ML20215A011
| ML20215A011 | |
| Person / Time | |
|---|---|
| Site: | Vermont Yankee  |
| Issue date: | 12/04/1986 |
| From: | Elsasser T NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20215A002 | List: |
| References | |
| RTR-NUREG-0737, RTR-NUREG-737, TASK-***, TASK-TM 50-271-86-22, GL-83-02, GL-83-05, GL-83-2, GL-83-5, GL-84-09, GL-84-23, GL-84-9, GL-85-06, GL-85-6, IEB-80-11, NUDOCS 8612110122 | |
| Download: ML20215A011 (27) | |
See also: IR 05000271/1986022
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U. S. NUCLEAR REGULATORY COMMISSION
REGION I
Report No. 86-22
Docket No. 50-271 License No. DPR-28
Licensee: Vermont Yankee Nuclear Power Corporation l
RD 5, Box 169, Ferry Road
Brattleboro, Vermont 05301
Facility: Vermont Yankee Nuclear Power Station
Location: Vernon, Vermont
Inspection Dates: September 4 - November 3, 1986
Inspectors: William J. aymond, Senior Resident Inspector
Thomas B. J1ko, Resident spector Trainee
Plackee fC Eape Chie , Quality Assurance Section
Approved by: -
M / Y[8[
Thomas C. Elsasser p f, Reactor Projects Section 3C Date
Inspection Summary: Inspection on September 4 - November 3, 1986 (Report No.
50-271/86-22)
Areas Inspected: Routine, unannounced inspection on day time and backshifts by
the resident inspectors of: actions on previous inspection findings; physical
security; plant operations; licensee actions in response to NUREG-0737 items;
surveillance testing; maintenance activities; followup of previous inspection
issues; GE AKF-2-25 circuit breakers used in ATWS circuits; and, licensee actions
to correct block wall discrepancies. The inspection involved 291 hours0.00337 days <br />0.0808 hours <br />4.811508e-4 weeks <br />1.107255e-4 months <br />.
Results: No violations were identified. Operational status reviews identified
no conditions adverse to plant safety. Further licensee and NRC followup actions
are warranted to assure that AKF-2-25 circuit breakers used in ATWS circuits are
reliable, as assured by application of a quality assurance program per NRC Generic
Letter 85-06 (section 9.0).
8612110122 861205
PDR ADOCK 05000271
G PDR
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DETAILS
1. Persons Contacted
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Interviews and discussions were conducted with members of the licensee staff
and management during the report period to obtain information pertinent to
the areas inspected. Inspection findings were discussed periodically with
the management and supervisory personnel listed below.
Mr. P. Donnelly, Maintenance Superintendent
Mr.- G. Johnson, Operations Supervisor
Mr. J. Pelletier, Plant Manager
Mr. D. Phillips, Senior Engineer, Electrical
Mr. D. Taylor, Maintenance Engineer
Mr. S. Wender, I&C Engineer
Messrs. T. Murley, W. Raymond, P. Lohaus, V. Rooney, and G. Lainas attended
a meeting of the Vermont State Nuclear Advisory Panel on October 8, 1986 in
Montpelier, Vermont to discuss the following issues: State of Vermont person-
nel attendance at NRC inspections of licensed activities; and, the status of
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- NRC review of the Mark I Containment Safety Study completed by the licensee.
The inspector also notified the Vermont State Nuclear Engineer by telephone
on October 6 and 30, 1986 of pending routine inspections at the site by Region
I personnel, and of the results of Region I Inspection Report 86-17 concerning
actions to address masonry walls for IE Bulletin 80-11.
The inspector also met with Messrs. Di Palo Luigi and Golfieri Manfredo of
the Italian Comitato Nazionale Per L'Energia Nucleare on October 9,1986 to
tour the site and discuss plant procedures and experiences relative to plant
operations with a nitrogen inerted containment.
2. Summary of Facility Activities
The plant continued routine operation at full power during the period, except
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as noted below. Reactor power was reduced on October 3, 1986 and the plant
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maintained in a hot standby condition (Mode Switch in Startup) while actions
were completed to repair a leak in the turbine-to-condenser boot seal. While
maintaining the reactor critical with the MSIVs shut on October 4, 1986, the
reactor scrammed at 5:33 p.m. on high neutron flux as the HPCI system was
secured. The turbine seal failure and the reactor scram are discussed further
in Section 5.0 below. The plant was restarted on October 5, 1986 and routine
power operations continued.
3. 0 Status of Previous Inspection Findings
3.1 (Closed) Violation 84-11-09: Containment High Range Monitor. In an SER
dated March 25, 1986, NRC:NRR accepted the existing detector locations
for the containment high range monitors, based on additional information
provided by the licensee in a submittal dated November 22, 1985. The
licensee's followup actions for this violation are acceptable and no
further action is required. This item is closed.
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3.2 (Closed) Inspector Follow Item 85-36-07: Review of Revision 1 to LER
85-11. The licensee submitted Revision 1 to LER 85-11 which described
the events associated with the inadvertent PCIS Group III actuation that
occurred on October 9, 19 and 20, 1985 due to spurious signals from the
West Refuel Floor Zone radiation monitor. The inspector reviewed the
revised LER and determined that the report accurately described the facts
surrounding the event including the cause of the event. The corrective
actions taken were acceptable, and the pertinent codes for NRC Form 366
were properly included. The inspector noted that there were no addi-
tional spurious signals from any of the refuel floor ARMS since October
20, 1985. This item is closed.
3.3 (Closed) Violation 86-15-02: Standby Liquid Control Boron Concentration
Surveillance. A violation was issued for the failure to determine the
boron concentration of the standby liquid poison tank following the ad-
dition of water on July 8 and July 15, 1986. The licensee's corrective
actions, documented in letter FVY 86-96 dated October 16, 1986, were
reviewed and found acceptable. The inspector verified an operator aid
tag was placed on the demineralized water addition valve to the SLC
storage tank that instructs the operator to inform the Shift Supervisar
when the valve is opened. Additionally, the inspector reviewed the
changes proposed to procedures OP 4611, OP 4114 and OP 2114 to prevent
recurrence of the event. No inadequacies were identified. This item
is closed.
3.4 (Closed) Unresolved Item 86-15-04: Traversing In-Core Probe (TIP) Modi-
fications. The licensee completed corrective actions to prevent the
recurrence of an inadvertent retraction of the TIP detectors from the
shielded position back into the TIP drive housing.
The corrective actions included adding a mechanical stop that would iso-
late motor current to the TIP drive unit in the event that the drive unit
rotated backwards when the probe was already in the shielded position.
Software changes included redefining the home position (0000) to be a
constant rather than a variable, so that electrical line noise will not
change the inshield position. Additionally, a 20-inch stopping range
was provided behind the home position to prevent overshoot of 0000. The
probe can be driven forward from any position within this 20-inch range.
The final modification involved having the TIP control unit (TCU) deter-
mine where the TIP detector was located prior to initiating the " withdraw
TIP" command upon receiving a Group 2 isolation signal, to prevent with-
drawal of the TIP when the detector is already in the shielded position.
No inadequacies were identified. This item is closed.
During the above review, the inspector noted that the TIP ball valves
did not function in the same manner as originally intended by the licen-
see when the TIP system modification was initiated during the last outage.
This item was identified by the licensee and corrective actions were in
progress. The TIP ball valves are 120 VAC solenoid-operated valves fed
from non-Class 1E power panel PP-6A, that operate energize-to-open and
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spring-to-close. The 120 VAC supply to the solenoids is controlled
within the TCU in a 24 VDC logic circuit. The specific discrepancy was
that the licensee ordered the new TCU from GE with a logic design that
would require the valves to go closed upon loss of control power. How-
ever the TCUs were received with software and a 24 VDC control scheme
with the opposite logic (i.e., energize-to-close), which was not fail
safe for containment isolation purposes.
