ML20056A910
| ML20056A910 | |
| Person / Time | |
|---|---|
| Site: | Brunswick  |
| Issue date: | 07/17/1990 |
| From: | Dance H, Prevatte R NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20056A908 | List: |
| References | |
| 50-324-90-19, 50-325-90-19, NUDOCS 9008100061 | |
| Download: ML20056A910 (18) | |
See also: IR 05000324/1990019
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REGION il
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NUCLEAR REGULATORY COMMIS$10N
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101 MARIETTA STREET.N.W.
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AT L ANT A, CEoROl A 30323
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. Report Nos.:
50-325/90-19 and 50-324/90-19
Licensee:
Carolina Power and Light Company
P. O. Box 1551
Raleigh, NC 27602
Docket Nos.:
50-325 and 50-324
License Nos.: DPR-71 and DPR-62
Facility Name: Brunswick 1 and 2
-Inspr.ction Conducted: June 1 - 30, l',90
Lead Inspector:
Id d
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M/7/fC
'R
L. Prevatte
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Dafte 5fgned
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Other Inspectors:
W. Levis
D. J. Nelson
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Approved By:-
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H..C. Dance, Section Chief
Dath Sfgned
Reactor Projects Branch 1
Division of Reactor Projects
SUMMARY
Scope:
This routine safety inspection by the resident inspectors involved the areas of
maintenance observation,c surveillance observation, operational safety verifica-
-tion, licensee self-assessment capability, Licensea Operator Requalification
Program and Operational Evaluations, onsite Licensee Event Reports review, and
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action on previous inspection findings.
Results:
In the' areas inspected, one violation was identified - failure to establish an
adequate procedure for locci operation of reactor feed pumps, (paragraph 4.c).
. Two non-cited- violations were identified. The first was one violation with two
examples of failure to follow procedure.
The two examples involved personnel
errors associated with surveillance tests, (paragraphs 7.a and b). The second
.non-cited. violation involved the qualifications of alternate Plant Nuclear
SafetyCommitteemembers,(paragraph 5).
Units 1 and 2 were restarted after two of three operating crews successfully
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passed Operational Evaluations. An inspector followup item was opened to track
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the ' licensee's corrective actions resulting from the Licensed Operator
Requalification Program analysis. (paragraph 6),
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A strength was noted in the licensee's calibration program as a result of
followup to.-the failure of the 2A Nuclear Service Water Pump to start on loss
ofpowerto'busE3,(paragraph 2),
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The: licensee's self-assessment capability was evaluated.
Some individual-
strengths and recent improvements were noted.
The licensee still failed to
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properly identify major issues;, (paragraph 5).
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A weakness was noted in contro' room' operators' monitoring of Reactor
Protection System parameters during startup. Two conditions involving Average
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Power Range Monitors had existed foi approximately 1 1/2 hours without the-
operations staff's< knowledge, (paragraph 4.a).
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REPORT DETAILS
1.
Persons Contacted
Licensee Employees
- K. Altman, Manager - Regulatory Complianca
F. Blackmon, Manager - Operations
- 5. Callis, On-Site Licensing Engineer
T. Cantebury, Manager - Unit 1 Mechanical Maintenance
- G. Cheatham, Manager - Environmental & Radiation Control
M. Ciemnicki, Security
R. Creech, Manager - Unit 2 1&C Mainten:nce
J. Cribb, Manager - Quality Control (' .
- F. Dumas, On-Site Nuclear Safety Engineer
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V. Grouse, Employee Relations
J. Harness, General Manager - Brunswick Steam Electric Plant
- W. Hatcher, Supervisor - Security
- A. Hegler, Supervisor - Radwaste/ Fire Protection
- R. Helme, Manager - Technical Support
J. Holder, Manager - Outage Management & Modifications (OM&M)
L. Jones, Manager - Procurement
M. Jones, Manager - Cn-Site Nuclear Safety - BSEP
R. Kitchen, Manager - Unit 2 Mechanical Maintenance
J. Leviner, Manager - Engineering Projects
- L. Martin, Interim Manager - Training
J. McKee, Manager - QA
- J. Moyer, Technical Assistant to Plant General Manager
- B. Poteat, Administrative Assistant to Plant General Manager
R. Poulk, Manager - License Training
W. Sinpson, Maneger - Site Planning and Control
S. 3mith, Managc
- Unit 1 I&C Maintenance
- R. Starkey, Vice President - Brunswick Nuclear Project
J. Titrington, Manager - Operations
- R. Warden, Manager - Maintenance
J. Whitehead, Principai QA Specialist - Corporate Quality Assurance (CQA)
B. Wilson, Manager - Nuclear Systems Engineering
Other licensee empioyees contacted *ncluded construction craftsmen,
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engineers, technicians, operators, office personnel, and security force
members.
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- Attended the exit interview
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Acronyms and initialisms used in the report are listed in the last
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paragraph.
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2.
