ML18152A073
| ML18152A073 | |
| Person / Time | |
|---|---|
| Site: | Surry  |
| Issue date: | 04/07/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML18152A074 | List: |
| References | |
| 50-280-97-02, 50-280-97-2, 50-281-97-02, 50-281-97-2, NUDOCS 9704170223 | |
| Download: ML18152A073 (29) | |
See also: IR 05000280/1997002
Text
Docket Nos:
License Nos:
Report No:
License(;?:
Facility:
Location:
Dates:
Inspectors:
Approved by:
9704170223 970407
ADOCK 05000280
G
U.S. NUCLEAR REGULATORY COMMISSION
REGION II
50-280. 50--281
50-280/97-02, 50-281/97-02
Virginia Electric and Power Company (VEPCO)
Surry Power Station, Units* 1 & 2
5850 Hog Island Road
Surry, VA* 23883
January 26 - March 8, 1997
R. Musser, Senior Resident Inspector
K. Poertner, Resident Inspector.
P. Byron, Resident Inspector
W. Sartor, *Reactor *Inspector (Section Pl.l)
D. Jones, Senior Radiation Specialist (Sections Rl.2,
Rl.3, and R8.l)
G. Belisle,.Chief, Reactor Projects*Branch 5
Division of Reactor Projects*
ENCLOSURE 2
EXECUTIVE SUMMARY
Surry Power Station, Units 1 & 2
NRC Inspection Report 50-280/97-02, 50-281/97-02
This integrated inspection included aspects of licensee operations,
engineering, maintenance, and plant support.
The report covers a 6-week
period of resident inspection; in addition, it includes the results of
announced inspections by two regional specialists.
Operations
Technical Specification (TS) requirements were satisfied during the
replacement of the Unit 1 source range detectors. *Startup activities
observed were conducted in accordance with approved procedures and the
unit restart.was carefully controlled (Section 01.2).
Safety system and operator response to the Unit 2 reactor trip was
acceptable.
Licensee reviews prior to restart were appropriate.* and the .
unit restart was carefully controlled. Crew performance during the main
turbine startup and main generator synchronization were excellent
(Section 01.3).
The operations shift response to the los*s .of Unit 1 pressurizer heaters
was appropriate. Prior to initiating a reactor trip, operations
personnel methodically determined their* course of action and carried out
these plans (Se~tion 01.4).
Unit 2 Auxiliary Feedwater (AFW) initiated as designed following a loss
of the operating main feedwater pump.
The Engineered Safeguards* Feature
actuation was reported as required by 10 CFR 50.72 (Section 01.5).
The Number r Emergency.Diesel Generator (EDG) was properly aligned in
accordance with the system alignment procedure. Material condition anq
housekeeping were good. The*diesel battery throwover switch was not
referenced in the system alignment procedure and the labeling on breaker
lEl on Motor Control Center (MCC) MCC-lHl-lA did not match the
description contained on the system alignment sheet. These two items
were expeditiously resolved after discussions with operations management
- (Section 02.2).
Operator simulator training in preparation for.an. upcoming Refueling
Outage (RFD) was well performed and was conducted at an appropriate time
just prior to the beginning of the RFD (Section 05.1).
Maintenance
A Non~cited Violation (NCV). was identified for failure to maintain two
trains of the Auxiliary Ventilation System operable as required by TS
(Section Ml.1).
A violation was identified for failure to include operabi.lity guidance
in an operating.procedure ~nd *tb proceduralize material restrictions
(Section Ml.1).
. '
2.
Number 3 EDG maintenance activities exceeded the Plant Specific Analysis
(PSA) outage time established*prior to removing the diesel from service.
The TS allowed Limiting Condition for Operations (LCD) time was not
exceeded.
Once licensee management became aware the PSA value had been
exceeded: increased upper management attention was evident (Section
Ml.2).
Testing* performed on the Unit 1' B Low Head Safety Injection (LHSI) pump
was accomplished in.accordance with procedure requirements and the test
- data obtained met acceptance criteria (Section Ml.3).
A violation for fa.ilure to meet the requirements of 10 CFR 50.9(a) for
accuracy of information in an LER was identified (Section.MB.1) ..
Engineering
For ventilation engineering, informal communications appears to be the
common mode of operation. *However, Maintenance and Operations allowed
this mode to perpetuate by not insisting on formal means of
. communicating decisions.
In addition, engineering conditions and .
1 imitations were not always procedural ized (Section E.1 ))'.
. A review of licensee Oversight reports indicated that many of the
current issues nad been pr~viously identified .. Discussions with the
licensee indicated that several of the Equipment De-ficiency Resolution
Plan (ERDP) items will be completed during the current Unit 1 RFD.
Implementation of corrective actions has been inconsistent. However,
the number of Deficiency Reports (DRs) written has increased indicating
that problems *are being identified (Section E7.1).
Plant Support.
An NCV was ident.ified for failure to obtain a grab sample within 12
hours as required by the Offsite Dose Calculation Manual (ODCM) (Section
Rl.1).
.
.
. '
.
.
The licensee was properly monitoring and controlling personnel radiation
exposure in accordance with station administrative procedures and
10 CFR Part 20 .. The maximum individual radiation exposures for 1995 and
1996 were well within the licensee's administrative limits and the
regulatory-limits specified in 10 CFR 20.1201(a) for occupational dose
(Section Rl.2).
.
- -
The licensee was closely monitoring collective dose in order to meet As.
Low As Reasonably Achievable (ALARA) goals and was properly posting area
radiological conditions (Section Rl.3).
One violation was identified with multiple examples of failure to follow
radiation protecti.on procedur~s (Section RB .1) .
3
- The emergency preparednes*s program was being maintained in a manner that
supported good emergency response in the event of an accident (Section
Pl.1) .
Report Details
Summary of Plant Status
Unit**l began the inspection period at hot shutdown with both source range
detectors inoperable. The source range detectors were replaced and the unit
returned to service on February 2.
On February 19, the unit was manually
.
tripped from 53 percent power due to the loss of primary plant pressure
control resulting from the failure of pressurizer heaters.* The u.nit was
returned to service on February 22.
On March 7, the unit was shutdown for a*
scheduled RFD.
At the end* of the inspection period the unit was in cold
shutdown.
Unit 2 began the inspection period at or near full power.
On February 18, the
unit was manually tripped due to a failure in the Electro-Hydraulic Control *
(EHC) system that resulted in the main turbine control valves drifting shut.
The unit was returned to service on February 21.
The unit operated at p9wer
the remainder of the reporting_ period.
I. Operations
01
Conduct of Operations
01.1 General Comments* (71707, 40500)
The inspectors conducted frequent control room tours to verify proper
staffing, operator attentiveness, and adherence to approved procedures.
The inspectors attended daily plant status meetings to maintain
awareness of overall facility operations and reviewed operator logs to
verify operational safety and compliance with TSs.
Instrumentation and
. safety system lineups were periodically reviewed from control room
- indications to assess operability. The inspectors observed Control room
shift turnovers during the inspection period. Frequent plant tours were
conducted to observe equipment status and housekeeping.
DRs were
reviewed to ass~re that potenti&l safety concerns were properly reported
and resolved. The inspectors found that daily operations wer.e generally
conducted in accordance with regulatory requirements and plant
procedures.
- The inspectors verified portions of tagout l-97-CH-0022, .Charging pump
lB, and verified that the tagout was properly prepared and authorized
and_ that the components were in the required po_sition~
The inspectors reviewed the status of containment penetrations 2-PN-PEN-
101 and 2-PN-PEN-51 and verified that they we.re configured
appropriately.
01.2. Unit i Source Range Replacement and Startup
a.
Inspection Scope (71707)
The inspectors monitored licensee actions to replace both.Unit 1 source
range detectors .and observed p*reparati.ons. and operations .associated with
unit restart.