The new hardware was installed as received, but interim administrative
controls were established to keep the ball valves from opening inadver-
tently by opening the PP-6A supply breaker to both the ball valves and
the TCUs whenever the TIPS were not in use. This configuration left the
TIPS parked in the shields with the ball valves closed. Actions were
completed by the licensee during this inspection to further modify the
ball valve control logic to achieve the desired configuration. This
matter will be reviewed during a subsequent inspection, including review
of the original and modified circuit designs, and verification that the
as-left circuit configuration meets the design and FSAR (Table 7.3.1)
requirements for a primary containment isolation valve.
3.5 (0 pen) Unresolved Item 86-10-07: Adequacy of HCU ASCO Rebuild Kits. This
item is discussed further in Section 8.1 below. The licensee submitted
a report under 10 CFR Part 21 based on his determination that ASCO re-
build kits HVA-405-90-2A (GE Part FV 204-139) contain a defect that might
create a significant safety hazard for other users. This item was also
addressed by GE in RICSIL No. 008. The licensee's action relative to
this part of the outstanding item is considered complete. This item will
remain open pending completion of actions relative to review of post-
maintenance testing and the sequence of rod scram testing following out-
ages.
3.6 (0 pen) Unresolved Item 86-10-02: Condensate Storage Tank (CST) Leakage
Monitoring. The inspector reviewed the licensee's ongoing leakage moni-
toring results for the CST and noted that none of the data collected
through the month of October was indicative of additional tank leakage.
This item will remain open pending completion of the licensee's long term
corrective actions identified in reports 86-10 and 86-15.
4.0 Observations of Physical Security
Selected aspects of plant physical security were reviewed during regular and
backshift hours to verify that controls were in accordance with the security
plan and approved orocedures. This review included the following security
measures: guard staffing; verification of physical barrier integrity in the
protected and vital areas; verification that isolation zones were maintained;
and implementation of access controls, including identification, authorization,
badging, escorting, and personnel and vehicle searches.
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4.1 Security Event
On September 11, 1986, a moderate loss of physical security effectiveness
occurred due to hardware failures within the central alarm station. The
event was reported via the Emergency Notification System at 9:30 a.m.
on September 11, 1986, and a written report dated September 12, 1986 was
submitted as Physical Security Event Report 86-05. The inspector re-
viewed the circumstances involved in the event, the compensatory actions
taken, the corrective actions to prevent the hardware failures, and the
content of the physical security event report. No inadequacies were
identified.
4.2 Demonstration
The Green Mountain Alliance and other groups conducted a planned demon-
stration against the plant on Saturday, September 27, 1986. Following
a noon rally by about 250 people in Brattleboro, a group marched to the
plant in spite of the previous refusal by the Vernon Town Selectmen to
grant an open air permit for the assembly. Plant security declared a
precautionary alert at 4:20 p.m. when about 200 persons arrived at the
plant main gate to block access to the site. The demonstrators conducted
themselves in a peaceful and orderly manner, and most people left the
gate area when requested by local law enforcement officials.
Vermont State Police arrested 35 persons who refused to leave the gate
area, who were transported to Rockingham for arraignment on charges of
trespassing and violation of the town ordinance for assembly without a
permit. All were subsequently released on personal recognizance. One
woman was injured while being removed by State Police from the gate to
a State police bus. She was treated by a licensee medical technician
and transported to Brattleboro Memorial Hospital by the Rescue, Inc.
ambulance service, where she was treated and released. All charges were
subsequently dropped.
The licensee had prepared for the demonstration based on pre-event pub-
licity, and special precautionary security measures were implemented.
All demonstrators were gone from the site area by 6:00 p.m. on September
27, 1986, and the plant security force then returned to a normal status.
The inspector reviewed the licensee's cecurity plans and measures and
identified no inadequacies.
5.0 Inspection Tours and Operational Status Reviews
Plant tours were conducted routinely to observe operating activities in pro-
gress and to verify compliance with regulatory and administrative requirements.
Tours of accessible plant areas included the control room, reactor building,
cable spreading and switchgear rooms, diesel rooms, turbine building, intake
structure and grounds within the protected area. Radiation controls were
reviewed to verify access control barriers, postings, and posted radiation
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levels were appropriate. Work activities reviewed for conformance with RWP
requirements. Plant housekeeping conditions were verified to be in accordance
with the requirements of AP 0042.
Shift logs and records were reviewed to determine the status of plant condi-
tions and changes in operational status. Control room working conditions and
activities were observed to be maintained in a professional and orderly manner
throughout the inspection period. In response to an NRC initiative, a radio
that has been used in the control room was removed on October 17, 1986 fol-
lowing a verbal request by Region I management. Items that received further
review arc discussed below.
5.1 Turbine-Condenser Boot Seal Failure
Due to a significant increase in the offgas air inleakage from 18 SCFM
on September 27, 1986 to 30 SCFM on October 3, 1986, the licensee reduced
power to 50 percent to facilitate helium leak testing. The increased
inleakage was caused by a defect in the turbine to condenser boot seal.
Reactor power was reduced, the mode switch was placed in Startup, and
the MSIV's were closed to allow inspection and repairs of the damaged
boot.
The rubber boot had a crack approximately 1.5" long and .25" wide which
originated at the location of a patch applied to the boot by the manu-
facturer in an attempt to repair a manufacturing defect. Since the crack
was limited in size to that of the original defect, gross failure of the
boot was determined to be unlikely. The torn section of the boot was
repaired by valcanizing new belts and rubber into the existing boot.
The original cords on the boot were left intact to provide continuity.
The remaining portion of the boot was inspected by the licensee and was
found to be in an acceptable condition. Following repair of the boot,
condenser air inleakage returned to its nominal value of about 16 SCFM
during power operations which commenced on October 5, 1986.
During the period of operation when condenser inleakage was greater than
normal, the inspector verified that the operators were aware of the con-
sequences of a sudden failure cf the turbine boot and what action would
be required should the event occur. The inspector identified no inade-
quacies.
5.2 Single Loop Operation
Reactor power was reduced to 50 percent of rated power on October 3, 1986
to facilitate the search for the source of the offgas air inleakage as
discussed above. During the period of reduced power, the recirculation
system was placed in single loop operation. Single loop operation is
permitted, with restrictions, per Technical Specifications (TS) 3.6.G.
The inspectnr verified that the TS required actions were completed during
single loop operation.
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TS 3.6.G specifies that during single loop operation "the recirculation
system controls will be placed in the manual flow control mode". The
inspector noted that on October 3, 1986, the recirculation flow control
system (RFCS) was in master manual while in single loop operation, with
the the individual transfer station for the operable loop in the auto- '
matic mode. The inspector questioned whether placing the RFCS in master
manual met the intent of the specification to be in " manual flow control "'
mode". The Operations Supervisor presented GE Report NE00-30060, "Ver-
mont Yankee Single Loop Operation", dated February 1983 for inspector
review, which showed that the intent of the specification was met.-The
inspector noted that Vermont Yankee's naster flow controller is pinned
in the master manual position thus mechanically prohibiting control in
the master auto mode.
No inadequacies were identified.
5. 3 Feedwater Water Hammer and Scram on October 4, 1986 *-
Plant operators maintained the reactor critical on IRM Range 6 on October
4,1986, using the RCIC system (and HPCI as necessary) for pressure con-
trol, and with one condensate and one feedwater pump in operation for
level control. The MSIVs were closed for turbine condenser work. All
reactor systems were operating normally with the exception of IRM D, ,
which had been bypassed previously due to its lack of response.
Maintenance personnel requested additional condenser cooling to improve
environmental conditions in the B condenser. Plant cperators initiated
cooling at 1:05 p.m. by opening the feedwater long cycle recirculation
valve V63-22A to spray the tubes in the A condenser. A water nammer
occurred in the recirculation line due to steam in the line~and steam
in the A condenser. The 22A valve was closed immediately. Operators
subsaquently established additional cooling at 1:30 p.m. by first .
throttling manual valve V63-23A open one turn before opening the 22A
valve.
