ML16342A647
| ML16342A647 | |
| Person / Time | |
|---|---|
| Site: | Diablo Canyon  |
| Issue date: | 01/12/1999 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML16342A646 | List: |
| References | |
| 50-275-98-21, 50-323-98-21, NUDOCS 9901200322 | |
| Download: ML16342A647 (32) | |
See also: IR 05000275/1998021
Text
ENCLOSURE 2
U.S. NUCLEAR REGULATORYCOMMISSION
REGION IV
Docket No
License No.:
Report No.:
Licensee:
Facility:
Location:
Dates:
Inspectors:
Contributing
Personnel:
Approved By:
50-275; 50-323
50-275/98-21; 50-323/98-21
Pacific Gas and Electric Company
Diablo Canyon Nuclear Power Plant, Unit 2
7 ~h miles NW of Avila Beach
Avila Beach, California
December 4 to 18, 1998
Scott A. Boynton, Senior Resident Inspector, WNP-2
Richard M. Pelton, Office of Nuclear Reactor Regulation
David L. Proulx, Senior Resident Inspector
Linda J. Smith, Acting Chief, Project Branch E
ATIACHMENTS:
Attachment
1
Attachment 2
Supplemental Information
Sequence
of Events
990i200322 990il2
ADQCK 05000275
8
e
EXECUTIVE SUMMARY
Diablo Canyon Nuclear Power Plant, Unit 2
NRC Inspection Report 50-275/98-21; 50-323/98-21
~Oerations
~
Overall, the operating crew responded satisfactorily to the degraded conditions in the
circulating water system and the manual reactor trip by effectively stabilizing the plant in
a safe condition. However, the generally successful response to the event was
adversely impacted by several performance issues (Section 04.1).
s
The crew did not understand the response of the intake screen differential pressure
indication to a unit trip, which led them to improperly leave Circulating Water Pump 2-2
operating and resulted in the screen differential pressure exceeding the design limits.
Weak fidelityamong the annunciator response procedures and an abnormal procedure
and the crew's narrow focus on pump motor amps also contributed to the delay in
securing the circulating water pump. One example of a violation of Technical Specification 6.8.1 was identified for failure to secure the pump in accordance with
abnormal operating procedures; however, because
the licensee implemented effective
corrective actions, no response was required (Section 04.1.b.4).
The crew's misunderstanding
of the effects of atmospheric dump valve pressure
setpoint adjustments on the reactor coolant system, coupled with a communication error
between the control operator and the shift foreman, resulted in a pressure setting of the
atmospheric dump valves that exceeded the setpoint specified in the procedure.
The
higher pressure setting unnecessarily challenged the main steam safety valves when it
contributed to the liftingof Main Steam Safety Valve RV-7. A second example of a
violation of Technical Specification 6.8.1 was identified for failure to implement
emergency operating procedure requirements; however, because the licensee
implemented effective corrective actions, no response was required (Section 04.1.b.5).
~
The management
process for collecting plant process information and evaluating
equipment response to the manual reactor trip was rigorous in identifying and
addressing equipment performance problems (Section 07.1).
~
~
The process for evaluating human performance lacked the same degree of formality
and structure as the management process for evaluating equipment response.
The lack
of structure, coupled with poor operating logs, made it difficultto reconstruct event
details and assess
the root cause of specific operator performance issues
(Section 07.1).
Maintenance
~
With the exceptions of the early liftof Main Steam Safety Valve RV-7 and the autostart
of Diesel Emergency Generator 2-2, plant equipment responded to the plant trip as
designed.
The licensee implemented appropriate corrective actions to address the low
setpoint on the main steam safety valve. The autostart of the diesel emergency
generator resulted from a long-standing design deficiency that had been previously
identified by the licensee and was not a safety concern.
The licensee had initiated
action to correct the deficiency prior to the plant trip (Section 02.1).