Maintenance Observation (62703)
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The inspectors observed maintenance activities, interviewed personnel, and
reviewed records to verify that work was conducted in accordance with
approved procedures, Technical Specifications, and applicable industry
codes and standards. The inspectors also verified that:
redundant
,
components were operable; administrative controls were followed; tagouts
were adequate; personnel were qualified; correct replacement parts were
used; radiological controls were proper; fire protection was adequate;
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quality control hold points were adequate and observed; adequate
post-maintenance testing was performed; and independent verification
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requirements were implemented. The inspectors independently verified that
selected equipment was properly returned to service.
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Outstanding work requests were reviewed to ensure that the licensee gave
priority to safety-related maintenance.
The inspectors observed / reviewed
portions of the following maintenance activities:
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90-UHW252
Inspect 2A Conventional Service Water Pump, Motor,
Discharge Valves, and Strainer
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Numerous
Re-calibration of Instantaneous Overcurrent Trip
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Relays on Emergency Switchgear
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During the loss of normal power to teus E3 event of May 30, 1990, the 2A
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NSW pump failed to start as designed.
The instantaneous overcurrent trip
relay (50 device) on one phase was found to be tripped, indicating a
potential overcurrent condition existed when the pump motor attempted to
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start.
Instantaneous overcurrent trip relays and time overcurrent trip
relays are employed in the power circuits of large electrical motors to
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protect circuits from high current conditions.
The licensee's initial
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investigation revealed that the above relay had a history of drifting
setpoints.
A recalibration af ter the event found the setpoint to be low,
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but within the acceptable setpoint range.
The investigation concluded
that the in-ruso current experienced by the pump motor was high enough on
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this particular start attempt to cause the "drif ting" relay to actuate too
conservatively and trip the circuit.
The relay was replaced.
The
licensee stated that neither the 2A NSW pump nor other emergency bus
loads had previously experienced unnecessary 50 device trips.
Addi tion-
ally, the eighteen monto surveillance that starts all emergency loads on
the EDGs had not revealed relay problems.
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Further investigation by
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'icensee concurrent with questioning by the
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inspector called into questloa the method used to calibrate other 50
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device relays.
The licensee determinea that vagueness in the calibration
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procedure misled the technicians in determining the correct trip setpoint.
An alternate calibration method showed the suspect relay to be several
amps low, approximately 16 amps vs. required 19 to 21 amps, resulting in
an excessively conservative setpoint.
Using the new calibration method,
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the licensee performed a calibration check of the remai ing 117 50 device
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relays in buth units while the units were shutdown.
All were determined
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to be within the calibration range.
This caused the licensee to refocus
on the particular. relay that had tripped, since the calibration method now
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appeared to be. immaterial.
The cause of the problem was determined to be
a pair of-contacts that were out of adjustment.
In addition to the changes already made to the calibration procedure, the
- procedure will also be modified to reflect' the adjustment of the relay's'
contacts if necessary.
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' Recognizing the- potential generic impact, the licensee demonstrated the
appropriate safety sensitivity by deciding to check all instantaneous
overcurrent reicys on safety equipment in botn units.
All 117' remaining
-relays- were found to be within t' e calioration range.
Based-on these
results,cthe: licensee's calibration program appears to be effective.
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Vio'<ations and deviations were not identified.
3.
Curveillance Observation (61726)
The inspectors observed surveillance testing required by Technical
Specifications.
Through observation, interviews, and record review, the
inspectors verified ^ that:
tests conformed to Technical Specification
-requirements; administrative controls were followed; personnel were
qualified; instrumentation was calibrated; and ' data was accurate and
complete. The inspectors independently verified selected test results and
proper return to service of equipment.
The inspectors witnessed / reviewed portions of the following test
activities:
1 MST-HPCl27M HPCI and RCIC CST Low Water Level Instrument Channel
Calibration
1 MST-RCIC15M RCIC Steam Leak Detector Channel Functional' Test
1 MST-RPS11W
Main Steam Line High Radiation Channel Functional Test
Violations and deviations ~were not identified.
- 4.
Operational Safety Verification (71707)
The inspectors verified that Unit 1 and Unit 2 were operated in compliance
with Technical Specifications and other regulatory requirements by direct
observations of activities, facility tours, discussions with personnel,
reviewing of records, and independent verification cf safety system status.
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1The inspectors verified that control room manning requirements of
- 10 CFRL50.5.' and the Technical Specifications were met. Control operator,
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~ ' shift cupervisor, clearance, STA, daily and standing instructions, and
jumper / bypass logs were reviewed to obtain information concerning operat-
'ing trends and out of service safety systems to ensure that there were no
-conflicts with Technicel Specification Limiting Conditions for Operations.
-Oirect observations of control room parais and instrumentation and
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recorder traces important to safety were conducted to verify operability
and that operating parameters were within Technical Specification : limits.
The inspectors observed shift turnovers to verify that syst_em status
continuity was maintained. The inspectors verified the status of selected
control-room annunciators.
Operability of a selected Engineered Safety Feature division was-verified
weekly by: nnsuring that:
each accessible valve in the, flow- path was -in
its corrcci position; each power supply -and . breaker was closed for
component.s that must activate upon initiation signal; the RHR subsystem
cross-tie valve for each unit was closed with the power removed from the
valve operatcet there was no leakage of major componen"
'here was proper
lubrication and ccoling water available; and condi
id not exist
which could p event 1elfillment of the system's funct _.. ; "equirements.
