap was used to tie i
off the replacement cables to the stator and the use of the tie wrap was being questioned.
The inspector observed the licensee's troubleshooting activities and the planning for those activities. The inspector noted that the maintenance manager, with assistance from engineering, developed an extensive troubleshooting plan: and following identification of the fault, developed an extensive retesting program for ensuring EDG operability.
The inspector noted that the failure on July 2,1997, was the second
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failure in the last twenty starts and would result in weekly testing of I
the 2A A EDG.
In addition, the July 2, failure was the sixth failure in the last 100 start attempts and required a 30 day report be' available for audit (due August 1). A subsequent ammendment to the Technical Specifications issued July 14, 1997, eliminated the requirements for increased testing and the 30 day report. An IFI is being identified to review the licensee's reliability improvement and failure analysis. (IFI 50 327, 328/97-06 03),
c.
Conclusions An IFI was identified to review the licensee's reliability and failure analysis.
A positive observation was noted with the extensive troubleshooting plan and post maintenance testing plan developed by the maintenance manager with the support of engineering.
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M1.3 Reclacement of Unit 2 Looo 2 Steam Generator Level Controller a.
Insoection Scope The inspector observed the replacement of the Unit 2 Loop 2 steam generator level controller on June 12, 1997.
b.
Observations and Findinos The inspector attended the pre job briefing and observed portions of the actual replacement of the Unit 2 Loop 2 steam generator level controller. The controller had a recent history of periodically drifting which would result in steam generator level increases as large as 7%. These level deviations were documented in IR 50 327, 328/97 04.
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The controller replacement was performed under Work Order (WO) 97-006224. The pre job briefing was thorough and the replacement of the j
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controller by instrument maintenance personnel was carefully performed.
i Operators involved in the evolution had received special training on the
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Sequoyah simulator prior to the controller replacement. The entire evolution was well planned and executed.
No further problems were noted during the inspection period.
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M1.4 Review of Fire Barrier Visual Insoections a.
InsDection Scooe
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The inspector reviewed work request (WR) C386982, WO-97007232, and 0 SI-
FPU 302-001.R. Fire Barrier Visual Inspection Auxiliary Building Elevation 690 and Below, Revision 0, and 0 SI-FPU 302 002.R. Fire Barrier Visual Inspection Auxiliary Building Elevation 706 and Above, Revision 0, regarding the licensee's visual inspections of fire barriers and penetrations of fire barriers in the auxiliary building.
b.
Observations and Findinas On April 8,1997, the licensee initiated WR C386982 to inspect the fire sealant material in nine penetrations located in the auxiliary building.
The licensee's inspection of these nine penetrations was part of a larger scope inspection of numerous penetrations. The purpose of the inspection was to ensure that the penetrations met the design drawing descriptions. Each penetration inspected had a unique penetration number for each end of the penetration. WR C386982 listed both identification numbers for each of the nine penetrations to be ins >ected. The WR stated that the penetrations were to be inspected on
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bot 1 sides of the penetration for an evaluation of penetration seal type and integrity.
Enough insulation on both sides of the penetrations was
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to be removed such that the depth and condition of the fire sealant material in the penetration could be inspected.
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On May 3, 1997, the licensee initiated WO 97007232 to inspect and rework the nine mechanical / electrical penetration seals identified in WR C386982. However, the WO only listed the identification number for one side of each of the nine penetrations and did not specify that both sides of the each penetration were to be inspected. The W0 directed that the pre and aost maintenance testing should be performed using 0-SI FPU 302-001.1 and 0 SI FPU 302 002.R.
Both of the sis, in Step 6.2, directed that the fire barriers were to be inspected on both sides of walls, floors, hatch covers and ceiling as listed in Appendix A of the SI.
On May 13, 1997, a maintenance technician visually inspected each of the nine penetrations.
However, the technician only inspected the one side listed in the W0. On the SI data sheet associated with each penetration, the technician wrote "na" (not-applicable) for the penetration side which was not inspected. The technician apparently followed the specific instructions in the W0, which only listed one side of each penetration, and in doing so, failed to comaly with the
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requirements of the SI to inspect both sides of eac1 penetration.
On June 14, 1997, WO 97007232 was signed off as being completed.
However, on June 20, 1997, one of the foreman assigned to the fire penetrations inspection, while reviewing his notes, discovered that-one of the penetrations needed additional inspection / work. He then took steps to retrieve the closed W0 and to reinspect the penetration in question (penetration number A06690W0034).
On June 25, 1997, the inspector accompanied the licensee to inspect penetration number A06690W0034 and verified that the penetration contained ',ess than the required 12 inches of insulation.
PER No.
SQ971629PER was written to document that the fire barrier contained less than the minimum required insulation. Although the licensee determined
that the penetration still met the requirement for a 1 / hour fire barrier,additionalsealantwasaddedtomeetthe12incilesrequirement.
The licensee also questioned whether other penetrations had been inadequately inspected and, as a corrective action, reinspected 100% of the previously inspected penetrations (138 penetrations).
c.
Conclusions The inspector determined that the licensee failed to inspect both sides of nine fire barrier penetration seals as required by procedures 0 SI-FPU 302 001.R and 0 SI FPU-302 002.R and failed to identify that one of the nine penetrations contained less than the recuired amount of sealant material. This licensee identified and correctec violation is being treated as an NCV, consistent with Section VII.B.1 of the NRC Enforcement Policy (NCV 50 328/97 06 04). A contributing factor to this NCV was WO 97007232 did not specify that both sides of fire barrier l
penetrations be inspected.
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M2 Maintenance and Material Condition of Facilities and Equipment (62707)
M2.1 Plant Housekeepina Condition Imorovements
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a.
Insoection Scope
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The inspectors observed the housekeeping of the facilities during routine plant observations, b.
Observations and Findinas
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During routine plant walkdowns the inspectors observed the housekeeping condition of the units. Specifically, significant im)rovements in housekeeping over the last six months were noted in t1e turbine building
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for both units. This included painting, cleaning and removal of equipment and debris.
In addition, the improvements were made following
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significant work in the turbine building for condenser tube replacements
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during the recent Unit 1 outage. The licensee's efforts were continuing
and were addressing other areas of the plant.
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Conclusions A positive observation was noted with housekeeping improvement noted in
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the turbine building.
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M4 Maintenance Staff Knowledge and Performance (61700, 62707)
M4.1 Imoroner Work Activities On the Unit 2 Excess Letdown Isolation Valve i
a.
Insoection Scope
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The inspector reviewed the maintenance and operation activities
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associated with the repair of the Unit 2 letdown isolation valve and the i
improper maintenance activities performed on the Unit 2 excess letdown j
isolation valve.
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Observations and Findinas i
At 1:47 p.m., on June 6,1997, the Unit 2 reactor coolant system letdown isolation valve failed closed. At 1:59 p.m., excess letdown was placed in service.
Subsecuently, reactor power was decreased to approximately 30% in order to recuce the area radiation levels so that personnel could enter the reactor building and inspect the letdown isolation valve.
During the ins >ection, maintenance noted that the ASCO solenoid valve associated wit 1 the letdown isolation valve had failed.
WRs were initiated to make the appropriate repairs, management oversight was assigned, and the maintenance workers were taken to Watts Bar Unit 2 to observe the location of the valve in containment.
In addition, prior to the start of the work activities, detailed pre job briefings were held with workers and supervisors.
Initial containment entries were made and the scope of the maintenance activities was determined. Health
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physics personnel accompanied the workers into the radiation areas and appropriate stay times were provided.
Following the initial entry by maintenance workers with a management observer, different maintenance workers entered containment to disassemble the letdown isolation valve (2 FCV 62 69). The management observer did not go to the work location with the workers during the initial disassembly. Approximately 10 minutes after the start of the l
work activities, the Unit 2 control room operator noted that the valve indicator lights for the excess letdown isolation valve (2-FCV 62 54)
had gone out and that the pressurizer level had decreased. The maintenance job supervisor was called and asked to verify maintenance activities on the correct valve.
It was determined that the maintenance workers had started work on the wrong valve. The excess letdown valve was reassembled and operations reestablished excess letdown flow and recovered pressurizer level.
The NRC resident inspector was observing control room activities during this evolution and noted that the control room operators did an excellent job in identifying the improper work activities. There were no alarm functions to warn the operators of the loss of excess letdown and if disassembly of the excess letdown valve actuator / operator had progressed, a high level pressurizer trip could have occurred.
Following the reassembly of the excess letdown valve, the maintenance workers were debriefed by plant management.
It was determined that the pre job briefing had not identified the fact that there were two similar valves in the work area. The inspector considered the most significant deficiency was that although extensively trained in "self checking techniques " the maintenance workers had failed to self check that they were on the correct valve prior to starting work.
In this event, the licensee considered this work to be a " sensitive" activity, extensive pre job briefs were conducted, on the job observation of the work area was conducted at Watts Bar Unit 2, management oversight was provided, and the valves were clearly tagged; however, the workers did not verify the valve identification tags prior to starting work. The failure to work on the correct valve is considered to be a failure to follow the maintenance W0 and is considered to be a violation.
The inspector noted that operations did an excellent job in identifying that work was being performed on the wrong valve and subsequently, maintenance did a good job in using positive reinforcement in dealing with this event by having the responsible manager and workers brief the rest of the maintenance staff and the NRC, on the human performance errors that led to this event. This licensee-identified and corrected violation is being treated as an NCV, consistent with Section VII.B.1 of the NRC Enforcement Policy (NCV 50 328/97 06-05).
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Subsequently, the licensee restarted repair activities for the letdown isolation valve. The ASCO solenoid was found to be degraded and was
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replaced; the air supply regulator was found maintaining air supply pressure at the wrong pressure (low) and was readjusted to ap3roximately 60 asig; this resulted in failure of the valve diaphragm whic1 then had
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to >e replaced.
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Conclusions j
One NCV was identified for failure to follow maintenance instructions.
A positive observation was noted for operations timely identification of improper work activities on the excess letdown valve.
M4.2 Testina of Safety Related Loaic Circuits a.
Inspection Scope Generic Letter (GL) 96-01, Testing of Safety Related Logic Circuits, was j
issued by the NRC to address problems in the industry with the testing of safety related logic circuits required by TSs. GL 96 01 required licensees to compare schematic drawings and logic diagrams to surveillance procedures for those systems to ensure that existing s
testing was adequate to satisfy TS surveillance requirements (SR).
The ins)ector reviewed licensee actions associated with GL 96 01 for Sequoyal. This review included a review of the licensee's disposition of various issues identified by the licensee during their review.
Additionally, the inspector selected various SRs and verified that the licensee's surveillance testing program was adequate and that the associated SR was satisfied.
b.
Observations and Findinas The inspector reviewed the Sequoyah GL 96 01 Review Report, which was issued on May 5, 1997. This report documented the licensee's review effort in this area along with disposition of the various issues identified during the review. The inspector determined that three separate examples of TS SRs which were not satisfied by existing sis had been identified by the licensee as the result of the GL 96 01 review.
Three PERs were generated to document these TS SR violations which resulted in issuance of two LERs, 50 327/97 003 and 50 327/97 008. One other example of an inadequate SI had been identified by the licensee's T&PS group prior to the GL 96-01 review and was addressed separately in the licensee's May 5, 1997 GL 96 01 Report. That issue was described in LER 50 327/97 001. The inspector reviewed these three LERs and determined that the licensee's corrective actions were adequate. These LERs are discussed in more detail in Sections M8.5, M8.6, and M8.7 of this report. The licensee had attributed the failure in each case to inadequate sis.
For each case the appropriate limiting condition for operation (LCO) was entered, required testing performed and the associated SI revised. The licensee failed to perform adequate
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surveillance testing, however this is being treated as an NCV,
consistent with Section VII.B.1 of the NRC Enforcement Policy (NCV 50-327, 328/97-06 06, Failure to Properly Perform Surveillance Testing).
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The inspector noted that the licensee had also identified numerous other
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examples of sis which failed to test all attributes of the logic i
circuits.
In all of those examples the licensee had determined that although the procedures required revision to test all attributes of the -
i logic circuits, existing testing had satisfied the language in TS.
In
each of those cases licensee personnel had documented the specific issue
in the GL 96 01 Review Report. These issues resulted in 11 additional
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change requests, and a required UFSAl change. The inspector selected several of those issues for detailed review to determine the adequacy of i :
the licensee's corrective actions. No problems were identified with the licensee's disposition of those issues. The inspector determined that
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significant corrective actions were taken, or were in the process of
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being completed by the licensee for the deficiencies identified by the
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licensee in the May 5, 1997, GL 96 01 Report.
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Conclusions
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The licensee's GL 96 01 review identified several inadequate sis along l
with needed UFSAR and TS revisions. This included four examples of SRs no' satisfied and an NCV for failure to perform required TS surveillance
te ting was issued. Significant corrective actions were taken, or were in the process of being completed by the licensee for the deficiencies identified by the licensee in the May 5,1997, GL 96 01 Report.
M4.3 Surveillance Testina a.
Insoection Scope The inspector selected several protective instrumentation and engineered safety features actuation system (ESFAS) SRs for calibration and functional testing and verified that actual testing performed during the recently completed refueling outage and two recent forced outages had satisfied the SRs.
b.
Observations and Findinas The inspector selected several TS SRs for review of existing licensee SI procedures to verify that the testing satisfied the SR. Those SRs selected included various protective instrumentation and ESFAS SRs for calibration and functional testing from TS Tables 4.3.1 & 4.3.2.
The inspector reviewed the associated licensee sis and verified that the instructions satisfied the SRs.
Additionally, the inspector reviewed various SRs from TS Tables 4.3.1 and 4.3.2 and verified that actual testing performed during unit outages had satisfied the SRs. Specifically, the inspector verified that the 18 month channel calibrations required by SRs 4.3.1.1.1 and 4.3.1.1.2 for
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reactor coolant pump (RCP) undervoltage, RCP underfrequency, and reactor trip system interlocks and containment ventilation isolation testing
required by SRc 4.3.1.1.1,.4.3.1.1.2, and 4.9.9 were performed as required during the recent refueling outage in March 1997.