2
b. Observations and Findings
During the previous inspection period, Unit 1 was shutdown to repair a
steam leak in the main steam valve house.
During the unit shutdown,
both source range detectors failed following energization. The unit
began this inspection period in hot shutdown with both source range
detectors inoperable.
With no source range detectors operable, TSs require that shutdown
margin be verified within one hour and every 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> thereafter. TSs
also require that at least one intermediate range detector be operable
at hot shutdown conditions. The source range and intermediate range
detectors are contained in a common housing assembly and to replace the
source range detector requires that the corresponding intermediate range
detector be removed from service.* The licensee initially decided to
replace the entire assembly for .ease of instalJation.
During replacement of the detectots, the inspectors verified that the TS
requirement for*an operable intermediate range detector and required *
shutdown margin were maintained.
During the installation process, one*
of the new intermediate range.detectors and both source range detectors
did not operate and had*to be replaced again~ During this evolution,
the assembly was removed from the neutron shield and the individual
detector-was replaced in the assembly housing.
During these evolutions,
an intermediate range detector was always operable. All four detectors
were replaced antj declared operable on February 1.
Unit 1 was returned to service on February 2 at 2:10 p.m., and obtained
100 percent power on February 3~*
The inspectors monitored activities in
the control room during plant restart. Startup activities observed were
conducted in accordance with approved procedures and the unit restart
was carefully controlled. The operations brief prior to the approach to
criticality was excellent.
c. Conclusions
TS requirements were satisfied during the replacement of the Unit 1
source range detectors. Startup activities observed were conducted in
accordance with approved *procedures and the unit restart was carefu*lly
controlled.
01.3 Unit 2 Reactor Trip and Restart
a.
Inspection Scope (71707)
The inspectors reviewed the circumstances surrounding the February 18
Unit 2 reactor trip. On February 21, the inspectors observed
preparations and operations associated with unit restart.
3
b: Observations and Findings
At approximately'2:50 p.m. on February 18, Unit 2 was manually tripped
from the*control room.
The control room operator observed turbine load
decreasing, the turbine governor valves drifting closed, numerous
computer alarms and high Tave and Tave/Tref deviation alarms prior to
manually tripping the unit. The control rods inserted and all three AFW
pump*s started on 1 ow 1 ow steam generator 1 eve 1 as designed. A 11 *rod .
bottom lights illuminated; however, three control rods indicated between
10 and 15 steps following the trip. The Reactor Coolant System (RCS)
was borated an additional 1110 gallons as required by the controlling
procedures.
The unit was stabilized at hot shutdown with Tave being maintained at
547 degrees Fahrenheit.
When the low low steam generator water level
signa'ls cleared on the C and A steam generators, the Turbine Driven
Auxiliary Feedwater (TDAFW) steam. supply valves automatically closed as
designed. Subsequent to the valve closure, level in the A steam
generator decreased below the low low level trip and a second automatic
start of the TDAFW pump was initiated. The low low*level signal
im~ediately cleared and the steam supply valves closed prior to fully
opening. The outside operator subsequently found the TDAFW pump trip
throttle valve tripped.
Review of the TDAFW pump trip determined that the pump tripped due to
receiving a second start signal prior to the* governor low speed stop
resetting. The governor has an inherent time period (approximately 16
seconds) during which a turbine restart will result in an overspeed
condition of the_ turbine. The TDAFW. pu_mp had received a restart signal
.almost immediately after the steam supply valves had automatically
closed. At the time of the TDAFW pump.trip, both motor driven pumps
were operating.and the TDAFW pump was not needed.
The licensee revised
the emergency operating procedures to require that the steam supply
valves to the TDAFW pump* be placed in the open position when the. pump is
operating to give the operator direct control of the steam supply
valves. The procedures were also revised to verify level in all three
steam generators great.er than 21 percent prior to securing the pump.
The inspectors verified that the procedure changes were incorporated.
The 1 i censee is reviewing the system operation to determine if
..
enhancements are possible to the control *circuitry. Followup on the *
licensee's actions with respect to future modifications associated with
the TDAFW pump control circuitry is identified as Inspection Followup
- Item (IFI) 50-280, 281/97002-01.
The inspectors determined that the
short term actions initiated *by the licensee should prevent an immediate
restart of the TDAFW pump and recurrence of this problem.
The inspectors reviewed the reac*tor trip report and associated pl ant *
response data to independently verify that safety system and operator
performance was as expE;!cted throughout'the event. Primary plant
response was normal and all safety systems performed as designed with
4
the exception of the TDAFW pump.
Items identified following the reactor
trip were resolved prior to returning the unit to service.
The turbine governor valves drifted closed due to a loss of both +15 *
Volts-Direct Current (VDC) power supplies in the turbine EHC panel. *.
Extensive troubleshooting by the licensee could not determine the exact
cause of the loss of both +15 VDC power supplies, but did identify that
the relay card that should have tripped the turbine following a loss of
both +15 VDC power supplies was defective and would not function.
The
power *supplies and.the defective relay card were replaced~ *
.
.
On February 21, the inspectors observed unit restart activities. Crew
performance during the main.turbine startup and main generat6r
synchronization were excellent.
c. Conclusions
The inspectors determined that safety system* and operator response to
the Unit 2 reactor trip was acceptable. Licensee reviews prior to
restart were approptiate, and the unit restart was carefully controlled.
Crew performance during the main turbine startup and main generator
synchronization were* excellent.
.
01.4 Unit 1 Manual Reactor Trip Due to Loss of Pressurizer Heaters
a.
Inspection Scope (71707}
.*.
The inspectors observed and reviewed the results of the Februa*ry 19
. Unit 1 manual reactor trip due to* a loss of the pressurizer heaters.
b. Observations and Findings .
On February 19*, at 8:40 p.m., a low pressurizer pressure alarm was
received i*n the Unit 1 control room .. This alarm actuates when pressure.
is less than 2205 psig (normal RCS pressure is -2235 psig). *1n
accordance with TS 3.12.F, pressure must be.restored to.greater than
2205 psig within- two hours or the unit must be less than~ percent power
in the next four hours.
The Operations Shift investigated the matter
and determined that the proportional pressurizer heater bank was not
functioning properly.
More specifically, the unit which controls the
.cycling of this heater bank (Robicon Controller Unit) was not allowing
current to flow to the heaters which resulted in the RCS pressure
decrease.
The inspectors -were informed of the situation at approximately* ..
9:15 p.m., and responded to the site. The Operations Shift had begun
reducing power at 8:52 p.m.
The inspectors arrived in the control room
at approximately 10:00 p.m.
At this point, RCS pressure was
approximately 2025 psig a.nd decreasing slowly._ Troubleshooting efforts
on the Robicon Controller Unit were ineffective. At 10:30 p.m., with:
RCS pressure continuing to decrease, it was apparent that the unit would
have to be shut down.
The licensee was concerned that following the
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5
trip, a Safety Injection (SI) signal would be generated on low pressure ..
Prior to initiating the trip, operations*personnel methodically
determined their* course of action to* help prevent an unwarranted SI from
occurring. Specifically, the operators determined that they would trip
the C Reactor Coolant Pump (RCP) following the reactor trip to help*
control plant cooldown.
(The C loop feeds the 14558 spray valve which
was tagged out but leaking by).
In addition. specific assignments were
made to each operator prior to the unit trip.
At 10:59 p.m., Unit 1 was manually tripped from approximately 53 percent
power.
Following the trip, the A RCP unexpectedly.tripped when
.
transferring from the station service transformer to the reserv~ station.
service transformer. All rod bottom lights lit and all Individual Rod
Position Indicators (IRPis) indicated less than 10 steps. The C RCP was
manually tripped as discus?ed and.in accordance with the Emergency
Operating Procedures.. This appeared to stop t.he decreasing trend in
plant cooldown.
Minimum RCS pressure observed following the trip was
approximately 1790 psig, about 15 psig above the SI initiation setpoint.
