ML16342D565
| ML16342D565 | |
| Person / Time | |
|---|---|
| Site: | Diablo Canyon  |
| Issue date: | 02/26/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML16342D564 | List: |
| References | |
| 50-275-96-24, 50-323-96-24, NUDOCS 9703120017 | |
| Download: ML16342D565 (60) | |
See also: IR 05000275/1996024
Text
ENCLOSURE 2
U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
Docket Nos.:
License Nos.:
Report No.:
Licensee:
Facility:
Location:
Dates:
Inspectors:
Approved By:
50-275
50-323
DPR-82
50-275/96024
50-323/96024
Pacific Gas and Electric Company
Diablo Canyon Nuclear Power Plant, Units
1 and 2
7 1/2 miles NW of Avila Beach
Avila Beach, California
December 22,. 1996, through February
1, 1997
M. Tschiltz, Senior Resident Inspector
S. Boynton, Resident Inspector
~ H. Wong, Chief, Branch
E
ATTACHMENTS:
1
fl
Partial List of Persons
Contacted
List of Inspection Procedures
Used
List of Items Opened,
Closed, and Discussed
List of Acronyms
.
'7703i200i7
970226'DR
ADOCK 05000275
8
~l
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EXECUTIVE SUMMARY
Diablo Canyon Nuclear Power; Plant, Units
1 and 2
NRC Inspection Report 50-275/96024; 50-323/96024
~Oerations
~
The licensee's
process
and attentiveness
for monitoring the operability of
postaccident
monitoring system (PAMS) instrumentation
on PAMS,panels
1 and 2
has continued to be weak.
As a result, control operators
did not recognize'that
'everal
instruments were not functioning properly until questioned
by the inspectors
(Section 01.2).
Maintenance
~
Modifications performed to remove interferences
between main steam safety
valve (MSSV) discharge elbows and rigidly mounted steam vent stacks were well
planned and executed.
Contingencies for resetting reactor trip setpoints and MSSV
testing were established.
A conservative decision to test a MSSV confirmed that
the interference had not caused
a significant change
in the MSSV set pressure
(Section M1.1.1).
The Technical Maintenance technicians who performed the loop calibration of
residual heat removal (RHR) Pump 2-1 were unfamiliar with the required test
equipment setup and did so improperly.
As a result, the test equipment needed to
be disconnected
and reconnected
in order to achieve
a proper filland vent of the
tubing.
Additionally, during testing, technicians misinterpreted the "as-found" loop
test results (Section M1.1.3).
Main turbine valve testing was closely monitored and controlled by the shift
foreman.
Communications were formal and peer checking was performed for the
control room evolutions. 'ecent Operations Department initiatives were noted to
have improved the formality of communications
and, command and control.
Personnel
performing main turbine valve testing did not adequately
research
all of,
the known equipment deficiencies prior to the commencement
of testing
causing'onfusion
during the test.
Additionally, longstanding
material problems caused
complications during testing (Section M1.2.1).
Efforts are continuing to improve equipment material condition by the reduction of
maintenance
backlog; however, no significant change
in the overall condition of
safety-related
equipment has been noted (Section H1.1).
I
Ih
-3-
~En ineerin
Engineers failed to perform a formal safety evaluation prior to implementing
a
change in reactor trip setpoints (more conservative setpoint than in Technical
Specifications [TS]) as required by 10 CFR 50.59.
In addition, the Plant Staff
Review Committee (PSRC) failed'to require that a formal safety evaluation be
documented
prior to approving the change.
A violation was identified
(Section E8.1).
As a result of potential nonconservative
assumptions
in the licensee's
calculations
related to switchover from the refueling water storage tank (RWST) to the
containment sump following a loss-of-coolant accident, operators could be
inappropriately directed by the emergency operating procedures
(EOPs) to take
actions that would result in placing the plant in a condition outside of its design
basis.
An unresolved item was opened,
pending the licensee's investigation of the
potential nonconservatisms.in
the calculation (Section E7.1.2).
The licensee's review and approval process for design calculations failed to identify
several nonconservative
errors that affected the licensee's containment performance
analysis.
Additionally, the calculation was inappropriately referenced
in the
licensee's
design criteria memoranda
(DCM) as the basis for the minimum time to
complete the switchover to cold leg recirculation.
A violation was identified
(Section E7.1.3).
An engineer's review of the Final Safety Analysis Report Update (FSARU) identified
specific piping configuration requirements that were not contained
in MSSV
installation procedures
which resulted in the identification of three MSSVs with
inadequate
clearance between the valve discharge
pipe elbow and the vent stack.
Plant Su
ort
The 'chemistry technician observed performing the Unit 2 postaccident
sample
system (PASS) weekly sample was knowledgeable
of both the procedure
and the
PASS sample room equipment.
pele
Several problems with PASS procedures
and equipment were noted which indicated
a need for additional management
attention to ensure timely identification of
problems, revision of procedures
and correction of equipment deficiencies
(Section R1.1).
Efforts to improve the cleanliness of the facility and paint equipment rooms and
equipment have improved the appearance
of the facility (Section H1.1).
0
4
-4-
Emergency planning supervisors
planned
and implemented appropriate contingency
actions following rainstorms which impacted site access
and communications.
Recommended
actions for dealing with the circumstances
were prudent and well
thought out, and demonstrated
an appropriate level of concern for emergency
planning activities (Section P1.1).
0
l~
t
'
Re ort Details
Summar
of Plant'tatus
Unit 1 began this inspection period at 100 percent power.
On January 3, 1997, the
licensee declared
an Unusual Event when a mudslide completely blocked the normal access
route to and from the site.
The mudslide was partially cleared to restore normal access
and the Unusual Event was terminated that same day.
On February
1, the unit was
brought to below 35 percent, power (below the P8 loss of flow interlock) to allow for safe
restoration of a reactor coolant system loop flow transmitter.
Unit 1 was at 75 percent
power at the end of the irspection period.
