ML16148A660
| ML16148A660 | |
| Person / Time | |
|---|---|
| Site: | Oconee  |
| Issue date: | 06/11/1992 |
| From: | Binoy Desai, Harmon P, Poertner W NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML16148A658 | List: |
| References | |
| 50-269-92-11, 50-270-92-11, NUDOCS 9207270077 | |
| Download: ML16148A660 (11) | |
See also: IR 05000269/1992011
Text
REG&I
UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTA STREET, N.W.
@
0
ATLANTA, GEORGIA 30323
Report Nos.:
50-269/92-11, 50-270/92-11 and.50-287/92-11
Licensee: Duke Power Company
P.
0. Box 1007
Charlotte, NC 28201-1007
Docket Nos.:
50-269, 50-270, 50-287, 72-4
License Nos.:
DPR-38, DPR-47, DPR-55, SNM-2503
Facility Name:
Oconee Nuclear Station
Inspection Condud ed:
il
6 - May 23, 1992
Inspector:
P..
or
esident Inspector
Date Signed
B. B. e
ide t Inspector
Date Signed
W. K. Po tner, R ident Inspector
Date Signed
Approved by: G. A lelisle,
tion Chief
Division of Reactor Projects
SUMMARY
Scope:
This routine, resident inspection was conducted in the
areas of operations, surveillance testing, maintenance
activities and followup on previous inspection
findings.
Results:
One violation involving the failure to use the proper
Reactivity Balance Procedure/Curves was identified
(paragraph 2.d).
9207270077 920612
ADOCK 05000269
G
REPORT DETAILS
1.
Persons Contacted
Licensee Employees
- H. Barron, Station Manager
- S.
Benesole, Safety Review
- D. Coyle, Systems Engineering
J. Davis, Safety AssuranceManager
D. Deatherage, Operations Support Manager
B. Dolan, Manager, Mechanical/Nuclear Engineering (Design)
W. Foster, Superintendent, Mechanical Maintenance
- J. Hampton, Vice President, Oconee Site
- 0. Kohler,. Regulatory Compliance
C. Little-, Superintendent, Instrument and Electrical .(I&E)
- M. Patrick, Performance Engineer
B. Peele, Engineering Manager
- S.
Perry, Regulatory Compliance
- G. Rothenberger, Work Control Superintendent
- P. Stovall, Superintendent, Operator Training
- R. Sweigart, Operations Superintendent
Other licensee employees contacted included technicians,
operators, mechanics, security forcemembers, and staff
engineers.
NRC Resident Inspectors:
- P. Harmon
- W. Poertner
B. Desai
Attended exit interview.
2.
Plant Operationsp (71707)
a.
General
The inspectors reviewed plant operations throughout the
reporting period to verify conformance with regulatory
requirements, Technical Specifications (TS), and
administrative controls.
Control room logs, shift
turnover records, temporary modification log and
equipment removal and restoration records were reviewed
routinely.
Discussions were conducted with plant
operations, maintenance, chemistry, health physics,
instrument & electrical (I&E), and performance
personnel.
Activities within the control rooms weremonitoredon
an almost daily basis.
Inspections were conducted on
day and on night shifts, during weekdays and on
2
weekends. Some inspections were made during shift
change in order to evaluate shift turnover performance.
Actions observed were conducted as .required by the
licensee's Administrative Procedures. The complement
of licensed personnel on .each shift inspected met or
exceeded the requirements of TS. Operators were
responsive to plant annunciator alarms and were
cognizant of plant conditions.
Plant tours were taken throughout the reporting period
on a routine basis. The areas toured included the
following:
Turbine Building
Auxiliary Building
CCW Intake Structure
Iidependent Spent Fuel Storage Facility
Units 1, 2 -and 3 Electrical Equipment Rooms
Units 1, 2 and 3 Cable Spreading Rooms
Units 1, 2 and 3 Penetration Rooms
Units 1, 2 and 3 Spent Fuel Pool Rooms
Unit 2 Containment
Station Yard Zone within the Protected Area
Standby Shutdown Facility
Keowee Hydro Station
During the plant tours, ongoing activities,
housekeeping, security, equipment status, and radiation
control practices were observed.