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Additionally, the inspector verified that the functional testing
requirements of SR 4.3.1.1.2 for the reactor trip system interlocks had
been satisfied prior to reactor startup following that refueling outage
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and from the forced outages in June 1996 and November 1996.
SR
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e 4.3.1.1.2 required that the logic for interlocks shall be demonstrated
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operable prior to each reactor startup unless wrformed during the
preceding 92 days. The inspector noted that t1e licensee's surveillance i
testing program required the reactor trip system interlocks to be tested such that each train was functionally tested every 62 days on a
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staggered test basis.
No problems were identified during this review.
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Conclusions
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l For each TS SR reviewed by the inspector, the licensee had performed required surveillance testing during the March 1997 refueling outage,
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and prior to reactor startup following the forced outages in June 1996 and November 1996.
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.MB Miscellaneous Maintenance Issues (92902)
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M8.1 (Closed) VIO 50-327. 328/96 02 05:
Failure to Control Imolementation of l
Plant Modifications as Reauired By SSP 9.3.
As discussed in IR 50 327, l
328/96 08, the inspector had verified the corrective actions and concurred with the licensee's root cause determination as described in the licensee's response letter dated May 22, 1996.
However, at the time of that review, the licensee's corrective actions were not complete. The licensee had committed in their response letter to evaluate the effectiveness of the actions in resolving site human performance issues. That evaluation, Assessment NA SQ 96 26, was L
completed on October 31, 1996, and concluded that while improvement had been achieved, the corrective actions had not resulted in the desired
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level of human performance. The evaluation recommended, and the licensee implemented, a consistent site-wide peer evaluation process.
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l The inspector determined that the licensee addressed the procedure
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problems associated with controlling plant modifications, and concurred i
with Nuclear Assurance's assessment that the desired level of
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performance has not yet been achieved.
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M8.2 (Closed) VIO 50 327. 328/96 12 01:
Failure to Revise Emeraency l
Operatina Procedures as a Result of Desian Chanaes to Abandon Plant
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j Eauioment. The inspector verified the corrective actions described in the licensee's response letter, dated February 3,1997, to be reasonable l
l and complete. No additional problems were identified during the l
inspector's review.
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M8.3 (Closed) LER 50-328/96 003:
Reactor Trio Breakers Were Manually Doened J
i With An Automatic Generation of a Feedwater Isolation Sional and a Manual Reactor Trio.
This event was discussed in IR 50 327, 328/96 05.
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No new issues were revealed by the LER.
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M8.4 (Closed) LER 50-328/96-006: Automatic Reactor Trio of the loss of Power
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to Start Bus 2A. the Start of Four Emeraency Diesel Generators. and Loadino of Emeroency Diesel Generator 2B 3.
This event was discussed in IR 50 327, 328/96 14.
In addition to the LER, the licensee initiated PER No. SQ963132PER which required a root cause investigation. That
investigation considered several root cause possibilities but was not able to determine the cause of the breaker opening.
M8.5 (Closed) LER 50-327/97 001:
Failure to ProDerly Perform Surveillance Testino on the EDG Start Timer Relays that are Contained in the Start Loaic Circuity.
This deficiency was identified by the licensee's T&PS
group prior to the GL 96 01 integration review phase and was addressed separately in the May 5, 1997, GL 96 01 Re art. The licensee determined that only one of the two channels of the EXi start timer relay circuitry per shutdown board had been tested under the existing SI. The inspector reviewed PER No. SQ970161PER along with other documentation provided by the licensee and verified that operations personnel had entered the-appropriate LC0 for Units 1 and 2 on January 25,-1997, and testing
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performed to test both channels of the start timer logic prior to exiting the LCO. The inspector noted that the appropriate SI was revised and that subsequent testing verified the as-found condition of each channel to be acceptable.
M8.6 LClosed) LER 50 327/97 003:
Failure to Properly Perform Surveillance Testina on the Centrifuaal Charaina Pumo Inlet Isolation Valve Loaic.
i This deficiency was identified by the licensee as Issue Number 3 in the
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May 5, 1997. GL 96-01 Report. The licensee determined that surveillance i
testing of the centrifugal charging pump inlet isolation valve interlock had not been performed as required by TS 3.5.2.a and 3.1.2.2.
Each volume control tank isolation valve had two parallel electrical initiation paths and the existing SI had not independently verified both paths. The inspector reviewed PER No. SQ970442PER along with other
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documentation provided by the licensee and verified that operations personnel had entered the appropriate LC0 for Units 1 and 2 on March 5, 1997, and special testing performed to test the individual contacts in i
each of the two parallel circuits prior to exiting the LCO. The
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inspector noted that the appropriate SI was revised and that the special
testing verified the +found condition of each channel to be acceptable.
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M8.7 (Closed) LER 50 327/97 008:
Failure to Properly Perform Surveillance
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Testino on the Containment Air Return Fan Start Loaic and on the
Blackout and Auto Seauencino of the Station Fire Pumos. These two
deficiencies were identified by the licensee as Issues Number 13 and 14 in the May 5, 1997, GL 96 01 Report. The licensee determined that
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surveillance testing of the blackout and auto sequencing timer circuit
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for the station fire pumps and the containment air return fan auto start
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logic had been inadequate to satisfy TS 3.8.1.2 and 3.6.5.6.
Surveillance testing of the station fire pumps used a handswitch and had not independently verified the blackout auto sequencing circuit which was parallel to the handswitch.
Surveillance testing of the containment air return fans had not verified the correct o>eration of the solid state protection system (SSPS) contacts which 1ad been jum)ered to simulate the auto start signal. The inspector reviewed PEl No.s SQ970610PER and SQ970611PER along with other documentation provided by the licensee and verified that operations aersonnel had entered the appropriate LCOs for Units 1 and 2 on Marc 1 25, 1997, and special testing performed to test the blackout auto sequencing circuit and the SSPS contacts for the containment air return fans prior to exiting the LCOs. The inspector noted that the appropriate sis were revised and that the special testing verified the as found condition of each logic circuit to be acceptable.
M8.8 (Closed) IFI 50 327. 328/94 30 01: Deficiencies in Check Valve Proaram Imolementation. This item identified weaknesses in the licensee's implementation of its check valve program. These weaknesses included a failure to issue quarterly reports specified by the program, failure to update the check valve database, and incorrect flow disturbance locations recorded in the check valve database.
In a letter dated December 13, 1994, the licensee informed the NRC of the causes of the weaknesses and of actions being taken to address the weaknesses. The inspectors verified completion of the actions stated in the letter, including PER No. SQ940772PER, which was initiated to develop corrective actions and resolve the condition.
M8.9 (Closed) IFI 50-327. 328/94 30-02:
Inadeauate Preventive Maintenance on Reach Rod Valves. This item identified weaknesses in the preventive maintenance performed for reach rod valves. As a result of omission of testing following preventive maintenance, a reach rod valve had remained open and resulted in the loss of a large volume of water.
Position indication on such valves was inaccurate, making it difficult to determine when a valve was closed.
In a letter dated December 13, 1994, the licensee informed the NRC of the causes and the actions being taken to address the weaknesses.
The inspectors verified completion of the actions stated in the letter, which included revisions to preventive maintenance instructions to require post maintenance stroking, development of corrective actions through PER No. SQ940106PER, and issuance of an order instructing operations personnel not to rely on the position indicators of reach rods.
M8.10 (Closed) IFI 50 327. 328/94 22 02:
Snubber Desian and Maintenance Items.
This item identified aerceived snubber design setting and maintenance problems for furtier review. The inspectors found that the licensee had prepared a paper regarding snubber inspections that res>onded to these perceived problems. This paper was entitled.
Tec1nical Specification and ASME Section XI Inspection for Sequoyah Snubbers, and was dated October 1994.
Explanations provided in this document were reviewed by the inspectors and considered adequate to allay the original concerns.
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j III. Enaineerina El Conduct of Engineering (37550, 37551)
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El.1 GL 89 10 Proaram Implementation a.
Insoection Scope (Temocrary Instruction 2515/109)
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This inspection provided an assessment of the licensee's implementation of GL 8910, Safety Related Motor-0perated Valve Testing and
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Surveillance. The licensee notified the NRC that they had completed i
implementation of GL 8910 in letters dated December 11, 1995 (Unit 1)
and July 1,1996 (Unit 2).
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The assessment included the scope of motor-operated valves (MOV) in the licensee's program, determinations of M0V settings and verifications of i
MOV capabilities, periodic verification of M0V capabilities, M0V corrective actions and trending, M0V post maintenance and post
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modification testing, and actions to address pressure locking and a
thermal binding. The NRC inspectors conducted the assessment through a review of the licensee's GL 8910 implementing documentation and through interviews with licensee oersonnel. The documents reviewed included:
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p Site Standard Practice SS)-6.61, Motor Operated Valve Program / Generic-Letter 89 10, Revision 1: Standard Engineering Procedure DS M18.2.21,
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Motor Operated Valve Thrust and Torque Calculation, Revision 8; and the calculations, test records, etc., referred to in the following 3aragraphs.
In addition, the inspectors reviewed summary tabulations of 40V information and calculation results prepared by the licensee.
Prominent among the tabulations was a list of "available valve factors"
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(AVFs) for the licensee's GL 8910 gate valves. The licensee prepared i
this list at the inspectors * request to aid them in assessing the capabilities of the licensee's MOVs. The AVFs were calculated using formulas described in previous NRC irs (e. g., IR 50 338, 339/97-01,
dated March 21, 1997). The inspectors compared the AVFs for the licensee's valves to valve factor requirements established in industry
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testing which the NRC had previously reviewed. These comparisons were
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performed to determine if the AVFs were conservatively higher.
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As part of the inspection, the inspectors performed detailed reviews of special test packages and engineering evaluations which the licensee had
developed for the following sample of M0Vs:
1-FCV 001 018 Turbine Driven Auxiliary Feedwater Pump Steam i
Isolation i
1-FCV-003 136A Essential Raw Cooling Water (ERCW) Isolation 1 FCV 003 136B ERCW Isolation
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1-FCV 026 243 Reactor Coolant Pump (RCP) Spray Isolation i
1 FCV 70 090 RCP Thermal Barrier Return Containment Isolation i
2 FCV 003 047 Steam Generator No. 2 Feedwater Isolation 2 FCV 068 332 Reactor Coolant System Pressurizer Block
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Observations and Findinas 1.
Scooe of MOVs Included in the Procram
i The scope of valves included in the licensee's GL 8910 program was
originally reviewd and determined acceptable by the NRC during Inspection 50-327, 328/91 18. At that time, the scope consisted of 278
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MOVs.
In the current inspection the inspectors found that the licensee
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had subsequently reduced the scope by 53 MOVs. The current program scope included 138 gate valves,16 globe valves, and 71 butterfly valves
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for a total of 225 valves.
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The bases for the removal of the 53 valves referred to above, were documented in Calculation EPM RJP 061091, Revision 6.
The inspectors t
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functions in emergency raw cooling water lines for the upper containment i
vent coolers. Their removal from the licensee's GL 89 10 program was L
based largely on a GL 8910, Supplement -1, statement that the types of i
MOVs covered by GL 8910 included gate, globe, and butterfly valves.
The inspectors noted that, while GL 89 10 focused on gate, globe, and
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butterfly valves; it did not exclude plug valves.
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j As noted above, the ins wetors did not agree with the bases given by the licensee for removing t1e plug valves from the GL 8910 program.
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i However, based on the design of these valves and on the operation,
testing, and preventive maintenance that the licensee provided: the
inspectors considered the capabilities of these valve adequately l
verified to meet the intent of GL 8910. The plug valves were small i
two inch quarter turn valves, their design resulted in minimal operating
torque requirements under flow conditions, and they were limit i
controlled to obtain full motor capability during' operation. They were
operated under flow conditions on occasion and were stroke timed
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quarterly.
Preventive maintenance was specified every three refueling
cycles and consisted of monitoring motor current, inspecting torque and
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limit switches, monitoring switch actuation, cycling the valve, cleaning
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electrical contacts, and inspecting actuator lubricant.
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Determinations of Settinas and Verifications of Capabilities for
Gate. Globe. and Butterfly Valves I
Switch Settinas
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The licensee controlled the operation of gate and globe valves through a combination of torque and limit switches. The torque switch was x.
j bypassed in the closing direction for 95 to 98% of stroke length, based i
on handwheel turns..For opening, the torque switch was bypassed for the
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entire stroke. Butterfly valves were limit switch controlled in both
directions.
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The licensee calculated the predicted thrust and torque to operate gate
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i and globe valves using standard industry equations. The predicted thrust requirements for gate valves were calculated assuming a 0.4 valve
factor with a 20% safety _ factor.
For globe valves, the licensee assumed a valve factor of 1.0 for closing and 1.2 for opening. Diagnostic error and torque' switch repeatability were accounted for in the switch setting calculations. The licensee obtained the predicted torque required to operate butterfly valves from the valve manufacturers.
The licensee _ established settings for gate and globe valves through a process that reconciled the predicted operating requirements calculated for the valves with results obtained from testing valves at Sequoyah or Watts Bar, or results from the M0V 3rogram conducted by the Electric Power Research Institute (EPRI). T1e licensee did not use information i
from other utilities in this process because of concern regarding the
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reliability of that information.
The thrust settings for Sequoyah's gate and globe valves were specified i
on setting drawings. The licensee informed the inspectors that these
drawings and the related design calculation packages had not been-
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revised to incorporate all of the most recent setting limits established
in the reconciliation process. Although the valves were currently set
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to values determined acceptable through the reconciliation process, the setting drawings and calculations permitted lower setting limits _ that might not'be acceptable in some cases.
Licensee personnel stated that maintenance personnel knew not to lower settings without first checking with engineering.
