ML20141H958
| 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) | |
See also: IR 05000327/1997006
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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
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Licensee:
Tennessee Valley Authority (TVA)
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Facility:
Sequoyah Nuclear Plant, Units 1 & 2
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Location:
Sequoyah Access Road
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Hamilton County, TN 37379
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Dates:
May 25 through July 5,1997
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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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E. Testa, RII Reactor Inspector (Section R1)
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P. Taylor, RII Project Engineer (Section 07.2
07.2)
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S. Sparks RII Project Engineer (Section 07.2
07.3)
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J. Starefos, Resident Inspector, Browns Ferry Nuclear
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Plant (Section 07.2
07.5)
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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
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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
ADOCK 05000327
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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
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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).
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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
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operator trainees to successfully parallel emergency diesel generators
to their shutdown boards (Section 05.1).
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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
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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
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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.
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(Section 07.3).
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A positive observation was noted for operation's timely identification
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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
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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
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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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During plant power changes, numerous equipment problems and material
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condition deficiencies caused challenges to the operations staff
(Section 01.2).
A positive observation was noted with the extensive troubleshooting plan
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and post maintenance testing plan developed by the maintenance manager
with the support of engineering (Section M1.2).
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The pre job briefing for the replacement of a Unit 2 Loop 2 steam
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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
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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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One non cited violation was identified for failure to follow maintenance
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instructions during repair work on a Unit 2 excess letdown isolation
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valve (Section M4.1).
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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
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complete to permit closure of the NRC review (Section E1.1).
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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
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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
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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
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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).
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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
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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
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storage areas were observed to be good. Material was labeled
appropriately, and areas were properly posted (Section R1.3).
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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
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follow site procedures (Section R1.3).
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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
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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
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integrity assessments as specified by tie Site Standard Practice
(Section R1.4).
The radiological impact from facility operation was less than 1 percent
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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
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at power for the remainder of the inspection period.
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Unit-2 began the inspection period in power operation. The. unit operated at
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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
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restored to 100% on June 19, and t1e unit operated at 100% until July 4, when
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power was reduced to approximately 60% due to a main transformer Bucholtz
relay actuation (high combustible gas concentration).
Power was restored to
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100% on July 5, and operated at 100% for the remainder of the inspection
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period.
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Review of Vodated Final Safety Analysis Reoort (UFSAR) Commitments
While performing inspections discussed-in this report, the inspectors reviewed
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the applicable portions of the UFSAR that were related to the areas inspected.
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The inspectors verified that the UFSAR wording was consistent with the
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observed plant practices, procedures, and/or parameters.
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Conduct of Operations (71707)
01.1 General Comments-
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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
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pump. Specific events and noteworthy observations are detailed in the
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sections below,
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01.2 Operational Challenaes Durina Plant Power Chanaes
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a.
Inspection Scope
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The' inspectors reviewed the various operational challenges encountered
during the four significant unit power reductions to perform plant
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repairs.
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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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During the power decrease:
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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compressor tripped on high oil temperature,
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Unit 2 Power Reduction to 60% on July 4 and Power Increase to 100% on
July 5.
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During the power increase: the 2A condensate booster pump tripped
during the start sequence due to an excessive amount of water in the
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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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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
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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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b.
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-
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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
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ERCW valves going open. Operators promptly closed the valves. Actual
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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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The licensee failed to perform steps of procedure 1 SI 0PS-003118.0 in
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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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consistent with Section VII.B.1 of the NRC Enforcement Policy
(NCV 50 328/97 06 01).
c.
Observations
One NCV was identified for failure to follow procedure steps in
sequence.
05
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
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adjusting the synchronizing scope to travel too slowly in the fast
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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
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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.
07
Quality Assurance in Operations (40500)
07.1 Review of the Unit 1 Cycle 8 Quality Assurance (0A) Outaae Assessment
a.
Inspection Scope
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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.
b.
Observations and Findinas
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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
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report, "The report identified numerous recurring human performance
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issues in the areas of conduct of operations, conduct of maintenance,
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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,
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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
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that were either inaccurate or insufficiently documented,
The conduct of event critiques needed improvement,
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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)
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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
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January adverse trend PER on procedural adherence, and the
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November PER on wrong unit / wrong train / wrong component was not
prompt and resulted in a missed opportunity to improve the areas
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prior to the outage.