Within the areas reviewed, licensee activities were
satisfactory.
b.
Plant Status
Unit 1
Unit 1 operated at full power until May 7 when a
reactor trip occurred from 100 percent power. A loose
pin connection in the exciter circuit caused a
generator lockout which caused an anticipatory turbine
to reactor trip. The unit was taken critical later
that evening. At 3:42 a.m., on May 8,.the unit tripped
from 14 percent due to anticipatory Loss of Feedwater
Pump reactor trip. A leak in the feedwater pump
suction instrument line was found after the trip. The
unit was cooled down to the low pressure injection
(LPI) switchover mode to isolate and repair the leak.
The unit was returned to power on May 11.
On May 22
the unit was shut down due to leakage associated with
reactor coolant pump (RCP) number 1 and 2 seals.. The
unit was cooled down and remained shutdown for the
3
remainder of the report period. The seal repair
outage is expected to last 11 days.
Unit 2
Unit 2 operated at full power until May 15 when it was
shut down .due to temperature on Main Transformer Y
Phase connection exceeding 360 degrees F. Following
repairs, the unit was taken critical and returned to
power operations on May 17. On May 21, a 2A1 RCP oil
pot level low alarm was received. Power was reduced to
30 percent-and upon entry in the reactor building, the
licensee discovered that the lower oil pot vent line
was broken. Fixing the line would have required a unit
shutdown. However, a.decision was made to delay the
shutdown due to power demand. Power was increased back
up to 70 percent and the unit operated with three RCPs.
The unit was shut down on May 22 and following repairs
to the vent line the unit was brought back up on May.
23.
The unit operated at power for the remainder of
the report period.
Unit 3
Unit 3 operated at full power until April 30 when the
3A1 RCP upper oil pot level low alarm came in. Power
was reduced and approximately 15 gallons of oil was
added. On May 6 power was reduced.again to secure the
3D1 Heater Drain Pump (HDP) and isolate the 3D1 HDP
recirculation line.
The unit operated at full power
for the remainder of the report period.
c.
Unit 1 Reactor Trips
On May 7, 1992, at approximately 1:55 p.m.,
Unit 1
experienced an automatic reactor trip from 100 percent
power due to turbine trip on Main Generator Lockout.
The Main Generator Lockout was apparently caused when a
loose pin connection caused a relay to actuate
spuriously, resulting in indication that the Generator
Field Breaker was open. All systems performed normally
following the trip.
At the time of the reactor trip, there were some
housekeeping (sanding/painting) activities in progress
in the vicinity of the Generator and it was initially
speculated that the Generator Lockout was related to
the ongoing work. However, the licensee later
concluded that this did not contribute to the trip.
The licensee performed an investigation and found a
loose pin connection on pin 6 of the EHC (EHC-6)
4
terminal which is mounted inside the generator exciter
housing cabinet. The licensee concluded that vibration
caused the generator protective circuitry to be
interrupted causing the 41MXa relay to actuate when the
pin connection became loose. Relay 41MXa falsely
sensed that the Main Generator field breaker was open
and caused the Main Generator to lockout causing
turbine trip and an anticipatory reactor trip.
The licensee implemented an exempt change which
installed a hard wire bypassing the pin connection
prior to startup. Similar trips on Unit 1 had occurred
in October 1991 and December 1984. These two trips
were attributed to EHC-6 coming loose at the connector
and not the terminal, though both have the same control
logic flowpath. The exciter housing in both instances
had recently been removed for maintenance during
refueling outages. This required manipulating the
connectors. Following the trip in October 1991, the
licensee inspected and tightened all loose terminal
plug connections and connectors. However, the licensee
apparently did not suspect the pin connection within
the terminal plug to be loose. As a permanent solution
to this problem, the licensee was evaluating the
failure logic of relay 41MXa to determine if
alternative logic schemes are needed.