Both motor driven AFW pumps and the TDAFW pump started and injected ..
Unit 1 source range Nutlear Instruments (Nis) came on scale as designed.
A short lived loss of detector voltage alarm on N32 came in for
approximately two minutes, however a loss of.detector voltage was not
seen. . This matter was attributed to a drifting bistable which was
subsequently recalibrated. The decision to trip the unit was
appropriate and the plant was stabilized in hot shutdown.
Because Unit 2 was in hot shutdown at the time of this trip, au4omatic
load shedding was enabled which.resulted in certain loads being shed
from the reserve station service transformers.* This-included the
running feed pump on Unit 2 (2A), and because the other Unit 2 feed pump
was secured for maintenance, AFW _(motor driven pumps) initiated. This
was expected and discussed with the-Unit 2 operators prior to the manual trip of Unit 1. A one -hour report to the NRC was made in accordance
with 10 CFR 50.72.
- The failure of the Robicon-controller module was determined to be age
related failures of various electronic components in a controller
circuit card. * The contra 11 er was rebui 1 t by the manufacturer. The
licensee plans to place the Robicon controller in its preventive
maintenance program and will evaluate replacement of the Unit 2 module
during the next RFO.
The A.RGP trip was caused by failure.of the
motor's speed sensing relays. The relay was replaced and the _licensee
pl ans to eva 1 uate . further corrective actions .in accordance with their .
corrective action program.
The unit was returned to service-on February 22 and reached 100 percent
power on February 23.
c .. Conclusions
The operations shift response to the loss or Unit 1 pressurizer heaters
- .was appropriate.* Prior to initiating a reactor*trip, operations
6
personnel methodically determined their course of action and carried out
these plans.
01.5 Unit 2 AFW Actuation
a.
Inspection Scope (71707)
The inspectors revi~wed the circumstances surrounding a Unit 2 AFW
actuation on February 19 while .the unit was being maintained at hot
shutdown following a reactor trip.
b. * Observations and Findings
On February 19, with Unit 2 at hot shutdown, both motor driven*AFW pumps
automatically started due to the loss of the A main feedwater pump.
At .
the time of the actuation, the B feedwater pump was removed from .service
for maintenance and the A *feedwater pump was operating to maintain steam
generator water 1 e_ve 1 . The A feedwater pump tripped on. a 1 oad shed .
condition caused by a Unit 1 reactor trip. The loss of both*feedwater
pumps initiated AFW.
Both motor driven AFW pumps started* as designed to
supply feedwater to th~ steam generators.
The Engine~red Safeguards Feature (ESF) actuation was.reported as
required in accordance with 10 CFR 50.72 as a non-emergency 4-hour
report. The licensee plans to issue an Licensee Event Report CLER)
describing the event -within.30 days.
The inspectors will review this
item further during review of the. ~ER.
c. Conclusions . *
AFW initiated as designed following a loss of the operating main
feedwater pump.
The ESF actuation was re~orted as required by 10 CFR
50.72.
.
.
- 02
- operational Status of Facilities and Equipment
02.1 Unit 2 Auxiliary Feedwater System Walkdown (71707)
On March 6, 1997, the inspectors walked down the Unit 2 AFW system and
verified* that the valve lineup for.those valves outside containment was
in accordance with Attachment 2 of Operating Procedure, 2-0P-FW-OOlA, .
Auxi 1 i ary Feedwater System Valve Alignment, Revision 1. * Chapter 10 .3 .5 .
of the Updated Final Safety Analysis Report *(UFSAR) was reviewed and.no
discrepancies were identified during.th~ walkdown.
Housekeeping in the
genera 1 area was acceptab 1 e ...
02.2
EOG Number 1 Walkdown
a.
Inspection Scope (71707)
.The inspectors performed a wa 1 kdown of the Number 1 EOG to verify *
equipment operability, material condition, and housekeeping ..
..
05
7
b. Observations and Findings
The inspectors determined that the Number 1 EDG was properly aligned in
accordance with operating procedures. Material condition and
housekeeping were good.
The inspectors identified that the system *.
alignment procedure did not verify that the EDG battery throwover switch
was in the proper position. The throwover switch was in the proper
position when inspected. The throwover switch allows the Number 3 EDG
- battery to be aligned to the Number 1 EDG and would only be operated
under *accident con_ditions.
The inspectors also identified that the
labeling for breaker lEl on MCC-lHl-lA did not match the description
contained on the system alignment sheet. These items were brought to
the attention of operations management for *resolution. The system
alignment procedures for the Number 1 qnd Number 2 EDGs were revised to
include the respective battery throwover switch and a new label was
installed on the MCC breaker. Both these. items were accomplished
expeditiously following _identification by the inspectors.
.
c. Conclusions
The Number 1 EDG was properly aligned in accordance with the system
alignment procedure." Material condition and housekeeping wer~ good.
The *inspectors identified that the EDG battery throwover switch was not
referenced in the system alignment procedure and that the labeling on
breaker lEl on MCC-lHl-lA did not match the description contained on the
system alignment sh~et. * Tne.se two items were expeditiously resolved *
after discussions with operations management.
Operator Training and Qualification
05.1 Operator.Simulator Training
a.
Inspection Scope (71707)
_ On February 28, the inspectors observed operator simulator training in
preparation for the upcoming Unit 1 RFO.
b. Observations and Findings
The inspectors observed portions of operator. simulator training on .
. February 28.
The training consisted of shutdown operations in *
preparation for the upcoming RFO.
More specifically, *the inspectors
observed evolutions/scenarios involving loss of the Residual Heat
Removal system and the manipulation of RCS water level. The inspectors
observed the operators following procedures appropriate to the tasks* at
hand.
The interface between the instructors and the operators was
carried out at the relevant point in the various scenarios .. The
instructors were not reticent in pointing out details which could aid
the operators duri.ng the.actual performance of the various evo 1 uti ons.
..
. C.
8
Conclusions
The inspectors determined that operator simulator training in
preparation for an u*pcoming RFO was well performed and was *conducte~ at
an appropriate time just prior to the beginning of the RFO.
'
IL Maintenance
Ml
Conduct of Mainten~nce
Ml.1 Auxiliary Ventilation System
a.
Inspection Scope (62707)
The lic.ensee continues to have problems with the Auxiliary Ventilation
System. These were previously discussed in Inspection Report Nos. 50-
280, 281/96-13. The inspectors followed the continuing issues and the
licensee's corrective actions.
b. Observations and Findings
On January 9, 1997. at 5: 08- a: m... the 1 i censee entered a 7 -day LCQ. as .
required by TS 3.22 to perform maintenance on the Auxiliary Ventilation
System Filter Exhaust Fan, Ol-VS-F-588.
I$sues related to this
maintenance outage are described in detail in Inspection Report Nos.
50-280, 281/96-13 .. During this maintenance outage, the actuator for the
Motor Operated Damper (MOD)-588, was replaced and its linkage-was
adjusted.
On January 13. the licensee observed *that the 588 fan was *
rotating in the reverse direction at* 13 rpm.
The reverse rotation
stopped after aligning the dampers f~r the fuel building suction path.
Engineering was contacted and stated that the 588 fan could be started
as l_ong as* reverse rotation was less than 125 rpm.
The LCO -was exited,
at 7:52 a.m. on January 15, after completion of Post Maintenance Testing
(PMT).
.
On January 16, 1997, at 1:00 a;m .. the 588 fan was.again observed
rotating in the reverse direction at 23 rpm.
The fan was declared
. inoperable approximately six hours later and a 7-day LCD was again
.
entered. Investigation determined that the reverse* rotation was due to
leakage through damper MOD-588.