Plant operators and maintenance personnel inspected portions of the re-
circulation line and noted no damage. The inspector also walked down
portions of the recirculation line on October 4, 1986 and noted no damage
to the piping or pipe supports. Additional licensee corrective actions
in this area are discussed further below.
While continuing to maintain the reactor critical on Range 6 on October
4th, plant operators noted that reactor pressure had increased to about
1000 psig. The HPCI system was started at 5:21 p.m. in the CST recir-
culation mode to reduce pressure. Neutron flux levels decreased to IRM
Range 1 due to the negative reactivity effects of reducing pressure to
, about 700 psig. When the HPCI system was secured at 5:33 p.m., the sud-
l den pressure increase caused vessel level to shrink from about 158 inches
i to 150 inches above the top of the active fuel. The vessel level control
system over-responded to the decrease and injected relatively cold (200
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degree F) water into the core through the startup feedwater valve FCV6-13.
Vessel level increased to 159 inches. However,:the cold water addition
caused a rapid flux increase and the reactor scrammed automatically on
a high neutron flux on IRM Range 1 (about 16 kilowatts of thermal power
, level).
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The' reactor responded normally to the scram-and the operators stabilized
r the plant in the hot shutdown condition. The reactor was left-hot but
, subcritical'with the MSIVs closed for the remainder of the condenser work.
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.v.. The licensee's summary and evaluation of the scram was provided in a Post
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Trip Report (VYAPF 0154.01) dated October 4,1986, which was reviewed and-
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u The inspector reviewed the reactor response to the scram using strip
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(,*' charts of reactor parameters, plant logs and computer information. Data
- ., s computer malfunction. This review confirmed that the. reactor scrammed
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as a result of the flux increase caused by the cold water injection,
, which resulted in a reactor period estimated by the inspector to be on
the order of five seconds. Thu reactor protection system responded
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promptly and properly to shut down the reactor,
i Subsequent licensee: review determined that the GEMAX 6-85 rack-mounted
controller for the startup feedwater valve ccn aibuted to the event be-
-t Cduse the valve did not respond properly to a flow demand signal. The
N . faulty controller was replaced on October 4, 1986 under maintenance re-
( i quest (MR) 86-2127. The licensee's review also identified procedural
3 d, and operator training deficiencies for both the scram and feedwater water
1 4 hammer events. For the scram, the licensee determined that, even Rough
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the mode of operating in hot standby with the MSIVs shut had been iione
successfully in the past for short periods, existing plant procedures
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do not provide adequate instructions to define the bounds for operational
. parameters. Additionally, the licensee identified the need to upgrade
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procedures that establish environmental control for work in the main
,- condenser, or other confined spaces. The water hammer and scram events
will be described in a plant information report (PIR) that is scheduled
for issuance in November, 1986. The PIR will contain recommendations
for procedure changes and operator training to cover the identified O s-
i crepancies. This item is unresolved pending completion of the proc wire
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changes and training, and subsequent review by the NRC (UNR 86-22-01,.
The licensee reported the scram per 10 CFR 50.72(b)(2)(ii) and notified
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the resident inspector at 6:00 p.m. on October 4, 1986. The licensee
submitted LER 86-15 for the scram by letter dated November 4, 1986, which
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< was reviewed by the inspector and found to accurately describe the event.
The plant was restarted at 7:54 p.m. on October 5, 1986 following the
, completion of the condenser work. The plant resumed full power operation
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without further incident.
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5.4 Transportation Violation
The licensee received a letter from the Barnwell, S.C. low level burial
site on October 9, 1986, imposing a $2,000 fine for a resin shipment
received at the burial site on September 24, 1986, that had about one-
half cup of resin beads on the outside of the liner. The burial site
measured loose surface contamination on the inside of the shipping cask
at 300,000 dpm/100 sq-cm. The burial site requires the licensee to pro-
vide prior notification for any shipment having greater than 50,000 dpm/
100 sq-cm loose contamination on the exteriors of the liner. The licen-
see has retained burial site privileges at Barnwell and is drafting a
response to the State of South Carolina to address what steps will be
taken to prevent recurrence. The licensee's actions and the adequacy
of the corrective measures will be reviewed by Region I health physics
personnel during the next transportation and process control program
inspection.
5.5 HPCI Vioration Testing
Vibration monitoring of the Vermont Yankee HPCI system was conducted on
October 20, 1986, to obtain supplemental information for a test conducted
in August of this year. The August test results indicated a possible
vibration problem associated with the HPCI pump pedestal which is be-
lieved to have a natural resonance frequency very close to the operating
frequency of the pump. The August test results were significant enough
to warrant additional vibration tests but were not indicative of an in-
operable system. It is noted that the required inservice inspection
vibration tests concluded on the HPCI system per ASME Section XI do not
indicate any degraded performance. The inspector noted that the highly
sensitive vibration testing conducted in August and October is an aid
used by the licensee in long term preventive maintenance testing. The
inspector verified that the testing on October 20, 1986 was conducted
without rendering the system inoperable.
The inspector observed the startup and running of the HPCI system during
the test conducted per operating procedure (0P) 2120 "High Pressure Cool-
ant Injection System". The HPCI test was successfully completed and the
system was returned to a standby condition. The inspector had no further
comments, except as discussed below.
OP 2120 has a precaution to instruct the operator to trip the system if
turbine vibration exceeds 2 mils. However, the procedure does not direct
the operators to activate the HPCI vibration monitor located on CRP 9-3
so that turbine vibrations can be monitored. The inspector discussed
these observations with the Senior Operations Engineer, who stated that
the procedure would be revised to incorporate the appropriate guidance.
The inspector had no further comments in this area. The vibration test
results of October 20, 1986, will be reviewed by the inspector during
a subsequent inspection.
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5.6 Offsite Train-Truck Accident
At approximately 9:11 a.m. on October 21, 1986, a train collided with
a propane tank truck at the intersection of the rail line with Route 142,
about one-half mile Southwest of the Vermont Yankee site. The accident
resulted in a minor propane leak from the tank truck which was stopped
at approximately 11:00 a.m.
The accident was reported to the Vermont Yankee control room at approxim-
ately 9:30 a.m. by plant security guards at gate 2 who heard a report
of the accident on a local radio station. The licensee dispatched the
fire brigade commander and other personnel to the accident site to per-
form a first hand evaluation of the event. The shift supervisor subse-
quently reviewed the site emergency plan and the emergency notification
procedure, and determined that no additional action was necessary. Ad-
ditionally, local authorities decided not to evacuate either the element-
ary school or the post office in the immediate vicinity of the collision
site.
The inspector reviewed the licensee's actions and no inadequacies were
identified.
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5.7 Seismic Event
An earthquake measuring 3.5 on the Richter scale and centered in Laconia,
New Hampshire occurred at 1:17 p.m. on October 25, 1986. Reactor opera-
tors at Vermont Yankee heard reports from offsite sources that tremors
were felt as near as Brattleboro, Vermont and Northfield, Massachusetts
(both within 5 miles from the site), but no tremors were felt onsite.
The onsite seismic accelerometer has a trigger level of 0.01 G and did
not register any ground motion. Plant operators noted the offsite re-
ports, but took no further action since no reporting or action levels
were reached at the site. The design of the site is such that a safe
shutdown can be made following a ground horizontal acceleration of .14
G. No inadequacies were identified.
5.8 Review of Inoperable Equipment
Actions taken by plant personnel during periods when equipment was in-
operable were reviewed to verify: (1) technical specifications limits
were met; (2) alternate surveillance testing was completed satisfactorily;
and, (3) equipment return to service upon completion of repairs was pro-
per. The above reviews were completed for the following items: (1) elec-
tric fire pump taken out of service for maintenance on October 21, 1986;
and (2) "B" standby liquid control pump taken out of service to facili-
tate the repair of the SLC squib continuity circuit. No inadequacies
were identified.