Unit 2 began this inspection period at 100 percent power.
The unit remained at full power
throughout the inspection period.
I. 0 erations
01
Conduct of Operations
01.1
General Comments
71707
Using Inspection Procedure 71707, the inspectors conducted frequent reviews of
ongoing plant operations.
In general, the conduct of'operations
was. professional
and safety conscious.
01.2 0 erator Attention to PAMS Instrumentation
a.
~
Ins ection Sco
e 71707
During the inspection period, the inspectors conducted control board and instrument
panel walkdowns in the control room to verify (1) system alignments were
appropriate for the operating mode, (2) process parameters
were within TS limits,
and (3) required equipment'was
operable or that appropriate actions were being
taken in accordance
with license requirements.
b.
Observations
and Findin'
System alignments were found to be in accordance
with plant proce'dures for the
operating mode.
Process parameters
were within TS limits and equipment was
being controlled in accordance
with TS requirements.
The inspectors noted on one
occasion that the Unit 2 subcooling margin monitor (SCMM) c'hart recorder, located
outside of the control operator's
area, had run out of recording paper.
The SCMM
and associated
chart recorder are required and controlled by plant TS.
Based upon
the speed of advance for the recorder, the inspectors concluded that the paper had
run out several hours earlier.
Additionally, the end of the recording paper used in
the PAMS recorders
is marked with a red stripe to indicate when changeout
is
necessary.
The red stripe provides for several hour's of advance
notice prior to
running out of paper.
It was apparent that the operators
had not monitored the
0
el
~ S
0'
-2-
SCMM chart recorder for a period of at least several hours; routine panel rounds are
conducted shiftly (every 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />).
Although the SCMM chart recorder was an isolated incident during the inspection
period, a similar concern was identified in November 1996, when one of the Unit 1
PAMS indications for waste gas decay tank pressure
had failed high without being
identified by the operators.
NRC Inspection Report 50-275(323)/95015
also
documented
additional ".oncerns with operability of PAMS instrumentation.
The licensee's
monitoring requirements for the PAMS instrumentation
is generally
limited to the monthly channel checks of the instrumentation
required by TS.
No
additional surveillance procedures
were identified for monitoring the Instrumentation
nels
1 and 2, located outside of the normal control operator area.
The
Plant" round sheet provides direction to the balance of plant control
check the chart recorders
on PAMS Panel
1 to ensure the recorders
ent paper and are inking properly.
The round sheet does not specifically
er ';nstrumentation
located on PAMS Panels
1 and 2 with the exception
he containment high range radiation monitor., The equipment and
tion listed on the round sheet is expected to be monitored on a shiftly
12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />)
~
on PAMS Pa
"Balance of
operator to
have suffici
address oth
of RM-29, t
instrumenta
basis. (every
c.
Conclusions
l
The licensee's
process
and attentiveness
for monitoring the operability of PAMS
instrumentation
on PAMS Panels
1 and 2 continued to be weak.
As a result,
control operators did not recognize that one instrument in this inspection period and
others in the past
were not functioning properly until questioned
by the inspectors.
II. Maintenance
M1.1
Maintenance
Observations
a.
Ins ection Sco
e 62707
The inspectors'bserved
all or portions of the following work activities:
~
C0146897
~
R0149252
~
R0138113
Replace Centrifugal Charging Pump 2-1 Gear Oil Cooler
Containment Spray (CS) Pump 2-2 Preventive Maintenance
Pump 2-2 Motor Relay Test
b.
Observations
and Findin
s
The inspectors found the work performed under these activities to be accomplished
in accordance
with procedures.
All work observed was performed with the work,
package present and in active use.
The inspectors observed system engineers
monitoring job progress
and that quality control personnel were present when
0
-3-
required by the procedure.
When applicable, appropriate radiation control measures
were in place.
It was also noted that plant management
was actively involved in
monitoring significant maintenance
activities.
M1.1.1
MSSV Dischar
e Pi in
Modifications
a.
Ins ection Sco
e 62707
The inspectors observed portions of the work performed for the modification of
MSSV discharge piping.
As a part of the inspection the following documents
were
reviewed.
~
Action Request
(AR) A0420175, Discrepancy between the FSARU and
existing MSSV discharge elbow to stack piping clearance
FSARU Section 3.9.2.5, Design and Installation Criteria, Pressure-Relieving
Devices
~
AR A0420816, Unit 1, Trim Discharge Pan on MSSVs MS-1-RV-5 and RV-9
,
AR A0420817, Unit 2, Trim Discharge Pan on MSSV MS-1-RV-9
Work Order (WO) C0149430, MS-1-RV-5 Modification.
-WO C0149431, MS-1-RV-,9 Modification
Maintenance. Procedure
(MP) M-4.10A, Revision 2, "Steam Generator Safety
Valve Removal and Reinstallation"
b.
Observations
and Findin
s
Modifications of the MSSV discharge piping drip pan were performed to reestablish
the clearance between three MSSV discharge piping elbows and their associated
vent stacks.
The deficiency was identified by the licensee during research for a
revision to MP M-4.10A. The licensee noted that Section 3.9.2.5 of the FSARU
specified that there is adequate
clearance
between the MSSV discharge elbow and
the vent stack during all phases
of operation.
The review of MP M-4.10A identified
that the procedure
did not require that the clearance
be checked at any point during,
or following, MSSV reinstallation.
Based upon this initial concern inspections were performed of the associated
piping,
which revealed that for 3 of the 40 MSSVs (Unit 1:
RV-5 and RV-9; Unit 2:
RV-9)
there was no clearance between the discharge elbow piping and the vent stack.
Following identification of the nonconformance,
the licensee performed
a prompt
(POA) and concluded that the valves were still operable.
0
4l
The evaluation noted that MSSV liftpressure
could be affected if the valve nozzle
loads were great enough to distort the valve body.