The damper actuator linkage was
adjusted to fully close the damper and fan reverse rotation ceased. The *
588 fan was declared operable at 12:57 p.m. on January 16 and the LCD
- was again exited. The 1 i censee determined that they imp roper 1 y exited
the LCO before full dampe.r closut-e was- verified. This resulted in the
7-day LCO being exceeded by 7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br /> and 49 minutes and the units were
not placed in Hot Shutdown within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> as required by TS 3.22. The
licensee reported this to the NRC by LER 50-280, 281/97002-00. The
failure of the licensee to place both units in Hot Shutdown within 6
hours after failing to*have both Auxiliary Ventilation System exhaust
trains operable within 7 days is*a violation of TS 3.22. The Auxiliary
-- ---~--
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-~- -- ~ -- ------
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9
Ventilation System was capable of performing its intended safety
function with the 58A fan and associated filter train during the
reported ti me frame.
The .1 i censee i dent i fi ed the matt.er, promptly
reported it, and took corrective -action to prevent recurrence. The
_ violation could not have been reasonably prevented by corrective actions
from a previous*violation and the matter*was not willful. This
licensee-identified and corrected violation is being treated as a Non-
cited Violation, consistent with Section VII.8.1 of the NRC Enforcement
Policy; This item *is identified as NCV 50-280, 281/97002-02.
The need to readjust the linkage for the replacement damper, MOD-588,
raises the question of the adequacy of the post maintenance testing
and/or installation verification. This matter was discussed with the
licensee. They concurred with this conclusion and stated that the PMT
adequacy would be reviewed.
Licensee engineering determined that the size of the opening which
existed with damp~r MOD-588 not fully closed would have caused the 588
fan to rotate at speeds in excess of 125 rpm i_n the reverse *direction
when the 58A fan was started. The inspectors questioned.the licensee as
to the technical basis for the 1~5 rpm backward rotation and were given *
a Maintenance Engineering Info*rmation Transmittal (MEIT) Record, dated *
October 2~. 1996, which states that.the blower and motor vendors
indicate that it is a good practice not to allow these components to
exceed 120 rpm backward rotation. *This information was not contained in
operating procedures.
The *inspectors asked how the operators knew of
this information and were informed that a copy of the memo was in the
control room .. The.inspectors requested the memo from the control room.
The operators were unable to 1 ocate the October 29 *, 1996, memo but
located an MEIT Record, dated December 16, -1993, which discusses
backward rotation of the Unit 1 and 2 fans.
rt*states that backward
rotation of less than 120 rpm for the 40A and 408 fans is not a problem.
It further states that 58A and 588 fans are.not allowed to rotate
backwards.
.
.
The inspectors reviewed procedures O-MOP-VS-004, Return to Service of
Auxiliary. Ventilation Exhaust Train A, Revision 2-P.l, O-MOP-VS-005, *
Return to Service of Auxiliary Ventilation Exhaust Train 8,
Revision 2-P.l, and O-OPT-VS-002, Auxiliary Ventilation Train Test,
Revision 4. These procedures provided no limitations relating to
reverse rotation of the 58A and 588 fans.
The licensee has a continuing problem with inleakage around the access
doors to safety related charcoal filters (1-VS-FL-3A/8) due to broken
door latches and deteriorated door gaskets. The gaskets were original
- installed equipment and the.licensee determined that the gaskets were
not in a Preventive Maintenance (PM) program .. The inspectors reviewed
DRs 96-1468 and*97-0182 which documented the door discrepancies. Work.
Order (WO) 346246-01 was written.to repair/replace.the filter 3A door
latches. The mechanics were unable to seal the doors and installed
Duxseal around the doors in accordance with verbal instructions from a *
- Maintenance*foreman.* Operation's personnel observed the Duxseal during
. ..
.
10.
their pre-operability walkdown and requested that*Engineering approve
the use of Duxseal.
Engineering rejected the use of Duxseal and DR 97-
0504 was issued to track the deficiency.
WO 346246-02 was issued to
remove the Duxseal and replace it with RTV which is an approved sealant.
The inspector? reviewed the above documents.
The inspectors interviewed the Maintenance foreman and learned that *he
did not* have instructions for an approved sealant material.
He stated
that he remembered that engineering had previously recommended Duxseal
for this application and other foreman supported his recollections.
He
then authorized its use to seal the leaks around the 3A charcoal filter
access doors.
The. inspectors also interviewed the system engineer and
learned that engineering had withdrawn Ouxseal as an approved material
for ventilation systems in 1988.
The inspectors asked where this
information was documented and learned that this information was not
documented but had been verba 11 y transmitted to Maintenance.
The system
engineer informed the inspectors that Engineering had recommended RTV as
a sealant as they had data*to support its acceptability. This
recommendation was also verbally transmitted to-Maintenance. The
inspectors discussed this issue with Maintenance supervision and learned
that there are no procedures which specify material a.cceptability.* The
material tag:5 only list* gross *limitations.
.*
.
- *
.
The failure to jnclude the.October 29, 1996, operating limitation in an
operating procedure and to proceduralize material restrictions are
identified ai violation so~200. 281/97002-03.
c. Conclusions
An NCV was identified for failure to maintain two trains of the
Auxiliary Ventila~ion System operable as required _by .TS.
A violation
was identified for failure to include operability guidance in an
operating procedure and to proceduralize material restrictions.
Ml.2
EOG Number 3 Maintenance Outage
a.
Inspection Scope (62707)
The inspectors monitored ma*intenance activities conducted on the
Number 3 EOG.
b. Observations and Findings
On February 3, the Number 3 *EOG was removed from service for major PM
activities.
TS allows the EOG to be inoperable for a 7-day period.
Prior to removing the EOG from service, the licensee performed a PSA
evaluation and determined that a maintenance outage time of less than
93 hours0.00108 days <br />0.0258 hours <br />1.537698e-4 weeks <br />3.53865e-5 months <br /> was appropriate. The scheduled maintenance was planned to be
accomplished in 84 hours9.722222e-4 days <br />0.0233 hours <br />1.388889e-4 weeks <br />3.1962e-5 months <br /> per ~he schedule.
The inspectors reviewed the status of the maintenance activity on a
daily bases to determine return to service progress. During return_ to
..
11
service testing several major problems were encountered. These problems
resulted in the outage time exceeding the 93 hour0.00108 days <br />0.0258 hours <br />1.537698e-4 weeks <br />3.53865e-5 months <br /> PSA value. The diesel
was returned to service on February 9 at 11:00 a.m. resulting in a total
out of service time of 149 hours0.00172 days <br />0.0414 hours <br />2.463624e-4 weeks <br />5.66945e-5 months <br />. The 7-day LCO time frame *was not
exceeded~
c. Conclusions
Number 3 EDG maint~nance activities exceeded the PSA outage time value
estab 1 i shed prior to removing the di ese 1 * from service. * The TS a 11 owed
LCO time was not exceeded.
Once liGensee management became aware the
PSA value had been exceeded, increased upper management attention was
evident;
Ml.3 Unit 1 Low Head Safety Injection CLHSI) Pump Test
a.
Inspection Scope (61726)
The inspectors observed a LHSI pump B test conducted on March 5.
b. Observations and Findings
The inspectors observed the performance of procedure 1-0PT-SI-005, LHSI
Pump Test, Revision 8, conducted. on March 5.
The testing was
accomplished in accordance with the -procedure*and the inspectors
verified that the procedure's. acceptance criteria were met. The test
results were satisfactory.
c. Canel us ions*
MB
M8.1
Testing performed on the LHSI pump B was accomplished in accordance with
procedure requirements and the test data met the acceptance-criteria.
Miscellaneous Maintenance issues (92700. 92902)
(Open) Licensee Event Report CLER) 50-280. 281/97002-00:. one train of
auxiliary ventilation system inoperable outside of technical
speci fi cations.
On January 15. 1997. the 1 i-censee exceeded a 7-day LCO
for TS 3. 22 by 7 hour8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br />s* -and 49 minutes for Auxi 1 i ary Vent i 1 at ion System *
Filter Exhaust* Fan, Ol-VS-F-58B.