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5.9 Feed Water Leak Detection
The inspector reviewed the feed water sparger leakage detection system
and the monthly performance summary provided by the licensee in accord-
ance with letter FVY 82-105. The licensee reported that, based on the
leakage monitoring data reduced as of September 30, 1986, there were no
deviations in excess of 0.10 from the steady-state value of normalized
thermocouple readings, and no failures in the sixteen thermocouples
initially installed on the four feedwater nozzles. No unacceptable con-
ditions were identified.
5.10 Safety System Review
The residual heat removal, residual beat removal service water, high
pressure coolant injection, core spray, stanaby liquid control, standby
gas treatment and reactor core isolation cooling systems were reviewed
to verify the systems were properly aligned and fully operational in the
standby mode. The review included: (1) verification that accessible,
major flow path valves were correctly positioned; (2) verification that
power supplies were properly aligned; and, (3) visual inspection of major
components for leakage, proper lubrication, cooling water supply, and
general condition. No inadequacies were identified.
5.11 Control Rod 18-31
Plant operators experienced difficulty getting control rod 18-31 to move
out from position 00 initially during the reactor startup on October 5,
1986. However, the rod did move after the operator increased drive pres-
sure to 350 psid and then back to the normal pressure of about 250 psid
per ON 3143. Plant operators and reactor engineering personnel reviewed
the status of the rod and determined it to be operable. The rod subse-
quently moved out of the core upon demand with the rest of its group
without further problem. The licensee measured flux profiles in the
vicinity of the rod as it was withdrawn. The inspector reviewed TIP
traces for rod moves from position 00, 04, 08, 12, 16, 20, 24 and 28,
and noted that the control rod was moving with the drive mechanism.
No other problems were noted with the rod, except for the inability to
move it beyond position 46. This problem was reviewed on previous in-
spections (reference: Inspection Reports 86-10, page 13, and 86-15,'page
8). The performance of control rod 18-31 will be reviewed during subse-
quent routine inspections. No inadequacies were identified.
5.12 Contaminated TBED Sump
The inspector reviewed licensee followup actions on September 12, 1986
after routine surveys identified a low level of contamination in the
normally " clean" turbine building equipment drain (TBED) sump. A water
sample from the sump had a specific activity that measured a few counts
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above background at 1.16 +/- 3 X10-6 uCi/ml. The licensee took actions
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to secure, drain and clean the sump. The licensee determined that the
most likely source of the contamination was the buildup of very low
levels of activity from turbine building floor areas drained into the
sump over long periods of time. The sump was resurveyed and returned
to service at 5:30 p.m. on September 12, 1986.
The inspector reviewed the licensee's actions and sample results for the
sump. The inspector also verified the license's compensatory measures
were acceptable to meet Technical Specification 3.9.A.1 requirements for
the service water effluent monitor during the 8-hour period that the TBED
sump was out of service. The inspector reviewed plant drawings and
walked down plant lines connected with the sump to verify that no un-
intended source of contaminated water from fluid systems was added to
the sump. No inadequacies were identified.
5.13 SBGTS Review
The inspector reviewed the standby gas treatment system (SBGTS) per the
requirements of inspection temporary instruction TI R1-86-01 to determine
whether certain design deficiencies existed which could render both SBLIS
trains inoperable from a single failure. The potentially generic defi-
ciency was identified by Boston Edison Co. (BECo) engineering personnel
during a review of the SBGTS design at the Pilgrim plant. The units at
Vermont Yankee were found to not have the subject deficiency.
The problem at Pilgrim stemmed from a design using a normally open, air-
operated cross connect valve on the discharge side of the parallel SBGTS
trains that would fail open on loss of power. BECo found that a single
failure in the fire protection sprinkler system adjacent to the SBGTS
at Pilgrim could place both trains in a degraded condition. At Vermont
Yankee, no water-based fire suppression is used for the SBGTS. Addi-
tionally, the compar'able cross connect valve, SGT-5, is a normally closed,
normally de energized air-operated valve that will fail closed on loss
of power (power / air-to-open, spring-to-close). Based on the above, the
postulated failure mode could not occur at Vermont Yankee.
One print discrepancy was identified on drawing G191238, Revision 16,
which shows SGT-5 as a motor-operated valve instead of an air-operated
valve. The discrepancy was referred to the engineering support super-
visor for review and followup action to submit a corrective update to
the drawing.
5.14 Shelf Life of Scram Valve Air Operators
The inspector received information from Region I on September 24, 1986
regarding a problem identified at Nine Mile 1 with potentially generic
implications at Vermont Yankee. The item concerned the failure of the
diaphram on the air operator for the scram outlet valve (CV13-127) on
a control rod. The control rod inserted upon failure of the air operator
at the other facility, which was a failure in the conservative direction.
The probability of this outcome for the failure is highly certain.
-- -
-_. - . - _
,
-
.
.
13
However, if the same part (GEI 92807A) is postulated to fail on the scram
inlet valve (CV13-126), it is not certain that insertion of the rod would
occur. Information from the NSSS vendor suggests that the rod would in-
sert for the failure of the 126 valve because the common air supply
header from the scram pilot valves (50 13-117 & 118) would bleed down ,
the air pressure and cause the 127 valve to open. However, further study
of this mechanism is planned, and operating experiences at another plant
(Clinton) indicates that rod insertion may not always occur.
The seced item of significance received by the inspector was the infor-
mation purportedly from the NSSS vendor that the material used in the
air operator diaphrams had a shelf life of 10 years if stored in the
original shipping package, and 5 years otherwise. The unit that failed
at Nine Mile 1 had been in service since 1975. Based on a preliminary
review and discussions with plant staff members, the inspector determined
that the same GE parts are used at Vermont Yankee, they have been in
service since the plant started up in 1972, and they are not included
in a shelf / service life control program. Plant personnel interviewed
did not recall experiencing any problems involving failure of the air
operator diaphrams.
This item was discussed with the operations superintendent on September
24, 1986, who noted the inspector's findings for followup review to de-
termine what further action may be warranted to address shelf / service
life limitations on the installed scram valve air operators. The licen-
see stated that this item would be assigned to the plant staff for fol-
lowup and review with the NSSS vendor. This item is unresolved pending
completion of the licensee's actions and subsequent review by the NRC
(UNR 86-22-02).
6.0 Surveillance Testing
The inspector reviewed portions of the surveillance tests listed below to
verify that testing was performed in accordance with administrative require-
ments. The review included consideration of the following criteria: proce-
dures technically adequate; testing performed by qualified personnel; test
data demonstrated conformance with technical specifications requirements; test
data anomalies appropriately resolved; surveillance schedules met; test re-
sults reviewed and approved by supervisory personnel; and, proper restoration
of systems to service.
--
OPF 2428.01 R/CE Checklist to Support Extended Single Loop Operation
dated August 19, 1986 and October 3, 1986
--
OPF 2428.02 R/CE Checklist for Returning to Two Loop Operation dated
August 20, 1986
--
OPF 4379.01 Drywell/ Torus Differential Pressure Functional Test
No inadequacies were identified.
t
. .
.
14
7.0 Maintenance Activities
The maintenance request (MR) log was reviewed to determine the scope and
nature of work done on safety-related equipment. The review confirmed that:
the repair of safety related equipment received priority attention; technical
specifications limiting conditions for operation were met while components
were out of service; performance of alternate safety related systems was not
impaired; and, the maintenance activity did not create an unreviewed safety
question.
Maintenance activity associated with the following was reviewed to verify
(where applicable) procedure compliance and equipment return to service,
including operability testing.