Distortion of the valve body
would physically displace the disc off of the nozzle seats and prevent proper
alignment of the disc with the nozzle seating surface.
The licensee estimated that
the nozzle loads were well below the point of affecting the valves'ift pressure.
Plans were made for performing the modifications on a weekend and to reduce
power in both units in order to accomplish the work. The inspectors observed the
worksites for both Units
1 and 2 before the licensee commenced the drip pan
modifications.
Portions of the work observed included:
installation and removal of
the MSSV gagging devices, cutting of the drip pan interference,
and measurements
of piping deflection following removal of the interference.
Maintenance
personnel
were observed to closely follow the instructions in the maintenance
WO. Prior to
commencing the work, the required tools and test equipment were prestaged
in the
work area and the system engineer was present to expedite the modifications and
obtain postmodification measurements.
Personnel
performing the modifications
were knowledgeable
of the task and maintenance
supervisors
were present at both
the Unit 1 and 2 worksites.
Contingency plans had been established for testing all of the valves, which had
piping modifications.
The decision of whether.to test the valves was based upon
the amount of movement that was noted following removal of the portion of the
discharge elbow drip pan that was causing the interference.
Based upon the
measured
movement of the three MSSVs following the modifications, one of the
valves-was tested.
Test results indicated that the valve's liftpressure
was within
the limits specified in the TS and that there had not been
a significant change
in lift
pressure.
Conclusions
Engineering demonstrated
a questio'ning atttitude when identifying discharge
p'iping
configuration requirements that were not contained
in the MSSV installation
procedure.
This resulted in the identification of three MSSVs with inadequate
clearance between the valve discharge
pipe elbow and the. vent stack.
The maintenance
work to reestablish
clearance between three MSSV discharge
elbows and the associated
vent stack was well planned and coordinated.
There
.
was close oversight at the work site by both mechanical maintenance
supervisors
and the responsible
engineer.
Overall performance from identification of the issue
through the planning and performance of the discharge
pipe drip pan modifications
was demonstrative
of effective problem identification and resolution.
0
t
e
-5-
M1.1.2 RHR Pum
2-1 Flow Indication Calibration
a.
Ins ection Sco
e 62707
The inspectors observed the installation of test equipment and a portion of the
calibration of the discharge recirculation flow channel (FIC-641A) for RHR
Pump 2-1. The following documents were reviewed as a part of the inspection:
~
WO R0147373, Loop Test 10-3 FIC-641A RHR PP2-1 Discharge
Recirculation Flow Channel Calibration
Loop Test 10-3, Revision 3, "RHR Pump 2-1 Discharge Recirc Flow Channel
FIG-641 A Calibration"
b:
Observations
and Findin s
During the installation of test equipment, following the removal of the instrument
tubing test tee caps, boundary valve seat leakage was noted.
Although the leakage
was minor, the technicians believed that it could interfere with test results and an
AR was written.
Due to the boundary valve leakage, the technicians chose to connect directly to the
differential pressure detector.
When connecting the test equipment, the technician
did not ensure that the test equipment lines going to the detector were filled with
water-.
Consequently,
when attempting to filland vent the lines, the technicians
were unsuccessful
in removing all of the entrapped
air.
In order t'o properly fillthe
'ines,
the pressure
source was disconnected
from the detector and the lines purged
with water from the pressure
source into.a drip bag.
After disconnecting
the lines,
the techniciansverified the detector was full of water prior to reconnecting the test
equipment.
Failing to ensure the test equipment lines were properly filled and
vented resulted in additional work on a contaminated
system with the increased
potential for the spread of contamination.
This appeared
to be due to a lack of
familiarity with the proper installation of the test equipment.
During the actual calibration, the technicians were confused by the test acceptance
criteria specified in the procedure;
Loop Test 10-3, Step 8.3.1, specified that the
for a given flow reading that the measured
differential pressure
should be within
~
R1.48 inches of water column of the desired reading.
During the calibration, the
technicians
applied the differential pressures
references
in the step and then read
the corresponding
flow from the flow gage.
Since the flow gage read in gallons per
minute and did not closely correlate with the table over the range of the gage, the
technicians thought the "as-found" reading were out of specification due to air in
the detector.
The inspectors pointed out that the acceptance
criteria was INWC
and not gallons per minute at which point the technicians recognized their error.
After determining the correct method for performing the channel calibration, the
-6-
technicians determined that there was not a problem with the test equipment and
that it was acceptable
to continue with the performance of the surveillance.
c.
Conclusions
Technical Maintenance technicians involved with the RHR.Pump 2-1 flow
instrument channel calibration were not familiar with the installation of the test
equipment.
This resulted in having to disconnect the test equipment
in order to
properly fill and vent the lines prior to performing the calibration.
Additionally, the
technicians were unfamiliar with the calibration procedure which initially caused
them to misinterpret the "as-found" readings.
M1.2
Surveillance Observations
a.'ns
ection Sco
e 61726
Selected surveillance tests required to be performed by the TS were reviewed on a
sampling basis to verify that:
(1) the surveillance tests were correctly included on
the facility schedule;
(2) a technically adequate
procedure existed for the
performance of the surveillance tests; (3) the surveillance tests had been performed
at a frequency specified in the TS; and (4) test results. satisfied acceptance
criteria
or were properly dispositioned.
The inspectors observed
all or portions of the following surveillances:
~
STP 1-38-A.1
Solid State Protection System Train A Actuation Logic
Test in Modes 1, 2, 3, and 4 (Unit 2)
~
STP P-CSP-12
b.
Observations
and Findin s
Routine Surveillance Test of CS Pump 1-2
The inspectors found that the surveillance reviewed and/or observed were being
scheduled
and performed at the requwred frequency.
The procedures
governing the
surveillance tests were technically adequate
and personnel performing the
surveillance demonstrated
an, adequate
level of knowledge.
The inspectorss
also
noted that test results were appropriately dispositioned.