The licensee determined on February 7,
that *they had exceeded the LCO and issueo the LER on February 14. This
event is described in more detail in Section Ml.l.
The inspectors* reviewed the LER and.determined that it contained
.
inaccurate information .. Specifically'; Section 5, Additional Corrective
Action, states that on February 7, 1997, the Shift Orders were revised
to reflect that if any reverse rotation of either 58 fan was observed
that the fan should be considered inoperable and at that time the fan
should be manually isolated. This information was not included in the
Shift Orders.
An Operations Shift Supervisor was asked where the
reverse rotation inoperability policy was documented and he thought it
was in the Shift Orders. -The inspectors reviewed the.Shift Orders
. .
M8.2
- 12
issued between January 10 and February 28, 1997, but were unable to
locate the policy. The licensee was questioned about this discrepancy
and subsequently informed the inspectors that the policy was added to
the Auxiliary Building Turnover Sheet (Logs) and the Shift Supervisors.
Log, but*not the Shift Orders. The inspectors reviewed the Auxiliary.
Building Logs for January and February 1997 and noted that on
January 20, a note was added for the operators to verify that. the 58A.
and 588 fans were not rotating backwards if they were secured. The
inspectors also revfewed the Shift Orders issued betw~en March 1 and 18,
1997, and noted that the 58 fan operability policy had been added on
March 6, 1997.
10 CFR 50.9(a) requires that information, provided'to
the Commission by a licensee shall be complete and accurate in all
material respects. Failure to meet the requirements of 10 CFR 50.9(a)
is identi fi eq as violation 50 -280, 281/97002 -04. *
The inspectors noted th~t Shift Order entries, including Standing
Orders, were usually one time entries. This method of documentation
requires considerable.resea~ch to locate policy and frequently resul~s.
in information being promulgated by "tribal knowledge.II
.
.
In addition, the. LER writeup did not specifically indi~ate why the fan
was considered inoperable .. The LER only*stated that the reverse
rotation caused the fan to be inoperable, even though the*inspectors had
been previously informed and the LER states that the 58 fans were only
considered inoperable if reverse rotation exceeded 125 rpm. Additional
discussions with the licensee provided the inspectors with sufficient
information to comprehend the basis for the reportability of the event
in that it was postulated that the 588 fan's reverse rotation speed
. could have exceeded the*125**rpm limit in this case. This matter was
- discussed with the 1 i censee and a revision to the LER is R 1 anned to
address this matter.
(Closed) LER 50-280/94001-00: *welding on pressurizer results in
hydrogen burn in pressurizer .. This LER describes*a hydrogen.burn event
in the Unit 1 pressurizer during welding activities conducted to install
a drain line on the 4-inch piping that runs from the pressurizer to the
power operated relief valves. The LER was submitted voluntarily due to
its potential safety si~nificance and interest to other licensees:
The inspectors reviewed the LER package and verified that the referenced
protedures had been changed to heighten awareness of systems that may
have the potential for explosive gas mixtures and to ensure that
precautionary measures are taken (i.e., sampling) prior.to performing
hot work.
III. Engineering
El
Conduct of Engineering
El.1 Auxiliary Ventilation System Engineering Effort
-*
13
a.'* Inspection Scope (37551)
The inspectors observed and reviewed engineering effort in the
resolution of. problems with the Auxiliary Ventilation System.
b. Observations and Findings
On March* 5, 1997, the Auxiliary Ventilation System Filter Exhaust Fan,
Ol-VS-F-588, .was observed to have*a reverse rotation of 3 rpm.
The
operators notified Engineering of their observation and were informed
that the fan was operable.
However. instructions had previously been
issued that with any reverse rotation the 588 fan was to be considered
inoperable. Later, on March 5, the operators observed a 15 rpm reverse
rotation of the 588 fan. *Engineering was informed and again provided
operations verbal guidance. Operations issued DR 97-0623 to document
this event. A second DR (97-0624) *was written by Operations to document
that insufficient information had been disseminated to the operators to
a 11 ow them to properly evaluate fan -operability-. The operators
requested that documented instructions be issued. *
Operations contacted Engjneeri'ng for operability determ,nations for
.
. backward rofation of the 58A and 588 fans because they were unaware of
the December 1993 MEIT record located in the control room.
The MEIT
stated that these .fans were not allowed to rotate backwards .
There.was conflicting engineering information being disseminated.
The
inspectors asked the licensee for the technical basis for the 125 rpm
- reverse rotatton limitation. Currently, Engineering is stating that
reverse rotation speeds in excess of 125 rpm will cause the fan to
separate from its. shaft when started. However, the December 16, 1993,
MEIT Record states that excessive motor starting torque and current
define the 120 rpm reverse rotation limitation.
On January 18, 1997, the licensee identified during testing of the 588
fan that there was inleakage around the west access door to.the 3A.
c_harcoa l filter.
DR 97 -0182 was written to document the deficiency and
requested engineering assistance to provide an engineering resolution.
This issue is identical to the condition described in Paragraph Ml.l.
Request for Engineering Assistance (REA) 97~0021 recommended the*
installation of a reinforcement plate along the outer edge of the
interior door and a thicker gasket'. It should be noted that the doors
in question are located on 4he suction side of the fans and are mounted
on *the interior of the ductwork and open inward.
The inspectors concluded that the doors should be mounted on the
exterior of the ductwork and open outward, thereby allowing the negative
pressure to assist in sealing the door rather than resist sealing.
Engineering recommended relocqting the* doors but determined it was too'
expensive based on the exten~ive engineering effort and craft time that
would add to the cost. The inspectors discussed the REA 97-0021
.
recommendations with the licensee. The inspectors considered the REA
.. ***
14
-recommendation to be a temporary repair that wou 1 d not so 1 ve the .
inleakage and maintenance issues. The licensee discussed the problem
with the vendor who informed them that the design of the doors was
inadequate.
Oh February 13, Engineering recommended to the Modification
Review Team (MRT) that the filter access doors be remounted to solve the
inleakage problem. This modification was approved by the MRT .
. c. Conclusions
The inspectors concluded that,' *at 1 east for venti 1 ati on engineering,
informal communications appears to be the common mode of operation.
However, Maintenance and Operations allowed this mode to perpetuate by
not insisting on formal means of communicating decisions.
In addition,
engineering conditions and limitations were not always proceduralized.
.
.
.
E7
Quaitty Assurance in Engineering Activities
E7.1 Correct,ve Action Program.
a. Inspection Scope (40500, 92720)
The inspectors reviewed the licensee's Corrective Action Program (CAP)
to determine its effectiveness. The inspectors held discussions with
licensee personnel and reviewed trend reports,. procedures, licensee
assessments, and DRs. *
b. * Observations.and.Findings
Procedure QANS*-1601, Corrective Action,* fs the Nuclear Business Unit
(NBU) governing document for.the CAP.
Revision 1 of this document
transfers respon*sibi 1 ity for the prograin from Qua 1 i ty Assurance to
Nuclear Oversi*ght. Virginia. Power Administrative Procedure, VPAP-1601,
Corrective Action, Revision 5, is the implementing procedure for the CAP
which is the responsibility-of Station Nuclear Safety (SNS).
In
addition to the above documents, the inspectors reviewed the following
procedures:
SEAP-004
VPAP-0104
VPAP-0212
VPAP-1501
VPAP-1801
VPAP-3002
Deviation Report Tracking and Trending*
NBU Management Station Self*Assessment Program
Human Performance Enhancement System
Deviation Reports
.
Program and Management Oversight of Quality
Operating Experience Program
Revision 2
Revision 1
Revision 4
Revision 6
Revision* 4
Revision 4
.
.