Re ort Details
Summa
of Plant Status
On December 4, 1998, Unit 1 operated at 50 percent power because
of a failed expansion joint
in the intake cooling system.
Operators returned Unit 1 to 100 percent power on December 5.
On December 17, operators shut down the reactor after identifying increased containment
sump leakage.
The licensee identified that the leak was from a weld on the component cooling
water supply line to Reactor Coolant Pump 1-3 upper bearing cooler.
Unit 1 was in Mode 3 at
the end of the inspection period.
Unit 2 was in Mode 3. Operators had manually tripped the reactor on December
1 because of
high kelp loading on the traveling screens.
Operators returned Unit 2 to full power on
December 9 following repairs to balance of plant equipment.
02
Operational Status of Facilities and Equipment
02.1
Plant E ui ment Performance
a.
Ins ection Sco
e 92901
The inspectors reviewed the sequence of events and compared it to the plant process
parameter data recorded during the event to determine the adequacy of plant
equipment performance.
Also, the inspectors evaluated corrective actions in which
equipment performance was not as expected.
b.
Observations and Findin s
In general, the plant responded as expected to the manual reactor trip, turbine trip, and
main steam isolation valve closure.
However, two safety-related components did not
respond to plant conditions as designed:
Main Steam Safety Valve RV-7 and Diesel
Emergency Generator 2-2. Main Steam Safety Valve RV-7 (nominal setpoint of
1065 psig) lifted unexpectedly when operators inappropriately raised steam generator
pressure to 1035 psig. The main steam safety valve lifted at a pressure just below its
Technical Specification pressure band of 1044 - 1097 psig. Subsequent
testing of the
main steam safety valve showed an as-found setpoint of 1039 psig, a pressure
consistent with the setting of the atmospheric dump valve pressure controllers. The
main steam safety valve was declared inoperable and its setpoint adju'sted within
1 percent of its Technical Specification-required value.
Valve RV-7 was the low
setpoint safety valve on Main Steam Lead 2.
To evaluate the generic implications of the low liftpoint on Main Steam Safety
Valve RV-7, the licensee tested Main Steam Safety Valves RV-3 and RV-8 on Steam
1 and 2, respectively.
The as-found pressure setpoints for both valves were
found to be within Technical Specification limits and the licensee concluded it was not
necessary to test other valves. The licensee selected these main steam safety valves
because
the valves had low values for their pressure setpoint and had been refurbished
at the same time as Main Steam Safety Valve RV-7. The inspectors determined that
corrective actions associated
with Main Steam Safety Valve RV-7 were appropriate.
-2-
Following the reactor trip, the electrical supply to the 4160V vital busses transferred to
the startup transformer.
Although the transfer to startup power is designed to preclude
a start of the diesel emergency generators,
Diesel Emergency Generator 2-2
autostarted; however, Diesel Emergency Generator 2-2 did not load onto its associated
vital bus, Bus H. This phenomenon,
which had occurred on two previous plant trips,
was previously evaluated by the licensee and determined to result from relatively light
electrical loading on Bus H. This light bus loading translated to a slow voltage decay
when the auxiliary feeder breaker opens.
The slow voltage decay allows the first level
undervoltage relay to time-out and start Diesel Emergency Generator 2-2 prior to
reaching the low voltage setpoint that closes the startup feeder breaker to Bus H. The
phenomenon
had also been observed, in one instance, with Diesel Emergency
Generator
1-1 on Unit 1.
To determine the impact of the inadvertent starts of Diesel Emergency Generators
1-1
and 2-2, the inspectors compared the number of inadvertent starts to the total number of
start demands placed upon the two diesel emergency generators.
Since 1992, there
had been oyer 500 start demands placed on Diesel Emergency Generators
1-1 and 2-2.
Of those starts, four resulted from a slow voltage decay on the vital bus following a unit
'rip. Therefore, the inspectors concluded that the inadvertent starts did not significantly
impact component aging or reliability of the diesel emergency generators.