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The nuclear assurance team noted the following strengths:
Overall planning and prioritization of outage activities were
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focused toward improvement of plant material conditions,
Positive management improvement initiatives were being
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implemented,
The conduct of complex and infrequently performed test pre-job
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briefings was good.
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Site engineering support improved significantly,
Improvement initiatives were implemented to capture lessons
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learned from Watts Bar and Browns Ferry,
The goals and objectives for improving plant material condition
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were fully accomplished,
The management oversight / observation process was expanded to
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include medium risks evolutions.
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The inspector noted that the assessment included extensive documentation
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of these findings. The inspector also noted that three of the weaknesses
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were related to and/or supported previously documented NRC inspection
report (IR) findings.
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c.
Conclusions
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The inspector concluded that the QA outage assessment effort was
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substantial and was effective in the identification of licensee
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strengths and weaknesses during the Unit 1 Cycle 8 refueling outage.
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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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b.
Observations and Findinas
The inspector reviewed corporate NA&L audit report SSA 9509, dated
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July 31,1995. This audit identified significant weaknesses concerning
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the CAP implementation and PER No. SQ950563PER was issued to address the
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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
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implementing (60 working days) of PER corrective actions.
Examples of inadequate root cause determinations leading to high
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levels of recurrence.
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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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showed that the problems identified in SSA 9509 audit continued to
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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
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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
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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
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period (April 1995 - September 1996).
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The inspector noted that Block 4 of PER No. SQ962526PER, "Immediate
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Actions Taken," had no assigned actions.
Block 9 of the PER,
" Corrective Action," had no specific corrective actions identified,
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except for a statement that an assessment of the site corrective action
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program implementation would be conducted in June 1997.
In discussing
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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.
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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
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with most of these PERs which were corrected. No additional
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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
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the steam traps to perform their function.
During a subsequent
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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
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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
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requirements.
In a subsequent telephone call with a Licensing
Department contact, the inspector was informed that the licensee had
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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,
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1997) to MRC activities in order to strengthen line manager's ownership
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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
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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
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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
'
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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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
1
were noted in the area of operations self-assessments. These included
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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
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to the increase in the number of PERs from prior years, and the peer
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review program.
!
'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
!
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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evaluation program by maintenance supervision to be good.
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Based on the peer evaluation program and NA&L monthly trends, the
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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.
'
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
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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
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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
.
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.
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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-
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15, 1997, and concluded that the failure was not related to any
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maintenance activities performed on the actuator and the licensee could
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not have predicted the failure. Once the failure was identified, the
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licensee worked expeditiously to replace the actuator and subsequently
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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
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actual failure mechanism of the actuator is described in LER 50 327/97-
002.
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(Closed) LER 50 327/97 002: Enforcement Discretion Granted When
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Problems With the 2A A Diesel Generator Actuator Was Identified. The
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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
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failure, as described in the LER, and determined that they were
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reasonable and complete.
No similar problems were identified.
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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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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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0 SI SXV-003 243.0
Full Stroke Testing of Check Valves 0 3-
4
894 and 0 3 895
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1 SI-SXP 003-201.B
Motor Driven Auxiliary Feed Water Pump
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1B B Performance Test
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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
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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
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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.
,
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
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visual inspections. The fault was eventually identified as a phase to
,
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.
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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
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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
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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-
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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
)
bot 1 sides of the penetration for an evaluation of penetration seal type
and integrity.
Enough insulation on both sides of the penetrations was
,
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
,
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
2
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
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penetrations be inspected.
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M2
Maintenance and Material Condition of Facilities and Equipment (62707)
M2.1 Plant Housekeepina Condition Imorovements
.
a.
Insoection Scope
>
The inspectors observed the housekeeping of the facilities during
routine plant observations,
b.
Observations and Findinas
)
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
'
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
'
during the recent Unit 1 outage. The licensee's efforts were continuing
and were addressing other areas of the plant.
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C.
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
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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
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improper maintenance activities performed on the Unit 2 excess letdown
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isolation valve.
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b.
Observations and Findinas
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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
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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
,
to >e replaced.
,
C.