Instrumentaticn essenthl to system actuation or performance was verified'
operable by obsarving o'i-scale indication. and . proper instrument valve
. lineup, if.accessibic.
LThe, inspectors
verified
that the licensee's health physics
policies / procedures were followed.
This included observation of HP
practices and a review of area surveys, radiation work permits, postings,
and instrument calibration.
The inspectors verified 'by general observations that:
the- security
organization was properly' manned and security personnel were capable of
performing their assigned functions; . persons :and packages were checked
prior to< entry into the protected area;- vehicles were properly authorized,
. searched-and escorted-within the PA; persons within the PA displayed photo
identification badges; personnel in vital' areas were authorized; effective
compensatory measures were employed when required; 'and security's response
to threats or alarms was adequate.
The insper. tors also observed plant housekeeping controls, verified
position of certain containment isolation valves, checked clearances, and
, verified the operability of onsite and offsite emergency power sources,
a;
APRM GAFs
While observing Unit 1 power ascension activities on June 13, 1990,
the inspector observed that the six APRMs were indicating reactor
power levels ranging from 25 percent to 40 percent.
The plant
process computer, located in the control-room, indicated reactor core
thermal power was 34 percent as measured -by heat balance.
readings, printed at the computer terminal, indicated that reactor
power was 23 percent to 38 percent.
Five of-the six APRMs had GAFs
indicating greater than 1.0.
During normal operation, the GAFs
should be less than or equal to 1, so that reactor power as measured
by the APRMs is greater than or equal to actual core thermal power as
determined L by heat balance.
The inspector informed the nuclear
engineer, who was present in the control room, of this condition.
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The nuclear engineer then took immediate steps to correct th'e APRM
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readings.
The inspector questioned the licensee on why this condition had not
been identified and corrected by the operators. The licensee. stated
that the operators observe APRMs for. trends and: general agreement' and -
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that actual- power -is determined by a heat balance. performed by the
process computer which is monitored by-the operators. The operators-
stated that the APRMs were trending properly and that -general
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. agreement existed between the channels.
The . inspector ~did not agree-
with the-licensee on this point. The operators must'be sensitive to
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- all indications of reactor power ^ during startup. The APRMs are used
by the RPS to initiate protective = action and - are, therefore,
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important to plant' safety.
A questioning _ attitude of the chart l
tecorder APRM readings and a review of - the process computer -
'information, which showed that APRM GAFs were out of their _ tolerance
for an hour and a half prior to the inspector observing the
condition, would have detected the discrepancy.
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The inspector reviewed Technical Specificaticas regarding the.
requirements to check the APRM GAFs and the licensee's implementi_ng
procedures.
'The licensee's PT-1.11, Core- Performance -Parameter
Check, Revision 26, is used to check the APRM GAFs. The procedure is
also used to verify that the thermal limits in Section 3/4.2 of the
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Technical Specifications are within limits. The licensee stated that-
the procedure was performed within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> following'an increase in
power to 25 percent CTP..
Table 4.3.1-1 lists- the surveillance requirements for the Reactor
Protection -System instrumentation.
Note (e) of this table states
that _ APRMs are to be adjusted to conform to power _ values calculated
by heat ~ balance:when thermal: power is greater than.or equal to 25-
percent CTP.- The applicability statement for the power distribution
- limits in Section 3/4.2 states that the limits are applicable-
whenever thermal power is greater than or equal to 25 percent:CTP.
Specification 3.0.4 is not listed as being not. applicable.for these
specifications.
The inspector stated that the APRM GAFs and the
thermal limits should be checked _ prior _ to exceeding' 25 percent CTP,
vice waiting 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> to check these values.
The licensee.did not
agree with -the inspector's interpretation of . these Technical
Specifications.
They agreed that it was good practice to check the -
GAFs and had, in fact, done so at 6:34 a.m. that morning, at which
time the appropriate number of channels were within specification.
The . licensee 'further stated that the process computer does not
provide good information regarding thermal limits.at low power levels
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and that the additional' time to perform the surveilh.nce allows for
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sufficient time to increase power and obtain meaningful information.
The inspector reviewed tne Technical Specificatica requirements and
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Ethe licensee's- interpr 1tation with both regional and headquarters
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personnel.
The NRR reviewer stated that the licensee's actions for
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checking their thermal limits and APRM GAFs within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after
exceeding 25 percent CTP, was technically correct. .In fact,.the new
stndard Technical Specifications ' allow 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and- 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> -to
check thermal limits and APRM GAFs, respectively, after exceeding
this- power level;
The inspector reported this information to the
licensee who then agreed to check these items before exceeding 25
percent CTP'during future startups.
The. licensee is evaluating lthe
need to submit a Technical Specification change to redefine these
, checks.
Since the licensee took action to correct a technicality problem with
their Technical Specifications and they met the intent of Technical
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~Specificationc for performing these surveillances, no further action
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'will be taken.