M1.2.1 Main Turbine Valve Testin
Unit 2
a 0
Ins ection Sco
e 61726
The inspector observed
portions of Surveillance Test STP M-21C, Revision 24,
"Main Turbine Valve Testing."
The inspector observed
control room activities
during the surveillance test and ARs A0410314, A0421358.
. 0
-7-
Observations
and Findin s
The turbine valve testing was well coordinated between the personnel
in the control
room and operators stationed at the valves.
Clear and concise formal closed-loop
communications were noted during the testing.
There were no other ongoing
activities that had the potential to distract the operators involved with the test
performance.
The shift foreman was directly involved in the supervision of the
testing and was positioned to provide effective oversight of the test.
Operators.
performed the testing in the specified sequence
and were noted to observe the
precautions
in the procedure.
The shift supervisor provided good management
oversight of the evolution and provided immediate feedback following the
completion of the testing.
I
During the testing several equipment problems were noted.
The inspector noted
that AR A0410314 had been written in August 1996, to document that the low
pressure "A" turbine reheat. stop valve, MS-2-FCV-173, indicated correctly when
.
the valve was closed; but when the valve was reopened, the indication remained in.
the mid-position.
Following review of the AR, it was appa'rent that corrective
actions had been scheduled
during the next forced outage or during 2RS and, as a
result, no action had been taken to correct the problem.
During the testing, similar
problems with the valve position indication were observed.
Since this was not an
expected equipment response,
it caused the operators to question if the valve had
repositioned
and whether it was necessary to reduce generator load.
The AR was
subsequently
updated to note that during future tests it might be necessary to have
personnel
available to make adjustments to the position indicator during the
performance of STP M-21C. This appeared to be an operator workaround.
A
Additionally, dunng testing, throttle stop valve MS-2-FCV-145 did not reopen during
testing until operators manipulated the air pilot valve to the bypass valve. This
problem was noted in AR A0421358 as a longstanding
problem.
Although the
procedure did.not specifically address the use of the air pilot valve, the inspectors
considered that the actions taken by the operator were prudent.
Since the safety
function of the high pressure
stop valve is to provide overspeed
protection for the
turbine, the failure of 'the. valve to re'open did not impact the valve's ability to
accomplish its safety functjon.
Conclusions
The surveillance test was well controlled and coordinated.
Communications were
clear and concise, and proper supervisory oversight was observed.
An existing
valve position indication deficiency was not recognized prior to commencing testing,
which caused concerns during testing when the valve position indication problem
recurred.
Recurring equipment problems during the performance of main turbine
valve testing created unnecessary
challenges to operators.
0
-8-
M8
Miscellaneous Maintenance Issues (92902)
M8.1
Closed Violation 50-275 323 92016-01:
loading of rigging equipment beyond its
safe working load during lifting of the primary and secondary
lids of a radwaste
shipping cask.
The licensee determined that the root cause of the violation 'was
personnel
error with weaknesses
in rigging instructions being a contributing factor.
To prevent recurrence of the violation, the maintenance
service manager discussed
industrial safety with the riggers to emphasize the importance of proper rigging,
personnel safety practices,
and the stopping of work when required activities are
outside of the scope of work.
The licensee also revised the rigging instructions in Procedure
MP M-50.2
"Loading Preloaded
Liners into NUPAC 10-142 Radwaste
Shipping Cask," to
enhance
the preplanning steps and control of lifting and rigging activities.
Specific
.
guidance was added for manipulating loads and seating lids on casks to ensure the
correct equipment is used..ln followup to these actions, quality control evaluated
rigging of heavy loads during Refueling Outage
1R5 and did not identify any
deficiencies in rigging practices.
These actions appeared
to adequately
address the
concerns identified by the violation.
III. En ineerin
E7
Quality Assurance
in Engineering Activities
E7.1
Errors in Desi
n Basis Calculations
E7.1.1 Nonconservative
Assum tions in Establishin
the Technical Basis for the Minimum
Re uired Volume in the RWST
Ins ection Sco
e 37551
g
NRC inspectiori Report 50-275(323)/96021
documented
an unresolved
item
associated
with the licensee's
analysis of the available time for operators to
complete the switchover. of the emergency
core cooling system
(ECCS) to cold leg
recirculation following a loss of primary coolant.
The inspectors reviewed the
following documents for accuracy in supporting the plant's licensing and design
basis for the minimum contained volume in the RWST:
FSARU, Sections 6.2 and 6.3
~
FSARU, Table 6.3-5, Safety Injection to Recirculation Mode; Sequence
and
Timing of Manual Changeover
~
PG5E Calculation STA-061, Revision 0, FSARU Table 6.3-5 Update
-9-
~
.
PGKE Letter dated March 20, 1980, Response
to Request for Additional
Information Regarding RWST Sizing Basis
DCM S-9, Safety Injection System
~
~
.
EOP E-1.3, Revision 14, Transfer to Cold Leg Recirculation
I
b.
Observations
and Findin s
Time Available to 0 erators to Com lete Switchover to Cold Le
Recirculation
Final Safety Analys Report Update, Table 6.3-5, describes the sequence
of actions
taken by operators to transfer the ECCS to recirculation following a loss of,.primary
coolant.
The table and description of manual operator actions are specified by
Regulatory Guide 1.70 to demonstrate
that the ECCS can meet performance
requirements.
The table provides the timeframe in which the operators would
complete the switchover based upon estimated times to complete each of the
manual actions.
The table also shows the time available for completing the
switchover based upon the RWST volume between the low level alarm (33 percent)
and low-low level alarm (4 percent) and the assumed
pump flow rates.
These
timeframes are 9 minutes 20 seconds
(estimated time required to take the manual
actions) and 22 minutes 19 seconds
(the time available to perform the manual
actions) for a margin of 13 minutes to complete the switchover process.
The
assumptions
utilized to develop these.timeframes
are included in Table 6.3-5;
however, the original calculation from which the timeframes were derived could not
be located by the licensee.