,
--
MR 86-1947, Loss of Closed Indication on System I Torus-To-Drywell "D"
l Vacuum Breaker
--
MR 86-1952, Uninterruptible Power Supply B - Blown Inverter Leg Fuse
--
MR 86-2064, Repair Oil Leak on "B" Recirculation MG Set
--
MR 86-2120, IRM D - No Response to Neutron Flux
--
MR 86-2131, SRM C - Drive Problems
--
MR 86-2235, Loss of SLC Squib Vaive Continuity
--
MR 86-2101, High Containment Air Usage
--
MR 86-2262, Repair Leak on RWCU-68 Valve
No inadequacies were identified.
8.0 Followup of Previous Inspection Findings
8.1 Part 21 Report
A licensee representative informed the inspector on September 12, 1986
of the completed licensee evaluation of the control room rod scram anom-
aly on June 4, 1986 (Reference: Inspection Report 86-10, Section 6), the /
licensee's conclusion that the event was reportable under 10 CFR Part
21. **
Of the three discrepancies noted with the ACS0 HVA-90-405-SA rebuild kits,
the licensee concluded that the discrepancy involving the partially at-
tached core assembly spring could create a significant safety hazard if
the mis-assembled springs are not identified during oreservice inspec-
tions and testing. The improperly assembled springs may not be identi-
fied during the normal post maintenance testing following rebuild of the
HCU 126 and 127 valve solenoid operators, but could subsequently cause
scram valve failure (and loss of proper rod scram function) after several
. .
_ _ _ - - _
.
.
.
15
operations of the solenoid valve. The ASCO rebuild kits are custom made
for BWRs and supplied to the industry as GE spare part kit FV 204-137.
The corrective actions taken by Vermont Yankee for this problem have been
previously reviewed and found acceptable.
The licensee submitted a written report per Part 21 requirements on
September 16, 1986 to alert other users of the kits of the potential
defects. The inspector reviewed the report and found that it accurately
reflected the circumstances and actions taken at Vermont Yankee. The
report will be reviewed for further action by the NRC staff. No inade-
quacies were identified.
8.2 Worker Exposure Concern
This item was previously reviewed and closed as described in Inspection
Report 85-40, Paragraph 5.4. A former licensee contractor employee and
his attorney contacted the inspector by telephone on October 10, 1986
to provide comments on their review of the inspection documentation of
this matter, which involved a radiation exposure concern identified by
the worker when he was a contractor at the site. The worker has filed
a civil suit against the Morrison & Knudsen Company (M&K), the former
recirculation piping contractor for Vermont Yankee, and is seeking dam-
ages from M&K after being fired on December 5,1985 for refusing to fol-
low the directions of his foreman on that date to wait in a " radiation
area" in the reactor building while staging was constructed at his in-
tended work station inside the drywell. The inspector's followup of the
worker's concerns regarding radiation exposure control did not substanti-
ate supervisory directions that were contrary to good ALARA practices.
The worker stated that the purpose of the October 10, 1986 telephone call
was to point out two errors of fact in the NRC inspection report, as
follows:
(1) The report indicated that the worker signed out on RWP 4114 prior
to leaving the job site. The worker stated that while he did sign
in on the RWP, he left the site without signing out, and thus,
someone else must have completed the sign-out process. The sign out
process involved recording the exit time and the whole body dose
rate as read on a pocket dosimeter upon leaving the RWP work area.
(2) The report indicated that the foreman directed the worker to wait
in a holding area outside the drywell. The worker stated that his
foreman in fact directed him to wait inside the drywell where the
radiation exposures were much higher. The inspector noted on Octo-
ber 10, 1986 that had the worker been asked to spend 1.5 non working
hours in the drywell where dose rates were much higher than in the
reactor building holding area, then that would have been a matter
of concern to the NRC for not maintaining good health physics prac-
tices.
-
. .
9
16
The inspector accepted the worker's statements on October 10, 1986 as
accurate. However, the inspector noted that the account of the worker's
activities in Inspection Report 85-40 was based solely on the interview
with him, and that on December 5, 1985, he stated that he was asked to
wait in the reactor building holding area designated in the inspection
report and surveyed on that date.
The worker stated further on October 10, 1986, in regard to previous work
practices, that M&K tried to use RWP information to show progress made
on the pipe replacement effort. The inspector thanked the worker for
the additional information and stated that the NRC would perform a fol-
lowup review of the December 5, 1985 events with this new information.
The above information was submitted to NRC Region I for management review
to determine whether a followup review of the drywell work practices
should be performed in light of the new information to determine whether
regulatory concerns exist. The inspector identified no concerns wherein
a third party signs off on the RWP under the circumstances where the
worker is no longer present, so long as the correct information from the
pocket dosimeter was used. The inspector noted that the control of work
activities in the drywell so as to minimize worker idle time was reviewed
during the outage by the resident and regional inspectors and no concerns
were identified.
This item is unresolved pending further NRC review of the information
provided by the worker (UNR 86-22-03).
8.3 Block Wall Concerns
This item was previously reviewed as 86-18-02. The licensee provided
a summary of the licensee plans and assessments relative to block wall
deficiencies in a letter to NRC Region I, serial FVY 86-85, dated Sep-
tember 19, 1986. The deficiencies concerned unqualified and unrestrained
block walls in the turbine building ventilation corridor that could fail
during a seismic event and potentially adversely affect the following
plant electrical circuits and systems:
(a) Cables for all four main steam line radiation monitors that provide
trip inputs (main steam line radiation levels 3X normal background)
for the reactor protection system and the primary containment (Group
I) isolation system. There is no backup isolation initiator to
assure the main steam lines automatically close in the event of a
dropped rod accident. However, the licensee's assessment noted that
the probability of a rod drop accident is highly unlikely: (1) due
to the fact that any components that would need to fail as part of
the control rod drop scenario are of Seismic Class I design, and
(2) due to the control rod coupling checks that are performed at
the beginning of each operating cycle. The inspector noted that
.
, _ _ - - - . - . - . - - -
-
,,_
17
control rod 18-31 in particular passed a coupling check at least
once at the start of the operating cycle (see further discussions
in section 5.11 above).
(b) Control cables for tihe four reactor recirculation units, RRU 5, 6,
'7 & 8, in the ECCS corner rooms in the reactor building. The RRUs
are normally in standby and receive a start signal when equipment
in'the respective. rooms are in service. The RRUs are required to
be operable to control corner room environmental conditions and
thereby assure ECCS equipment long term operability.
Assuming the reactor building is accessible following a seismic
'
event, the licensee stated that actions could be taken to (1) open
the corner room doors and install portable ventilation equipment,
! and (2) write a jumper and-lifted lead procedure to rewire the RRUs
locally and restart the fan cooler units. The licensee has calcu-
l lations on file that were' performed for 10 CFR 50 Appendix R an-
alyses that show that the RHR corner rooms would heat up to 128
degrees F within two hours assuming no ventilation flow, and the
. core spray pumps are operated 50% of the time. With the doors open
!
and portable ventilation fans providing 10,000 cfm of forced venti -
i
lation-at two hours into the event, the room temperatures would
stabilize between 108 and 113 degrees F, with core spray and RHR
running 50% and 67% of the time, respectively. 0ther calculations
-
- - show tut the above environmental conditions are within the ultimate
, equipment capabilities of the equipment following temperature ex-
cursions.
! The inspector requested and received for review a copy of the cal-
culations that demonstrate the equipment capabilities referenced
'
above. This review was.in progress at the end of the inspection.
The inspector noted that no temporary procedure had been written
i to show the conceptual design needed to rewire the RRUs locally,
or to translate the assumed ECCS equipment operating times into a
'
set of operational restrictions that would assure the bounding ,
assumptions used in the analyses would not be exceeded. The above
items will be reviewed further during a subsequent inspection, along
- with the radiological conditions assumed to exist in the reactor
building following a DBA SSE/LOCA with with no degraded core condi-
'
tions, to verify areas would remain accessible to perform the ac-
tions needed to mitigate the degraded conditions.