The underlying issue that the operations staff was
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unaware of (i.e., the disparity between reactor power ~
mdicated by '
the nuclear instruments and calculated by heat balanc( u
discussed.
in detail with the licensee.
The inspector stressed .W
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of the operators continuously monitoring all indicationi
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and -correcting any discrepant conditions.
Licensee management
acknowledged the inspectors consnents,
b.
APRM, Testing / Maintenance
On June 27, 1990, the inspector observed that APRM C.was bypassed on.
Unit 1.
A review of-the SF log showed that APRM A was inoperable due
to corrective maintenance activities on the power and flow poten'io-
meters for these channels.. Technical Specification3.3.1 requires
that-at least 2 lof 3 APRMs be operable per trip system.
If these
requirements are not satisfied, the trip system is to be placed in
the tripped condition within one hour.
Note (a) of Table 3.3.1-1
states that the' channel may be placed in an inoperable status for up
to 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> for required surveillance without placing the trip system
in the tripped-condition provided that at least one operable channel
in the same trip system is operable.. APRM C was' bypassed at-11:28
a.m. for performance of 1 MST-APRM11W for that channel.
No testing
was.bO ng performed.
The; condition was noted by the inspector at
approximately 12:50 p.m. and the APRM returned to operability:at 1:00
p.m.
From the aspect of Technical Specifications, no violation occurred.
. since the APRM was returned to operability within the two hour time
period.
In addition, although listed in the SF log as iroperable,
APRM A had its required maintenance complete and was awaiting
closeout of rework to declare it operable.
However, this event
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displays W6 weaknesses.
The maintenance personnel had received
' explicit
wuctions not to proceed with testing on APRM C until all
work, in. ludine ;cperwork closeout, was complete on APRM. A.
The
involve . techr cians had realized their mistake shortly after APRM C
was take N aypass and had stopped-their MST to finish the paperwork
on APRM A.
They had forgotten, however, to inform the operators of
this and, therefore, did not have operations place APRM C back to
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operate.
The-inspector also noted that the operationsJstaff_did not;
notice or question the fact that APRM C was in-bypass with no testing-
being performed and APRM A still' listed -as inoperable.
These.
. eaknesses were discussed with licensee management who acknowledged
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the inspector'.s comments,
c.
2A Reactor Feed Pump Speed Control Problems.
The inspector reviewed PIR 90-024, dated June 6,- 1990, which de-
scribed the event and circumstances regarding 2A reactor feed pump
-speed control problems and the subsequent recirculation pump runback
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reported in. Inspection Report 90-14, dated May 7, 1990. The incident
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report concluded that the event was caused by a ' failure of the
operations staff to recognize the complexity of manually removing the
feed pump from service and to either properly preplan it or prepare:
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instructions for it.
2-0P-32, Condensate and Feedwater System-
Operating Procedure, Revision 57, provides no instructions to the :
operators on- how to perform this evolution.
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The failure to adequately preplan or provide written instrucCons for
this evolution resulted in the feed pump recirculation val,e auto-
matica11y opening on low flow and a subsequent vessel-' level
perturbation followed by a runback of both recirculation. pumps due to
thellow feed flow and low level conditions. This runback is designed
'to- reduce reactor power sufficiently so that it is within the
capacity of: a single' feed pump. The setpoint is 45 percent core flow
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or 35 MLB/hr. which is just above the upper limit of flow' instability
region C, as shown in figure 02-2 'of 0P-02, Reactor Recirculating
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System,' Revision 68.
The reactor ' operator, who noted the decreasing-
water level, intervened at this time and further: decreastd
recirculation flow -and power level to aid in level recovery. . This
action reduced core flow to 32 fLB/hr. which placed the unit in- flow
instability region C.
This: condition existed for approximately 11
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minutes until the plant monitor noted that core flow was in the -
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instability region. At that time, the appropriate actions were taken
to exit the regio. .. Section 8.3 of OP-02, which implements ' the
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requirements -of Bulletin 88-07, does not permit operation-in this
area and requires that the _ operator immediately exit the area by
inserting control rods or increasing recirculation flow.
A manual
scram:is also required if any instabilities are noted.
The 505 believed that the evolution of manually removing a feedpump
from service was within the " skill of' the craft", ed that no specif-
ic procedure was required.
Section 4.0 of 01-O' . Operating
Principles and Philosophy, Revision 32, requires that all plant
evolutions, except simple evolutions, be conducted in accordance with
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. approved plant- procedures.
If a procedure does not exist, the plant
is to be placed in a safe condition until the apprrpriate procedures
can-bo developed and approved.
Simple evolutions include such things
as changing chart paper or blowing down air receivers.
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'to perfe m this evolution in accordance with approved procedures is a
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violation.of Technical Specification 6.8.1.a and is identified as a-
Violation: .
Lack of Procedure for Local Feed Pump Operation,
(324/90-19-01).-
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One violation was identified.
5.-
Evaluation of Licensee Self Assessment (40500)
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The inspectors. reviewed the activities of the licensee's various oversight-
groups including CNS, ONS,-QAAU and PNSC.