As a result, the licensee issued PGSE calculation
STA-060 which reconstituted the basis for Table 6.3-5.
The results of STA-060
showed that the 13 minute margin equated to a remaining deliverable volume in the
RWST (volume above the low-low level alarm) of'63,000 gallons.
Another way to
view this is that from the time of the RWST low level alarm plus the 9 minutes
estimated for operators to manually sw'itchoyer to containment recirculation, there
would still be 63,000'gallons
available in the RWST.
In response to a request for additional information regarding the bases for the sizing
of the RWST, the licensee,
in a letter dated March 20, 1980, provided
a calculation
for the minimum contained volume in the RWST required by TS. The letter provided
information on the time required for operators to complete the switchover process
and the remaining deliverable volume in the RWST following completion of the
switchover to cold leg recirculation.
This information was based upon FSARU
Table 6.3-4a, which was the predecessor
to Table 6.3-5.
In the letter, the licensee
stated that 78,000 gallons of usable RWST capacity would be available following
the switchover process.
The licensee also determined that the most limiting single
'failure for completing theswitchover process was the failure of one of the RHR
pumps to trip when RWST level reached 33 percent.
The licensee concluded that
-10-
this failure would reduce the available volume during the switchover by 17,500
gallons to provide a remaining deliver'able volume from the RWST of approximately
60,000 gallons (78,000 minus 17,500 gallons).
Table 6.3-4a did not reflect the
reduction in available RWST volume due to the single failure.
In June 1980, the staff issued Supplement
9 to the Diablo Canyon Safety
Evaluation Report (SSER).
SSER 9 documented
the staff's acceptance
of the
minimum contained volume requirements for the RWST. The staff's acceptance
was based,
in part, upon the licensee's
analysis provided in the March 20 letter that
showed there was sufficient volume in the RWST to complete the manual
switchover procedure to cold leg recirculation with a margin of 60,000 gallons.
The
staff's analysis concluded that the minimum deliverable'olume
remaining
gn the
RWST following completion of the switchover would be as little as 32,500 gallons
when considering the most limiting single failure (complete documentation
is not
available to determine how the value of 32,500 gallons was derived).
The licensee recalculated the time available to complete the switchover to cold leg
recirculation and documented
it in STA-061, Revision 0, dated January
14, 1997.
STA-061 utilized 'more conservative flow rates for both the RHR pumps and
CS pumps.
STA-061 also considered the impact of one of the RHR pumps failing to
trip on an RWST low level condition (reduction in the available RWST volume
of 17,500 gallons).
Based upon these assumptions,
the results of STA-061 showed
that the minimum deliverable volume remaining in the RWST following the
switchover to cold leg recirculation would be 23,000 gallons.
The inspectors identified two concerns with STA-061.
First, the calculation
assumed
a containment pressure of 20 psig would be conservative
in that actual
pressure would remain above 25 psig throughout the switchover process.
However,
a recent analysis performed by Westinghouse
for the licensee showed
that with all containment press'ure
suppression
system operating, containment
pressure
could be as low as approximately 10 psig during the switchover process.
The assumption
utilized in STA-061 was apparently based upon design basis
conditions with minimum safeguards
equipment operating.
Second, STA-061 revised the RHR pump flow rates from 3500 gpm to
approximately 4200 gpm.
However, the limiting single failure of an RHR pump to
automatically trip at'the RWST low level alarm was not adjusted to reflect this
higher flow rate.
The inconsistency was not justified in the calculation.
Based
upon these concerns, the licensee will be revising STA-061 to more accurately
reflect the limiting conditions.
Time Re uired for 0 erators to Com lete Switchover to Cold Le
Recirculatl'on
STA-061 also included an update to FSARU Table 6.3-5 to incorporate the specific
steps in the current revision to EOP E-1.3, "Transfer to Cold Leg Recirculation."
This portion of the table redefined the time needed for operators to complete the
-1 1-
switchover process
by considering the expected duration of performing individual
steps in the EOP.
The table showed that the total time needed to complete the
switchover was 9 minutes 35 seconds.
This time, however, did not consider the
time required to perform steps
1, 2, 3a, 3b, and 3c of EOP E-1.3.
The exclusion of
these steps in STA-061 was not adequately justified. Additionally, the updated
table included two separate
steps to verify decreasing
RHR heat exchanger outlet
temperature following the restart of the associated
RHR pump.
The assumed
duration to perform each of these steps was 10 seconds.
No justification was
provided for that assumption.
Inclusion of the time to perform steps
1, 2, 3a, 3b,
. and 3c of EOP E-1.3 would increase the total time to perform the switchover by
1 minute 20 seconds.
The operations director agreed that these steps should be
included in the sequence.
Based upon the CS pump flow rate utilized in STA-061,
the additional time from inclusion of these steps would result in a margin of
14,500 gallons remaining in the RWST following the switchover piocess.
c.
Conclusions
The differences between the actual performance of the RHR and CS pumps
following a design basis loss-of-coolant accident (LOCA) and the performance
stated in Table 6.3-5 of the FSARU constitutes
a weakness
in the calculation.
This
change resulted
in a reduction in the remaining deliverable volume in the RWST
following the switchover to cold leg recirculation.
Unresolved
Item 50-275;323/96021-07
remains open pending the licensee's
and the staff's
evaluation of the safety consequence
of this reduction in volume.,
E7.1.2 Minimum Containment Flood Level to Su
ort Lon
Term ECCS Coolin
Re uirements
Ins ection Sco
e 37551
The inspectors reviewed the following information to determine the adequacy of
incorporating design basis information calculations, procedures,
and specifications
for'supporting
ECCS performance during the recirculation cooling
phase:
FSARU, Sections 6.2 and 6.3
SSER 9
DCM S-9, Safety Injection System
~
DCM T-16, Containment Function
0'
-1 2-
~
PGSE Calculation M-580, Revision 3, Determination of Post LOCA
Containment Flood Level
EOP E-1, Revision 13, Loss of Reactor or Secondary
Coolant
~
EOP E-1.3, Revision 14, Transfer to Cold Leg Recirculation
PGRE Calculation PAM 0-09-940, Post Accident Containment Recirculation
Sump Level Indication Uncertainty
'bservations
and Findin s
A review of DCM S-9 found that the calculated minimum containment recirculation
sump level for conditions under which the sump might be used for RHR pump
suction is 92.75 feet, as measured
from, sea level.