Conclusions
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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
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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).
.
The inspector noted that the licensee had also identified numerous other
.
'
examples of sis which failed to test all attributes of the logic
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circuits.
In all of those examples the licensee had determined that
although the procedures required revision to test all attributes of the -
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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
^
' PERs associated with 37 required SI >rocedure changes, five needed TS
,
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
,
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.
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c.
Conclusions
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The licensee's GL 96 01 review identified several inadequate sis along
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with needed UFSAR and TS revisions. This included four examples of SRs
no' satisfied and an NCV for failure to perform required TS surveillance
1
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.
.
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
!
and from the forced outages in June 1996 and November 1996.
SR
.
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4.3.1.1.2 required that the logic for interlocks shall be demonstrated
'
operable prior to each reactor startup unless wrformed during the
preceding 92 days. The inspector noted that t1e licensee's surveillance
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testing program required the reactor trip system interlocks to be tested
such that each train was functionally tested every 62 days on a
,
staggered test basis.
No problems were identified during this review.
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c.
Conclusions
)
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For each TS SR reviewed by the inspector, the licensee had performed
required surveillance testing during the March 1997 refueling outage,
'
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
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Plant Modifications as Reauired By SSP 9.3.
As discussed in IR 50 327,
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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
!
level of human performance. The evaluation recommended, and the
licensee implemented, a consistent site-wide peer evaluation process.
]
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The inspector determined that the licensee addressed the procedure
"
problems associated with controlling plant modifications, and concurred
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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
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Operatina Procedures as a Result of Desian Chanaes to Abandon Plant
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Eauioment. The inspector verified the corrective actions described in
the licensee's response letter, dated February 3,1997, to be reasonable
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and complete. No additional problems were identified during the
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inspector's review.
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M8.3 (Closed) LER 50-328/96 003:
Reactor Trio Breakers Were Manually Doened
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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.
.
M8.4 (Closed) LER 50-328/96-006: Automatic Reactor Trio of the loss of Power
'
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
.
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
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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
'
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
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each of the two parallel circuits prior to exiting the LCO. The
'
inspector noted that the appropriate SI was revised and that the special
testing verified the +found condition of each channel to be
acceptable.
.
M8.7 (Closed) LER 50 327/97 008:
Failure to Properly Perform Surveillance
~
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
.
surveillance testing of the blackout and auto sequencing timer circuit
'
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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III. Enaineerina
El
Conduct of Engineering (37550, 37551)
,
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
,
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
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MOV capabilities, periodic verification of M0V capabilities, M0V
corrective actions and trending, M0V post maintenance and post
,
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:
.
p
Site Standard Practice SS)-6.61, Motor Operated Valve Program / Generic-
Letter 89 10, Revision 1: Standard Engineering Procedure DS M18.2.21,
,
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
!
performed to determine if the AVFs were conservatively higher.
.
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
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Isolation
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1-FCV-003 136A
Essential Raw Cooling Water (ERCW) Isolation
1 FCV 003 136B
ERCW Isolation
,
1-FCV 026 243
Reactor Coolant Pump (RCP) Spray Isolation
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1 FCV 70 090
RCP Thermal Barrier Return Containment Isolation
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2 FCV 003 047
Steam Generator No. 2 Feedwater Isolation
2 FCV 068 332
Reactor Coolant System Pressurizer Block
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26
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b.
Observations and Findinas
1.
Scooe of MOVs Included in the Procram
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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
4
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MOVs.
In the current inspection the inspectors found that the licensee
'
had subsequently reduced the scope by 53 MOVs. The current program
scope included 138 gate valves,16 globe valves, and 71 butterfly valves
- .
for a total of 225 valves.
-
The bases for the removal of the 53 valves referred to above, were
documented in Calculation EPM RJP 061091, Revision 6.
The inspectors
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plug valves. These plug valves performed supply and discharge isolation
functions in emergency raw cooling water lines for the upper containment
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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
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MOVs covered by GL 8910 included gate, globe, and butterfly valves.
The inspectors noted that, while GL 89 10 focused on gate, globe, and
.
butterfly valves; it did not exclude plug valves.