To correct the deficiency, the licensee submitted a license amendment request in
October 1998 to set the first level undervoltage relays to a lower value. The lower value
is expected to limitthe time between the start of the first level undervoltage relay timer
and the low voltage setpoint that closes the startup feeder breaker.
Thus, the timer
would not time-out prior to restoring bus voltage from startup power.
Conclusions
With the exceptions of the early liftof Main Steam Safety Valve RV-7 and the autostart
of the Diesel Emergency Generator 2-2, plant equipment responded to the plant trip as
designed.
The licensee implemented appropriate corrective actions to address the low
setpoint on the main steam safety valve. The autostart of the diesel emergency,
generator resulted from a long-standing design deficiency that was not a safety concern.
The licensee had initiated action to correct the deficiency prior to the plant trip.
Operator Knowledge and Performance
0 erator Res
onse to Loss of Main Condenser and Manual Reactor Tri
Ins ection Sco
e 92901
The inspectors evaluated operator performance in preparing for and responding to the
degraded intake conditions and manual reactor trip. Specifically, the inspectors
evaluated command and control, operator knowledge, internal and external
communications, and procedure use and adequacy.
0
-3-
In responding to the plant conditions produced by'the high sea state, operators utilized
the following procedures:
ARP PK13-04, "Condenser Delta P Hl PPC," Revision 3
OP AP-7, "Degraded Condenser," Revision 17
OP L-7, "Plant Stabilization Following Reactor Trip," Revision 2
OP 0-28, "Intake Management," Revision 2
EOP E-O, "Reactor Trip or Safety Injection," Revision 12
EOP E-0.1, "Reactor Trip Response," Revision 13
Observations and Findin s
b.1
Communications
Attachment
1 to Procedure OP1.DC11, "Conduct of Operations - Abnormal Plant
Conditions," Revision 12, stated that three-way communications were the standard for
communication.
This standard was established during the 1998 training cycle and had
been in place for approximately 6 months.
From operator interviews, the inspectors
determined that three-way communications were not consistently utilized during the
event and tended to degrade as the event progressed.
The inspectors validated this
finding through direct observation of two separate crews on the plant simulator and
control room observations of the Unit 2 plant startup.
In each observation, inconsistent
use of three-way communication indicated that three-way communication had not yet
become a habit with the operators.
The lack of complete three-way communications
only resulted in one identified human performance error. Specifically, inadequate three-
way communications between the control operator and the shift foreman contributed to
the improper setting of the 10 percent atmospheric dump valve controllers discussed
below in Section 04.1.b.5.
Prior to the manual reactor trip, the operating crew was cognizant of the degrading
conditions in the Unit 2 main condenser and established a conservative'action
level to
reduce plant load when condenser quadrant differential pressure reached 9 psid (plant
procedures require load reduction at 10 psid). Subsequently, condenser quadrant
differential pressure continued to increase at a rate of between 0.5 and 1.0 psid/hr.
Procedure OP 0-28, "Intake Management," Revision 2, recommended
notification of the
operations services manager and the operations director if it was likelythat a load
decrease
will be required.
However, operations management was not notified of the
potential need to reduce plant load. Early notification of operations management would
have allowed management
to be involved in the decision process regarding continued
plant operations.
b.2
Command and Control
Overall, the shift foreman demonstrated
good performance in carrying out his control
room command responsibilities.
Assignment of the senior control operator to monitor
circulating water and condenser conditions ensured timely closure of the main steam
isolation valves when Circulating Water Pump 2-2 was secured.
Proper focus of the
-4-
balance-of-plant control operator on auxiliary feedwater allowed for timely identification
of the feedf low mismatch on Steam Generator 2-2 and investigation of a possible steam
or feedwater leak.
One weakness was identified in regard to crew briefings. Crew briefings were not
performed when the operators transitioned to Procedure EOP E-0.1, "Reactor Trip
Response,"
Revision 13, or when they transitioned to Procedure OP L-7, "Plant
Stabilization Following Reactor Trip," Revision 2. The lack of briefings was inconsistent
with management expectations as specified in Procedure OP1.DC11.