The inspectors reviewed Nuclear Oversight Corrective Action Audits 95-09
and 96-09 and the Nuclear Oversight quarterly report for the fourth
quarter of 1996. The inspectors_ noted that ineffective corrective
action was the most common finding .. Audit S96-24 addressed the
troubleshooting/repair of Waste Gas Decay Tank oxygen analyzers (1-GW-
AIT -150A/B) . . The audit had three fi nd1 ngs: ( 1) i nit i a 1 * engineering
failed to address the impact of the modification on other parts of the
. system; (2) a hit or miss approach to troubleshooting; and (3)
.
- * 15
ineffective ownership of the problem resolution. The.licensee concluded
that the latter two issues had been corrected, but resolution of the
problem was still open.
The inspectors do not agree that the latter two
issues had been corrected as evidenced by the licensee's efforts to*
troubleshoot the problems associated with the Auxiliary Venttlation .
System Filtered Exhaust Fan (Ol-VS-F-588) as described in Section Ml.1.
The number of DRs issued has steadily increased since 1991: from 1949 to
2822 in 1996 .. The licensee attributes this to their lowering the
threshold for writing DRs. * The inspectors compared the number of open
DRs at the end of. the fourth quarter to the number of DRs issued. for
that year and noted that percentage of DRs which remained open at the.
end of the year ranged from 4.4 percent in 1992 to 12.2 percent in 1995.
It should be.noted that during 1996 the licensee reduced this to 6.4
percent. However, open DRs are not a good indicator of corrective
action effectiveness as _they can be closed out prior*to all action being
complete.
DRs are closed out for many longstanding issues and are
tracked by other systems, sych as the Commitment Tracking System (CTS).
The inspectors reviewed a printout of *1995 and 1996 DRs classified a~
frequent.
Frequent as*defined in Section 4.14 of VPAP 1601, Corrective
Action, Revi.sion 5, is the same event or* component problem which has
occurred twice in the previous three years. This data also indicated
inconsistent corrective action effectiveness as indicated by the
following:
DRs Issued
Issues
1995
1996.
Unit 1 Compo.nent Cooling Heat Exchangers
32
9
P~50 Computer
9
24
Emergency Lighting Batteries
123
. 81
Radiation Monitors
17
7
Main Steam Governor Valve 2
12
7
Safety Injection Pumps
24
6
Unit 1 Service Water Pumps
10
8
Unit 2 Containment Spray Valve 97
3
5
It can be seen that only the Component Cooling Heat Exchangers and the
SI pumps showed a significant *improvement based on a full year of
historical data.
The *licensee recognized weaknesses in their* CAP and an EQRP to address
longstanding i,ssues was implemented duri.ng March 1996. Jhe purpose of
the EDRP is to focus IJ)an.agement attention to 1 ongstandi ng issues.
On
.,
16
March 25, 1996, 12 issues were i~cluded in the EDRP.
Eight.were
assigned to,Engi~eering and the balance to Maintenance.
The inspectors reviewed the EDRP and noted that over 50 percent of the
completion*dates have been extended since the EDRP was issued.
Emergency lighting issues were identified in the mid 80's and the latest
completion date is the end of 1997. Unit 1 Source Range Nuclear
Instrumentation issues were identified in March 1989 and the source
range cable replacement during the ongoing RFO will complete the
corrective actions. The inspectors noted that none of the 12 issues
. from the EDRP has been closed out and the completion of the Instrument
Module (Hagan racks) problems has been extended to 2002.
The Emergency Response Facility Computer System (ERFCS) issues were
identified in 1990 and res9lution is currentl.y scheduled for February
1998. A review of ERFCS problems in the site DR database, which was
imp 1 emented in 1990, revea 1 ed that 135 DRs have been issued and o.f these
91 were issued since 1995.
Fourteen DRs documented events that were
reportable to the NRC.
The inspectors consider that for ERFCS the
corrective actions were-not effective.
The weld leaks in the Unit 2 .let<;town hne piping were another example of
ineffective corrective action. There were four weld leaks on the Unit 2
1 etdown line piping between December 13, 1995 and September 11,. * 1996 .
On January 6, 1997, a fifth weld leak was identified in the Unit 2
letdown line pipi_ng. This event is described in detail in Inspection
Report Nos. 50-280, 281/96-13~
Each event had the same.causal factor.
c. Conclusions
The inspectors review of licensee.Oversight reports indicated that many
of the c;:urrent issues had been previously identifie.d. Discussions with
the 1 i censee indicated that s*evera 1 of the ERDP i terns wi 11 be comp 1 eted
during the current Unit 1 RFO.
The inspectors concluded that
implementation of corrective actions has been _inconsistent.
However,
they noted that the number *of DRs written has increased indicating that
problems are being identified.
IV. Plant Support
Rl
Radiological Protection and Chemistry CRP&C) Controls*
Rl.1 Failure to Obtain Grab Sample as Required
a.
Inspection Scope (71750)
The inspectors reviewed the circumstances surrounding a faiiure to
obtain grab samples as required by the ODCM .
I,,.
-*.
17
b: Observations and Findings
On January 28 at'9:08 a.m., the vent vent gaseous effluent monitor 1-VG-
RM-104 was declared out of service by operations.
VPAP-2103, ODCM,
Attachment 14, allows releases to continue via this pathway provided
grab samples are obtained at least once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. Operations
l')Oti.fied HP to commence sampling. At 12:00 a.m., on January 29, .it was
determined that the required grab sample had not been obtained. A g~ab
sample was immediately initiated and completed at 12:32 a.m.
The time
period specified by the ODCM for obtaining a grab sample had been
exceeded by 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> and 24 minutes. The sample results were
satisfactory.
The cause of the missed sample was miscommunication between* the count
room *personnel and the HP shift personnel. Corrective actions included:
(1) adding an item to the count room scheduler program to review *
inoperable rad monitors for TS compliance (2) purchasing a status board
for the count room (3) adding an item to .the HP~Ops scheduler prompting
a review of inoperable monitors and (4) adding_a section .to the count
room shift log *for indicating inoperable monitors. *The failure to meet
the requirements of VPAP 2103 is identified as a violation. This
licensee-identified and corrected violation is being treated as an NCV,
consistent with Section VII.B.1 of the NRC Enforcement Policy, and is
identified as NCV 50-280, 281/97002-05.
c. Conclusions
A NCV was identified for failure to obtafn a grab sample within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />
as required by t.he ODCM.
Rl.2 Occupational Radiation Exposure Control Program
a.
Inspection Scope (83750)
.
.
.
.
The inspectors reviewed implementation of selected elements of the
licensee's radiation protection program pertaining to control of
occupational radiation exposure.
The review included examination of
records and reports of individual personnel exposures and comparison of
those exposures to the occupational dose limits specified in Subpart C
to 10 CFR 20 and the licensee's procedurally established administrative
limits for personnel exposure.
b. Observations and Findings
The licensee provided the inspectors with current records and reports
from the Personnel Radiation Exposure Management System (PERMS) for the
year 1996.
The data presented in the table below were compiled by the
inspectors from the current data provided by the licensee and from
s i mil a r data contained . in previous inspect i 9n reports. *
18
Maximum Individual Radiation Doses (Rem)
,Year
Skfo
Extremity
Eye Lens
1995
2.817
3.674
3.674
2.850
1996
2.160
2.220
2.220
2.160
Regulatory and Administrative Limits
- 5.000
50.000.
50.000
15.000
Admin.
4.000
40.000
40.000
12.000
.
.
The above administrative annual dose limits established by the license
were delineated in procedure VPAP-2101, Radiation Protection Program,
Revision 11.
As indicated in the table, the. maximum individual
radiation exposures for *1995 and 1996 were well within the licensee's
administrative limits and the*regulatory limits specified in
c.
Conclusions
.
Based on the above reviews, the inspectors concluded that the licensee
was properly monitoring and controlling personnel radiation exposure i~
accordance with station :administrative procedures and 10 CFR.Part 20.