The unit was taken critical at 1:42 a.m. on May 8. At
approximately 3:42 a.m.,
the unit experienced another
reactor trip from 14 percent power. Just prior to the
trip, the operators had received a High Hotwell Level
alarm and the hotwell level was found to be fluctuating
between 72 inches and 79 inches. The normal level is
between 63 inches and 69 inches. There was no guidance
available to the operators with regard to responding to
the alarm and the perceived abnormality. The operators
were concerned about.losing condenser vacuum if the
Condensate Steam Jet Air Ejector suction lines were to
flood from the Condenser due to High Hotwell Level.
Based on this concern, the operators decided to use
condensate recirculation and move some water from the
hotwell to the Upper Storage Tank (UST).
Operations
personnel considered the evolution to be within "skill
of-the-craft", and did not feel that a written
procedure was required.
After verifying that condensate recirculation control
valve 1C-128 was closed, operators began opening block
valve 1C-124. Opening of valve 1C-124 initially acts
to fill a partially vacated Condensate Recirculation
pipe. The volume between IC-124 and 1C-128 is large.
5
It is believed that a significant volume of the
Condensate Recirculation pipe had been emptied by
evaporation of the water to the UST via leakage through
iC-128.
Upon opening 1C-124, a feedwater swing
developed and low suction pressure at the Condensate
Booster Pump and a low discharge pressure at 1B Main
Feedwater Pump (FWP) condition was created. The
FWP/anticipatory reactor trip RPS setpoint of 802 psig
was reached on the 1B FWP discharge. This caused the
reactor to trip. Trip response was normal with control
systems functioning as required to bring the unit to
Hot Shutdown.
The licensee concluded that the oscillations were
caused during the power increase from 0 to 15 percent.
During this period, the steam generator level is held
constant, and the steam bypass system dumps steam to
the hotwell as reactor power is raised to approximately
15 percent.
The impingement of steam from the bypass
system onto the hotwell water level causes turbulence
and false level increases at the level detectors. This
was verified during the startup on May 11.
The
inspectors determined later that some operators were
aware of this phenomenon. The operating crew on shift
at the time of the trip did not realize that false
level indications were routine during steam bypass
system operations. The inspectors discussed this event
with the licensee and the licensee agreed to review
this event to determine if additional training is
required. In addition, the licensee revised the alarm
response procedure for Emergency High Hotwell level to
reference a new enclosure to the Condensate and
Feedwater procedure, OP/1,2,3/A/1106/02. This new
enclosure provides guidance on how to reduce Hotwell
level.
The licensee made the appropriate notifications to the
NRC. In addition, Licensee Event Reports (LERs)
describing these events will be issued by the licensee.
The inspectors will follow.the licensee's long term
resolution of the circumstances that caused these two
reactor trips through the LERs.
d.
Reactivity Management Problems During Unit 1 .Startup
On May 12, during a review of completed procedures, the
licensee identified that during the Unit 1 startup on
May 11,
the Estimated Critical Boron Concentration
(ECB),
Estimated Critical Rod Configuration (ECP), and
the.Subcritical Multiplication (1/M) measurements were
performed by the Unit 1 Supervisor (SRO) using the Unit
2 Reactivity Balance Calculation Procedure/Curves. A
06
second, redundant calculation performed by the Shift
Manager (STA) also used the wrong procedure/curves.
Unit 1 was started up and taken critical using data
derived from Unit 2 procedures/curves. The differences
in the core characteristics between Unit 1 and 2 were
insignificant.
To account for changes in Xenon concentration, RCS
temperature, and boron concentration, the ECB as well
as the ECP are deemed valid only if performed within
one hour of criticality. Initial intent was to go
critical at 1:00 p.m. The Reactivity Balance
Calculation Procedures for Unit 1 and Unit 2, PT/1 or
2/A/1103/15, are located on the common bookshelf of
the Unit 1 and 2 Control Room. The Unit 1 Supervisor
inadvertently pulled the Unit 2 procedure/curves and
performed the ECB and ECP calculations. The STA then
used the same procedures to independently verify the
calculations. Startup was postponed several times and
consequently the ECB and ECP had to be performed three
times. Each time the Unit 2 procedure/curves were
used. Independent verification by another licensed SRO
was also performed using Unit 2 procedure/curves. ECP
based on the Unit 2 Reactivity Balance Procedure was
determined to be 65 percent on Rod Group 6.