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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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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
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verified to meet the intent of GL 8910. The plug valves were small
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two inch quarter turn valves, their design resulted in minimal operating
torque requirements under flow conditions, and they were limit
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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
!
limit switches, monitoring switch actuation, cycling the valve, cleaning
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electrical contacts, and inspecting actuator lubricant.
4
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2.
Determinations of Settinas and Verifications of Capabilities for
Gate. Globe. and Butterfly Valves
I
Switch Settinas
!
The licensee controlled the operation of gate and globe valves through a
combination of torque and limit switches. The torque switch was
x.
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bypassed in the closing direction for 95 to 98% of stroke length, based
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on handwheel turns. .For opening, the torque switch was bypassed for the
!
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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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
'
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-
.
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
,
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 -
4
-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:
s
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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
'
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
1
-not clear whether criteria recommended by-EPRI had been considered in
.
extrapolating the opening test data. The licensee demonstrated the
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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
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results. The licensee was able to rely on full motor capability in
'
determining the available valve factors, since the torque switch was
bypassed for most of the closing stroke. The licensee set-the bypass
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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
,
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
,
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,
,
etc.) and a> plying the EPRI PPM (Performance Frediction Model) to
'
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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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
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The licensee assumed a stem friction coefficient of 0.15 in its H0V
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calculations. Where subsequent testing of a particular gate or globe
valve indicated a higher value, the licensee assumed the test value in
'
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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dynamically tested, as the licensee had not developed a formal
)
evaluation to support the assumption. The_ inspectors evaluated the
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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
'
effects, the licensee found that the licensee's Velan 1500 lb rated gate
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valves exhibited more severe effects than other gate valves. The-
,
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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
'
that were not dynamically tested. This evaluation demonstrated adequate
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capability for the Velan 1500 lb valves.
However, the licensee's
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calculations indicated that valves 2-FCV 68 332 and 333 (pressurizer.
4
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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dated July 8,1997, the licensee indicated that it would demonstrate
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that these valves greater structural capcbility in revisions to the
related valve calculations.
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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
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licensee provided test' data to demonstrate that the 10% reduction in
thrust output was reasonable. However, the inspectors found that the
{
licensee had not addressed the ~ potential for reduction in thrust output
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of the actuator under dynamic conditions when the torque switch was
3
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
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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
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The inspectors found that the licensee had not made any provision for
I
degradation of MOVs and brought this to the licensee's attention.
In
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its letter to the NRC letter dated July 8,1997, the licensee stated it
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would add a 5% margin as a minimum requirement for MOV degradation.
!
This licensee indicated that this requirement would be incorporated into
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the valve calculations by November 7,1997.
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3.
Periodic Verification
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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
,
pressure conditions until there was technical justification to eliminate
?-
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
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testing of GL 8910 valves had been performed during the last outages
for Unit 1 and 2.
The licensee's periodic verification actions were
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found to be adequate for closure of GL 8910. The NRC may re assess the
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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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Safety Related Motor 0perated Valves,
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4.
MOV Trendino
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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
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that there were' no administrative controls specified.
During the
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current inspection, the inspectors found that-the licensee had
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subsecuently implemented the necessary administrative controls through
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Periocic Instruction 0 PI EMV 317-001.0, Revision 0 (with procedure
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changes 97 507 and 0081). This instruction designated the data to be
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gathered, the required reporting period, responsibilities.for data
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gathering and evaluation, and responsibility for report issuance. The
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licensee's M0V trending was satisfactorily implemented.
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5.
Documentation. Analysis. and Corrective Actions for MOV
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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
1
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
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unclear in two cases reviewed. The inspectors reviewed PERs documenting
[
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
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were as follows:
4
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
3
provided adequate documentation, analysis, and corrective actions for
!
the M0V failure. However, the failure had resulted from a long standing
problem that should have teen recognized and corrected earlier by the
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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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III violation. The violation had been transmitted to the licensee in a
letter dated December 24, 1996.
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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
,
PER provided adequate documentation, analysis, and corrective actions
'
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
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throttle valve 1 FCV 1-51 to meet its stroke time requirement. T1e
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measured opening time was 8.9 seconds versus a maximum allowed by
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3rocedure of 8.4 seconds, (note: the design allowable was estimated to
3e 20 seconds in a later review). The inspectors found the analysis
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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
,
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.