However, as the licensee had previously informed the NRC that implementation of GL 8910 was complete, the inspectors expressed concern that the settings and calculations had not been updated and that more definitive controls were not in place.
In response, the licensee issued change 97 0525 (dated June 12, 1997) to
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Procedure 0 MI-EMV 317-144.0, Procedure for Testing Motor Operated-
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Valves Using M0 VATS Signature Analysis System, requiring licensee personnel to contact Site Engineering to determine appropriate switch settings rather than applying information from the setting drawings.
Further, in a letter dated July 8,1997, the licensee committed to issue a design change notice (DCN) to update the switch setting sheets after calculations are completed. The letter stated that this DCN would be completed for both units by December 1,1997.
The licensee assumed run efficiency in the closing direction when predicting the torque output capability of its actuators. The inspectors noted that the actuator manufacturer is 3reparing new guidelines that might affect the acceptability of t1e licensee's use of run efficiency.
Licensee personnel stated they were aware of this situation and had been in contact with the manufacturer. The manufacturer had provided no guidance but indicated it would be forthcoming shortly.
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Desian Basis Caoability
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Gate Valves -
-The design basis capability of Sequoyah's gate valves was established on
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a group by group basis, after dividing the 138 gate valves into 23 r
separate groups. The licensee had dynamically. tested 39 of these valves
and the dynamic thrust data was evaluated and extrapolated to design-
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basis conditions for reconciliation with predicted values. Many of the.
23 groups did not include any valves that had been dynamically tested.
F For these groups, the licensee relied on test data from Watts Bar or the
EPRI program where possible, but in some cases' had obtained no test data.' The inspectors identified the following issues for resolution:
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The thrust requirements (or valve factors) for gate valve groups 1-8, 10, 14, 18 21, and 23 were not reliable, as they were based on 1'
insufficient test data. Generally, the requirements for these groups
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were either not supported by any applicable test data or were based on data from testing a single valve. Also, in the case of group 4, it was
-not clear whether criteria recommended by-EPRI had been considered in
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extrapolating the opening test data. The licensee demonstrated the i
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design basis capability of these gate valves by showing that their-
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available valve factors were reasonably bounding of general industry j
results. The licensee was able to rely on full motor capability in
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determining the available valve factors, since the torque switch was bypassed for most of the closing stroke. The licensee set-the bypass i
based on handwheel turns and the inspectors questioned the reliability of this method. The-licensee agreed with this concern and demonstrated the extent of torque switch bypass for several marginal valves using diagnostic traces. The licensee used additional justification for M0V capability where the torque switch was found not to be bypassed into the valve seating region.
In its letter dated July 8,1997, the licensee-stated that it would strengthen the group valve factors for its gate
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valves. The letter further stated that industry differential pressure
. test data will be evaluated to justify existing valve factors and that a group valve factor of 0.6 will be used unless test data supports a
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different value.
The licensee was relying on information from pump flow testing at Sequoyah to justify its predictions of thrust requirements for power operated relief valve block valves 1/2-FCV 68 332/333 (group 7) and had not addressed the potential effects of blowdown operation.
In its letter dated July 8,1997, the licensee indicated that further actions would be taken to justify the capabilities of these valves under blowdown conditions. These actions included maintenance improvements (e. g., radiusing internal' valve edges, checking internal clearances,
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etc.) and a> plying the EPRI PPM (Performance Frediction Model) to
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establish t1e thrust requirements for these block valves. The actions are to be completed for each unit by the end of their next refueling outages.
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Containment saray valves 1/2 FCV 72 002 and 039 (group 18) were marginal in their capaaility, based on available information, In its letter dated July 8,1997, the licensee stated that it would verify the flow
orientation of these Aloyco 12-inch split wedge valves and that the
thrust requirements would be predicted using the EPRI PPM or other test
data.
The licensee had tested most of its globe valves under dynamic conditions. This testing demonstrated that all of the licensee's globe valves were capable of performing their design basis functions.
However, the licensee had not evaluated the adequacy of the closing valve factor assumption of 1.0 which was used to predict thrust requirements for its Velan globe valves.
In its letter dated July 8, 1997, the licensee committed to reconcile its closing valve factor assumption for the Velan globe valves with its test data by September 30, 1997.
Butterfly Valves -
Sequoyah's butterfly valves were manufactured by Posi-Seal and Pratt.
i The licensee did not calculate predicted torque requirements for operation of these valves at design basis conditions but obtained the operating torque requirements from the manufacturers. The butterfly valves were all limit controlled and the licensee determined that the capabilities of the valves were well above the specified requirements (greater than 30%).
The licensee did not consider it practicable to test Sequoyah's butterfly valves with diagnostics to demonstrate that the operating torque requirements specified by the manufacturers were satisfactory.
Instead, the licensee used test results from other plants.
The licensee demonstrated the edequacy of the torque requirements specified for its Posi-Seal valves through tests performed at its Watts Bar plant. The Sequoyah Posi Seal valves were similar in size to those tested at Watts Bar and the inspectors found that the Watts Bar data supported the adequacy of torque requirements specified by the manufacturer.
The licensee supported the adequacy of the torque requirements specified for its Pratt butterfly valves based on results from EPRI's testing of a single 6 inch valve and information obtained from Virginia Power regarding the results of testing that other licensees had performed on 24 and 36 inch Pratt butterfly valves. Sequoyah had forty two 6 inch and three 24 inch Pratt butterfly valves but also had 12,18, and 20-inch sizes. The inspectors did not consider the licensee's information sufficient to demonstrate the adecuacy of the manufacturer's torque requirements.
In its letter datec July 8,1997, the licensee stated
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l that it would work with Duke Power Company or obtain appropriate test data from other sources to validate the Pratt requirements.
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Stem Friction Coefficient t'
The licensee assumed a stem friction coefficient of 0.15 in its H0V j
calculations. Where subsequent testing of a particular gate or globe
valve indicated a higher value, the licensee assumed the test value in
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its evaluation of that H0V. The inspectors questioned the reliability of.the 0.15 stem friction coefficient for the H0Vs that were not
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i dynamically tested, as the licensee had not developed a formal
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evaluation to support the assumption. The_ inspectors evaluated the
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i-licensee's dynamic test results and found that they supported the
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assumed 0.15 stem friction coefficient together with a 10% thrust
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reduction which the licensee assumed to account for rate of loading.
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In reviewing test data for stem friction coefficient and rate of loading
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effects, the licensee found that the licensee's Velan 1500 lb rated gate i
i valves exhibited more severe effects than other gate valves. The-
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i licensee evaluated the capability of the valves, using worst case thrust
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and torque test data from the tested valves for evaluating the valves
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that were not dynamically tested. This evaluation demonstrated adequate
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i capability for the Velan 1500 lb valves.
However, the licensee's J
calculations indicated that valves 2-FCV 68 332 and 333 (pressurizer.
power uperated relief valve block valves) had marginal capability with F
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- respect to the torque structural limit.
In its letter to the NRC letter
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i dated July 8,1997, the licensee indicated that it would demonstrate i
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that these valves greater structural capcbility in revisions to the related valve calculations.
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j Rate of Loadina
The licensee assumed a reduction of 10% in thrust delivered at torque
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switch trip under dynamic conditions from thrust settings at static
conditions for rate of loading.
In response to inspector questions, the i
licensee provided test' data to demonstrate that the 10% reduction in
thrust output was reasonable. However, the inspectors found that the
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licensee had not addressed the ~ potential for reduction in thrust output i
of the actuator under dynamic conditions when the torque switch was
bypassed and operation was controlled by limit switch.
The licensee i
agreed that it had not addressed this issue and demonstrated that its
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MOVs operated by the limit switch had sufficient capability with an L
assumed 10% reduction in thrust output.
In its letter dated July 8, 1997, the licensee committed to provide a 10% rate of loading thrust F
margin for limit switch control until further evaluation showed a p
different value was appropriate.
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M0V Dearadation i
i The inspectors found that the licensee had not made any provision for I
degradation of MOVs and brought this to the licensee's attention.
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its letter to the NRC letter dated July 8,1997, the licensee stated it i
would add a 5% margin as a minimum requirement for MOV degradation.
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This licensee indicated that this requirement would be incorporated into j
the valve calculations by November 7,1997.
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Periodic Verification
,l The licensee's requirements for periodically' testing GL 89-10 MOVs were I
' described in Site. Standard Practice SSP 6.61 Revision 1.
SSP 6.61
prescribed testing each M0V statically, as a minimum.
It also indicated that a sample of GL 89-10 gate valves would be tested under differential
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pressure conditions until there was technical justification to eliminate
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these tests. The inspectors reviewed 3rintouts for 'a sample of M0Vs in
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the licensee's database and verified t1at the periodic static diagnostic r
testing of GL 8910 valves had been performed during the last outages
for Unit 1 and 2.
The licensee's periodic verification actions were i
found to be adequate for closure of GL 8910. The NRC may re assess the i
licensee's long term periodic verification program as part of its review
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for GL 96 05, Periodic Verification of Design Basis Capability of
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MOV Trendino i
The licensee's trending of MOV failures and degradation was previously reviewed during Inspection 50 327, 328/95 01. That inspection determined that data was being appropriately collected for trending but i'
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that there were' no administrative controls specified.
During the 7--
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current inspection, the inspectors found that-the licensee had i
subsecuently implemented the necessary administrative controls through i
Periocic Instruction 0 PI EMV 317-001.0, Revision 0 (with procedure j
changes 97 507 and 0081). This instruction designated the data to be r
gathered, the required reporting period, responsibilities.for data i
gathering and evaluation, and responsibility for report issuance. The l
licensee's M0V trending was satisfactorily implemented.
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5.
Documentation. Analysis. and Corrective Actions for MOV l
Dearadation and Failures I
This area was previously reviewed during Inspection 50-327, 328/95 01, That. inspection determined that the analyses and corrective actions
reviewed were satisfactory but that there were weaknesses in the
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document; tion. ~For instance, cause information was not given or was j
unclear in two cases reviewed. The inspectors reviewed PERs documenting
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additional examples of MOV failures during the current inspection to further evaluate the licensee's documentation, analysis, and corrective
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actions for MOV failures. The examples and the inspectors' findings l
were as follows:
PER No. SQ962636PER This PER described water damage to main feedwater
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isolation valve 2-FCV-3 100B. The inspectors found that this PER
provided adequate documentation, analysis, and corrective actions for
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the M0V failure. However, the failure had resulted from a long standing
problem that should have teen recognized and corrected earlier by the i
licensee. The inspectors learned that the licensee's failure to perform adecuate evaluations earlier and preclude recurrence of the adverse
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concition had been previously identified by the NRC as a severity level
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PER No. SQ950293PER This PER described the intermittent failure of residual heat removal heat exchanger by valves due to motor contactor problems. pass valve 2 FCV 74 33 and other The inspectors found that this
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PER provided adequate documentation, analysis, and corrective actions
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for the MOV failures. The inspectors observed that the licensee had experienced similar failures for years but had been previously been unsuccessful in correction.
PER No. SQ961773PER This PER described the failure of TDAFW tri) and l
throttle valve 1 FCV 1-51 to meet its stroke time requirement. T1e l
measured opening time was 8.9 seconds versus a maximum allowed by l
3rocedure of 8.4 seconds, (note: the design allowable was estimated to 3e 20 seconds in a later review). The inspectors found the analysis l
recorded in the PER under the heading " recurrence control" unsatisfactory.
It first stated that troubleshooting was initiated without identifying any problems. Then, on a separate continuation
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sheet, it went on to indicate that the valve had failed to open the third time it was cycled for troubleshooting.
The PER postulated that
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this failure was due to the operator not holding the switch in the open aosition for a sufficient period of time for the open signal to seal in.
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iowever, there was no entry of the operator's response to this conjecture and no supporting evidence of the recorded view.
Licensee inservice testing personal informed the inspectors that the operator had been questioned and indicated that he had held the switch in position until he became concerned that the motor would fail. The operator was
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reportedly no longer employed at Sequoyah and could not be questioned by the inspectors. The ins)ectors noted that the troubleshooting following i
the initial failure of tie valve had apparently been limited to cycling the valve and checking motor amps. There was no ir.dication that the licensee either reviewed the available historical test data for this valve or that diagnostic equipment was considered for troubleshooting the condition identified. A review of the test data from the last
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replacement of this actuator would have shown that the stroke time i
normally measured for this valve during surveillance tests was too short (less than 6 seconds versus an actual stroke of about 11 seconds).
PER No. SQ970392PER - This PER described another stroke time failure of valve 1-FCV-1 51 like that referred to in the previous paragraph. The measured value was 9.5 seconds versus the maximum allowed by procedure of 8.4 seconds and a normal measurement of 5 to 6 seconds. This occurred just over 6 months after the previous failure. The licensee's corrective action for this more recent failure included more precise testing with diagnostic equi) ment and refurbishment of the valve (note:
only current and time could 3e measured on this valve with the licensee's diagnostic equipment). The inspectors found that this PER generally provided adequate documentation, analysis, and corrective actions for the failure, though some uncertainty remained because the failure cause was not established. The inspectors noted one entry in
the PER which they considered unsatisfactory, involving the adequacy of
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l stroke time measurements. The licensee's investigation found that only l
about half the actual stroke time was being measured during surveillance
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testing due to improperly set indication. The PER indicated that this
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was acceptable as the maximum value specified for the surveillance test i
was based on deviation from a reference stroke time value and exceeded no design limit. The entry failed to recognize that the test was
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intended to measure changes over the entire stroke, whereas the licensee
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was only timing about half the stroke.
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Pressure Lockino and Thermal Bindina The inspectors reviewed the licensee's GL 95 07 submittals dated i
February 13, March 15 and August 6, 1966. During the inspection, the licensee stated that a supplemental response to GL 95 07 would be submitted to provide pressure locking and actuator capability calculations for Units 1 and 2 valves FCV 116, FCV-62138, FCV 631, FCV 63 6, FCV 63 7, FCV-63 25, FCV 63 26, FCV 63 156, FCV 63 157, FCV-i 68 132, FCV 68 332, FCV 72 2, FCV 72 39, FCV-72 40 and FCV-72 41. The i
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sup)lemental response would also address the basis for any bonnet
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leacage assumptions that were used in pressure locking calculations.