The briefings
would have been beneficial in: (1) highlighting the overall strategy of the procedures,
(2) emphasizing specific actions and the threshotds at which they are taken, and
(3) assigning specific crew responsibilities for those actions, as necessary.
Detailed
briefings were also not conducted prior to use of Procedures
OP 0-28 and OP AP-7,
"Degraded Condenser," Revision 17. These procedures addressed
the potential
consequences
of the high swell warning in effect and provided specific strategies for
protecting the normal plant heat sink. Discussing the strategies could have highlighted
the requirement to immediately secure a circulating water pump when the intake screen
differential pressure exceeded the design limitof 50 iwg specified in Procedure 0-28,
Section 6.3.
The shift foreman also failed to ensure that actions were completed to reset the
atmospheric dump valve pressure controllers in accordance with Procedure EOP E-0.1,
as discussed below in Section 04.1.b.5.
b.3
Procedure Use and Ade uac
Prior to the reactor trip, operators responded to several alarms associated with main
condenser and intake screen differential pressures.
No information was found to
indicate that the annunciator response procedures associated
with the alarms were not
properly implemented.
However, the inspectors noted a gap between
Procedures ARP PK13-04 and OP AP-7 that did not provide for a smooth transition
between the two procedures and contributed to a delay in taking actions.
The entry
criteria for Procedure ARP PK13-04 were lower than the action criteria in
Procedure OP AP-7. Specifically, Procedure ARP PK13-04 was entered when an alarm
was received for one or more of the following conditions:
~
Condenser quadrant differential pressure at 9.5 psid
~
Condenser quadrant differential pressure at 12.5 psid
~
Rate-of-change
in differential pressure is greater than 0.5 psid/hr when quadrant
differential pressure
is greater than 7.0 psid in any quadrant.
If any of the above conditions was determined to be valid, then operators were directed
to implement Procedure OP AP-7. However, Procedure OP AP-7 did not require any
actions to be taken until condenser quadrant differential pressure exceeded
10.0 psid.
With differential pressures
below this criterion, Procedure OP AP-7 directs operators to
return to the procedure and step in effect (e.g., Procedure ARP PK13-04). Thus, prior
0
-5-
to the plant trip at 3:47 a.m. with condenser quadrant differential pressures less than
10.0 psid,.the operating crew did not believe they had formally entered
Procedure OP AP-7. This contributed to the crew briefing weakness discussed above in
Section 04.1.b.2.
At 3:45 a.m., when Circulating Water Pump 2-2 intake screen differential pressure
exceeded
100 iwg, operators promptly initiated a rapid downpower of the unit to prepare
to remove the circulating water pump from service.
Within approximately
1 minute, with
screen differential pressure remaining greater than 100 iwg, the shift supervisor
recommended and the shift foreman directed a manual reactor trip. Although not
required by procedure, operators initiated the manual reactor trip based upon already
degraded conditions in the main condenser.
The inspectors concluded that the decision
by the shift supervisor and shift foreman was appropriate and demonstrated a good
awareness
of plant conditions.
b.4
Circulatin
Water Pum
2-2 Tri
Although the manual reactor trip was initiated based upon the threat of damage to
Circulating Water Pump 2-2 and loss of the normal heat sink, operators did not secure
the circulating water pump.
Both Procedures
OP 0-28 and OP AP-7 provided direction
to immediately secure the circulating water pump under the high differential pressure
conditions observed.
Procedure OP 0-28 stated that "ifscreen differential pressure
increases to the point where failure is imminent, or if the screens stop running, the
[circulating water pump] must be immediately secured, even if this requires a reactor
trip." Procedure OP AP-7 specifically requires the circulating water pump to be secured
when screen differential pressure exceeds 50 iwg, the design differential pressure for
screen integrity.