(c) Control cables for the fans in the A and B diesel rooms. -The diesel
room fans are required to operate during diesel generator operation
! to maintain room environmental conditions acceptable. The licensee
i stated that actions could be taken following a seismic event to
start the fans locally and/or otherwise provide for room cooling.
A temporary design change was issued to the control room as Jumper
and Lifted Lead 86-146 on October 14, 1986, but not implemented.
l
l
l
t.
I , - _ . . ~ . . . _ . . _ - _ _ , . . _ - _ __ . _ . _ .- _ .-_,- _ --- _ .- _--_._-_ -. __
.
.
,
18
The inspector reviewed the proposed circuit modifications with the
. cognizant engineer and verified that the revised circuit would pro-
vide for diesel room fan operation independent from.the HVAC panel,
and provide circuit isolation from the panel. Aside from the above,
a design change initiated.as a result of Appendix R concerns is
presently scheduled for. implementation during the first quarter of
1987. No inadequacies were identified.
(d) Service building air conditionina (SAC) unit'1A and associated duct l
work. SAC 1A is part of the normal and emergency heating and ven-
. tlTation system for'the main control room. Failure of.a block wall
'
'
adjacent to SAC 1A could affect the unit control circuits and damage
a portion of the fresh air intake and closed circuit recirculation
ducting for the control room HVAC.
i The licensee stated that upon failure of the SAC 1A unit, actions
could be taken locally to provide for cooling in the control room
by opening doors and installing portable ventilation fans. The
inspector noted that this action would address room heating concerns,
I. but would not address concerns due to a potential radioactive source
i term that could be present, for example, from MSIV leakage.
The inspector noted that irrespective of the damage that a failed
4 block wall may cause to SAC 1A, the remainder of the control room
1
HVAC, even though it is safety class 3, it is not seismically quali-
fied, since the HVAC was installed as non nuclear safety during the
- initial plant design and was administrative 1y upgraded to safety
i
-class 3 during the late 1970's to assure repair and modification
-
of the system would be subjected to the quality assurance program.
The licensee stated that protection of the control room environment .
>
source term) condition was beyond the design basis for the plant.
l The licensee's engineering evaluation addressed the above items and pro-
vided a justification for continued operation pending completion of ac-
'
' tions to correct the block wall deficiencies. The licensee evaluation
concluded that no immediate safety concerns exist, but the affected areas
! should be upgraded. The licensee submittal of September 19, 1986 stated -
, that modifications to either relocate control cables or to support block-
walls would be completed as necessary to address inadequacies in each
!
of the above four areas. The licensee's submittal also stated that a
schedule for completing the required modifications (for other than item
c c above) would be established by the end of 1985 after preliminary (con-
ceptual) design changes are established. The inspector noted that the
licensee's written commitment departed significantly from the verbal
commitment made previously, as documented on page 15 of NRC Inspection
Report 86-18.
This item remains unresolved pending completion of the licensee's actions
,
noted above to assess and correct the identified discrepancies, and pend-
}
ing NRC staff review of the licensee's actions.
.
,. , - - . . . , . , ,-.,e.n.-- -me. ., ,,,e.-.w-, .c .e,, .,- . .e.,--, e sm ,,mm, ,.- . - - - , %-, -.- rgm ,w me* s mew - -wr-e-e,---c= w-~ --
-
.
,
19
9.0 Review of GE AKF-2-25 Field Breakers
The inspector reviewed recirculation pump trip system design features and,
in particular, the maintenance and failure history of GE-AKF-2-25 field
breakers in accordance with NRC Region I temporary inspection instruction No.
RI-86-02. Details of the review are discussed below.
9.1 Design
The recirculation pump trip (RPT) system mitigates the consequences of
an anticipated transient without scram (ATWS) event and is accomplished
by opening the field breaker for the recirculation pump motor generator
(MG) set. This field breaker is a GE-AKF-2-25 unit. The field breaker
is designed to open upon completion of a two-out-of-two trip taken once
logic using any combination of two high reactor pressure or two low-low
reactor level trip input setpoints, arranged in two trip channel systems.
The technical specification required set point for high reactor pressure
is 1150 psig, and for low-low level is 82.5" above the top of the active
fuel, after a ten-second time delay.
The reactor high pressure signal is obtained from the slave trip units
of Rosemont 1152 DP level transmitters and the low-low level signal is
obtained from the slave trip units of Rosemont 1152 GP transmitters.
The master trip unit and other slave units are used to provide trips
required by the facility's emergency core cooling systems. Upon comple-
tion of the two-out-of-two taken once logic in a trip system, the neces-
sary contacts will be made and one of the two redundant shunt trip coils
will be energized to trip the AKF-2-25 field breakers for botn recircu-
lation MG sets. The entire trip system is safety grade except for the
breakers and the shunt trip coils. The instruments are powered from the
station instrument bus. The power to the logic is supplied by the sta-
tion batteries. The DC power to the trip units is supplied by dedicated
batteries. The RPT system interfaces with other safety systems that are
protected by fuses. Inadvertent actuation of the RPT system is minimized
by selecting set points such that this system would actuate only after
the set points for reactor scram are exceeded. The sensing instruments
and the trip logic are designed to be tested during power operation.
However, the breakers are not designed to be tested at power.
The licensee's design conforms with the Monticello design discussed in
BWR owner's group topical report NEDE-31096-P except for the trip sensor
arrangement. The Monticello design uses two-out-of-two logic for sepa-
rate reactor pressure or level trip channels. VY design uses both reactor
level or pressure trip input signals for each of the two trip channels.
9.2 Preventive Maintenance and Surveillance
Technical Specification Tables 3.2.1 and 4.2.1 specify the trip set
points and surveillance requirements, respectively, for the RPT actuation
instrumentation. These instruments are required to be checked daily,
. .. .
_ _________-_ _ . _ - _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ . __ _____ _
. .
,
20
functional tested monthly and calibrated once per operating cycle. Plant
procedures OP 4342 and 4369 are specifically established to control func-
tional tests and calibrations of the RPT actuation instrumentation.
,
The MG set field breakers are tested once every operuting cycle. Plant
l- procedure OP 5221 is established to control the inspection, testing and
calibration of these breakers. Maintenance personnel are responsible
for the testing and calibration of the RPT MG set field breakers. The
history of those breakers is maintained on readily available "VISIrecord"
sheets.
9.3 Use of GE-AKF-2-25 Breakers
The licensee uses AKF-2-25 breakers for the recirculation pump MG set
field breakers and the main generator field breaker. During 1981 there
were four failures of recirculation pump MG set field breakers and in
1986 there was a failure of the main generator field breaker. As a re-
sult of the earlier failures, the licensee implemented a more thorough
preventive maintenance program for AKF-2-25 breakers in 1981. Since then,
no further failures were noted in the recirculation pump MG set field
breaker. The same preventive maintenance program is also applied to the
main generator field breaker. However, this did not prevent the recent
failure of the main generator field breaker.
9.4 Reliability of the RPT System
The system, except for the field breaker, is designed to be safety grade.
The redundancy and separation requirements inherent in the design adds
to the reliability of the instrumentation and trip logic. The licensee
also has a detailed preventive maintenance program and equipment history
files. As stated in the licensee's letter FVY 85-93 dated September 29,
1985 in response to NRC Generic Letter 65-06, the plant has the equipment
to trip the reactor coolant recirculating pumps automatically under the
conditions of an ATWS. However, the licensee has not established the
reliability of this system and in particular the MG set field breaker.
The inspectors discussed the 10 CFR 50.62 requirement, "This equipment
must be designed to perform its intended function in a reliable manner.",
and the use of the NRC guidance for non-safety related components
(Generic Letter 85-06) with the licensee's management.