The adequacy of the licensee's actions to address pressure locking and thermal binding remain under NRC evaluation but will be reviewed
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separately from GL 89-10.
In the future, the NRC staff will address the adequacy of the licensee's actions in a safety evaluation of the i
licensee's responses to GL 95 07.
7.
Strenaths The inspectors observed the following strengths in the licensee's implementation of GL 8910:
Accurate diagnostic measurements.
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Personnel who were knowledgeable of the MOV industry issues.
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c.
Conclusions Implementation of GL 89-10 at Sequoyah was not sufficiently complete to permit the NRC to close its review. The licensee had demonstrated that the current settings and capabilities of the Sequoyah GL 89 10 MOVs were adequate. However, it had not adequately determined and specified limitations on the requirements for many of these MOVs to ensure long-term operability.
In a letter to the NRC dated July 8,1997, the licensee committed to nine actions to improve its implementation of GL 89 10. The inspectors considered that these actions, when sufficiently completed, would resolve the remaining issues regarding the long term capabilities of Sequoyah MOVs and 3ermit closure of the NRC review of GL 89-10 implementation at Sequoyal. NRC verification of
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completion of the actions stated in the licensee's letter of July 8, 1997, was identified as IFI 50 327, 328/97 06 07, Actions to Resolve Remaining GL 89 10 Issues.
In accordance with its commitment letter,
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the licensee is to notify the NRC of the status of the commitment actions by the end of 1997.
Weakr. esses were identified in the analyses of stroke time faihres of i
TDAFW trip and throttle valve 1-FCV 151 documented in two PERL The inspectors noted two licensee strengths, which are described in L
Section E1.1.b.7.
E2 Engineering Support of Facilities and Equipment (37551)
E2.1 Imorocer Settina of the Safety In.iection System Relief Valves a.
Inspection Scope The inspectors reviewed the activities associated with an over pressure condition of the safety injection system.
In addition, the inspectors reviewed the American National Standards Institute (ANSI) code requirements associated with the safety injection system relief valves, b.
Observations and Findinas IR 50-327, 328/96 14 discussed a deficient condition which occurred on
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November 2, 1995. The Unit 2 operators noted that the safety injection
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system pressure was indicating 1850 psig and the design pressure for the system was only 1750 psig. Three system relief valves were available in the safety injection system and should have relieved system pressure before exceeding 1805 psig.
Immediately following the event, one of the relief valves was removed and tested and was found to be set at approximately 1840 psig. The relief valve was reset to 1750 i3% psig; however, the other two relief valves were not tested and were not reset, although the licensee had knowledge from the event that the setpoint exceeded 3% of the nominal.
The licensee stated that the relief valves were not known to be functioning outside an acceptable range (6%) as documented in their relief valve program.
In addition, the corporate TVA QA organization conducted an assessment of the program and found the program to be acceptable. The inspectors reviewed the ANSI code requirements and had concerns with the licensee's interpretations.
Several meetings were held with the licensee's engineering staff to discuss the ANSI code requirements.
IFI 328/96 14 01 was identified to follow u) the safety injection relief valve setpoint issue.
In addition, a Tas( Interface Agreement (TIA 97 01) was initiated by the resident inspectors and forwarded to NRC headquarters for review and resolution of the issue.
NRR res)onse to TIA 97 01, Relief Valve Lift Settings Required By Applica)le Codes (TAC No. M97281) was issued May 21, 1997 and is l
included as an attachment to this report.
It noted that as left l
tolerance for setting relief valves is allowed to be as high as 13%.
The as found tolerance should be supported by an analysis of the j
limiting operational or transient events for overpressure or other
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l safety parameters to verify that the design limits of the piping,
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vessel, or system are not exceeded. The overpressure event of November 2, 1996, is considered by the inspectors to have provided the licensee with an as-found condition outside i3% and the relief valves
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should have been reset to with 13%, unless a system analysis existed to
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support the as found condition for the limiting operational or peak
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l transient events for overpressure and other safety parameters to verify that the design limits of the piping and system are not exceeded. The TIA also noted that the licensee's arocess of " stacking" the as left and i
as found tolerances to obtain even ligher allowable limits was improper and therefore did not appear to conform to the ANSI /American Society of Hechanical Engineers (ASME) OM 1 code requirements.
Following the November 2 event, on December 5, 1996, the licensee performed a preliminary system analysis to support leaving the valves in
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the as-found condition. On January 11, 1997, the licensee submitted a code interpretation to the National Code Committee. A verbal res]onse from the committee was received on March 11, 1997, and it noted tlat the
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licensee was not in compliance with the code unless a system analysis had been performed to support the higher system pressure. On April 4, 1997, the licensee revised the safety injection system relief valve testing procedure 0-SI-SXV 000 264.0. On June 20, 1997, the licensee
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completed a formal approved system calculation for the safety injection
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system relief valves. The licensee noted that the subject relief valves
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would be tested during the next Unit 2 refueling outage (Fall 1997).
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l The inspector noted that the licensee failed to reset the safety injection relief valves lifting setpoints following the November 2, 1996, event and did not have an analysis to support the as left valve relief setting. Additionally, it is not clear why 3-out of-3 relief valves failed to operate within 3% of the nominal setpoint.
Further review noted that the licensee was not initially in compliance with the l
ANSI OH-1 requirements for resetting the relief valves or reanalyzing the system. The licensee's failure to implement adequate corrective actions to correct the deficient safety injection system relief valves lifting setpoint is considered to be inadequate corrective actions and l
is identified as VIO 50 328/97 06 08.
c.
Conclusions i
A violation was identified for the licensee's failure to implement
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adequate corrective actions to correct the improper setting of the safety injection system relief valves.
E2.2 Inadecuate Section XI Surveillance Activities a.
Inspection Scope The ins)ectors reviewed the activities associated with the failure of the TDAN trip and throttle valve to properly stroke on the first attempt during Section XI testing.
In addition, the inspectors reviewed
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the two year Section XI remote accuracy surveillance associated with this valve.
b.
Observations and Findinas
On February 24, 1997, the Unit 1 TDAFW valve (1 FCV-51) failed its initial stroke test. Subsequent restroking of the valve documented acceptable stroke times.
Further review noted that this valve had failed a previous stroke test on June 17, 1996, and that subse restroking of the valve had provided acceptable stroke times. quentFollowing the second stroke failure in February 1997, the licensee developed an extensive troubleshooting plan with potential root causes. During the l
1997 Unit I refueling outage, the licensee noted problems with the valve
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internal clearances and subsequently replaced the valve stem, bushings and valve disc. The valve was successfully tested following the maintenance activities.
Following the February 24, 1997, stroke failure, the inspectors reviewed the associated technical operability evaluation. The evaluation noted that 1 FCV 51 was still operating within the design limits listed in the UFSAR, but it did not identify the cause for the deviation / failure. The inspectors also reviewed PER No. SQ961723PER. initiated following the June 17, 1996, failure to stroke.
Following subsequent local
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observations with ric further problems, engineering documented in the PER that valve 1 FN 51 had failed to stroke as required possibly due to operator error, but again did not identify the cause for the deviat ion /f:ilure. The two evaluations were considered to be lacking
be.cause they did not clearly identify and analyze the cause for the failures.
Following the February 24, 1997, failure, the inspectors performed a l
walkdown of the Unit 1 and Unit 2 TDAFW pumps and pump rooms. The
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inspectors noted that the TDAFW trip and throttle valve (1-FCV-51 and 2-l FCV 51) position indicators were set differently. The inspectors then
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reviewed the Section XI test data for both tri) and throttle valves.
l The data noted that when measured locally, bot 1 valves stroked open in a) proximately 11 seconds.
It also noted that the Unit 2 trip and tirottle valve stroked open in approximately 11 seconds when measured remotely. However, the data documented that the Unit I trip and
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throttle valve only took 5-6 seconds to open when measured remotely.
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The licensee was informed of this discrepancy and during the Unit 1, 1997, refueling outage the licensee reset the Unit 1 trip and throttle valve limit switches.
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l Due to the potential misadjustment of the limit switches on 1 FCV 51, the inspctor reviewed the " Remote Valve Position Indication"
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surveillance to verify the licensee's program for ensuring the proper accuracy of valve limit switches. The inspector noted that the surveillance acceptance criteria only required the remote indication to
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indicate open with the valve fully open and closed with the valve fully closed.
It did not require the remote indication to accurately indicate l
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valve position, so in this case, AFW valve 1 FCV 51 remotely indicated
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100% open with the valve actually at about 50% open.
c.
Conclusion j
The licensee is reviewing the requirements against their program.
Pending completion this is identified an URI 50 327/97-06 09: Remote Position Indicator Test.
E2.3 PER No. S0950890PER. MOVs without "T" Drains j
a.
Insoection Scoce The inspector reviewed corrective actions developed and implemented for the above PER in order to verify that condensate drainage into MOV limit switch compartments (LSC) had been effectively addressed and the environmental qualification status of the MOVs had been maintained.
b.
Observations and Findinas TVA established the following design requirement in response to potential drainage into LSCs through the conduit system because of condensed steam inside long vertical conduit runs.
Flooding at higher elevations and containment spray were also considered as sources for potential drainage.
"T drains must be added to the low point of the limit switch compartment (LSC) unless it can be determined by field inspection that one of the following situations exist:
(1) Conduit runs are installed such that condensation would not drain into the LSC: or (2) the motor has a T drain located at the low point of the actuator in such a manner that the motor would also drain the LSC."
PER No. SQ950890PER was written on July 25, 1995, to document the identification of 35 MOVs that required field inspections in order to verify if T drains were required in the LSC. 8ased on the results of the field inspections it was determined that T drains would be required
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in the low point of the LSC of the valves.
Installation of the re T drains were assigned a Master Issues List (MIL) item number MIL # quired 96017 and the PER was closed on February 9,1996 as a required enhancement in accordance with Appendix G of SSP 3.4, Corrective Action, Revision 14.
On May 8, 1996, TVA management wrote PER No. SQ96961353PER to document the closure of PER No. SQ950890PER as an enhancement which did not comply with NRC guidance delineated in GL 9118 for nonconforming conditions. The licensee determined that because the deficiency addressed an adverse condition it could not be treated as an enhancement only. A review of all PERs closed to Appendix G of SSP-3.4 was performed by TVA management. This review revealed that 27 PERs had been previously closed with a conflict with the licensing basis still existing. Twenty six of these PERs represented UFSAR discrepancies.
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TVA's review of the Appendix G documentation also indicated that these conditions were not considered adverse conditions since there was no adverse impact on safe plant operation. Additionally, the Appendix G form did not provide clear guidance concerning what were adverse conditions.
PER No. SQ961107PER was written to initiate corrective actions for this licensee finding. Revision of SSP 3.4 to delete the
l use of Appendix G, paragraph f process and clarifying the definition of
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adverse conditions relative to the guidance of GL 91-18 was completed by l
the licensee in response to this programmatic deficiency.
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The inspector reviewed the corrective action that had been i
completed for the 35 MOVs requiring LSC T drains. The following
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documents were reviewed during this effort:
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o Environmental Qualification (EQ) Binder No. SONEQ MOV 003, Limitorque Actuators Outside Containment with Class RH Motors, Revision 27.
l EQ Binder No. SQNEQ H0V 004, Limitorque Actuators Outside e
Containment with Class B Motors Revision 34.
EQ Binder No. SONEQ MOV 005, Limitorque Actuators Outside e
Containment with Class B Motors and Brakes, Revision 28.
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Based on the above review the inspector determined that a Technical I
Operability Evaluation (T0E), had been wrformed to justify continued i
operation without the installation of t1e T drains in the LSC until
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Unit 2 Cycle 8 and Unit 1 Cycle 9 outages. The inspector concluded that the T0E provided reasonable assurance that the equipment will perform
l its safety function in its accident environment when called u mn to do i
so.
Plant modifications DCN No. H 13071A and M 13103A are scleduled to l
be prepared for installing the T drains in the MOV LSC for Units 2 and 1 I
respectively. The inspector reviewed the scope of both DCNs and verified that all MOVs listed on Attachment 2 of PER No. SQ950890PER were included within the scope of the plant modifications.
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Conclusion l
l The inspector concluded that the licensee had developed corrective
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actions for nonconforming MOVs that were consistent with design
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requirements and NRC's guidance delineated in GL 91 18.
E2.4 Plant Modifications DCN Nos. M8777A and M8780A a.
Inspection Scope The inspector reviewed plant modifications DCN No.s M8779A and M8780A in order to verify that nonconforming conditions involving environmentally
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qualified equipment were corrected in accordance with the requirements of the ANSI N45.2.11 1974 design engineering program. The plant
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modifications were reviewed with special emphasis on (1) the a
identification of design inputs: (2) the technical adequacy of setpoint l
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controls and (3) the technical adequacy of safety evaluations performed in accordance with the requirements of 10 CFR 50.59.
b.
Observations and Findinas The scope of the above plant modifications consisted of three aarts.
The first part involved addition of temperature detectors in t1e auxiliary building to detect a high energy line break (HELB). The second part involved changes to the auxiliary building environment based on the results of design basis calculation SQN NAL3 007. Interim Normal Operation Dose for Equipment Qualification Outside the Shield Building:
and the third involved updating the 100 day integrated accident doses which also included revising the EQ Binders and associated instrument accuracy calculations for affected areas / components in the auxiliary building.
The addition of temperature detectors (RTDs) in the residual heat removal (RHR) Sump rooms (1A A and 1B B), the RHR heat exchanger room (1A and 1B); t1e chemical and volume control system (CVCS) letdown heat exchanger room and the boric acid evaporator package rooms (A and B) were intended to provide the operator with an early detection of a high temaerature alarm.