Following the reactor trip and entry into Procedure EOP E-O, the senior control operator
continued to focus on the condition of Circulating Water Pump 2-2 by monitoring the
pump motor amps to look for indication of pump cavitation.
In addition, the transfer of
electrical power to the startup transformer resulted in the temporary loss of the Unit 2
intake screen differential pressure signal and an erroneous indication of 0 iwg across
the intake screens for Circulating Water Pump 2-2. The senior control operator,
believed the indication was valid and took no action to secure the pump.
Although valid indication of the intake screen differential pressure was restored in
approximately 2 minutes, the continuing high differential pressure was not recognized
for another 4 minutes when pump motor amps began to fluctuate from pump cavitation.
Thus, the failure to secure the circulating water pump before damage occurred to the
intake screens resulted from both a lack of understanding of the response of the screen
differential pressure indication following a Unit 2 trip and a narrow focus on pump motor
'mps.
The licensee indicated they would implement a method to ensure the screen
differential pressure indications are more reliable.
In addition, the licensee willdiscuss
this error in licensed operator training.
0
-6-
The failure to immediately secure Circulating Water Pump 2-2 when its associated
screen pressure exceeded 50 iwg was identified as one example of a violation of
Technical Specification 6.8.1 for failure to implement the procedural requirements of
Procedure OP AP-7 (50-323/98021-01).
b.5
Im ro er Pressure Settin
for Atmos heric Dum
Valves
When implementing the requirements of the "response not obtained" column in
Procedure EOP E-0.1, Step 10.d, because of the unavailability of the main condenser,
the control operator began lowering the pressure setpoint of the atmospheric dump
valves to 1005 psig. However, when the atmospheric dump valves began to open in
response to lowering the setpoint, the operator mistakenly believed that the valve
response would result in an excessive cooldown of the reactor coolant system and
improperly returned the setpoints to 1035 psig. As noted above, an apparent
'
miscommunication between the control operator and shift foreman also contributed to
the improper setting.
Shortly thereafter, Steam Generator 2-2 Main Steam Safety
Valve RV-7 lifted because of the proximity of its liftsetpoint to steam generator
pressure.
Personnel statements and operator interviews indicated that, following the resetting of
the atmospheric dump valve pressure controllers to 1035 psig; the intent was to slowly
lower the pressure setpoints to 1005 psig. However,.plant computer data showed that
the setpoints were not adjusted until 8 a.m. when pressure was lowered to
approximately 980 psig to successfully reseat Main Steam Safety Valve RV-7. Both
Procedures EOP E-0.1 and OP L-7 directed that operators reset the pressure controllers
for the atmospheric dump valves from a setpoint of 1035 psig to a setpoint of 1005 psig
when the main condenser is unavailable.
This action would allow the atmospheric dump
valves to stabilize reactor coolant system temperature at the no-load average
temperature of 547'F.
It also prevents interaction between the atmospheric dump
valves and the low setpoint main steam safety valves that are set at 1065 psig.
In an incident summary developed by the operations director, the performance issues
that resulted in the improper setting of the atmospheric dump valve pressure controllers
were identified and corrective actions were developed.
Specifically, the licensee
corrective actions included:
(1) having procedure writers ensure that the wording is
properly human factored, and (2) describing the error as part of the trip response
discussion in industry events training. The failure to set the pressure controllers for the
atmospheric dump valves in accordance with Procedure EOP E-0.1 is a second
example of a violation of Technical Specification 6.8.1 for failure to followprocedures
(50-323/98021-01).
b.6
0 erator Knowled e
Two operator knowledge deficiencies were identified that adversely impacted the event
response.
In evaluating the condition of Circulating Water Pump 2-2 and its associated
intake screens,
the crew was unaware that, upon a Unit 2 trip, indication of intake
e
-7-
screen differential pressure is temporarily lost and willindicate as 0 iwg until the signal is
restored.