The plant manager informed the inspectors that, other than an established
PM program and history files, there are no special reliability measures
for the MG set field breakers, and the breakers are not treated any dif-
ferently than other non-safety related equipment. The licensee has not
compared the existing controls for maintaining the field breakers to the
NRC guidance published in Generic Letter 85-06. The licensee management
stated that actions will be taken within six months to establish posi-
tions to (1) determine reliability of the RPT system during an ATWS and
(2) show that the licensee reliability measures for the RPT system are
_ _ _ _ _ _ _ _ _ _ _ - _ _
- '
..
21
comparable to the NRC positions stated in Generic Letter 85-06. The
effectiveness of licensee's actions in this regard will be reviewed dur-
ing a future NRC inspection (UNR 86-22-04).
In the event that the recirculation pumps fail to trip automatically on
demand, the control room operators are required to run back and trip the
pump manually. If this is not possible, the breakers can be tripped
locally at the breaker. The inspectors noted that the operators and the
electricians were knowledgeable of the back-up actions in the event the
RPT is not accomplished automatically.
At the time of this inspection, the licensee had no plans to further
enhance the RPT system reliability through design change.
10.0 Status of Actions on NURfG 0737 - TMI Items
10.1 Item II.E.4.1.2, Dedicated Hydrogen Penetrations
This item was previously reviewed during Inspection 81-18 and was left
open pending development of the NRC staff position regarding the instal-
lation of hydrogen recombiners for post-accident hydrogen control in the
containment. Following amendment of 10 CFR 50.44 on December 2, 1981,
the NRC staff issued Generic Letter 84-09 on May 8, 1984, to clarify the
requirements for hydrogen control, including the use of hydrogen recom-
binars. The licensee rasponded to the amended regulation and the generic
letter by letters FVY 82-40 dated April 9, 1982, FVY 82-81 dated July
6, 1982, FVY 84-108 dated August 24, 1984, and FVY 84-128 dated October
31, 1984.
In FVY 84-104, the licensee committed to modify the existing air con-
tainment atmosphere dilution (CAD) system to make it a nitrogen purge
and repressurization system. The necessary modifications were completed
per plant design change request 85-04 prior to the startup from the re-
fueling outage that began in September, 1985. Completion of this action
eliminated the CAD system as a potential source of oxygen in the post-
accident drywell environment. NRC:NRR determined in a safety evaluation
,
dated September 10, 1985, that the three criteria of Generic Letter 84-09
! were satisfied and that recombiner capability per 10 CFR 50.44(C)(3)(II)
was not required.
l
'
Based on the above, the inspector determined that the licensee commit-
ments for this NUREG item were met and no further actions were required.
This item is closed.
10.2 Items I.C.1.2.8 and 3.B, Transient and Accident Procedures
l
,
The requirements of the original NUREG item were superseded by Supplement
l
'
1 issued on December 17, 1982. This item was last reviewed in Inspection
Reports 86-13 and 85-18, which verified implementation of new emergency
operating procedures (EOPs) following operator training.
!
l
l
.6 '
'22
The licensee implemented new emergency' operating procedures in accordance
with the Emergency Procedure Guidelines developed by the BWR Owner's
Group and approved by the NRC in Generic Letter ~83-05, Safety Evaluation
of Emergency Procedure Guidelines, NED0-24934. . NRC staff approval of
~this document constituted the pre-implementation review and approval of
the procedure technical guidelines, as required by section 7.2 of Sup-
- plement 1 of the NUREG. Revision 3 of the guidelines were implemented
in the following E0Ps in November, 1985: OE 3100 - Reactor Scram; OE
<
,' 3101 - Reactivity Control; OE 3102 - RPV Level Control; OE 3103 - Drywell ,
'
Pressure and Temperature Control; and, OE 3104 - Torus _ Temperature and ,
.
Level Control. The guidelines for secondary containment control were
subsequently implemented by the licensee as OE 3105 Secondary Containmant
Control prior to startup from the refueling outage ending June, 1986.
The licensee also submitted an E0P Procedures Generation Package, inclu-
~
i
sive of a Writer's Guide, by letter FVY 84-75 on June 29, 1984, which
is presently under review by NRC:NRR. Implementation of the above pro-
.
cedures and completion of the above actions satisfied the licensee's
l commitments for this item.
1
The licensee is presently considering enhancements to the present E0Ps
'
i as part of the recent Containment Safety Study completed in August, 1985.
The procedure upgrade would consider incorporation of changes made_in
Revision 4 of the_E0Ps, and include instructions and/or enhancements for
combustible gas control, reactor level / power control and containment
venting. The inspector noted that_an in process, partial review of the
E0Ps has been completed by NRC inspection personnel during previous in-
[ spections of procedure validation activities and completion of operator
training on the procedures.(Reference: Inspections 84-21, 85-10, 85-18,
85-36, 86-10 and 86-13). Additionally, use of the procedures on the VY
plant-specific simulator were reviewed as part of the operator licensing
activities in July, 1986. However, the inspector noted that a systematic, '
comprehensive review of the E0Ps remains to be completed in accordance
i
with NRC:IE inspection instructions (TI 2515/79) pending approval of the
PGPs by NRC:NRR. This review will be completed to verify that the E0Ps
- are prepared in accordance with the approved PGPs and are adequate to
control safety related functions following an accident. This item will
e be reviewed during a subsequent inspection and will be tracked under
i
NUREG Item I.C.1.3.B. Item I.C.1.2.B is considered closed administra-
tively.
+
10.3 Item II.E.4.2.7, Containment Vent and Purge Valves
'
This item was last reviewed during Inspection Report 81-18, which con-
tained an open staff item to review the ventilation system purge path
- after plant operations began with the drywell inerted with nitrogen.
j NRC letter NVY 82-201 dated December 9, 1982 accepted the licensee's
'
design for this item, which relies on radiation monitors installed on
the reactor building ventilation ducting to detect elevated radiatien
- levels in.the drywell and to initiate a containment isolation in the
- event trip setpoints are exceeded. This approach is acceptable as long
l ,
- - - . - . - _ , - - . _ - - - . - . - - . . . - - . .
. . - - . - -
!
. *
l
.
23
as the method of drywell-to-torus differential pressure control maintains
a vent path from the torus through the standby gas system filter trains,
located below the radiation monitors. The inspector noted that the above
vent path was maintained subsequent to the start of plant operations with
an inerted drywell in May, 1982.
The licensee responded to the NRC staff's request for changes to the
technical specifications for this item by letter FVY 83-38 dated May 17,
1983. Based on the existing plant design and technical specifications,
the licensee concluded that no further actions were required for this
item. No inadequacies were identified. This item is closed.
10.4 Item II.K.3.18, ADS Actuation Logic
This item was last reviewed during Inspection 84-01, and was left open
pending NRC:NRR's approval of the licensee's position to not make any
modifications to the existing ADS logic. NRR rejected the licensee's
position by letter dated October 7, 1985, and requested that one of two
designs developed in conjunction with the BWROG and approved by the staff
be implemented.
In FVY 85-109 dated November 11, 1985, the licensee agreed to implement
one of the two modifications after completion of a limited probabilistic
risk assessment to aid in the selection of a design. The licensee's
initial preference would be to modify the existing ADS logic by adding
a manual inhibit switch in conjunction with a timer that would bypass
the high drywell pressure permissive after a sustained low vessel water
level. The FRA was scheduled for completion by November, 1986, so that
the final design details could be submitted for NRC staff review and
approval in time for implementation of the design change during the
refueling outage starting in June, 1987.