The Technical Specification
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requirements of-these organi?ations were reviewed along with documentation-
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detailing the results V the1r reviews.
Key personnel from each of the
groups were interviewed.- The inspector also attended two PNSC meetings.
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-The following review results are provided for each of the organizations.
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QAAU
Technical Specification 6.5.5 establishes the time perio'd .and specific-
audits that must be performed by this group.
The inspector reviewed
several of these audits induding the ALARA audit dated June 29, 1990,
E&RC audit dated May 14, U90, EDS audit dated March 30,1990, Fire
Protection audit dated December 29, 1989, Operations audit dated September
18, 1989, NED audit dated September 7, 1989,-and Maintenance audit dated
August 7, 1989. The inspector concluded.that these audits, especially the
recent ALARA and the EDS audits, were performance based and indicative of
a knowledgeable and aggressive audit team. The-inspector also noted that
th.ese.recent audits were willing to make broad based conclusions regarding
the nature of their findings. This is-an improvement from previous audits
which -tended to only list. individual findings.
The inspector questioned the process for closing out previous' findings and
the method of accepting the plant's proposed, corrective action for the
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findings.
It was not-clear to the inspector that the group had ownership
of the identified problems, including their closeout, especially in the
case of the EDS audit.
This question was discussed with the^ manager of
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the auditing group, who stated that this particular case was unique
because of the number and complexity of the issues involved, ~but that
periodic followup, including review of the plants quarterly update, would;
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be performed 'to determine the adequacy of the plant's response.
Inspec-
tion' items are tracked, trended and verified to be implemented prior to
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' closeout.
These particular areas will be examined more closely in future
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inspections.
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ONS responsibilities are described in Section 6.2.3 of the Technical
Specifications. They serve to review outside experience feedback reports,
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'~ perform surveillances of facility activities and make recommendations, as
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a)propriate, to the manager of CNS on methods to improve facility safety.
~ Tie inspector found supporting examples of Technical Specification re-
quirements being met.
Twenty-four hour coverage of the Unit 2 startup
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following refueling, assessment of the Unit 2 loss of offsite power event,
standardization of performance. indicators, and problems noted in the Unit
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2tSAT motor operated disconnect coupling / uncoupling- latch are a 'few
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examples of ONS initiatives.
Open items are generated when necessary and
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tracked to completion.
Another item noted by the inspectors which does
not ' appear to be in.the 0NS charter but which the inspector felt was.
useful, was the' report prepared for the plants project review meeting..
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This report provides a summation to the plant of all ONS activities, rates.
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weak areas of performance, and identifies adverse trends.
'
CNS activities are ' described in Technical Specification 6.5.4.
They.
provide an independent review of various site activities to detect = trends
,
and ensure that discrepancies described in reportable- events are properly
,
investigated and corrected.
The inspector reviewed the bimonthly reports
,
for the last year that are a summation of CNS recommendations and
. concerns. The following observation; were made regarding these reports:
Only 1. high. priority recommendation resulted from a CNS review of
Technical-Specification 6.5.4.9 documents.
CNS was not always aggressive in resolving high priority items.
{
The excessive backlog of review items reduces the quality of reviews.
The majority of the recommendations resulted from-ONS generated items. No-
',
special investigations-resulted from the reviews. Approximately 190' items
madei up- the review backlog at the end of April.
The trend for.1990'
indicated that the- backlog. would increase.
Inspection . Report
50-400/90-08, dated June 1, 1990,calso noted-these same conditions for the
't
Harris Plant.
A contributing factor to this situation may be that only
four. people perform these r.eviews for all three sites.
These same people
are also used to participate in special investigations which further taxes
their. resources.
The 'CNS made some .recent improvements to resolve their concerns and
recomendations.
Iteins are now prioritized and -placed in the plant's
' FACTS systems.- The priority is reviewed by CNS personnel and appropriate
discussion held with plant personnel to ensure that the issue is
understood and the assigned priority is correct.
The inspector reviewed
'
documentation that verified- that recent ' actions in this area have-
occurred.
PNSC
PNSC activities are described in Technical Specification 6.5.3. - They
function to provide a means for regular review and evaluation of plant
,
activities. The inspector reviewed PNSC meeting minutes for. the last year
I
to determine if the appropriate frequency and quorum requirements were met
and to evaluate the effectiveness of their reviews.
The inspector
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concluded that. PNSC met, as ' required, and that quorum requirements were
, satisfied.
The inspector did note that members of the administrative
staff had served as alternate members of PNSC in the past. ._ Technical Specification 6.5.3.5 requires that alternate members be qualified in
~
accordence with Section 4.4 of ANSI N18.1-1971.
This standard requires
7
academic training and experience in some technical discipline.
The
inspector reviewed the ineeting minutes in detail for those cases in which
'
an administrative staff member served as an alternate.
The inspector
4
concluded that this member did not affect any technical- discussion- nor did
their: vote -. affect the outcome of any issue.
The failure to have the
a
alternate properly qualified is a violation of Technical Specification.
16.5.3.5.