Believing the indication of 0 iwg was valid following the manual reactor trip,
the crew delayed securing the circulating water pump.
In stabilizing the plant in accordance with Procedure EOP E-0.1, the control operator
misunderstood the response of the plant to adjustments of the pressure controllers of
the atmospheric dump valves. The control operator, believing that adjustment of the
pressure controllers to 1005 psig could result in an excessive cooldown, reset the
controllers back to 1035 psig, contrary to procedural requirements.
However, an
adjustment of 30 psig on the pressure controllers equates to less than a 5 F change in
reactor coolant system temperature.
Conclusions
Overall, the operating crew responded satisfactorily to the degraded conditions in the
circulating water system and the manual reactor trip effectively stabilized the plant in a
safe condition. However, the generally successful response to the event was adversely
impacted by several performance issues.
The crew's misunderstanding
of the effects of atmospheric dump valve pressure
setpoint adjustments on the reactor coolant system, coupled with a communication error
between the control operator and the shift foreman, resulted in a pressure setting of the
valves that exceeded the setpoint specified in the procedure.
The higher pressure
setting unnecessarily challenged the main steam safety valves when it contributed to the
lifting of Main Steam Safety Valve RV-7. One example of a violation of Technical Specification 6.8.1 was identified for failure to implement emergency operating
procedure requirements; however, because
the licensee planned effective corrective
actions, no response was required.
The crew did not understand the response of the intake screen differential pressure
indication to a unit trip, which led them to improperly leave Circulating Water Pump 2-2
operating and resulted in screen differential pressure exceeding the design limits. Weak
fidelityamong the annunciator response procedures and an abnormal procedure and
the crew's narrow focus on pump motor amps also contributed to the delay in securing
the circulating water pump. A second example of a violation of Technical Specification 6.8.1 was identified for failure to secure the pump in accordance with
abnormal operating procedures; however, because the licensee planned effective
corrective actions, no response was required.
0
-8-
07
Quality Assurance in Operations
07.1
Licensee Event Reconstruction and Assessment
Ins ection Sco
e 92901
The inspectors reviewed documentation available to support event reconstruction and
assessment.
Based upon the available information, an evaluation was made of the
depth and scope of the self-critique.
Observations and Findin s
The self-assessment
of the event was generally thorough; however, it was hampered by
poor documentation.
The operating logs of the shift foreman, the control operator, and
the turbine building watch were inadequate to reconstruct the significant activities
associated with the event response.
Neither the shift foreman nor the control operator
logs document the closure of the main steam isolation valves, indications of the liftingof
Main Steam Safety Valve RV-7, or the entry into Procedure OP L-7. Between 3:47.a.m.
and 6 a.m., a period when actions were being taken in accordance with
Procedures OP AP-7, EOP E-O, EOP E-0.1, and OP L-7, no entries were made in the
shift foreman's log. The level of detail in the operating logs was not consistent with the
recommendations
in Procedure OP1.DC37, "Plant Logs," Revision 12.
Although a postshift critique with the'operators involved in the trip response
is
recommended
by Procedure OP1.DC1, "Administrative Program to Control the Return
to Power After a Reactor Trip," Revision 2A, the licensee did not complete the review
after shift change immediately following the event. The use of a group debriefing is also
recommended by Procedure XI1.ID3, "Event Investigation Team, Event Response
Team, and Event Investigation Report," Revision 0. The licensee determined that this
was a missed opportunity to collect information details that are forgotten over time and
to identify the improper setting of the atmospheric dump valves, which was first
identified by the NRC resident inspectors.
The licensee determined that they would
have eventually identified the improper setting of the atmospheric dump valves during
their posttrip review.
Procedure XI1.ID3 required written statements to be obtained from each person
involved in the event that describe their observations and actions regarding the
circumstances of the event.
It further states that the statements should be obtained as
soon as practical after the event and prior to the involved individuals leaving site.
However, personnel statements
regarding the event did not meet this recommendation.