Manual isolation of a line break in the RHR
) ump or leat exchanger room or the CVCs heat exchanger room would then
>e initiated by the operator.
If the line break occurred in the CVCS heat exchanger rooms automatic isolation of the auxiliary steam line break would occur by closure of valves 0 FCV 12 79 and 82.
Environmental changes in temperature, pressure, humidity, and radiation in the auxiliary building were addressed by these plant modifications.
Revised category and operating time calculations and instrument loop accuracy calculations were prepared to demonstrate continued EQ of various instrument loops. The new instrument loop requirements were specified in setpoint and scaling documents contained in the DCNs.
Additionally, Environmental Design Criteria SQN DC-V 21.0, was issued for use and superseded the environmental drawings 47E235 series.
The inspector reviewed the safety assessment / safety evaluation prepared for the plant modifications in order to verify the technical adequacy and compliance with the requirements of 10 CFR 50.59. The safety assessment correctly applied the screening criteria in assessing the impact of the changes to the plants licensing basis delineated in the UFSAR and the TSs. Changes to the UFSAR described on the UFSAR Change Request Form were verified to have been incorporated by amendment 12 to the UFSAR. The safety evaluation clearly described the changes implemented within the scope of the plant modifications and concluded that an unreviewed safety question did not exist because of the design changes. The inspector concurred with the conclusion documented.
No deficiencies were identified during this review.
The licensee's approved design engineering program has established requirements for design inputs to be identified, documented and their selection reviewed and approved. Changes from specified design inputs are also required to be identified, approved, documented and controlled.
Design inputs are required to provide detail information which permits the design activity to be carried out in a correct manner and to provide l
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a consistent basis for making design decisions, accom verification measures, and evaluating design changes.plishing design Add 1tionally, the l
design process is required to demonstrate an auditable path from
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approved design outputs to the source of the design input. The inspector chose a random selection of EQ Binders and reviewed selected environmentally qualified equiment in order to verify that the environmental parameters for w11ch the equipment was qualified was t
supported by approved design input information. The following design l
basis calculations were reviewed during this effort:
Calculation No. SQNAPS2 119, Auxiliary Building High Energy e
Line Break Mass and Energy Release for Environmental Analysis Revision 0
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Calculation SQNAPS2121 Environmental Response of Auxiliary e
Building to HELB, Revision 2 e
Calculation No. SONNAL3 007, Normal Omration Dose for Equipment Qualification Outside the S11 eld Building, Revision 6 Category and Operating Time Calculations e
SQN-0SG7 0027 Residual Heat Removal System (074) 10 CFR 50.49 Category and Operating Time Calculation, Revision 7 e
SQN 0SG7 0019, Chemical and Volume Control (062) 10 CFR 50.49 Category and Operating Time Calculation, Revision e
SQN 0SG7 0012. Auxiliary Boiler System (012) 10 CFR 50.49 Category and Operating Time Calculation.-Revision 7 l
Based on review of the above calculations the inspector determined that environmental parameters of temperature, pressure, humidity, and 40 year
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normal radiation doses had been identified for various areas of the
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auxiliary building. The following EQ Binders and the listed equipment
were reviewed to verify that environmental parameters specified in the l
Environmental Design Criteria SON DC V 21.0 for areas in which the
equipment was located were consistent with values delineated in the above calculations:
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UNID E0 binder 0 TS12-91A SQUEQ ITS 001, R23 l
0-TS 12 91B SQNEQ ITS 001, R23 l
2-TS 074 0043 SONEQ ITS 002, R30 i
1 TS 074 0044 SQNEQ ITS 002, R30
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1-FCV 62 63 SQNEQ H0V-005, R28 i
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1 FCV 62-77 SONEQ IZS 001, R35 Based on the above review the inspector concluded that environmental parameters of temperature, pressure, humidity, and 40 year normal radiation doses contained in the EQ Binders were consistent with values specified in the Environmental Design Criteria SQN DC V 21.0. These values were also supported by the referenced calculations. The Class 1E equipment listed had also been evaluated to identify its appropriate category and operating times. A category and operating time was assigned to each component for each 10 CFR 50.49 event that might create a harsh environment in the location of that component.
No deficiencies were identified during the review to establish an auditable trail from approved design output information for the listed equipment to the source of the design input.
The licensee performed demonstrated accuracy calculations to determine the accuracy of instruments located in a harsh environment during loss of coolant accident /high energy line break (LOCA/HELB) following a seismic event. The accuracy of the instruments for normal, post seismic and accident conditions were determined by considering the environmental parameters tabulated in the design input section of the calculations.
The inspector selected the following demonstrated accuracy calculations for review in order to evaluate the technical adequacy of set point controls:
e Demonstrated Accuracy Calculation PS 43 200A, Revision 7 e
Demonstrated Accuracy Calculation 1 TS 1 17A, Revision 5 J
e Demonstrated Accuracy Calculation 0 TS 12 91A, Revision 5 e
Demonstrated Accuracy Calculation 1, 2 PDT 65-80, Revision 8 The inspector performed a review of the calculations and verified that environmental )arameters in the location of the instruments were consistent wit 1 approved design documents. Additionally, the calculated accident accuracy values were reviewed to ensure that they had properly incorporated these parameters in the analysis. The following design documents were reviewed during this effort:
e SQNP Environmental Design Criteria SON DC V 21.0, Revision 6 e
EQ Binder SONEQ ITS 001, Revision 23
e EQ Binder SONEQ XHTR 005, Revision 14 l
Based on this review the inspector identified discreaancies in numerical values of the 100 day integrated accident doses in t1ree calculations.
Discrepancies were identified in calculations 1 TS-1-17A PS-43 200A, 1,2 PDT 65 80 and the values listed in the EQ Binder and/or the Environmental Design Criteria SQN DC V 21.0. The root cause of this problem appears to be the incorrect reference to the environmental l
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42 drawings contained in the calculations. These drawings were voided by SQN DC V-21.0 which now specifies 100 day integrated accident doses based on 1000 effective full power day average core exposure.
TVA management was informed of this inspection finding.
PER No. SQ971513PER
dated June 5, 1997 was prepared by TVA to initiate corrective action for this deficiency.
The inspector verified that the 100 day integrated accident doses in the EQ Binders were bounded by the test values and that the above equipment were qualified to the requirements of 10 CFR 50.49.
The inspector concluded that the demonstrated accuracy calculations were performed using accepted industry practices and the results were technically adequate.
c.
Conclusions The inspector concluded that the 10 CFR 50.59 Safety Evaluations were technically adequate. Additionally, the design control program was implemented in accordance with the requirements of ANSI N45.2.111974 in that there was a clear and auditable path from selected design outputs back to the source of the design inputs. Set point controls were
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determined to be technically adequate. The overall quality of plant modifications DCN M8779A and M8780A was determined to be good and appears to have achieved the design objective of re establishing configuration control of Sequoyah's EQ program.
E.8 Miscellaneous Engineering Issues (92903)
E8.1 (Closed) VIO 50 327. 328/97-03 02:
Failure to Follow In.structions in a Work Order Resultina in an ESF Actuation. The inspector verified the corrective actions described in the licensee's response letter, dated June 11, 1977, to be reasonable and complete.
No similar problems were identified.
(Closed) LER 50-327/97 007: Diesel Generator Starts That Resulted From Cuttina a Cable While Drillina a Panel and Durina Repairs to the Damaaed
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Cable. This LER was closed based on the corrective actions of VIO 50-327, 328/97 03 02.
No new issues were revealed by the LER.
E8.2 (Closed) LER 50 327/96 004:
Inadvertent Enaineered Safety Feature (ESF)
Actuation. Loss of Power Sianal and Start of Four Diesel Generators.
The inspector reviewed the event which occurred due to a breaker failure when operators attempted to transfer the 2B start bus from the alternate to the normal aower su) ply. The inspector concluded that the corrective actions descriaed in t1e LER were reasonable and complete.
No new l
issues were revealed by the LER.
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E8.3 (Closed) LER 50 327/96-008: A Quarterly Backseat / Closure Test on Five Check Valves On Each Unit Was Not Performed As Recuired By the American
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Society of Mechanical Enaineers (ASME)Section XI In Service Valve Testina Proaram Basis Document.
This issue was discussed in IR 50 32'7, l
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328/96 08 and resulted in the issuance of NCV 50 327, 328/96 08 03.
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new issues were revealed by the LER.
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E8.4 (Closed) LER 50 327/96-009: An Auxiliary Buildina Secondary Containment Boundary / Fire Barrier Was Not Maintained as Reauired by Desian Resultina From a Failure to Follow the Desian Control Process. This LER was a minor issue and was closed.
E8.5 (Closed) IFI 50 327. 328/96 14 02: Review Corrective Actions Related to Continuina Steam Dumo System Operational Problems.
(Closed) IFI 50 327. 328/96 17 03: Steam Dumo Drain System Imorovements.
The above two IFIs discussed problems related to the operation of the
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steam dump systems on both units. Proposed corrective actions were l
developed and were documented in IR 50 327, 328/97 17. During the Unit 1 outage, the licensee implemented various modifications to the steam dump system. The success of the modifications was discussed in IR 50 327, 328/97 04 Section E2.1. Walkdowns of the steam dump system during startup noted that the modifications had corrected the mild water
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l hammering, observed during previous startups and shutdowns.
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J E8.6 (Closed) 1.ER 50 328/96 004: After a Reactor Trio Breaker Was Removed.
It Was Found To Have Inocerable Auxiliary Contacts.
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(Closed) LER 50 328/96 004. Revision 01: After a Reactor Trio Breaker
Was Removed. It Was Found To Have InoDerable Auxiliary Contacts, The above two LERs discussed the inadequate maintenance activities l
associated with the on line refurbishment of the Unit 2 "B" reactor trip breaker and the subsequent installation of that breaker into the reactor
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l 3rotection system.
IR 50 327, 328/96 13 identified apparent violations l
EEI 96 13-07. EEI 96-13 08, and EEI 96 13 09, which were subsequently documented as escalated enforcement action EA 96 414. The corrective actions associated with these LERs will be reviewed and documented l
during the followup of EA 96 414.
l E8.7 (Closed) IFI 328/96 14 01: Safety In.iection Relief Valve Setooint
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Discrepancies. This item was originally discussed in IR 50 327, 328/96-l 14, which documented a November 2, 1996, overpressure condition with the i
Unit 2 safety injection system. A TIA was initiated and after l
completing actions NRR forwarded TIA 97-01 to Region II on April 18, l
1997. The TIA noted that on November 2, 1996, the licensee was not in compliance with the ANSI code requirements for as found settings of the subject safety injection system relief valves.
IR 50 327, 328/97 06 identified the issue as VIO 328/97-06 08.
E8.8 (Closed) IFI 327. 328/96 02-02: Review Corrective Actions of PER No.
S0960759PER Recardina CCS Surae Tank Overflow. The inspector reviewed the above PER and determined that closure for this item was based on
i implementation of NRC commitment NC0960030002. TVA management in a
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realy to a Notice of Violation stated that a design issue will be su)mitted to address the component cooling system (CCS) surge tank vent piping arrangement for potential modification of the system.
Based on objective evidence reviewed the inspector verified that Issues No.96060 and 96061, dated June 13, 1996, were submitted to the Plant Issues Committee (PIC) by Technical Support in response to the NRC commitment. The proposed solution for the design deficiency was broader in scope than the commitment delineated in TVA's letter dated May 22, 1996. The scope of the plant modification for resolution of the design deficiency will include:
Surge Vent Valve route piping from vent valves 1 FCV 70 66 e
to the floor drain located beneath the CCS surge tank.
e Surge Tank level instrumentation replace level transmitter dry reference leg with a wet reference leg.
The inspector concluded that the corrective action to be implemented by the proposed plant modification was consistent with the corrective action delineated in block C.9 of PER No. SQ960759PER and the intent of the licensee's commitment. This item is closed based on review of objective evidence.
E8.9 (Closed) IFI 327. 328/93 35 02:
B0P Fuse Control. The inspector reviewed actions completed by the licensee in connection with establishing a project to review ar.d upgrade BOP fuse control. TVA management has taken credit for existing administrative controls of B0P fuses delineated in procedure SSP 12.2 System and Equipment Status Control Revision 20. Additionally, TVA stated that B0P fuses th6t cause plant transients or power reductions are within the scope of the Maintenance Rule which requires B0P functional failures to be recorded
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and trended. A root cause analysis is required to be performed and developed corrective action plans need to be implemented for recurrence control.
The inspector performed an independent review of SSP-12.2 and verified that procedural controls have been established for selecting Non 1E fuses which are installed in circuits identified by the System Operating Instruction Power Availability List. Procedure SSP 12.2, Section 3.9.1.C identified the Equipment Management System Fuse Tabulation as an a) proved design output document which is maintained current to reflect t1e as built plant configuration.
Substitution of Non 1E fuses is permitted by NE design standard DS E8.1.1 and DS E8.1.2.
This process is implemented by use of the Non 1E Fuse Substitution List sheen on TVA drawing 45A700 series and the Non 1E Substitution Notification Form, Appendix G to SSP 12.2.
l The licensee also stated that a review of Tracking and Reporting of Open l
Items (TROI) for fuse related problems revealed that fuse problems at Sequoyah are primarily misluling and misidentification.
Fuse size and
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j type discrepancies identifieu in B0P circuits have not caused plant
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i transients nor plant reliability problems. The inspector reviewed a l
l printout of TROI dated May 5, 1997, which had been prepared based on the l
word search fuse. The total listing of plant 3roblems related to the word " fuse" covered a field of 198 entries. T1e inspector determined i
from this review that objective evidence did not demonstrate that plant i
problems caused by BOP fuses had resulted in plant transients nor i
L challenges to safety systems. The inspector concluded that reasonable
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assurance existed for control of B0P fuses. This item is closed based on the review of objective evidence.