This is a Violation:
Inadequate Qualification- of Alternate
Plant Nuclear Safety. Committee Members, (325/90-19-02 and 324/90-19-02).
However, based on the safety significance = and the fact that corrective
action is- in progress to correct the situation, this NRC identified
violation is not being cited-beause criteria specified in Section V.A of
the NRC Enforcement Policy were satisfied.
The inspector also attended two PN5C meetings. The first was the normal
monthly meeting.
There was very little discussion during the meeting
since items for review had been reviewed ahead of time wi".h the comments
resolved.- _The second ' meeting reviewed two items that aad not been-
previously reviewed.
There was much more discussion-on these issues and
the acting chairman effectively focused the group's discussion on plant
safety.
When the issue was brought to a vote, one dissenting vote was
cast.- The inspector;had noted that very few dissenting votes had been.
. recorded in the past.
When questioned about this point following the
meeting
the tacting chairman stated that concerns / disagreements are
usually- resolved before an issue -is brougnt to a vote, but' that much
discussion occurs during their normal' review process. The inspect'or will
look atithis aspect in greater detail in future inspections.
PLANT
The licensee has taken several other initiatives to monitor overall plant
performance.
The Plant Performance Indicator Book is.a compilation of
. performance indicators of both a hardware and-sof tware nature that allows-
the' PGM to monitor plant performance and to focus resources as necessary.
Some -of the specific improvements that have resulted from monitoring
. performance indicators are the reduction of lit- annunciators, less
. inoperable control board instruments, and improved safety system
availability.
' CORRECTIVE ACTION
The inspector reviewed the licensee's corrective action program. The DET
had previously identified that the corrective action program lacked
provisions for effective problem identification and root cause determina-
-tfon; Additionally,-the DET determined that more management attention was
~ needed to implement an effective corrective action program with a lower
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threshold for problem identification.
Accordingly, the licensee's_IAP
-items D9 and 010, Corrective Action Program, address thase concerns.
'
The licensee stated that interim _ improvements have been man.
Specific-
,
ally.. Plant Program Procedure PLP-04, Corrective Action . Program, has been
<
revised to: incorporate guidance for performing Human Performance Evalua -
.
tion- System (HPES) evaluations on_ events involving ~ personnel error, on
addressing operability concerns, and _ to lower the threshold for perform -
ance: of = root cause determination.
Regulatory Compliance Instruction.
RCI-6.7, HPES Evaluations, has been issued to_ provide for HPES. evalua-
-
.tions.
Administrative Instruction AI-65, Incident Reporting and Control,
was revised in April,1990, to provide = a mechanism for individual plant
workers to formally identify unusual: plant occurrences or events.
A-
licensee - review of > AI-65 - Plant Event Identification Reports, submitted
since the rmston, -indicates that progress is being made in problem
identificction. ' The--inspector reviewed all completed Al-65 reports made
since the revision (approximately thirty) and concluded that, while some
lower threshold problems have been identified, more time is required to-
assess the success of the improvements.
4
The licensee's corporate wide corrective action program has not been fully
implemented.
Completion is anticipated by the end of 1990, in accordance
with IAP item D10.
Based on ' the review of -the various oversight groups, the inspector
concluded that t_he . required Technical Specification reviews were being
performed.
Some weaknesses were noted in CNS review activities.along with'
the closecut of high priority items.
The. inspector did note, however,
that although each group is contributing and providing useful, comments and
recomendations, the summation or overall conclusions were lacking.
Of
the -.seven major weaknesses characterized by the licensee in a;recent
commissioner presentation, none had been identified by the licensee.
Some
were :self-evident, while others were identified by other outside.
organizations.
The licensee has recognized tiis weakness and formed a
Project Quality Team to evaluate their self-assessment capabilities.
This
group is finalizing their findings and recomendations. This is IAP item
1
E5 and will be inspected further during future IAP inspections.
One non-cited violation was identified.
1
6.
Confirmation of Action:
Licensed Operator Requalification (92703)
'
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. At the beginning of the reporting period, both Brunswick units remained
~ hut' down under a Confirmation of Action Letter from Region II to_ the
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licensee dated May 21, 1990.
On Juria 10,1990, the Regional Administrator granted CP&L approval to-
restart both firunswick units.
The approval came after two out of three
.
,
1
crews successfully passed NRC administered simulator examinations which
were given on Junc 9 and 10.-
Having demonstrated to the NRC that both
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' " units could be safely operated with four shifts (now composed of the two
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-crews which recently passed and two othe*s which -passed NRC administered -
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examinations .in May), Unit 2 and. Unit I were restarted on June 10 and 11,
(
respectively.-
,.
As committed, CP&L provided NRC (an June 14) their plan to qualify a fifth
operating shift crew.
In suninary, the plan indicates that two crews will
be prepared for. NRC administered operationa' evaluations by July.25 and
-
26,1990. . The first of these two crews, whi A failed during the June 9
and 10 examinations,. is to be utilized as tne fifth operating shift crew.
The members of the-second-crew.are to be reassigned to the five opercting-
.
shift crews to provide additional qualified personnel on shift.