Unit 1 was taken critical at 3:17 p.m., on Rod Group 6
at 89 percent. This was within the acceptable band of
plus/minus 1 percent delta k/k of the total inserted
rod worth. The 1/M calculations used to predict
premature criticality were also based on Unit 2
procedures. At that time there was no reason to doubt
the ECP. The next morning at approximately 6:00 a.m.,
the Unit 1 Supervisor for the night shift identified
the error during his review of completed procedures.
Appropriate personnel were notified and available
shutdown margin was verified to be within acceptable
limits. Additionally, the ECP was recalculated using
the appropriate unit procedure and was determined to be
57 percent on Rod Group 6. The critical-data was
within the acceptable band based on the revised
calculations. Consequently, the error made in
calculating the ECP did not significantly affect
startup.
The consequences of this event were insignificant due
to the similarity in the Unit 1 and Unit 2 cores.
However, this event illustrates continued problems in
the area of attention to detail and the failure of the
independent verification process to prevent such
occurrences.
Further attention is warranted in the
area of reactivity management. As an interim
7
corrective action, the licensee color coded the unit
specific Reactivity Balance Procedures. The licensee
has also initiated an upper tier Problem Investigation.
Failure to use the proper Reactivity Balance
Procedure/Curves is identified as violation 50-269/92
11-01.
The inspectors will continue to monitor the
licensee's performance in the area of reactivity
management.
e.
Operator Logs
The inspectors reviewed the operators' logs associated
with the reactor trips and noted that only three
entries consisting of a total of five lines were
entered. The inspectors have discussed the lack of
detail in operator logs in general terms with station
management on other occasions. The information being
logged is not consistent with the management guidance
provided in this area. Operations management had
agreed to address this issue, but instances of
inadequate logging persist. The inspector will
continue to monitor licensee actions pertaining to this
concern.
Within this area, one violation was identified.
3.
Surveillance Testing (61726)
Surveillance tests were reviewed by the inspectors to verify
procedural and performance adequacy. The completed tests
reviewed were examined for necessary test prerequisites,
instructions, acceptance criteria, technical content,
authorization to begin work, data collection, independent
verification where required, handling of deficiencies noted,
and review of completed work. The tests witnessed, in whole
or in part, were inspected to determine that approved
procedures were available, test equipment was calibrated,
prerequisites were met, tests were conducted according to
procedure, test results were acceptable and systems
restoration was completed.
Surveillance reviewed and witnessed in whole or in part:
PT/0/A/251/13 Component Cooling Check Valve Functional
Test.
PT/0/A/600/01
Periodic Instrument Surveillance
No violations or deviations were identified.
8
4.
Maintenance Activities (62703)
Maintenance activities were observed and/or reviewed during
the reporting period to verify that work was performed by
qualified personnel and that approved procedures in use
adequately described work that was not within the skill of
the trade. Activities, procedures, and work requests were
examined to verify; proper authorization to begin work,
provisions for fire, cleanliness, and exposure control,
proper return of equipment to service, and that limiting
conditions for operation were met.
Maintenance reviewed and witnessed in whole or in part:
WR 92015377 Repair 2B LPI Pump Vent Line Leak.
The inspectors observed portions of the work activities
associated with WR 92015377 to repair minor leaks on the 2B
low pressure injection pump casing vent line connection and
the pump suction line connection. The work activity
involved disconnecting the lines and cleaning the
connections then reassembling the lines. The inspectors
observed that work activities did not commence on the pump
until at least five hours after the pump had been isolated
by operations for maintenance even though the removal of the
2B LPI pump placed the unit in a twenty four hour limiting
condition for operation.
The post maintenance test for this activity consisted of
filling and venting the pump and performing a visual
inspection of the pipe connections. The pressure -head of
the borated water storage tank, approximately 20 psig,
supplied the pressure source. However, the pump casing vent
would experience a pressure approaching the pump discharge
pressure, approximately 170 psig. The inspectors questioned
the adequacy of the post maintenance test and were told by
the operations staff that the test performed was adequate
and that running the pump was not required.