)
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
.
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
'
replacement of this actuator would have shown that the stroke time
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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
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the PER which they considered unsatisfactory, involving the adequacy of
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stroke time measurements. The licensee's investigation found that only
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about half the actual stroke time was being measured during surveillance
)
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
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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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6.
Pressure Lockino and Thermal Bindina
The inspectors reviewed the licensee's GL 95 07 submittals dated
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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-
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68 132, FCV 68 332, FCV 72 2, FCV 72 39, FCV-72 40 and FCV-72 41. The
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sup)lemental response would also address the basis for any bonnet
'
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
.
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
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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.
'
Personnel who were knowledgeable of the MOV industry issues.
.
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
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TDAFW trip and throttle valve 1-FCV 151 documented in two PERL
The inspectors noted two licensee strengths, which are described in
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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
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included as an attachment to this report.
It noted that as left
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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
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limiting operational or transient events for overpressure or other
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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
!
should have been reset to with 13%, unless a system analysis existed to
,
support the as found condition for the limiting operational or peak
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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
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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
,
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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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
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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
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is identified as VIO 50 328/97 06 08.
c.
Conclusions
i
A violation was identified for the licensee's failure to implement
'
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
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1997 Unit I refueling outage, the licensee noted problems with the valve
!
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
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walkdown of the Unit 1 and Unit 2 TDAFW pumps and pump rooms. The
~
inspectors noted that the TDAFW trip and throttle valve (1-FCV-51 and 2-
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FCV 51) position indicators were set differently. The inspectors then
,
reviewed the Section XI test data for both tri) and throttle valves.
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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
,
throttle valve only took 5-6 seconds to open when measured remotely.
'
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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Due to the potential misadjustment of the limit switches on 1 FCV 51,
the inspctor reviewed the " Remote Valve Position Indication"
'
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
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37
valve position, so in this case, AFW valve 1 FCV 51 remotely indicated
,
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
'
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
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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
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the licensee in response to this programmatic deficiency.
,
The inspector reviewed the corrective action that had been
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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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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.
,
Based on the above review the inspector determined that a Technical
I
Operability Evaluation (T0E), had been wrformed to justify continued
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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
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its safety function in its accident environment when called u mn to do
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so.
Plant modifications DCN No. H 13071A and M 13103A are scleduled to
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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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c.
Conclusion
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The inspector concluded that the licensee had developed corrective
.
actions for nonconforming MOVs that were consistent with design
!
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
,
qualified equipment were corrected in accordance with the requirements
of the ANSI N45.2.11 1974 design engineering program. The plant
,
modifications were reviewed with special emphasis on (1) the
a
identification of design inputs: (2) the technical adequacy of setpoint
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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
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a consistent basis for making design decisions, accom
verification measures, and evaluating design changes.plishing design
Add 1tionally, the
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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
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supported by approved design input information. The following design
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basis calculations were reviewed during this effort:
Calculation No. SQNAPS2 119, Auxiliary Building High Energy
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Line Break Mass and Energy Release for Environmental
Analysis Revision 0
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Calculation SQNAPS2121 Environmental Response of Auxiliary
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Building to HELB, Revision 2
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Calculation No. SONNAL3 007, Normal Omration Dose for
Equipment Qualification Outside the S11 eld Building,
Revision 6
Category and Operating Time Calculations
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SQN-0SG7 0027 Residual Heat Removal System (074) 10 CFR 50.49 Category and Operating Time Calculation, Revision 7
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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
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Based on review of the above calculations the inspector determined that
environmental parameters of temperature, pressure, humidity, and 40 year
.
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
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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:
.
UNID
E0 binder
0 TS12-91A
SQUEQ ITS 001, R23
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0-TS 12 91B
SQNEQ ITS 001, R23
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2-TS 074 0043
SONEQ ITS 002, R30
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1 TS 074 0044
SQNEQ ITS 002, R30
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1-FCV 62 63
SQNEQ H0V-005, R28
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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:
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Demonstrated Accuracy Calculation PS 43 200A, Revision 7
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Demonstrated Accuracy Calculation 1 TS 1 17A, Revision 5
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Demonstrated Accuracy Calculation 0 TS 12 91A, Revision 5
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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:
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SQNP Environmental Design Criteria SON DC V 21.0, Revision 6
e
EQ Binder SONEQ ITS 001, Revision 23
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EQ Binder SONEQ XHTR 005, Revision 14
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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
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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.