-In regard to the examination failures which prompted the voluntary shut
1
down of both units-on.May 20, 1990, CP&L conducted a roct cause analysis.
.The results of this root- cause analysis and the associated long-term
corrective action plan, which will be incorporated into the Brunswick
Integrated Action Plan, was submitted for NRC review on June 30, 1990.
The effectiveness of the corrective actions will be inspected and tracked-
under an 'nspector Followup Itc.m:
Review and Followup on Implementation
.
and Effcctiveness of Long-Term Corrective Action for Operator Training,
(325/!0-19-04 and 324/90-19-04).
Violations and deviations-were not identified.
7.
OnsiteReviewofLicenseeEventReports(92700)
The below: listed LERs were reviewed to verify that the-information
provided _ met NRC reporting requirements. - The verification included-
- adequacy of event description and -corrective action taken. or planned,
existence of potential generic problems and the relative safety
significance 'of the event.
Onsite inspections were performed and-
concluded that necessary corrective actions have;been'taken in accordance
with existing requirements, license conditions. and commitments, unless
otherwise stated.
.
~ a.
(CLOSED)
LER 2-90-03, Main Steamline Isolation Valve Closure Caused
,
by an Isolation Signal During the Performance of a Periodic Test on
the Main Steam Line Area High Temperature' Switches. 'This event was
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-initially described in Inspection Report-325,324/90-11. The licensee
'i
determined that the auxiliary operator failed to ensure that the~"A"
-logic cuannel was reset prior to testing the "B"
channel, as re-
quired, during tne performance of PT-2.1.22, PCIS - Main Steamline-
Area High Temperature.
The licensee also concluded that the proced-
ure was a contribut's g factor because it is written to go directly
i
from- testing one logic traln to testing the other.
For corrective
action, the licensee stated that the personnel involved with this
event were counseled.
Additionally, the licensee plans to split the
PT into two tests which will test one logic train at a time.
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The failure of the A0 to ensure that the first logic channel was
. reset prior to_ testing the second represents one example-of a failure
to _ follow procedure ' and is a Violation of TS 6.8.1.c. ' A second
example .is discussed below.
,
b.
(CLOSED)
LER 2-90-05, Unplanned Closure of HPC111 solation Valve Due
to Personnel Error.During Surveillance Test. During the performance
g
of MST-HPC113M, HPCI- Steam Leak Detection Channe1~ Functional Test,. on .
May 14, 1990, an unplanned closure of HPCI Inboard Steam Isolation,
Valve 2-E41-F002 occurred.
This was caused by an I&C technician who
placed-the RCIC key lock test switch in test instead of the HPCI, key
. lock test switch as stated in the MST.
Subsequently, when a test -
signal was applied to the HPCI isolation logic, an actual isolatiu.
oacurred.
The' licensee stated that personnel error _was the cause'of
the event. - Contributing factors included the test switch layout _ and
common annunciator for HPCI and RCIC steam leak detection. Corrective
action provided counseling for the personnel involved and the MST
will be revised to include an: independent verification of the switch'
placement. .The same or similar action will be evaluated for use on
the _ Nuclear Steam Supply Shutoff / Reactor Protection System panels'
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which have similar test switch configurations.
The failure of the technician to position the correct test switch-
trepresents a second' example of a failure to follow procedure and is a
,
Violation of ' TS 6.8.1.c:
Personnel Errors Associated With
Surveillance Tests, (324/90-19-03).. _ Excessive personnel errors
during surveillance testing has -not been- a problem.
When personnel
errors have occurred, the licensee generally takes appropriate-
corrective action in addition to counseling or retraining.
These two examples of failure to follow proceoure are not being cited,
' because criteria specified -in Section V. A of the NRC Enforcement
9
Policy were satisfied.
.
One non-cited violation with two examples was identified.
' 8.
TMI Action Item (25565)
(CLOSED)
Item II.K.3.16.B. Reduction in Challenges and Failures of Safety
' Relief Valves.
This item was previously inspected in reports-
~325,324/84-07, 325,324/85-38, and 325/86-24 and 324/86-25.
.
As stated in report 325/86-24 and 324/86-25, a letter to the licensee from
- NRR dated-November 14, 1984, concluded that actions taken or committed to
would achieve the objectives of NUREG-0737, Item II.K.3.16.
At the time
.
of'that report, the only incomplete action was a modification to change
1
- the main steam isolation valve closure on -low -reactor water level from
1
Elevel 2 to level 3.
This modification, PM-87-164 and 87-165 for Units 2
and 1, respectively, was functionally completed' on April 12, 1988 and
' March. 20, 1969.
.The inspector reviewed the plant modification
documentation.
The modifications are' operable, but not administrative 1y
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complete.
The- incomplete paper work does not affect the system
operability.' This item is' closed.
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Violations ~and deviations were not identified.
.
9'. - . Action or Previo's Inspection Findings (92701)-
u
' a '.
(OPEN)
URI 325/90- 17-03 and 324/90-17-03, Loss of Offsite Power to-
.
1
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Unit.2 Emergency Bus E3.
The licensee has concluded that this event
!