E8.10 (Closed) Unresolved Item (URI) 327. 328/93 02-04:
NRC Review and
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Evaluate GDC 17 Plant Grid Interface.
PER No. SQ940164PER dated March 1, 1994, documented an event where on March 18, 1994, the system peak load of 24,723 megawatts (MW) exceeded the value of 24,000 MW analyzed
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by the Customer Grou) and resulted in the delayed offset power being inoperable.
Sequoyal received no notification of this condition and
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compensatory actions required by LC0 3.8.1.1 were never taken.
PER No.
I SQ951121PER dated August 10, 1995, documented an event where on August 10, 1995, the Transmission and Power Supply (TPS) load
coordinators forecasted a system record peak load of 26,100 MW to occur
on August 14, 1995. The TPS analysis section had set a system load of l
25,722 MW as the maximum analyzed system load for maintaining minimum
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161 kV voltage requirements for Sequoyah offsite power. TPS recommended
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that Sequoyah enter applicable LC0 when the system peak load exceeded
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25,722 MW.
Sequoyah procedure SWYD letter 18, however, had not established requirements for responding to this scenario. The root i
cause for this deficiency was determined to be ineffective corrective l
action for a previously identified problem. This deficiency was
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corrected by revising procedure Switchyard letter-18, SWYD-18.
i The NRC staff's concern regarding the reliability of the offsite power grid at Sequoyah were discussed in NRC IR 50-327, 328/93 02 and in a letter dated March 27, 1996, to TVA recuesting additional information.
TVA's response to that letter was datec July 17, 1996. The NRC has l
reviewed the response received from TVA in connection with this request.
l The staff has, however, determined that additional information is needed.
In a letter dated January 17, 1997, the NRC requested
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l additional information within 60 days of TVA's receipt of the letter.
TVA, in a letter to the NRC dated June 2, 1997, Subject:
Sequoyah
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Nuclear Plant-Response to Request for Additional Information Regarding Reliability of Offsite Power System (TAC Nos. M93319 and M93320),
provided the information requested. The inspector discussed the t
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submittal with TVA's engineering personnel and requested copies of the i
following documents'which provided the basis for TVA's argument l
concerning the adequacy and reliability of the offsite power system:
i DNE Calculation No. SQN GRID STUDY 004 Sequoyah Nuclear e
Plant (SQN) Transmission System Study (TSS) Grid Voltage
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Study of Sequoyah Offsite Power System, Revision 0
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DNE Calculation No. SON GRID-STUDY 003, Transmission System o
Study (TSS) Sequoyah Nuclear Plant (SQN) 161 and 500 kV Grid Voltage Schedules and Operating Instructions with a Coincident Extreme Load Forecast Update, Revision 0.
i e
Switchyard Operations SWYD 18. Plant Voltage Schedule l
Procedure, Revision 15, l
The inspector determined that calculation No. SQN GRID STUDY 004 was a
" Planning" TSS performed on a three year cycle to evaluate steady state and transient conditions at Sequoyah.
It evaluated the current year when issued and a five year look ahead. This calculation documented load flow and transient stability studies of the offsite power system, j
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l The load flow study determined the minimum acceptable steady state voltage at Sequoyah to be 153 kV. The study concluded that with an instantaneous net system load of 28,284 MW: all switchyard inter ties
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closed; and with the Sequoyah capacitor bank in service this design criteria would be satisfied until the year 2000. The minimum voltage requirement would be violated in the summer of 2000, under the following conditions, the Raccoon Mountain inter-tie being out of service is a l
pre event: there is a LOCA for Sequoyah Unit 2: and the Sequoyah inter-
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tie transformer is out of service.
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The transient stability study concluded that there were no voltage recovery problems on the Unit and shutdown boards.
j Calculation No. SON-GRID STUDY 003 was described as an " operational" TSS j
which is performed on an annual basis.
It defines for the current year the following:
l l
e The 161 kV and 500 kV operating voltage schedule e
Sequoyah operating parameters for (1) the main generators.
(2) the 500/161 kV inter tie transformer, (3) the 161 kV capacitor bank l
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This calculation used an instantaneous net system peak load of 28,797 MW and was performed for the following four base cases with various pre-existing conditions:
1)
All switchyard ties closed
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2)
Sequoyah inter-tie transformer bank outage 3)
Raccoon Mountain inter tie transformer bank outage 4)
Sequoyah inter-tie transformer bank outage and outage of Sequoyah 161 kV capacitor banks
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The study concluded that the Sequoyah offsite power supply was adequate for a net system load u) to 28,797 MW with two immediate sources whenever the capacitor aanks were available. Requirements for ensuring the availability of the two immediate sources were identified as:
1)
Only if operation of the capacitors includes maintaining them in automatic control on the wide band continuously.
j 2)
And only if specific indicators are monitored and controlled. These indicators are Sequoyah Unit 2 reactive i
output. Sequoyah 161 kV bus voltage, and Sequoyah 500/161 kV inter tie transformer bank reactive flow.
i Attachment V of calculation SQN GRID-STUDY 003, Operating Guide Memorandum, was reviewed and verified to provide new Sequoyah grid i
operating instructions based on the results of the calculation. The inspector reviewed procedure SWYD-18, Revision 15, and A)pendix C, Units 1 and 2 Gross Reactive Generation Limits, and verified t1at administrative controls had been established for monitoring and i
controlling the indicators identified above. Section 3.1, Peak System Load, requires Secuoyah to enter LC0 3.8.1.1 Action d, if the total system load exceecs those requirements specified in the Chickamauga Load Dispatcher grid voltage limits which were summarized by Appendix C.
This item is closed based on review of objective evidence and discussions with NRR concerning the results of the review. Ongoing NRR review of the issue continues under TAC M93319 and M93320.
E8.11 Ellis and Watts Procurement Activities NRC's memorandum from Robert M. Gallo, Chief Special Ins)ection Branch to Johns Jaudon, Director Division of Reactor Safety, Su) ject:
Deficiencies Regarding Air Conditioning Equipment Purchased By the TVA and Texas Utilities Company from Ellis and Watts, recommended regional followup of TVA's procurement activities involving Ellis and Watts.
The inspector discussed this issue with TVA's personnel and reviewed documentation summarizing the results of TVA's Vendor audits of Ellis and Watts. The licensee has conducted several audits of Ellis and Watts beginning in September 1976 and continuing up to June 1996.
In February of 1995 based on an action item from PER No. BFPER940133 the Vendor Audit Services performed an audit to investigate the cause of problems with TVA/Bechtel Contract 21042-M 01060.
Based on the results of this audit a restriction was added that all design for assemblies and i
dedication packages for dedicated commercial items be submitted for Site Engineering ap,roval.
In October of 1995 TVA performed a review of NUPIC Audit 964-11 and additional restrictions were added concerning l
l material verification and traceable weld material. NUPIC recommended l
that utilities have Ellis and Watts submit dedication plans for I
approval. The Vendor Audit Services received information from NUPIC in April of 1996 that a followup visit to Ellis and Watts revealed l
continuing weaknesses in the driic3 tion process. Based on this
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information Ellis and Watts was dropped from TVA's accepted supplier list.
E8.12 (Closed) URI 50-327. 328/95 01 01: Caoabilities of Motors to Achieve Toraue Switch Trio at Dearaded Voltaae and Accident Temoerature. The licensee had derated the capabilities of actuators with alternating current motors in accordance with recent information from the actuator manufacturer on the effects of temperature calculated to be present at
the time of MOV operation.
NRC Ins 3ection 50 327, 328/95 01 identified i
that the licensee had not ensured tlat the recalculated actuator capabilities were above the present torcue switch settings.
In the current inspection, the inspectors founc that the licensee had
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subsequently compared the settings and capabilities and determined that
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the settings of six MOVs should be lowered. The inspectors verified
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that the settings of these MOVs had been appropriately reduced in i
accordance with DCN M10824 during the Cycle 7 refueling outage.
E8.13 (Closed) IFI 50 327. 328/93 36 01: Review of Electrical Modifications for ERCW MOVs.
This item was opened to provide an NRC review of
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completed modifications to 24 emergency raw cooling water valves. These were plug valves whose function was to close for containment isolation.
The modification involved changing the valves from torque switch controlled seating to limit switch controlled seating. The inspectors verified documentation of adequate comaletion of this modification.
Their review included the PER No. SQPE1930302 that specified the modification, DCNs M 0937 A and M 09956 A, and examples of a completed WO (95 00911 00 for valve 1 FCV 67130) and diagnostic post modification test (for valve 2 FCV 67 139) for the valves.
E8.15 (Closed VIO 01012/EA 95 252:
Failure to Ensure that Provisions of 10 CFR 50.7 were complied with. This violation identified that in July through September 1991, the licensee discriminated against an employee engaged in protected activities.
Specific corrective action for this violation was reviewed and documented in NRC Inspection Report 50-327,328/96 17. This violation is closed for record purposes; however, the staff will continue to monitor plant specific indicators related to discriminatory employment practices. These indicators include, in part, allegations of
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discrimination reported to the NRC and proceedings initiated as a result of complaints made to the Department of Labor alleging discrimination j
for engaging in protected activity.
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IV. P1 ant Support
R1 Radiological Protection and Chemistry (RP&C) Controls (71750, 83750, 84750, 86750, TI 2515/133)
R1.2 Transoortation of Radioactive Materials
j a.
Insoection Scope The inspctors evaluated the licensee's transprtation of radioactive
materials program for implementing the revised Department of Transportation (D0T) and NRC trans>ortation regulations for shipment of
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radioactive materials as required )y 10 CFR 71.5 and 49 CFR Parts 100
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through 177.
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b.
Observations and Findinas j
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The inspectors reviewed procedures and determined that they adequately
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addressed the following:
1) assuring that the receiver has a license to
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receive the material being shipped: 2) assigning the form, quantity
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type, and proper shipping name of the material to be shipped: 3)
l classifying waste destined for burial: 4) selecting the type of package required: 5) assuring that the radiation and contamination limits were l
met; and 6) preparing shipping papers.
I The licensee's records for technical staff training were reviewed and j
the inspectors determined that the technical staff had received the requisite training for rad material shipments. The training for the technical staff this year has been scheduled for July.
The inspectors requested that the licensee produce a sample shipping manifest using their software program. The inspectors provided sample input information and the resultant printed sample manifest was
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reviewed. The inspectors determined that the form met the current requirements.
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Conclusions
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Based on the above reviews, the inspectors determined that the licensee had effectively implemented a program for shipping radioactive materials
required by NRC and D0T regulations.
a j
R1.3 Occuoational Radiation Exoosure Control Proaram
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a.
Insoection Scope The inspectors reviewed implementation of selected elements of the
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licensee's radiation protection program (10 CFR 20.1101). The review i
included observation of radiological protection activities including personnel monitoring (10 CFR 20.1502), radiological postings (10 CFR 20.1904 & 1902), high radiation area controls (10 CFR 20.1601 &
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1602), and verification of posted radiation dose rates (10 CFR 20.1501 &
1502) and contamination controls within the RCA. The inspectors also i
reviewed licensee records of personnel radiation exposure and discussed as low as reasonably achievable (ALARA) program details, implementation,
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and goals.
b.
Observations and Findinas The inspectors toured Auxiliary Building facilities, Truck Bay, and radioactive waste storage area. At the time of the inspection,
radiological housekeeping was observed to be good. Radiologically controlled areas observed were appropriately posted and radioactive material observed was appropriately stored and labeled.
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The inspectors reviewed the postings and performed independent contamination and boundary radiation surveys in the auxiliary building at the boric acid pumps and storage tanks. All postings were found accurate and current.
Boundary surveys were as posted and no contamination was found on the inspector requested smears.
The Fiscal Year 1997 site exposure goal has been set at 300 person rem.
At the time of the inspection, the site person-rem was about 275.105 Jerson rem (not TLD corrected); thus, about 92 percent of the goal had
3een expended. Individual radiation worker internal and external doses were being maintained well below regulatory limits and the licensee was continuing to maintain exposures ALARA.
The inspectors reviewed PER No. SQ970929PER and the actions taken by tfe licensee in response to the identified problem. On A)ril 8, 1997 a Radiography supervisor did not comply with Procedure,1CI 16 " Radiation Protection During Radiographic Operations" Revision 3, and Procedure RCI-14 " Radiation Work Permit (RWP) Program" Revision 20. Specifically,
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the Radiograahy supervisor did not: (1) receive authorization from the responsible ladcon Shift Supervisor prior to exposing the source (RCI 16 Step 7.7E) (2) positively verify personnel were evacuated from the established zone prior to exposing the source (RCI 16 Step 7.7A) and (3)
follow the conditions required by the RWP (RCI-14 Step 7.1).
The licensee immediately stopped radiography operations. The event was reviewed and written statements from personnel who were present were discussed during a meeting with affected employees. TLD and electronic dosimetry results were analyzed and no measurable dose was found. This was primarily due to distance from the source, worker location and the short source exposure.
Exposure to the affected radiography area had been controlled by the radiographer in compliance with his safety manual. The licensee instituted the following interim corrective actions: (1) Adequacy of communications was stressed (2) The effects of fatigue were reviewed (3) Radiography RWP's to be written and approved by the Radeon Manager, and (4) Radcon personnel were briefed on responsibilities and expectations for Radiographic Operations. The licensee made a informational call to Region II and the notified the Site Resident Office. The licensee was informed that the failure to follow licensee site procedures was a violation. This licensee-
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identified and corrected violation is being treated as a Non Cited Violation consistent with Section IV of the NRC Enforcement Policy. (NCV
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50-327, 328/97-06-10).