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
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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,
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328/96 08 and resulted in the issuance of NCV 50 327, 328/96 08 03.
No
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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
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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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hammering, observed during previous startups and shutdowns.
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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
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Was Removed. It Was Found To Have InoDerable Auxiliary Contacts,
The above two LERs discussed the inadequate maintenance activities
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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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3rotection system.
IR 50 327, 328/96 13 identified apparent violations
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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
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during the followup of EA 96 414.
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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-
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14, which documented a November 2, 1996, overpressure condition with the
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Unit 2 safety injection system. A TIA was initiated and after
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completing actions NRR forwarded TIA 97-01 to Region II on April 18,
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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
4
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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
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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.
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The licensee also stated that a review of Tracking and Reporting of Open
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Items (TROI) for fuse related problems revealed that fuse problems at
Sequoyah are primarily misluling and misidentification.
Fuse size and
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type discrepancies identifieu in B0P circuits have not caused plant
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transients nor plant reliability problems. The inspector reviewed a
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printout of TROI dated May 5, 1997, which had been prepared based on the
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word search fuse. The total listing of plant 3roblems related to the
word " fuse" covered a field of 198 entries. T1e inspector determined
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from this review that objective evidence did not demonstrate that plant
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problems caused by BOP fuses had resulted in plant transients nor
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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
!
by the Customer Grou) and resulted in the delayed offset power being
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.
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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
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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
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cause for this deficiency was determined to be ineffective corrective
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action for a previously identified problem. This deficiency was
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corrected by revising procedure Switchyard letter-18, SWYD-18.
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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
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reviewed the response received from TVA in connection with this request.
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The staff has, however, determined that additional information is
needed.
In a letter dated January 17, 1997, the NRC requested
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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
,
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
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submittal with TVA's engineering personnel and requested copies of the
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following documents'which provided the basis for TVA's argument
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concerning the adequacy and reliability of the offsite power system:
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DNE Calculation No. SQN GRID STUDY 004 Sequoyah Nuclear
e
Plant (SQN) Transmission System Study (TSS) Grid Voltage
>
Study of Sequoyah Offsite Power System, Revision 0
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DNE Calculation No. SON GRID-STUDY 003, Transmission System
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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.
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Switchyard Operations SWYD 18. Plant Voltage Schedule
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Procedure, Revision 15,
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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,
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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
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pre event: there is a LOCA for Sequoyah Unit 2: and the Sequoyah inter-
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tie transformer is out of service.
!
The transient stability study concluded that there were no voltage
recovery problems on the Unit and shutdown boards.
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Calculation No. SON-GRID STUDY 003 was described as an " operational" TSS
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which is performed on an annual basis.
It defines for the current year
the following:
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The 161 kV and 500 kV operating voltage schedule
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Sequoyah operating parameters for (1) the main generators.
(2) the 500/161 kV inter tie transformer, (3) the 161 kV
capacitor bank
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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.
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2)
And only if specific indicators are monitored and
controlled. These indicators are Sequoyah Unit 2 reactive
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output. Sequoyah 161 kV bus voltage, and Sequoyah 500/161 kV
inter tie transformer bank reactive flow.
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Attachment V of calculation SQN GRID-STUDY 003, Operating Guide
Memorandum, was reviewed and verified to provide new Sequoyah grid
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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
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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
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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
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material verification and traceable weld material. NUPIC recommended
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that utilities have Ellis and Watts submit dedication plans for
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approval. The Vendor Audit Services received information from NUPIC in
April of 1996 that a followup visit to Ellis and Watts revealed
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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
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the time of MOV operation.
NRC Ins 3ection 50 327, 328/95 01 identified
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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
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accordance with DCN M10824 during the Cycle 7 refueling outage.
E8.13 (Closed) IFI 50 327. 328/93 36 01: Review of Electrical Modifications
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
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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
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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
.
through 177.
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b.
Observations and Findinas
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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)
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classifying waste destined for burial: 4) selecting the type of package
required: 5) assuring that the radiation and contamination limits were
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met; and 6) preparing shipping papers.