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is not' reportable pursuant to 10 CFR 50.73. This conclusion is based
on the licensee's interpretation that an ESF actuation is reportable-
[
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.only when the actuation is the result <of a valid signal from a sensor
%A
of- the component / system.
Therefore, the SBGT system actuation in
both units as . well as the numerous group isolations are not -
,'
considered to be ESF actuations, since they were caused by either the'
/
RPS A de-energizing' or stack radiation monitor de-energizing or both. ,
All four EDGs started due.to the simulated undervoltage on' bus 2D,
,,
and EDG' 3 started- and loaded on E3 due- to an actual undervoltage on
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E3, but the Brunswick EDGs are not considered to be ESF equipment,
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since they 'are not listed as such in the FSAR. . The question of
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reportability for this item has been referred to Region II.
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During the event, the 2A NSW pump failed to start automatically as
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designed.
This -issue has been resolved and is discussed in
paragraph'2.-
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-The root'cause and resultant corrective actions for the loss of power '
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is still under investigation by the licensee.
Therefore, this item
.will remain open pending completion of the investigation and review.
'
by the-inspectors.
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b.
(OPEN)
IFI 325/90-14-01 and 324/90-14-01, Followup on Implementation.
and. Effectiveness of Licensee's Independent IAP Audit Processes. The:
licensee's -program for monitoring the effectiveness of ,1I AP
.
- implemented actions was approved on June 6,.1990. After each level 1
..
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item is completed, an assessment will be- conducted by one -of three
independent assessment . grogs to verify that- the item was completed,
,
.
that documentary evidence of completion exists' and that measures are
in place to ensure that improvement can.be sustained. 'In addition,
the CQA Department will'be monitoring the continuing effectiveness of=
',
the IAP. 'The inspector reviewed the schedule in Attachment 1 of the
program' document and the QAAU schedule for inspection.
The majority
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of the inspections are due to begin later this year.
Additional
i
inspection will be done at this time to determine the effectiveness-
of.the audit process.
Violations and deviations were not identified.
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10.'ExitInterview-(30703)
The inspection scope and findings were summarized on July 3.-1990, with
those: persons ' indicated in paragraph 1.
The inspectors described the
areas inspected --a'd discussed in dett.il the-inspection findings listed
below.
Dissentin3 comments were not received- from the licenset ,
Proprietary information is not contained in this report.
,
Item Number
Description /Refere_n.ce Paragraph
324/90-19-01
VIOLATION - Lack of Proc ure for Local-Feed Pump
Operation, (paragraph 4.
.
325,324/90-19-02
NON-CITED VIOLATION - Inadequate Qualification of1
of Alternate Plant Nuclear Safety Comittee
Members, (paragraph 5).
>
,
324/90-19-03
NON-CITED VIOLATION - Personnel Errors AssociateU
With Surveillance Tests, (paragraph 7.a and b).;
325,324/90-19-04
IFI - Review and Followup on Implementation and
OperatorTraining,(g-TermCorrectiveActionfor
Effectiveness of 1.on
paragraph 6).
11. Acronyms and hitialisms
-Al
Administrative Instruction
'As low As Resonably Achievable
A0
Auxiliary Operator-
Average Power Range Monitor
BSEP-
Brunswick Steam Electric Plant
CNS_
Corporate Nuclear Safety
CQA
Corporate Qdality Assurance
Condensate Storage Tank
Core Thermal Power
-E&RC'
Environmental & Radiation Control
-EDG
Emergent, Diesel Generator
EDS -
Electrical. Distribution System
Engineered Safety Feature
.F
Degrees Fahrenheit
..
' FACTS-
Facility Automated Comitment Tracking System
GAF
Gain Adjustment Factor
'
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'HP'
Health Physics
C
High Pressure Coolant Injection
LHPES
Human Performance ? valuation System
Integrated Action Plan
'I&C
Instrumentation and Control
IE=
NRC Office of Inspection acd Enforcement
IFI
Inspector Followup Item
IPBS
Integrated Planning, Budgeting and Scheduling
,
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'LER-
Licensee Event Report
Maintenance Surveillance Test
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NEDc huclear Engineering Department
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NRC.
. Nuclear Regulatory Commission
i
-Nuclear Reactor Regulation
j
-NSW
Nuclear Service Water
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01:
. 0perating-' l en ruction
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0NS
.Onsite Nuclear Safety
OP
- Oper ating' Procedure
protected Area-
Primary Containment' Isolation System
PGM-
Plant General Manager
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PIR-
' Plant _ Incident Report
PLP
Plant Procedure
Plant Modification
PNSC-
Plant Nuclear Safety Committee
Periodic Test
,
-QA
Quality Assurance
~
QiAU :
Quality Assurance Audit Unit
Quality Control ~
L
RCI'
Regulatory Compliance Instruction
.
RCIC-
Reactor Core Isolation Cooling
SAT-
Startup Auxiliary Transformer
Standby Gas Treatment
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'SF
Shift Foreman
SOS
-Shift Operating Supervisor
.STA
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.TMI
Three Mile Island--
TS-
Technical Specification
Unresolved item'
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