The inspectors reviewed PER No. SQ971429PER that involved a spill of radioactive liquid at ap elevation Railroad Bay. proximately 16:25 on May 19,1997, in the 706'
The liquid came from a failed conductivity arobe on the inlet to the Modularized Fluidized Transfer Jemineralization System (MFTDS). Approximately 3000 gallons were
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released during the spill and about 300 gallons were released from the Waste Packaging Area to the rad waste yard immediately adjacent to the railroad Bay Door. The inspectors reviewed Procedure 0 VI 0PS 077 001.0
" Operating Procedure for CNSI Modular Fluidized Transfer Demineralization System Chem Nuclear Systems, INC", Revision 1.
At the time of the inspection decontamination had been completed inside of
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the plant and the areas had been released. The inspectors reviewed the
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clean up activities and the results of the soil samples from the excavated soil. Approximately 4500 cubic feet of slightly contaminated soil and asphalt paving had been removed and the process of backfilling
the excavation was underway. Samples of the storm drain in the proximity to the rad waste yard indicated no presence of the spilled material. The yard pond was also sampled and indicated no presence of contamination. There were no personnel contaminations or injuries as a
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result of the spill. Closeout activities from the spill were still in progress.
Preliminary dose estimates by the licensee using conservative assumptions (upper bounding dose) determined the incremental maximum
individual dose at the site boundary (0.870 km in the South Direction)
to be 2.75 E 04 mrem to the Liver (critical organ) and 1.40 E 04 mrem to the total body. These doses are small percentages of annual dose limits. The inspectors reviewed the Action Plan for Recovering EL 706'
Radwaste Yard, Revision 1 dated June 25, 1997.
During a. followup tour
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of the Railroad Bay the ins sectors noticed physical openings alongside
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of the railroad tracks whic1 pass under the door. An empirical
measurement of air flow performed by the inspectors found that the flow was toward the outside. Review of the Updated Final Safety Analysis
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Report at Section 9.4.2.1 Design Ba~is for the Auxiliary Building states that " Areas of the building which ar. subject to radioactive contamination are maintained at a slig:? negative pressure to limit out leakage.
In addition, the system has the cap:bility of isolating the
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contaminated areas from outdoors. All exhaust ah is routed through a duct system, and is discharged into the Auxiliary BLilding exhaust stack which is located atop the Auxiliary Building, and extends above the roof." In addition Detailed Design Criteria WO. SQN DC V 1.1.7 Titled Auxiliary Building Railroad Access Door ead Associated Equipment, dated July 29, 1971, states in Section 3.3, Falure Criteria, "During normal
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conditions with a pressure differentia; of 1/4" water, air leakage for the door is not to exceed 1500 cfm". Section 4.1.2. Seals, states
" Removable, rubber blocks shall be pr(vided for sealing at each of the railroad rails where they pass f "ough the embedded door sill". A i
search of the Work Request SysN idencified a work request No: C053504 dated April 14, 1994 associatid with the Roll up Door. The request
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identified the rubber seals in the railroad tracks as having
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deteriorated and needing replacement. At the time of the ins seals had not been replaced although the WR was still active.pection the The failure to replace the rubber gasket seals and the failure to maintain the auxiliary building at a negative pressure at this location were identified as a violation (50 327, 328/97-0611).
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Conclusions Radiological facility controls and housekeeping in radioactive waste storage areas were obrerved to be good. Material was labeled appropriately, and areas were pro)erly posted.
Radiation worker internal and external doses were )eing maintained well below regulatory limits and the licensee was continuing to maintain exposures ALARA. One non cited and one cited violation were identified.
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R1.4 Water Chemistry Controls a.
Inspection Scoce The inspectors reviewed implementation of selected elements of the licensee's water chemistry control program for monitoring primary and secondary water quality. The review included examination of program guidance and implementing procedures and analytical results for selected chemistry parameters, b.
Observations and Findinas The inspectors reviewed technical specifications (TSs), which described the operational and surveillance requirements for reactor coolant activity and chemistry, and Final Safety Analysis Report (FSAR), Section 10.3.5, Water Chemistry. The section indicated that guidelines for maintaining reactor coolant and feedwater quality were derived from vendor recommendations and the current revisions of the Electric Power Research Institute (EPRI) Pressurized Water Reactor (PWR) Primary and Secondary Water Chemistry Guidelines. The UFSAR also indicated that detailed operating specifications for the chemistry of those systems were addressed in the Station Chemistry Section.
The inspectors reviewed selected analytical results recorded for Unit 1 and Unit 2 reactor coolant and secondary samples taken during the inspection period. The selected parameters reviewed for primary chemistry included dissolved oxygen, chloride, fluoride, and sulfate levels. The selected parameters reviewed for secondary chemistry included hydrazine, iron, and cop>er levels. Those primary parameters reviewed were maintained well wit 11n the relevant TSs limits and within the EPRI guidelines for power operations.
The ins)ectors reviewed the June 16, 1997 memo from reactor engineering to the )lant Manager discussing Sequoyah Units 1 and 2 Fuel Integrity Status. Unit 1 observed an instantaneous fuel defect event after about 8 Effective Fuel Power Days burnup, May 23, 1997, after starting Cycle 9 defect free.
Indications were that 2-3 " average" defects occurred.
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Unit I was classified in Action 1 of Site Standard Practice (SSP) SSP-
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i 12.55 Fuel Integrity Assessment Program.
Unit 2 continues in Action 1.
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One defect was believed to have been carried over from Cycle 7 and the
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licensee believes the defect has a high probability of discharge during
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the next outage. The conditions that define Action 1 are: 0.003 < I-131 s 0.025 C1/g or 0.1 s Xe-133 s 1.0 pC1/g. The actions ::pecified are: (1) Notify plant management and Nuclear Fuel (2) Estimate number, nature, and burnup of failed fuel (3) Determine possible causes and appropriate actions to mitigate radiological impact and prevent
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additional failures (4) Survey industry experience (5) Notify fuel supplier (6) Establish contingencies for fuel inspection. The inspectors reviewed the isotopic results and confirmed that the actions taken were as stated in the SSP.
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Conclusions Based on the above reviews, it was concluded that the licensee's water chemistry control program for monitoring primary and secondary water quality had been implemented, for those )arameters reviewed, in accordance with the TSs requirements. T1e Fuel Integrity Assessment team was aerforming the required fuel integrity assessments as specified by the SS).
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R1.5 Annual Effluent Release Report and Annual Radiolooical Environmental Operatina Report a.
Insoection Scope Technical Specifications Section 6.8.1(1) titled Offsite Dose Calculation Manual details the methodology and parameters used in the calculation of offsite doses.
Section 5.1 and 5.2 require the submission of The 1996 Annual Radioactive Effluent Release Report and Annual Radioloaical Environmental Ooeratina Report, b.
Observations and Findinas The inspectors reviewed The 1996 Annual Radioactive Effluent Release Report. The report detailed the solid waste shipped offsite for burial or disposition. A tabulation for this waste is listed below.
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Type of Waste Unit 12 Month Est. Tot.
Period Error %
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Spent resins, filter m'
2.19E+01 i5.00E 01 sludges, evaporator Ci 5.65E+02 i1.50E+00 i
bottoms, etc.
b.
Dry Active Waste, m'
5.75E+01 i5.00E 01 Compressible Waste Ci 7.43E+00 i5.00E 01 Contaminated Equipment, etc.
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Irradiated Components, m'
None N/A Control Ci None N/A Rods, etc.
d.
Other - Thermal destruction m'
6.06E+00 i5.00E 01 of scintillation fluids Ci 3.35E+01 i5.00E 01
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External gamma radiation levels were measured by thermoluminescent dosimeters (TLDs) deployed around Sequoyah as part of the offsite Environmental Radiological Monitoring Program. The quarterly gamma radiation levels determined from these TLDs during this reporting period averaged approximately 15.7 mR/ quarter at onsite (at or near the site boundary) stations and approximately 14.5 mR/ quarter at offsite stations or approximately 1.2 mR/ quarter higher onsite than at offsite stations. This may be attributable to natural variations in environmental radiation levels, earth moving activities onsite, the mass of concrete employed in j
the construction of the plants, or other undetermined influences.
Fluctuations in natural background dose rates and in TLD readings tend to mask any small increments which may be due to plant operations.
Sequoyah Environmental TLD Direct Radiation Environmental Monitoring results reported for the first quarter 1997 in NUREG-0837 NRC TLD Direct Radiation Konitorina Network range from 16.5 t 0.9 mR/Std.Qtr to 17.1 i 1.6 mR/Std.
Otr.. There were no aty)ical results for Sequoyah identified in the NUREG.
The licensee concluded t1at there was no identifiable increase in dose rate levels attributable to direct radiation from plant equipment and/or gaseous effluents.
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To determine compliance with 40 CFR 190, annual total dose contribution to the maximum individual from Sequoyah radioactive effluents and all other nearby uranium fuel cycle sources were considered. Cumulative annual total doses are presented in the following table.
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Total Dose from Fuel Cycle
1996
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First Second Third Fourth Dese Quarter Quarter Quarter Quarter i
Total Body or any Organ (except thyroid)
Total body air 7.88E 04 1.05E 03 8.22E 04 1.39E-03 submersion Critical organ dose 1.04E 02 7.74E 03 1.90E 02 1.84E-02
(air)
l Total body dose 1.7E-02 1.9E 02 5.6E 03 2.1E 03
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(liquid)
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Maximum organ dose 2.3E 02 2.5E 02 7.1E 03 2.5E 03
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(liquid)
Direct Radiation Dose 0.0E 00 0.0E 00 0.0E 00 0.0E-00 Total 5.1E-02 5.3E-02 3.3E-02 2.4E-02 Cumulative Total Dose (aren)
1.6E-01
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Annual Dose Limit (ares)
2.50E401 Percent of Limit
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Thyroid
Total body air 7.88E 04 1.05E 03 8.22E 04 1.39E 03 submersion Thyroid dose 1.04E 02 7.74E 03 1.90E-02 1.85E 02 (airborne)
Total body dose 1.7E 02 1.9E-02 5.6E 03 2.1E 03 (liquid)
Thyroid dose (liquid)
3.2E-03 4.5E 03 2.1E 03 1.7E 03
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Direct Radiation Dose 0.0E-00 0.0E 00 0.0E 00 0.0E 00 Total 3.1E-02 3.2E-02 2.8E-02 2.4E-02 Cumulative Total Dose (ares)
1.2E-01 Annual Dose Limit (ares)
7.50E+01 Percent of Limit
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l The inspectors selectively reviewed the Annual Radioloaical Environmental Ooeratina Report and the data supporting the report. The inspectors' review of the data determined that there was no radioactivity attributable to the plant detected in the 1996 monitoring program.
Environmental radioactivity measured by the program was due to naturally occurring radioactive materials or radionuclides commonly found in the environment as a result of atmospheric fallout. The exposures calculated from the Annual Radioloaical Environmental Doeratina Report resultant data were consistent with results from the preoperational monitoring program.
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Conclusions The radiological imaact from the facility operation was less than 1 percent of the 40 C R 190 regulatory limit. The exposures calculated from the 1996 Annual Radioactive Effluent Release Report resultant data
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were consistent with results from the preoperational monitoring program.
V. Manaaement Meetinos
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X1 Exit Meeting Summary The inspectors ) resented the inspection results to members of licensee management at t1e conclusion of the inspection on July 16, 1997. The licensee acknowledged the findings presented.
The inspectors asked the licensee whether any materials would be
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considered proprietary.
No proprietary information was identified.
PARTIAL LIST OF PERSONS CONTACTED Licensee
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- Bajestani, M., Site Vice President (as of June 30, 1997)
- Beasley, J., Acting Site Quality Manager Bryant, L., Outage Manager
- Burton, C.. Engineering and Support Services Manager
- Butterworth, H., Operations Manager
- Flippo T., Site Support Manager
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Herron, J., Plant Manager Hunt, W., Operations Training Manager Kent, C., Radcon/ Chemistry Manager
- Koehl, D, Assistant Plant Manager
- Lorek, M., System Engineering Manager O' Brian, B., Maintenance Manager Reynolds, J., Operations Superintendent
- Rupert, J., Engineering and Support Services Manager
- Salas, P., Manager of Licensing and Industry Affairs
- Valente, J., Engineering & Materials Manager
- Attended exit interview
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INSPECTION PROCEDURES USED
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IP 37550:
Engineering IP 37551:
Onsite Engineering IP 40500:
Effectiveness of Licensee Controls In Identifying,
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Resolving, & Preventing Problems IP 61700:
Surveillance Procedures and Records
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IP 61726:
Surveillance Observations IP 62707:
Maintenance Observations
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IP 64704:
Fire Protection Program IP 71707:
Plant Oprations IP 71714:
Cold Weather Preparations IP 71750:
Plant Support Activities IP 83750:
Occupational Radiation Exposure IP 84750:
Radioactive Waste Treatment, And Effluent And Environmental
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Monitoring IP 86750:
Solid Radioactive Waste Management And Transportation Of Radioactive Materials IP 92901:
Followup - Operations
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IP 92902:
Followup Maintenance IP 92903:
Followup Engineering TI 2515/109:
Inspection Requirements for Generic Letter 89 10, Safety Related Motor 0perated Valve Testing and Surveillance TI 2515/133:
Implementation of Revised 49 CFR 100179 and 10 CFR 71
ITEMS OPENED. CLOSED. AND DISCUSSED
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The following escalated enforcement items (EEI) were reviewed as part of an enforcement conference with the licensee on June 27, 1997. Subsequent
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enforcement was taken on the issues by letter dated July 10, 1997.
Based on the enforcement conference and two violations issued on July 10, 1997, the EEIs listed below are closed.
Followup of licensee corrective actions for the
violations documented in the July 10, 1997, enforcement action will be conducted as part of the violation closecuts.
Tyge Item Number Status Description and Reference
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EEI 50-327, 328/97 05 01 Closed Inadequate Corrective Actions for EA 97 232 the 1993 Drain Down Event
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EEI 50 327, 328/97 05 02 Closed Failure to Follow SSP 12.1, Conduct EA 97-232 Operations
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The following violations were issued as a result of escalated enforcement action taken on July 10, 1997.