The maximum individual radiation exposures for 1996 were well within the
licensee's administrative limits and the regulatory limits specified in
. 10 CFR 20.1201(a) for occupational dos~.
Rl.3
ALARA Program
a.
Inspection Scope (83750)
The inspectors reviewed licensee records and reports of.annual and
outage collective dose and discussed ALARA program goals with the
licensee. The collective doses were compared to the licensee's
established ALARA goals.
b. Observations and Findings
The licensee.provided the inspectors with current records and reports of.
annual site collective dose and outage collective dose for the year
1996.
The data presented in the table below*were compiled py the
inspectors from the current data provided by the licensee and from
similar data contained in previous inspection reports.
..-
'.
Year
- 1994
1995
1996
19
Collective Dose (.per$on -rem)
Annual Dose
Outage Dose
Actual
Goal*
3 Year
Unlt *
Actual
Goal
Days
Mean
378
642
450
U- i1
233
312
64
U-22
29
20
22
U-12
29
22
28
403
460
390
U-21
- 158
164
47
U-13
197
191
34
214
2.09
332
U-23
155
164
35
1 10 ye*ar ISI and RFO, 2 SG cleaning, *3 RFD
As indicated in the table, the licensee was generally successful in
meeting established ALARA goals *for both annual and outage.collective
dose.
The 1996 ALARA goal for annual collective was slightly exceeded
due to an unexpected year-end outage for repair.of Unit 2 letdown
piping. However. the inspectors noted, from a review.of a licensee
provided listing* of annual collective dose for each year since the start
of power operations in 1973, that the annual collective dose for 1996
was the lowest ever achieved bJ the.licensee fqr *a fµll year of plant
operation. The above table also indicates generally decreasing trends
in the three year moving average for annual collective dose and in* the
collec~ive outage *dose.
The inspectors also* reviewed licensee records for Personal Contamination
Events (PCEs) and contaminated floor space*within the Radiologically
. Controlled Area (RCA).
The licensee's threshold fo'r a PCE was 100
counts per minute (cpm) above background as measured by a hand held
frisker. The. licensee's records indicated that there were 104 PCEs.
during 1996, which was approximately one half of the number of
occurrences during1994 and 1995, -i.e., 199 and 198 respectively. The
- inspectors noted that the licensee tracks temporarily contaminated.floor
space on a daily basis. Areas were included in the running total if *
they become contaminated during work activities and deleted after
reclamation. During 1996 the temporarily contaminated floor space
averaged 498 square feet (sq. ft.) during non-outage periods and 2400 *
sq. ft. during the May outage. Those values were 0.36 percent *and 1.75
percent of the total floor space within the RCA.
The total floor space
included the radwaste processing area but excluded the area within the
containment buildings. There were some contaminated areas within the
RCA which the licensee had no .immediate plans to reclaim. Those areas
included inaccessible locations in which radiation dose rates were high
- and not routinely entered, and other locations, such as the Decon Room
.,
'.
20
which remains potent i a 11 y contaminated due to the type a.f work performed
in that area. Those inaccessible and/or continually contaminated areas
amounted to 4275 sq. ft.,.or 3.1 percent of the total .RCA floor space.
During tours of the RCA the inspectors noted that general areas and
individual rooms.were properly posted for radiological conditions.
Posted survey maps were used to indicate dose rates and contamination
levels at specific.locations within rooms.
At the inspector's request,
a licensee HP staff member per.formed dose rate and contamination surveys
in several rooms and locations. The inspectors verified that the survey
instrument readings were consistent with the dose rates and
contamination levels recorded on the posted survey maps.
c. Conclusions
Based on the above reviews, the inspectors concluded that the licensee
was closely monitoring collective dose in order to meet ALARA goals and
was properly posting area radiological conditions.
'RB
Miscellaneous RP&C Issues (92904)
R8.l *cclosed) Unresolved Item (URI) 50-280, 281/96010-01: _failure to follow
radiation. protection procedures.
During the inspection conducted during
September 9-13, 1996, the inspectors reviewed the details of activities
associated with a Unit 2 containment entry made on August 17, 1996.
The
licensee had documented those details in DR 96-1771.
As indicated in
the DR, two workers (electricians) entered the Unit-2 containment
building, accompanied by a Health.Physics Shift Supervisor (HPSS), to
investigate.an *oil level alarm on a RCP motor.
The Radiation Work
Permit (RWP) used for that entry, standing* RWP 96-1-0012, required,- in
part, that the DADs be set to al arm when the ac*cumul ated dose reached
100 mrem and that all members of the entry team were to evacuate
containment upon receiving any DAD alarm. Standing RWP 96-1-0012 also
specified that a special RWP was required to be written for any task in
which an individual is expected to exceed 100 mrem per entry. Review.of
past radiation surveys should have caused the Health Physics Shift
Supervisor to write a special RWP.
Section 6.2.4.c of Health Physics
Procedure HP-1081.2, Radiation Work Permits: RWP. Briefing and
Controlling Work, required, in part, that if individual worker DAD dose
and dos*e rate alarm setpoints were to be used, then the desired alarm
settings were to be recorded on the RWP Briefing Attendance Roster and
that the alarm settings. were to be entered into the PERMS.
During the.
containment entry, the DADs worn by the two workers audibly alarmed, due.
to the accumulated dose having exceeded the dose alarm setpoint of 100
mrem, but the workers *were unable to hear their alarms because of the
high noise level. The HPSS was aware of those alarms but, contrary to
the RWP and procedural requirements, made an unauthorized decision to
remain in containment and continue the work.
The workers received doses
of 186 ahd 205 mrem during the entry. Following their exit from
containment, the HPSS uti 1 ized the "Revised DAD Al arm Setpoint" column .
of the RWP Briefing Attendance Roster to indicate that workers' DAD
alarm setpo,nts had*been set at 250 mrem when in fact they had not;
'I
'.
,
L
Pl
21
however, the HPSS subsequently informed the NRC that the work was
appropriately controlled to 250 mrem/hour despite the failure to exit
containment, reset the DAD, or initiate a special RWP.
The discrepancy
- between the PAD setpoints and the actual worker doses was noted by the
licensee*during a subsequent RWP review.
The procedural violations *tor
this event were : (1) failure to exit containment when the workers'
DADs alarmed; (2) failure to write a specfal RWP for expected doses in
excess of 100 mrem; and (3) failure to appropriately u~e the RWP
Briefing Roster to record DAD alarm setpoints. The licensee's
corrective actions. for this event included: (1) taking.disciplinary
action against the. HPSS; (2) briefing the Health Physics Operations
staff on the event; (3) a review of previous RWP non-compliance events
to ensure that a programmatic problem did not exist; and (4) issue a .
Training Information Bulletin to all s~ation personnel regarding**
"Procedural Compliance and Personal Accountability". The licensee was
informed by the inspectors that this issue was characterized as an URI
pending further review by NRC management.
Subsequent to that
inspection, NRC management determined that, although the licensee
identified and took.corrective*actions for these procedural violation,
those violations would be cited due to licensee supervision i.nvo l vement.
During this inspecti'on additional examples of procedural viola_tions were
identified. The inspectors reviewed details regarding six occurrences
of individuals entering the RCA without DADs.
Sections 6.8.4, 6.6.1.b,
and 6.8.7.f of Virginia Power Administrative Procedure VPAP-ZlOl,
Radiation Protection . .Progr?)m .. require, respectively, that a RWP is
required .for entry into or work in an RCA; workers shall wear _dosimetry
required by their RWP, and workers s~all comply with the RWP and ALARA
requirements, instructions, and precautions.
DRs for entering the RCA.
- without DADs as required by RWPs were written by the licensee for each
of.the six occurrences~* The dates of occurrence and DR numbers were*:
September 6, 1996/S-96-1957; September 13, 1996/S-96-2004; October 4, *
1996/S-96-2165; December 23, 1996/S-96-2773; January.10, 1997/S-97-0099;
and February*3, 1997/S-97"-0343.