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The licensee's records for technical staff training were reviewed and
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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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c.
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.
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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
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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
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reviewed licensee records of personnel radiation exposure and discussed
as low as reasonably achievable (ALARA) program details, implementation,
.
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
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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,
,
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-
.-
. . -
.
.
. .
,
.
.
I
51
identified and corrected violation is being treated as a Non Cited
Violation consistent with Section IV of the NRC Enforcement Policy. (NCV
'
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
"
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
,
the plant and the areas had been released. The inspectors reviewed the
,
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
.
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
,
of the Railroad Bay the ins sectors noticed physical openings alongside
-
of the railroad tracks whic1 pass under the door. An empirical
4
measurement of air flow performed by the inspectors found that the flow
was toward the outside. Review of the Updated Final Safety Analysis
'
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
'
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
!
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
,
identified the rubber seals in the railroad tracks as having
,
.
,
',
52
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).
c.
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.
>
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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.
.
53
.
Unit I was classified in Action 1 of Site Standard Practice (SSP) SSP-
)
i
12.55 Fuel Integrity Assessment Program.
Unit 2 continues in Action 1.
1
.
One defect was believed to have been carried over from Cycle 7 and the
{
licensee believes the defect has a high probability of discharge during
-
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
'
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.
c.
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).
'
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.
.
..
'.
54
Type of Waste
Unit
12 Month
Est. Tot.
Period
Error %
i
a.
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.
c.
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
'
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.
,
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.
.
I
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_ - .
- _.
_-
-
_ - .
-
--
.
.-
-
-.
.
,
'
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'
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'
55
.
Total Dose from Fuel Cycle
1996
1
.
'
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
'
(liquid)
,
Maximum organ dose
2.3E 02
2.5E 02
7.1E 03
2.5E 03
'
-
(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
'
Annual Dose Limit (ares)
2.50E401
Percent of Limit
<12
5
Thyroid
1
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)
1
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
)
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
<1%
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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56
c.
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
)
were consistent with results from the preoperational monitoring program.
V. Manaaement Meetinos
,
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
<
considered proprietary.
No proprietary information was identified.
PARTIAL LIST OF PERSONS CONTACTED
Licensee
~
- 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
-
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
.
INSPECTION PROCEDURES USED
,
IP 37550:
Engineering
IP 37551:
Onsite Engineering
IP 40500:
Effectiveness of Licensee Controls In Identifying,
<
Resolving, & Preventing Problems
IP 61700:
Surveillance Procedures and Records
.
.
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. .
'
.
57
IP 61726:
Surveillance Observations
IP 62707:
Maintenance Observations
-
IP 64704:
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
.
Monitoring
IP 86750:
Solid Radioactive Waste Management And Transportation Of
Radioactive Materials
IP 92901:
Followup - Operations
-
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
4
ITEMS OPENED. CLOSED. AND DISCUSSED
'
--
The following escalated enforcement items (EEI) were reviewed as part of an
enforcement conference with the licensee on June 27, 1997. Subsequent
,
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
_
50-327, 328/97 05 01
Closed
Inadequate Corrective Actions for
EA 97 232
the 1993 Drain Down Event
.
50 327, 328/97 05 02
Closed
Failure to Follow SSP 12.1, Conduct
EA 97-232
Operations
,
The following violations were issued as a result of escalated enforcement
action taken on July 10, 1997.
,
Tvoe Item Number
Status
Description and Reference
01013
Open
Failure to Identify and Take
>
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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_
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,
o
58
01023
Open
Failure Properly Log a Unit 1
,
EA 97 232
RCS Drain Down Evolution (IR 50 327.