This level is also referenced
in
the NRC staff*s safety evaluation for sizing of the RWST.
Both EOP E-I and E-1.3 contain decision points to direct operators to evaluate
containment sump level prior to initiating steps to transfer the ECCS to cold leg
recirculation.
Specifically, operators
are to verify that recirculation sump level is
greater than 92.5 feet as indicated on level indicator (LI)-940 and LI-941,
containment recirculation sump narrow range level instruments.
Table 7.5-2 of the
FSARU states that the accuracy of the recirculation sump narrow range level
instruments
is s6.5 percent of instrument span or approximately a6 inches.
PGSE
calculation PAM 0-09-940 also showed that, under post accident conditions,
accuracy of the level indication should remain within a6 inches.
The inspectors raised
a concern regarding the EOP. decision point of 92.5 feet.
Specifically, if minimum containment sump level was actually 92.75 feet, indicated
level on LI-940 and Ll-941 could be as low as 92.25 feet. This indicated level
would prevent operators from initiating the transfer to cold leg recirculation and
would'irect them to enter Emergency Contingency .Action (ECA) 1.1, Loss of
Emergency Coolant Recirculation.
ECA 1.1 would place the plant in a,con'dition that
is outside of the assumptions
of the accidents
analyzed. in Chapter 15 of the
FSARU.
In response,
the licensee provided calculation M-580 which determined the
minimum and maximum ex'pected flood levels in containment following a LOCA.
For determining minimum flood level, M-580 included the following assumptions:
1.
The deliverable volume in the RWST during the injection phase
and the
volume of the ECCS accumulators would be directed to the recirculation
sump.
/,
-1 3-
2.
For small and intermediate break.LOCAs, reactor coolant system
(RCS)
volume is maintained by the ECCS and does not contribute to the level in the
sunlp.
3.
For small and intermediate break LOCAs, the.'P'ignal
is not expected to be
reached
and, therefore, the volume of the spray additive tank would not
contribute to containment sump level.
4.
The amount of water that does not reach the sump due to condensation
on
surfaces, water in the form of steam, and pooling in various equipment
I -pockets is not considered.
5.
Transit time for water to migrate to the lower level of containment was not
considered.
Based upon these assumptions,
the calculation resulted in a minimum sump level
of 93.0 feet k1 inch.
Calculation M-580 provided
a qualitative discussion
on the
conservatisms
applied in the derivation of minimum level.
In that discussion it was
concluded that the conservativ'e
assumptions
more than offset the nonconservative
assumptions.
No quantitative analysis was included to support that conclusion.
Additionally, the licensee was unable to locate the original minimum containment
sump level calculation referenced
in the DCM and SSER 9 and, therefore, could not
determine the basis for the difference between the results of the two calculations.
The inspectors
raised concerns with the licensee regarding the assumptions
utilized
in.M-580 for determining the minimum containment sump level.
Specifically, the
assumptions
did not appear to address the full range of loss of primary coolant
accidents that may require operators to transfer to cold leg recirculation.
That is,
small break LOCAs may not depressurize
the RCS sufficiently to allow for injection
of the ECCS accumulators
and, therefore, the accumulators
may not contribute to
volume in the recirculation sump.
Also, the amount of water that does not reach
the lower level of containment
and the transit time of coolant to the recirculation
sump were not estimated
in M-580 to determine their potential impact.
The
licensee
is revising calculation M-580 to address these concerns.
Based upon the concerris raised by the inspectors, the licensee initiated a POA to
address the minimum containment sump level following a LOCA. The POA included
a compensatory
measure to administratively control RWST level above 92 percent.
The normal surveillance procedure controls RWST level greater than 87 percent and
the TS minimum contained volume is approximately 81 percent.
The compensatory
measure was designed to ensure
an adequate
volume of water in the containment
sump when the RWST level reached the low level alarm of 33 percent.
-14-
c.
Conclusions
The inclusion of the EOP decision point to direct operators to transition to an ECA
when containment sump level is less than 92.5 feet, coupled with the minimum
expected sump level in the containment sump and level instrument inaccuracies,
has the potential to inappropriately direct operators to take actions that are outside
of the assumptions
of the accident analyses.
Further NRC review is pending the
licensee's revision to the calculation for minimum containment sump level. An
unresolved
item (URI 50-275;323/96024-01)
will be opened to track this issue."
E7.1.3 Calculated Minimum Time for CS 0 eration
a.
Ins ection Sco
e
37551
The inspectors reviewed the following documents that supported,
in part, the
licensee's containment performance
analysis:
PGBrE Calculation N-095, Revision 0, Duration of SC Operation
PGSE Calculation N-095, Revision
1
DCM S-9, Safety injection System
PGS.E Calculation J-54, Revision 6, Nominal Setpoint Calculation
b.
Observations
and Findin s
PG5E Calculation N-095, Revision 0, was developed to provide the minimum CS
operating time as an input to the licensee's containment analysis.
To minimize
.
spray operating 'time, the licensee utilized maximum ECCS pump flow rates plus
10 percent for conservatism.
These flow rates were then applied to the available
RWST volume during. the injection and the transfer to recirculation phases to derive
a minimum time that CS would operate prior to reaching
a low-low level condition in
the RWST.
In determining the available volume in the RWST for the injection phase,
the licensee as'sumed
an initial RWST volume of 400,000 gallons (TS minimum) and
a final volume of 149,200 gallons at the RWST low level alarm.