The work activities associated with the LPI pump (WR 92015377) are considered to be an example of poor
scheduling. The operations group's acceptance of the post
maintenance testing of the LPI pump is considered to be an
example of poor post maintenance testing.
No violations or deviations were identified.
9
5.
Inspection of Open Items (92700)(92701)(92702)
The following open item was reviewed using licensee reports,
inspection, record review, and discussions with licensee
personnel, as appropriate:
(Open) Vio 50-287/91-35-01, Example b
This violation involved the inadvertent dilution of the
Concentrated Boric Acid Storage Tank (CBAST) on Unit 3. The
violation specified that procedures were not followed in
that a valve had been mispositioned which caused an
unmonitored dilution of the CBAST. The event occurred
December 17, 1991. The licensee's investigation and
assessment of the event were completed during this
inspection period. The investigation and report was
performed by the site Safety Review Organization. The
report was comprehensive and accurate regarding the root
cause and contributing causes of this event. Several poor
work practices were identified along with recommendations
for correction.
The report as written contains elements of an effective
investigation and corrective action program. The resident
staff will review licensee management's.response to the'
report for inclusion in the closure of the violation.
6.
Low Pressure Service Water Pump Deadheading Issues
NRC Inspection Report Nos. 50-269, 270, 287/92-09 described
a February 9, 1992, event involving an instance of a
deadheaded Low Pressure Service Water (LPSW) pump. The pump
is shared between Unit 1 and Unit 2. With Unit 1 shut down
at the time, decreased cooling demands and maintenance
activities required the isolation of LPSW to several
components. As a result, total system flow decreased to the
point where the two running pumps interacted with each other
and the weaker pump experienced deadheading or intermittent
zero flow. Operators realized a pump was deadheading based
on the intermittent surging sounds of the LPSW piping
directly above the control room. This was confirmed by the
B.LPSW pump discharge pressure and pump current instruments
in the control room. After checking the pumps locally and
verifying that the B LPSW pump's discharge check valve was
closed, the operators stopped the B pump and the surging
noise stopped.
Following this incident, the inspectors questioned if the
LPSW pump had been damaged. The licensee performed ASME
Section XI testing on the pump and concluded that it was
operable. The inspectors expressed concern to the licensee
that the ASME Section XI testing did not appear adequate to
10
identify damage that could be caused by deadheading. The
licensee, based on information from the pump vendor,
reiterated that the testing performed was acceptable and
that additional testing was not required.
Because of the LPSW incident described, the inspectors
questioned the licensee's response to NRC Bulletin 88-04,
Safety-Related Pump Loss. The licensee stated that the
response, dated January 15, 1990, was adequate. That
response stated that the LPSW system design does not
preclude pump interaction that could lead to deadheading,
but the system configuration would be maintained with
adequate flow paths and total system flows above the minimum
required for deadheading. The Bulletin also requires that
if the system design does not preclude the possibility of
pump-to-pump interaction that could result in deadheading,
the system must be evaluated for flow division including
actual line and component resistances for the as-built
configuration. The evaluation should include development of
head versus flow characteristic curves of the installed
pumps, and actual test data for the "strong" versus -"weak"
pump flows.
This evaluation was not performed, and a basis
for minimum flow requirements has not been established. The
licensee has not determined the minimum flow above which
they stipulated the system would be operated.
The licensee's response to Bulletin 88-04 will be discussed
with the NRC Office of Nuclear Reactor Regulation.
7.
Exit Interview (30703)
The inspection scope and findings were summarized on May 28,
1992, with those persons indicated in paragraph 1 above.
The inspectors described the areas inspected and discussed
in detail the inspection findings. The licensee did not
identify as proprietary any of the material provided to or
reviewed by the inspectors during this inspection.
Item Number
Description/Reference Paragraph
Vio 50-269-92-11-01
Unit 2 ECP Procedures Used to Start
Up Unit 1 (paragraph 2.d).