-
328/97-05)
-
Ooened
Type Item Number
Status
Descriotion and Reference
_
50 328/97-06 01
Ogn/
Failure to Follow Procedure Which
i
Close
Resulted in Establishing a Flow Path
'
for ERCW to Enter and Contaminate
the "A" CST (Section 01.3)
-
IFI
50 327, 328/97 06-03
Open
Review the Licensee *s Emergency
'
Diesel Generator Reliability and
Failure Analysis (Section M1.2)
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)
50 328/97 06 05
Ogn/
Failure to Follow a Maintenance Work
Close
Order Resulting in Work on Wrong
'
Valve (Section M4.1)
'
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)
50 328/97 06-08
Open
Inadequate Corrective Actions for
,
Deficient Safety Injection System
Relief Valves Lifting Setpoints
(Section E2.1)
50 327/97 06-09
Open
Remote Position Indication Testing
(Section E2.2)
50 327, 328/97 06-10
Open/
Failure to Follow Procedures RCI-14
Closed
and RCI 16 (Section R1.3)
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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_
. . .
_ _ _
...
'
..
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.
59
Closed
Tygg Item Number
Status
Description and Reference
_
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)
.
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
!
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
50 327, 328/96-02 05
Closed
Failure to Control Implementation of
Plant Modifications as Required By
SSP-9.3 (Section M8.1)
'
50 327, 328/96 12 01
Closed
Failure to Revise Emergency
Operating Procedures as a Result of
,
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
".
of a Feedwater Isolation Signal and
'
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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f
60
l
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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)
j
l
l
LER
50 327/97 008
Closed
Failure to Properly Perform
Surveillance Testing on the
!
Containment Air Return Fan Start
'
Logic and on the Blackout and Auto
'
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
,
!
Reach Rod Valves (Section M8.9)
IFI
50 327, 328/94 22 02
Closed
Snubber Design and Maintenance Items
(Section M8.10)
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
,
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
'
Follow the Design Control Process
,
(Section E8.4)
,
-
_ _ . . _ . _ - _ _ _ _ . _ _ _ _ _ _ _ _ . _ _ . _ . _ _
f
-
. .
-
.
61
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
,
l
(Section E8.5)
'
LER
50 328/96 004
Closed
After a Reactor Trip Breaker Was
!
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
,
(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)
327, 328/93 02 04
Closed
NRC Review and Evaluate GDC 17 Plant
Grid Interface (Section E8.10)
l
'
50 327, 328/95 01 01
Closed
Capabilities of Motors to Achieve
Torque Switch Trip at Degraded
,
Voltage and Accident Temperature.
l
(Section E8.12)
IFI
50 327, 328/93-36 01
Closed
Review of Electrical Modifications
01012 EA 95 252
Closed
Failure to Ensure that Provisions of
l
10 CFR 50.7 Were Complied with
!
(Section E8.15)
l
<
l
e
. _ . - .
e
. - . _ - .
. . . . - .
- - - .
~ - - . +
- ~ - - - r- - ~ ~
- - - - - - --- - - ' ~
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g2 Mo
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g
j ,
UNITED STATES
NUCLEAR REGULATORY COMMISSION
C
WASHINGTON, D.C. 20666 4 001
%-
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#
t
_
-
-
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
,
l
CODES (TAC NO. M97281)
.
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
'
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
cc w/ attachment:
R. Cooper, Region I
.
W. L. Axelson, Region III
$
,
!
J. Dyer, Region IV
!
$
,
[S
'"
N
by
-
,_
l
,
i.
!
i
Attachment
.
._
.
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.
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_ _ . _
_
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_
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_
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RESPONSE TO 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
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design pressure), but the valves apparently did not lift to relieve the
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pressure from apparent back-leakage through the check valves.
The Region has
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provided information from the licensee's relief valve test program and
excerpts from the system design codes- American Society of Mechanical Engineers
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(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
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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,
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when setting the relief valves? Should it be set at or below the system
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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,
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ATTACHMENT
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1.
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
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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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higher allowable limit. To do so is inconsistent with other
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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.
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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
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3% of their stamped set pressures. As a practical consideration,
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as-left criteria should be based on the capability of the most accurate
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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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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
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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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the supporting analysis must include the effects of the allowed as-found
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setpoint tolerance.
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3.
Because of the considerations in item 1 above, NRR concludes that the
licensee's procedure for testing the one relief valve may be inadequate
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if the procedure does not clearly indicate what the as-found setpoint
criteria is or if the licensee has no analysis which demonstrates that
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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
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parameters are acceptable. Therefore, if the licensee has not
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demonstrated that i 6% is the acceptable as-found setpoint tolerance,
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the operability of the other two SI system relief valves would be in
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question.
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