The TS minimum
of 400,000 gallons is'referenced to the bottom of the RWST and takes into account
the usable arid'unusable
volumes.
The volume utilized for the RWST low level
alarm, however, is referenced to the level of the RHR pump suction inlet and, thus,
only takes into account the usable volume.
The inspectors noted that this disparity
resulted in.a nonconservative
value being utilized for the available volume during the
injection phase.
The licensee revised N-095 to correct the above discrepancy
and to verify that the
containment performance
analysis was not adversely impacted.
In Revision
1 to
N-095, the licensee eliminated the additional 10 percent pump flow utilized in
0
-15-
Revision 0 and based the ECCS and CS pump flow rates on a containment
backpressure
of 25 psig.
The reduction in pump flow rates realized by these
assumptions
more than offset the error in available RWST volume and resulted in
minimum spray operating times greater than those stated
in Revision 0. The
inspectors noted, however, that Revision
1 did not take into account drawdown of
the RWST by the high head and intermediate head safety injection pumps during the
transfer to recirculation phase.
The licensee's failure to include the impact of the
high pressure
FCCS pumps during the transfer phase was nonconservative
and
without technical justification.
The licensee also identified other nonconservatisms
in the uncertainties
assumed for the RWST level instrumentation.
'
Based upon the follow-on concerns, the licensee
is revising Calculation N-895.
Maintenance of DCM
Section A4.3.1.2 of Appendix A to DCM S-9 references
Calculation N-095 as the
desigr. basis calculation for the minimum time for switchover to cold leg
recirculation and references Table 6.3-5 of the FSARU.
Calculation N-095 resulted
in a minimum switchover time of 15 minutes.
Table 6.3-5 of the FSARU provides
that.the available switchover time is 22 minutes.
The inspectors questioned the
licensee regarding the differences between the two timeframes and the process by
which design basis information is incorporated into the DCMs. The licensee
determined that Calculation N-095 was inappropriately referenced
the design'basis
calculation and that a safety evaluation of the differences between
N-095.and Table 6.3-5 was not performed prior to revision of the DCM.
Procedure
CF3.ID2, Revision 2, "Design Criteria Memoranda," governs the process
for maintaining the DCMs. Section 5.3.5 of Procedure
CF3.ID2 requires all
revisions to the DCMs to have a licensing basis impact evaluation
(LBIE) screen
performed in accordance
with Procedure TS3.ID2, Revision 2b, "Licensing Basis
Impact Evaluations."
If the.LBIE screen of the revision results in an impact on the
licensing basis,
a full evaluation must be performed. in accordance
with
Procedure TS3.ID2 to determine the acceptability of the change'.
When
Calculation N-095 was added to Appendix A to DCM S-9 in January 1994, an
evaluation was not performed in accordance
with Procedure TS3.ID2. This was a
violation of Procedure
CF3.ID2 (VIO 50-275(323)/96024-02).
Conclusions
The licensee's review and approval process for design calculations failed to identify
several nonconservative
errors in calculation N-095 ~ These errors were considered
significant enough to cause changes
in other assumptions
to ensure the results of
the revised calculation remained within the assumptions
of the containment
performance
analysis.
0
-1 6-
Calculation N-095 was improperly incorporated into DCM S-9 as the basis for the
available switchover time to cold leg recirculation.
The licensee missed an
opportunity to identify this error when an evaluation of the change to DCM S-9 was
not performed in accordance
with plant procedures,
E8
Miscellaneous Engineering Issues (92903)
E8.1
Closed
Unresolved Item 50-275 323 96023-04:
Failure to Perform Safety
Evaluation Prior to Changing
RCS Low-Flow Reactor Trip Setpoints
<<h
with the measurement
of Unit 2 RCS flow rates, the licensee concluded in@lay
1996, prior to returning Unit 2 to power following 2R7, that the RCS loss of flow
reactor trip setpoint specified in TS Table 2.2-1 was nonconservative.
Specifically,
the total uncertainty for 6 of the 12 loss of flow instrument channels was greater
than 3 percent and therefore would no longer ensure that the low flow reactor trip
would occur prior to 87 percent of the. minimum measured flow (MMF) assumed
in
the safety analysis.
TS and FSARU Re uirements
The setpoints for the reactor protection trip function following a loss of flow are
specified in Table 2.2-1 of the TS.
The TS table is referenced
in FSARU
Table 7.2-3, "Trip Correlation," which identifies that RCS low flow trip setpoints
provide protection for partial loss of forced reactor coolant flow. TS Table 2.2-1
specifies that the RCS low flow trip setpoint be set at greater than or equal to
90 percent of MMF. The table also provides'an allowable value for the trip setpoint
of greater than or equal to 89.7 percent of MMF. Operation with setpoints less
than 90 percent, but greater than or equal to 89.7 percent is allowable to
accommodate
for instrument drift that may occur between operational test;
however, when trip setpoints for a channel
are determined to be less than
89.7'percent,
the channel
is required to be dec(ared inoperable.
Revision of Reactor Tri
Set pints
To ensure that the Unit 2 trip setpoints were maintained above the value assumed
in the safety analysis the licensee administratively established
the trip settings at.
90.5 percent of MMF. In addition, the TS allowable value was incr'eased from
89.7 percent to 90.2 percent of MMF. This was accomplished
by TS
Interpretation 96-10 which was approved by the PSRC.
Although this trip setting
value was different than the TS specified limit, the licensee considered it acceptable
since they were establishing
a limitthat was more conservative than that specified
by TS.
Since the RCS low flow reactor trip setpoints
are derived based upon
90 percent of the actual measured flow, which was greater than MMF, no change
in equipment settings was required to ensure that the trips occurred at or above
90.5 percent of MMF.
0
-17-
During review of this issue, the inspectors requested
a copy of the safety evaluation
performed prior to changing the RCS low flow trip setpoints.