Only three statements were obtained immediately after the event, while the last
statement, from the shift technical advisor, was not obtained until 3 days later.
Further,
the information provided in the personnel statements
did not provide sufficient detail to
fill in the gaps in the operating logs. This included information regarding entry into and
exit from Procedure OP AP-7, time of exit from the emergency operating procedures,
and the basis for not returning the pressure control setpoint of the atmospheric dump
valves to 1005 psig after reseating Main Steam Safety Valve RV-7.
-9-
To help fillin the information gaps in the control room logs and personnel statements,
the operations director met with the operating crew involved with the trip response
2 days after the event to develop an incident summary and lessons learned.
The
incident summary effectively captured the significant performance issues.
C.
In reviewing the requirements and guidance in Procedure OP1.DC1, the inspectors
concluded that the procedure provided adequate
requirements for collection and
archiving of information related to equipment and plant performance concerns.
However, the requirements for collecting information and assessing
human performance
were not as clear. As stated above, it was only recommended to conduct a postshift
critique with the involved crew. Additionally, the procedure did not give specific
guidance to operators regarding the appropriate level of detail needed in their personnel
statements.
Attachment 6.1 of Procedure OP1.DC1 did not require an assessment
of
human performance.
I
Conclusions
The management
process for collecting plant process information and evaluating
equipment response to the manual reactor trip was rigorous in identifying and
addressing equipment performance problems.
The process for evaluating human
performance lacked the same degree of formality and structure.
The lack of structure,
coupled with poor operating logs, made it difficultto reconstruct event details and
assess
the root cause of specific operator performance issues.
X1
Exit Meeting Summary
The inspectors presented the inspection results to members of licensee management
at the
conclusion of the inspection on December 18, 1998. The 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.
Attachment
1
Supplemental Information
PARTIALLIST OF PERSONS CONTACTED
Licensee
J. Molden, Operations Services Manager
W. Garrett, Operations Director
B; Lewis, Senior Operations Supervisor
J. Haines, Operations Training
G. Goelzer, Shift Supervisor
M. Wright, Shift Foreman
W. Bumen, Senior Control Operator
R. Kline, Control Operator
A. Duracher, Balance of Plant Control Operator
IP 92901:
INSPECTION PROCEDURES USED
Followup - Operations
ITEMS OPENED, CLOSED, AND DISCUSSED
0 ened and Closed
50-323/98021-01
failure to secure circulating water pump in accordance with
abnormal procedures and failure to properly set atmospheric
dump valve pressure controllers in accordance with emergency
operating procedures (Sections 04.1.b.4 and 04.1.b.5)
0
Attachment 2
SEQUENCE OF EVENTS
(Alltimes are noted in PST)
Date/Time
11/30/98
8:00 p.m.
12/1/98
- 12:00 a.m.
12/1/98
- 2:00 a.m.
12/1/98
- 3:00 a.m.
12/1/98
3:15 a.m.-
3:30 a.m.
12/1/98
3:45 a.m.
Event
High swell warning in effect. Circulating water differential pressure across
the Unit 2 condenser approximately'5 psid. A senior control operator is
stationed at the intake structure in accordance with Procedure OP 0-28,
"Intake Management."
Because of rising differential pressure across the Unit 2 condenser (6 psid),
the shift supervisor and Unit 2 shift foreman agree to curtail the unit to
50 percent power if differential pressure reaches
9 psid.
Note: Procedure OP AP-7, "Degraded Condenser," directs curtailment when
condenser differential pressure exceeds
10 psid.
Differential pressure across the Unit 2 condenser increased to approximately
7 psld.
Maximum condenser limiting differential pressure is greater than 8 psid and
rising at approximately 2 psid/hr. Large bed of kelp observed floating in front
of the Unit 2 intake screens.
Based upon conditions in the condenser,
Procedure AR PK13-04, "Condenser Delta P Hi PPC," directs entry into
Procedure OP AP-7. No actions currently required by the abnormal
procedure.