The licensee stated that scheduled completion of the PRA study has been
impacted by the containment safety study, but the engineering should be
completed carly in 1987. The licensee will proceed concurrently with
the development of EDCR 86-409 so that the modifications can be installed
during the 1987 outage as planned. The inspector stated that proposed
changes to the ADS technical specifications should be submitted early
in 1987 to allow sufficient time for NRR staff review of the amendment
request in time for startup from the outage. The licensee noted the
inspector's comments.
This item is open pending completion of the licensee's actions to modify
the ADS logic in a manner approved by the NRC staff, and subsequent re-
view during a future inspection.
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10.5 Item II.F.1.3, Containment High Range Monitor
This item was last reviewed during Inspection 84-11, and based on an NRR
safety evaluation (SE; dated July 16, 1985, the licensee was requested
to take actions to relocate the monitors within the drywell to better
meet the NUREG criteria for the radiation monitors. Following a Septem-
ber 4, 1985 meeting on the issue in NRC Region I, the licensee submitted
FVY 85-110 on November 22, 1985 to provide the basis for a technical
deviation from the requirements of the NUREG 0737 Table II.F.1-3 criteria
regarding location of the radiation detectors. In a subsequent SE dated
March 25, 1986, NRR accepted the existing installation based on addi-
tional information provided in the November 22, 1985 submittal, which
showed that the objectives of the NUREG criteria were met. No further
actions is required by the licensee on this item and this matter is
closed.
10.6 Item I.D.2.2&3, Safety Parameter Display System (SPDS)
The licensee provided commitments to this item in response to NUREG 0737
Supplement 1 by letter FVY 83-30 dated April 19, 1983. By letter FVY
85-10 dated February 1,1985, the licensee submitted a functional safety
analysis for the proposed SPDS, and committed to implement the modifica-
tions in conjunction with an upgrade to the plant computer. The computer
will be upgraded in two phases starting with the 1987 refueling outage,
and the SPDS will be completed during the Fall 1988 outage and thus be
operational for startup for operating cycle 14.
The licensee approach to this item was to finalize the SPDS design in
conjunction with the actions taken in response to other Supplement 1
items, which resulted in a schedule to fully implement the original NUREG
requirements upon initial installation of the necessary hardware. NRC:
NRR accepted the licensee's plans and schedule, as confirmed in an Order
dated August 29, 1985. Based on the above, NUREG Item I.D.2.2 is con-
sidered closed administrative 1y, and subsequent licensee actions for the
SPDS will be tracked under Item I.D.2.3. This item will be reviewed
further upon completion of the licensee's actions.
10.7 Item II.F.2, Inadequate Core Cooling Instrumentation
This item was last reviewed during Inspection 84-01. In response to this
NUREG item and Generic Letter 84-23, the licensee committed in letters
FVY 84-144 dated December 6, 1984 and FVY 85-29 dated March 28, 1985 to
change the reactor vessel level measurement system during the 1985-86
refueling outage. The plan was to replace the existing Yarway columns
and cold reference columns with a dual cold leg arrangement. The modi-
fications will be installed as safety class equipment and seismically
supported. The purpose of the change is to reduce Yarway level measure-
ment inaccuracies resulting from density variations caused by elevated
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s
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1
drywell temperatures, and to allow the reference _ legs to operate at a
lower temperature to reduce the possibility of boiling / flashing in the
legs.
In a letter dated May 24,_1985, NRR provided the results of the staff's
review of the licensee's proposal and approved the intended modifications
-
and schedule to complete:the NRR action for Item II.F.2. By letter dated
July 18,.1985,-the licensee _ proposed deferral of the modifications until
the 1987 outage to allow field verification of the exiting drywell con-
i figurations to finalize the new reference level support' design. NRR
- accepted the revised schedule by letter dated September 6, 1985.
The' inspector had no further comment on this item. Completion of the
licensee actions to meet comnitments will be reviewed during a subsequent
inspection.
{
\ . 10.8 Item II.K.57, Manual Actuation of ADS
The licensee responded to this item by letter FVY 80-170 dated December
15, 1980 and stated that no actior would be tsken until the new symptom-
1 orientated emergency procedure guidelines were developed by the BWROG
i and approved by the NRC staff. The licensee implemented new emergency-
i operating procedures in accordance with Revision 3 of the guidelines,
- - as discussed in section 10.2_above, which were approved by the NRC staff.
'
'
The inspector reviewed licensee procedure OE 3102, Reactor Pressure
Vessel Level Control, Revision 2. Step LC/D-10 cautions the operator
'
to assure low head pumps sufficient to maintain vessel water level are
running and available for injection prior to manually blowing down the
vessel with the ADS system.
l The licensee has satisfied the requirements for this item. This item
i
is closed.
!
10.9 Item III.A.1 & III.A.2, Emergency Response Capability (ERF Approval)
l By letter dated October 30, 1986, the licensee affirmed to NRC:NRR that
j. actions had been completed per Confirmatory Orders dated June 12, 1984,
r September 28, 1984, and August 29, 1986 to implement all emergency re-
sponse capability and meteorological data upgrade items required by Sup-
plement 1 of NUREG 0737, with the exception of the SPDS, which will be
[ completed prior to the startup from the 1988 refueling outage. NRR
acknowledged the licensee's commitments by letter dated April 28, 1986
and stated that an ERF Appraisal audit will be scheduled at a future time.
This item will be reviewed further during a subsequent inspection.
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10.10 Technical Specifications for NUREG 0737 Items
The licensee responded to NUREG 0737 and Generic Letter 83-02 by letters
FVY 81-178 dated December 29, 1981, FVY 83-38 dated May 17, 1983, FVY
84-146 dated December 14, 1984 and FVY 85-117 dated November 26, 1985
to propose changes to the technical specifications (TSs) for various TMI
items, or otherwise provide justification why changes were not required.
Proposed Change No. 99 (FVY 81-178) covers the stack high range noble
gas monitor and is still outstanding. By letter dated August 11, 1986,
the NRC staff safety evaluation (SE) erroneously concluded that the TS
requirements for II.F.1.1 were addressed in the new RETS issued with
Amendment 83 on October 9, 1984. The new RETS address only the existing
(low range) stack noble gas monitors. This item will be followed with
NRC:NRR.
By letter dated August 11, 1986, NRR issued Amendment No. 96 to the
Technical Specifications to address modifications made per Items
III.D.3.4, II.F.1.3, II.F.1.4, II.F.1.'5, and II.F.1.6. The NRC staff
also concluded that no TSs or changes were required for Items II.B.1,
II.B.3 and II.F.1.2. In letters dated December 9,1982 and March 4, 1985,
the staff SEs concluded that no TSs were required for Items II.E.4.2.7
and II.K.3.28, respectively. The inspector noted that TS changes will
subsequently be required for Item II.K.3.18 upon installation of the ADS
design changes during the 1987 outage. No TS changes are required for
II.E.4.1, II.E.4.2.5, II.E.4.2.6, II.K.3.19 and II.K.3.45.
Technical specification changes have previously been issued for
I.A.1.1.3 - STA Training, II.K.3.15 - HPCI and RCIC Isolation, and
II.K.3.27 - Reactor Vessel Reference Level.
By letter FVY 83-38, the licensee provided reasons why TS changes are
not required for Items I.A.1.3, II.K.3.3, II.K.3.13 and II.K.3.22, and
no further actions are planned. The licensee's position on this item
has yet to be approved by NRR. This item will be followed during a sub-
sequent inspection.-
This item is unresolved pending completion of licensee and NRC actions
as listed above regarding NUREG 0737 technical specifications (UNR 86-
22-05).
11.0 Errata
The licensee informed the inspector of an error on page 26 of Inspection Re-
port 86-13, Section 10.0. The recirculation project team QA Supervisor was
Mr. R. L. Martin, and not Mr. A. Small.
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12.0 Management Meetings
Preliminary inspection findings were discussed with licensee management peri-
odically during the inspection. A summary of findings for the report period
was also discussed at the conclusion of the inspection and prior to report
issuance.
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