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Tvoe Item Number Status Description and Reference VIO 01013 Open Failure to Identify and Take
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EA 97-232 Corrective Actions for Loss of RCS Inventory Cont ml While Draining Pressurizer (IR 50 327, 328/97 05)
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VIO 01023 Open Failure Properly Log a Unit 1
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EA 97 232 RCS Drain Down Evolution (IR 50 327.
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328/97-05)
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Ooened Type Item Number Status Descriotion and Reference
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NCV 50 328/97-06 01 Ogn/
Failure to Follow Procedure Which i
Close Resulted in Establishing a Flow Path
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for ERCW to Enter and Contaminate the "A" CST (Section 01.3)
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IFI 50 327, 328/97 06-03 Open Review the Licensee *s Emergency
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Diesel Generator Reliability and Failure Analysis (Section M1.2)
NCV 50-327/97 06 04 Open/
Failure to Inspect Both Sides of
Closed Nine Fire Barrier Penetration Seals as Required by Procedures (Section
M1.4)
NCV 50 328/97 06 05 Ogn/
Failure to Follow a Maintenance Work
Close Order Resulting in Work on Wrong
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Valve (Section M4.1)
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NCV 50-327, 328/97 06 06 Open/
Failure to Properly Perform Close Surveillance Testing (Section M4.2)
IFI 50 327, 328/97 06 07 Open Actions to Resolve Remaining GL 89-10 Issues (Section E1.1)
VIO 50 328/97 06-08 Open Inadequate Corrective Actions for
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Deficient Safety Injection System Relief Valves Lifting Setpoints (Section E2.1)
URI 50 327/97 06-09 Open Remote Position Indication Testing (Section E2.2)
NCV 50 327, 328/97 06-10 Open/
Failure to Follow Procedures RCI-14 Closed and RCI 16 (Section R1.3)
VIO 50 327, 328/97 06 11 Open Failure to Meet 10 CFR 50, Appendix B, Criterion XVI, Corrective Action, Requiring That Measures Shall be Established to Assure that Conditions Adverse to Quality are Promptly Identified and Corrected (Section R1.3)
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Closed
Tygg Item Number Status Description and Reference
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LER 50 328/96 007 Closed Engineered Safety Feature (ESF)
Actuation, Start of the Auxiliary Feedwater System, As a Result of Inadequate Return of Equipment to Service (Section 08.1)
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LER 50 327/96 006 Closed A Failed Coupled Capacitor Potential Device Caused Actuation of the Generator Backup / Transformer Feeder Relay Tripping the Turbine and the Reactor (Section 08.2)
IFI 50-328/97 01 05 Closed Review Root Cause Which Led to N0ED
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on EDG (Section 08.3)
LER 50 327/97 002 Closed Enforcement Discretion Granted When
Problems With the 2A A Diesel Generator Actuator Was Identified (Section 08.3)
i VIO 50 327, 328/96-02 05 Closed Failure to Control Implementation of Plant Modifications as Required By SSP-9.3 (Section M8.1)
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VIO 50 327, 328/96 12 01 Closed Failure to Revise Emergency Operating Procedures as a Result of
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Design Changes to Abandon Plant Equipment (Section M8.2)
LER 50-328/96 003 Closed Reactor Trip Breakers Were Manually Opened With An Automatic Generation
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of a Feedwater Isolation Signal and
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a Manual Reactor Trip (Section M8.3)
LER 50 328/96 006 Closed Automatic Reactor Trip of the Loss of Power to Start Bus 2A, tho Start of Four Emergency Diesel Generators, and Loading of Emergency Diesel
Generator 28 B (Section M8.4)
l LER 50 327/97 001 Closed Failure to Properly Perform
Surveillance Testing on the EDG Timer Relays that are Contained in the Start Logic Circuity (Section M8.5)
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LER 50 327/97 003 Closed Failure to Properly Perform Surveillance Testing on the Centrifugal Charging Pump Inlet Isolation Valve Logic (Section M8.6)
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l LER 50 327/97 008 Closed Failure to Properly Perform Surveillance Testing on the
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Containment Air Return Fan Start
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Logic and on the Blackout and Auto
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Sequencing of the Station Fire Pumps l
(Section M8.7)
IFI 50-327, 328/94 30-01 Closed Deficiencies in Check Valve Program Implementation (Section M8.8)
IFI 50 327, 328/94 30 02 Closed Inadequate Preventive Maintenance on
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Reach Rod Valves (Section M8.9)
IFI 50 327, 328/94 22 02 Closed Snubber Design and Maintenance Items (Section M8.10)
VIO 50 327, 328/97 03 02 Closed Failure to Follow Instructions in a Work Order Resulting in an ESF q
Actuation (Section E8.1)
l LER 50 327/97 007 Closed Diesel Generator Starts That Resulted From Cutting a Cable While Drilling a Panel and During Re) airs to the Damaged Cable (Section 18.1)
I LER 50 327/96 004 Closed Inadvertent Engineered Safety Feature (ESF) Actuation, Loss of Power Signal and Start of Four
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Diesel Generators (Section E8.2)
LER 50-327/96 008 Closed A Quarterly Backseat / Closure Test on F%e Check Valves On Each Unit Was l
Not Performed As Required By the l
American Society of Mechanical l
Engineers (ASME)Section XI In-l Service Valve Testing Program Basis l
Document (Section E8.3)
LER 50 327/96 009 Closed An Auxiliary Building Secondary Containment Boundary / Fire Barrier Was Not Maintained as Required by Design Resulting From a Failure to
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Follow the Design Control Process
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(Section E8.4)
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IFI 50 327, 328/96-14 02 Closed Review Corrective Actions Related to Continuing Steam Dump System Operational Problems (Section E8.5)
IFI 50-327, 328/96-17-03 Closed Steam Dum) Drain System Improvements
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LER 50 328/96 004 Closed After a Reactor Trip Breaker Was
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Removed It Was Found To Have Inoperable Auxiliary Contacts i
(Section E8.6)
LER 50 328/96 004 Closed After a Reactor Trip Breaker Was Revision 01 Removed, It Has Found To Have l
Inoperable Auxiliary Contacts
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(Section E8.6)
IFI 328/96 14 01 Closed Safety Injection Relief Valve l
Setpoint Discrepancies (Section l
E8.7)
l IFI 327, 328/96 02 02 Closed Review Corrective Actions of PER No.
l SQ960759PER Regarding CCS Surge Tank j
Overflow (Section E8.8)
IFI 327, 328/93 35 02 Closed B0P Fuse Control (Section E8.9)
URI 327, 328/93 02 04 Closed NRC Review and Evaluate GDC 17 Plant Grid Interface (Section E8.10)
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URI 50 327, 328/95 01 01 Closed Capabilities of Motors to Achieve Torque Switch Trip at Degraded
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Voltage and Accident Temperature.
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IFI 50 327, 328/93-36 01 Closed Review of Electrical Modifications for ERCW MOVs (Section E8.13)
VIO 01012 EA 95 252 Closed Failure to Ensure that Provisions of l
10 CFR 50.7 Were Complied with
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(Section E8.15)
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UNITED STATES NUCLEAR REGULATORY COMMISSION C
WASHINGTON, D.C. 20666 4 001
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May 21, 1997
c MEMORANDUM T0:
Jon,RJJohkon,iDirector,.._
Division of Reactor Projects Region II FROM:
Frederick J. Hebdon, Director C i
Project Directorate II-3 5#
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Division of Reactor Projects - I/II Office of Nuclear Reactor Regulation SUBJECT:
NRR RESPONSE TO TIA 97-01, SEQUOYAH NUCLEAR PLANT, UNITS 1 AND 2 - RELIEF VALVE LIFT SETTINGS REQUIRED BY APPLICABLE
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l CODES (TAC NO. M97281)
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By memorandum dated January 15, 1997, Region II requested technical assistance l
regarding the regulatory requirements and acceptance criteria for relief valves. An issue was raised during plant heatup of Sequoyah Unit 2 in
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November 1996. During this heatup, the Safety Injection system pump discharge header was noted to be pressurized to 1850 psig due to check valve back-l leakage; the system design pressure is 1750 psig. Although the nominal i
setpoint for the three relief valves on the header-is also 1750 psig, none of the relief valves had lifted to relieve pressure. Because of Tennessee Valley Authority's (TVA's) interpretation of the applicable codes, as discussed in the Task Interface Agreement request, TVA concluded that failure of the valves to lift at 1850 psig did not constitute an operability or reportability. issue.
l Region II disagrees with TVA's conclusion and has asked for a NRR position.
NRR has completed its review of this issue and has developed the position in regards to TVA's code interpretation / practice as noted in the attachment.
i Docket No. 50-327 and 50-328
Attachment:
Evaluation
REGION II TASK INTERFACE AGREEMENT (TIAl 97-01 EVALUATION OF SE000YAH PRACTICE REGARDING RELIEF VALVE SETP0INTS Description of Event In a memorandum dated January 15, 1997, Region II requested NRR assistanca
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regarding issues involving the as-found setpoints of plant safety injection
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(SI) system relief valves. During an event at Sequoyah Unit 2 on November 2, 1996, the plant licensee found an SI piping segment, which is isolated from the primary coolant by check valves, to be pressurized to 1850 psig. The
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nominal setpoints for the system relief valves are 1750 psig (also the system l
design pressure), but the valves apparently did not lift to relieve the l
pressure from apparent back-leakage through the check valves.
The Region has i
I provided information from the licensee's relief valve test program and excerpts from the system design codes-American Society of Mechanical Engineers
(ASME)Section VIII for vessels and American National Standards Institute
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(ANSI) 831.7 for piping).
The licensee's test procedure involves setting the relief valves to within 3% of the nominal settings and allows another i 3%
for as-found conditions when the valves are retested after being in service.
Following the event on November 2,1996, one of the three system relief valves was tested and found to have a setpoint of 1840 psig which is within the l
licensee's high side acceptance criterion of 1750 psig + 3% + 3% (or 1855 psig). The licensee stated that this condition did not require reporting or
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cause the valves to be inoperable.
Specifically, the Region is requesting NRR assistance regarding the following:
1.
What establishes the regulatory requirements for relief valve setpoints at Sequoyah?
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2.
What is the maximum allowable as-left condition, including tolerance, I
when setting the relief valves? Should it be set at or below the system l
design pressure of 1750 psig or can it be set at 1750 i 3%?
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3.
Is the condition of the two untested relief valves acceptable, knowing that they will not lift up to 1850 psig in a system with a de::ign pressure of 1750 psig? Can the licensee's program have up to 6% drift from nominal setpoint and still consider the valves to be acceptable?
Evaluation The NRR Mechanical Engineering Branch has evaluated these issues, and the results of our review for the above three items are discussed below, i
ATTACHMENT l
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The NRR staff agrees with the Region II concern that the licensee's
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relief valve testing procedure and acceptance criteria may not meet all I
requirements.
It is our conclusion that it is improper to stack (or-add) the as-left and as-found tolerances together to obtain an even
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l higher allowable limit. To do so is inconsistent with other i
requirements, is not logical, and is misleading.
For example, no licensee (including this one) is allowed to take the i 1% as-left criterion for the pressurizer safety valves or the main steam safety valves and add it to the i 1% (or i 3%) as-found criterion to obtain i 2% (or i 4%) to satisfy the plant technical specifications for
operability.
l The as-left tolerance for setting relief valves is allowed to be as high as i 3% by some design codes including the Section VIII Code applicable to Sequoyah and the later Section III Codes for some liquid relief
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valves.
(The B31.7 Code for piping does not provide a specific
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allowable as-left tolerance; however, some piping designed to B31.7
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requirements also attaches to a Section VIII or Section III vessel such
that the i 3% would apply.) Also, ASME OM-1 for testing of pressure
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relief devices requires resetting and other actions if setpoints exceed
f 3% of their stamped set pressures. As a practical consideration, l
as-left criteria should be based on the capability of the most accurate l
and precise methodology available..That is, as-left criteria should be significantly less than as-found criteria since relief valves are known to drift, and it is not desired to exceed the as-found criteria when the valves are next tested after some time in service.
Therefore, a more
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i stringent as-left tolerance should be favorable for helping assure setpoints within the as-found tolerance.
The as-found tolerance should be supported by an analysis of the limiting operational or transient events for overpressure or other
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safety parameters to verify that the design limits of the piping, vessel, or system are not exceeded. Apparently, the as-found setpoint tolerance for the SI system relief valves which has been used at Sequoyah is effectively i 6%; however, it is not clear that the licensee clearly defines that the relief valves are allowed to drift this much
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and that the licensee has an analysis which demonstrates that i 6% is
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acceptable.
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2.
In order to meet ASME or ANSI Code requirements, certain system relief valves are required to be set at pressures no higher than the system
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design pressures.
It is our conclusion that the highest as-left setpoints are allowed to be based on adding the nominal setpoint values and the as-left tolerance criteria when setting the setpoints, assuming a supporting analysis exists.
For example, if a relief valve has a j
nominal setpoint of 1750 psig and a i 3% as-left tolerance, the valves could be set at 1750 psig + 3% (or 1803 psig), even though 1750 psig is
the system design pressure.
This is consistent with the ASME Code since the Code does not require that valves be set with zero tolerance, and
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j the supporting analysis must include the effects of the allowed as-found i
setpoint tolerance.
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Because of the considerations in item 1 above, NRR concludes that the licensee's procedure for testing the one relief valve may be inadequate I
if the procedure does not clearly indicate what the as-found setpoint criteria is or if the licensee has no analysis which demonstrates that i
the as-found criteria is acceptable. The as-found tolerance should be a
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clearly identified number or percentage. range (i.e., not the result of
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adding two tolerances together), and the supporting analysis should demonstrate that the peak overpressure and other limiting safety i
parameters are acceptable. Therefore, if the licensee has not
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demonstrated that i 6% is the acceptable as-found setpoint tolerance,
the operability of the other two SI system relief valves would be in
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question.
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