As described in those DRs the
licensee's corrective actions generally consisted of disciplinary action
and/or counseling the individuals involved and di.scussion of the event
with _the individuals' departmental co-workers.
NRC manag~ment
determined that, although the licensee identified and took corrective
actions for these.additional examples of procedural violation, those
violations would be cited due to their frequency and repetition. The
. above procedural violations are identified *as VIO 50-280, 50-281/97002-
06, multiple*examples of failure to follow radiation protection
procedures.
Conduct of Emergency Preparedness CEP) Activities
Pl.1 Operational Status of the Emergency*Preparedness Program
a.
Inspection Scope (82701) .
The inspectors reviewed day-to-day routine operations and program
.
changes to assess the effectiveness of the licensee's implementation of
L,
J
22
their Emergency Plan in meeting regulatory. requirements of EP.
The*
following routine areas were reviewed:
changes to the Emergency Plan and implementing procedures
maintenance of select~d emergency facilities, equipment and
supplies
changes to t.he emergency organization or management control
systems
review of the independent audit report conducted since the last
inspection, and
~ffectiveness of licensee controls in the identification and
resolution of issues identified in the area of EP
The inspectors observed a training exercise*conducted during the
inspection week which exercised the staffing and functioning of the
Technical Support Center (TSC) and Operational Support _Center (OSC).
while also meeting the requir~lilents for a semi-annual radiological
mqnitoring drill.
- . * * *
.
b. Observations and Findings
One revision to the. Emergency Plan had been submitted since the NRC had
documented the previous review.
The revision of the Emergency Plan
currently in effect was Revision 41, effective December 17, 1996. The
- inspector reviewed the revision and found the changes to be primarily
administrative in nature. The inspe~tors were informed that no
emergency declarations with *the concomitant implementation of the
Emergency Plan had occurred since the last inspection.
The inspectors observed that the equipment and supplies that supported
the TSC and OSC during the training exercise wer~ functional and
adequate for the facilities .
. Organizational changes *made since the *last -inspection focused on the
centralizatio~ of EP responsibilities with the Director of Nuclear
Emergency Preparedness in Innsbrook, VA.
The position for Station
Coordinator Emergency Preparedness now has responsibilities for both
North Anna and Surry Power Stations. The inspector did not observe*any
- degradation. in the program as a :e~ul t of the organi zat i ona l change~.
The inspectors reviewed Nuclear Oversight Emergency Plan Audit Report
96-03 dated May 16, 1996.
The audit was performed using both
performance and compliance based techniques, and the inspectors found it
was thorough and met *regulatory .requirements. The audit team spent a
week at the Surry facility and an identified issue was promptly
corrected.
,
(.*
23
The inspectors selected the failed December 16, 1996, off-hours call-out
drill as a means to evaluate the effectiveness of licensee controls in
the identification and resolution of EP issues. Licensee evaluation
focused on the failure of the Emergency Response Organization Automatic
Notification System (EROANS) to function as expected, and another test
was run two days later and was successful. The licensee's corrective
actions for the deficient system were satisfactory although the
inspectors noted s~veral items where additional follow-up could be
useful~ These items were: (1).the security manual call-outs for
selected minimum staffing positions did not result in those positions
being fi 11 ed: * (2) one person had been twice contacted by the Corporate
EROANS but had twice failed to properly. acknowledge: .and (3) were
sufficient personnel trained for the Field Team Radio Oper~tor minimum
staffing position?--the test resulted in one individual responding not
fit for duty and the other not being at home--th~ position remained *
unfilled. The licensee acknowledged these observations and indicated
additional follow-up would occur and corrective action would be taken as
necessary.
The inspectors also*used the personnel call-out list for
this drill as the random selection of names to. verify the status of
training for the emergency response organization. All personn~l were
'.ound to be current for traini_ng.requirements.*
The inspec;tor*s noted that the training exercise was e*ffective for
meeting the intended goals and the licensee-was proactive in identifying
and recommending corrective. actions for issues identified in the OSC.
c. Conclusions
The inspectors found the EP program to be maintained in a manner that
supported good emergency response in the event qf an accident.
Sl
Conduct of Security and Safeguards Activities (71750)
On numerous occasions during the inspection period,.tne inspectors
- performed walkdowns of the protected area perimeter to assess security
and general barrier conditions.
No deficiencies were noted, and the
inspectors concluded that security posts were properly manned and that
the perimeter barrier's material condition was properly maintained.
V. Management Meetings
Xl
Exit Meeting SUD1Dary
The inspectors presented the inspection results to members of licensee
management at the conclusion*of the inspection on March 17 and April 7, 1997.
1he licensee acknowledged the findings presented.
The inspectors asked the licensee whether any materials examined during the
inspection should be considered proprietary.
No proprietary information was
- identified.
.
.
. *
.. !
24
PARTIAL LIST OF PERSONS CONTACTED
Licensee
R. Blount, Superintendent, Maintenance
D. Christian, Station Manager
M. Crist, Superintendent, Operations*
J. McCarthy, Assistant Station Manager, Operations & Maintenance
B. Shriver, Assistqnt Station Manager, Nuclear Safety & Licensing
T. Sowers, Superintendent, Engineering
B. Stanley, Director, Nu~lear Oversight*
J. Swientoniewski, -Supervisor, Station Nuclear Safety
W. Thorton, Superintendent, Radiological Protection
NRC
G. Belisle, Chief, Reactor Projects Branch 5, Division of Reactor Projects,
Region II
IP 37551:
IP 40500:
IP 61726:
IP 62707:
IP 71707:
IP 71750:
IP 82701:
IP 83750:
IP. 92700:
IP 92720:
IP 92902:
IP 92904:
Opened
INSPECTION PROCEDURES USED
Onsite Engineering
.
.
Effectiveness of Licensee Controls in Identifying, Resolving, and.
Pre venting Prob 1 ems *
.Surveillance Observation
. Maintenance Observation
Plant Operations
Plant Support Activities
.
- Operati ona 1. Status of the Emergency* Preparednes.s Program
Occupational Radiation. Exposure_
Onsite Followup of Written Reports of Nonroutine Events at Power
Reactor Facilities
Corrective Action
Followup * Maintenance
Followup * Plant Support
ITEMS OPENED, CLOSED, AND DISCUSSED
50-280, 281/97002-01
IFI
Long term corrective actions to*resolve ..
potential TDAFW. pump overspeed trips (Section
50-280, 281/97002-02
01.3).
.
Failure to maintain two trains of the Auxiliary*
Ventil.ation System operable as required by TS
(Section Ml.1) .
.,
. 50-280, 281/97002-03
50:280, 281/97002-04
50-280, 281/97002-05
50-280, 281/97002-06
Closed
25
vro*
Procedures not appropriate to the circumstances
(Section Ml..1).
Failure to meet the requirements of 10 CFR .
50.9(a) For LER 50-280, 281/97002-00 (Section
M8.l).
Failure to obtain grab sample as required by the
ODCM (Section Rl.1).
.
.
Multiple examples of failure to follow radiation
protection proce~ures (Section R8.1).
50-280, 281/97002-02.
Failure to mainta,n two trains of the Auxiliary
Ventilation System operable as required by,TS
(Section Ml.1).
50-280/94001-00
LER
Welding on pressurizer results jn hydrogen'burn
in pre.ssurize'r (Section M8.2).
50-280, 281/97002-05
Nev*
Failure to obtain grab sample as required by the
50~280, 281/96010~01
Discussed
50-280, 281/97002~00
ODCM (Section Rl.1).
URI * Failure. to follow radiation protection
procedures (Section R8.1).
LER
One train of *auxiliary ventilation system
inoperable outside of technical specifications
(Section M8 .1) .
- *