Several manual and automatic actions were taken to vary intake screen
speed in response to high screen differential pressure and a continuing rise
on condenser differential pressure.
Unit 2 condenser limiting differential
pressure approaching 9 psid.
Rapid rise observed on the differential pressure across the circulating water
Pump 2-2 intake screens to greater than 100 iwg. The Unit 2 shift foreman
directs a rapid power decrease
at a ramp rate of 50 percent.
12/1/98
3:47 a.m.
NOTE: Procedure OP AP-7 required the affected circulating water pump to
be tripped when its associated
intake screen differential pressure is greater
than 50 iwg.
Based upon the high differential pressure across the Circulating Water
Pump 2-2 intake screen, the shift foreman directs the control operator to trip
the reactor.
The reactor trip was not required by procedure.
0
-2-
Date/Time
12/1/98
3:47 a.m.+
Event
Circulating Water Pump 2-1 trips as expected upon transfer of Unit 2
electrical loads to startup power. Light electrical loading on vital 4160V vital
Bus H results in a relatively slow bus voltage decay and a start of Diesel
Emergency Generator 2-2.
12/1/98
3:49 a.m.
12/1/98
3:53 a.m.
Operators leave Circulating Water Pump 2-2 operating based upon an
erroneous pressure indication of 0 iwg. The 0 iwg pressure reading from the
plant process computer is actually the result of a temporary loss of power to
its associated signal processor during the transfer to startup power.
Unit 2 intake screen differential pressure signal is restored in the control room
and reads greater than 100 iwg. However, this is not observed by control
room operators.
Senior control operator observes Circulating Water Pump Motor 2-2 current
swings of approximately 20-30 amps and secures the pump. This action is
consistent with Procedure OP AP-7.
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3:54 a.m.
12/1/98
4:10 a.m.
12/1/98
- 4:12 a.m.
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4:17 a.m.
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- 4:45 a.m.
12/1/98
':55
a.m.
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- 5:30 a.m.
With loss of all circulating water, the senior control operator recommends and
the shift foreman directs the closure of the main steam isolation valves.
Procedure EOP E0.1, "Reactor Trip Response,"
is entered.
Source:
control
operator log.
Control operator adjusts atmospheric dump valve pressure control setpoints
from 1035 psig to 1005 psig in accordance with Procedure EOP E0.1.
Because of a miscommunication with the shift foreman, the control operator
readjusts the atmospheric dump valve pressure control setpoints back to
1035 psig.
Steam Generator 2-2 pressure increases to approximately 1040 psig and
Main Steam Safety Valve RV-7 opens.
Steam Generator 2-2 pressure falls to
approximately 1005 psig and stabilizes with the relief valve remaining partially
open.
This valve has a nominal setpoint of 1065 psig.
Procedure OP L-7, "Plant Stabilization Following a Reactor Trip," is entered.
Vacuum broken on the Unit 2 main condenser.
This action is directed by
Procedure EOP E0.1.
Source: plant process computer
Operators observe a low water level condition in Steam Generator 2-2 and a
higher than expected auxiliary feedwater flow. Actions are initiated to restore
water level in Steam Generator 2-2 and operators are dispatched to
investigate a possible steam leak. Source:
PSRC meeting minutes
0
e
-3-
Date/Time
12/1/98
- 6:30 a.m.
Event
Observations at the Steam Lead 2 pipe rack area identify that Main Steam
Safety Valve RV-7 is open.
12/1/98
8:19 a.m.
Shift turnover to the oncoming operating crew is in progress and the shift
supervisor and shift foreman make a conscious decision to delay actions to
reseat the main steam safety valve until completion of turnover. This
decision was based upon the stability of reactor plant parameters and the
desire to carefully plan those actions.
Lowering of the Steam Generator 2-2 atmospheric dump valve pressure
control setpoint successfully reseats Main Steam Safety Valve RV-7 at a
pressure of 987 psig.