Following the request,
the licensee Informed the inspectors that a safety evaluation had not been
performed prior to changing the setpoints and that only an LBIE screen had been
performed.
Although it was apparent that the licensee had performed
a detailed analysis
to'rovide
a technical basis for the change
in the trip setpoint, the inspector concluded
that a formal safety evaluation was required in accordance
with 10 CFR 50.59,
prior to implementing the change
in that the setpoint change affected
a value in the
TS.
Following related questions
raised by the NRC associated
with uncertainties
in
performing the primary flow calorimetric at the end of cycle, the licensee changed
the flow determination back to the beginning of cycle to reduce the uncertainties
and in so doing eliminated the need for the increased
Unit 2 reactor trip setpoints.
PSRC TS interpretation 96 10 was subsequently
rescinded by the PSRC.
The failure
to perform a written safety evaluation pursuant to the requirements of
10 CFR 50.59 prior to changing
RCS low flow trip setpoints which are referenced
in
the FSARU is a violation of 10 CFR Part 50.59 (VIO 50-323/96024-03).
It should be noted that the licensee's
PSRC reviewed and approved TS
Interpretation 96-10 without requiring that a formal safety evaluation be
documented.
The PSRC should have required that a formal safety evaluation be .
documented
prior to approval of the change.
Unresolved Item 50-275(323)/96023-04
included potential NRC concerns with the
licensee having changed the performance of a primary flow calorimetric from the
beginning of cycle to the end of cycle. That portion of the unresolved item remains
open and will be tracked as a separate
unresolved
item
(URI 50-275(323)/96024-04).
Closed
Licensee Event Re ort
LER 50-275 96005-00:
potential for flashing in
containment fan cooler units.
This item is being administratively closed since
Revision
1 to the LER has been issued which supersedes
the original LER. Review
of this issue will be documented
in the review of. Revision 1.
Review of FSARU Commitments
A recent discovery of a licensee operating their, facility in a manner contrary to the
FSARU description highlighted the need for a special focused review that compares
plant practices, procedures,
and/or parameters to the FSARU description.
During
the inspection period, the inspectors reviewed the applicable sections of the FSARU
that related to the inspection areas discussed
in this report.
The following minor
inconsistencies
were noted between the wording of the FSARU and the plant
practices, procedures,
and/or parameters
observed
by the inspectors:
0
-18-
Table 7.5-2 of the FSARU specifies an instrument range of 88.5 feet-97 feet
for the containment sump narrow range level instruments.
Actual instrument
range provided on control room indicators LI-940, and LI-941 are
88.5 feet-96.6 feet.
Procedure
EOP E-1.3, Revision 14, Transfer to Cold Leg Recirculation,
contains
a note that directs operators to continue CS for a minimum of two
hours following initiation of recirculation.
The EOP basis document for this
note cites a commitment in Section 6.2 of the FSARU.
Section 6.2 of the
FSARU no longer includes this commitment due to a design change.
IV. Plant Su
ort
R1
Radiological Protection and Chemistry (RRPC) Controls
R1.1
a.
Ins ection Sco
e 71750
The ipspectors observed
a primary coolant sample drawn through the PASS utilizing
the following chemical analysis procedures
(CAPs):
CAP P-1, Revision 1, "PASS Initial Actions"
"~
-CAP P-2, Revision 0, "PASS RCS"
Observed evolutions included, the initial valve lineup and purge of.the lines and
drawing of the sample, the gas stripping and dilution of the sample, and the
dissolved oxygen, hydrogen and conductivity analyses.
Additionally, the inspectors
observed the overall material condjtion of the equipment
in the PASS laboratory and
reviewed the following documents:
AR A0260355, FCV-137 Dual Position Indication
Clearance 53874, Shift Foreman administrative tagout to maintain
'ontinuous flow through Penetration
59B
AR A0419372, Post LOCA Water Supply Pressure
Gage Reading Off-Scale
High
WO R0165335, Functional Test of Containment Hydrogen Analyzer Cell-82
Equipment Control. Guideline 11.1, "PASS"
STP G-14 Rev. 11, "Operability Determination of Post Accident Sampling
Program"
0
1'
-19-
b.
Observations
and Findin s
Primar
Sam
le Observation
The licensee obtains and analyzes
PASS samples weekly.
During the performance
of the sample obtained on Unit 2 on January 23, 1997, the inspectors observed
that the chemistry technician was very knowledgeable
and familiar with both the
equipment andprocedures
utilized to obtain the sample.
The inspectors determined
that the technician's qualifications for obtaining and analyzing
a PASS sample were
current.
The inspectors reviewed chemistry and radiation protection technician
work schedules
and determined that for the month of January 1997 there was at
least one technician assigned
per shift that was qualified to obtain a PASS~sample.
During the CAP P-1 valve lineup performed prior to obtaining a sample, the
inspectors noted that Valve CVCS-2-FCV-137, "Volume control tank liquid sample
isolation to sampling system," position indication showed the valve to be in the
intermediate position (i.e., both open and closed indicators lit). CAP P-1 required
that the control switch for Valve FCV-137 be in the "close" position with the valve
closed.
Chemical and volume control system (CVCS)-2-FCV-137 can bs remotely
.
operated from the PASS room.
The inspectors questioned
the u'se of the position
indication for verification of the valve's position, but was informed by both the
chemistry technician and his supervisor that they were confident that the valve was
closed since the control switch was in the close position, and therefore, no
additional verification of valve position was necessary
prior to continuing with the
sample.
AR A0260355 had been written in March 1992, to document that the valve
position indication for CVCS-2-FCV-137 was inoperable.
Further. investigation
revealed that the valve position indication had not been functional since the valve
had been replaced
in 1990 and that the AR had been assigned the. lowest priority
for corrective. actions (priority 4).
On January 9, 1997, a minor maintenance
had been issued to install position switches and associated
linkage and the work
has been scheduled to be accomplished
on March 12, 1997.
The CAP P-1 initial valve lineup required that Valve NSS-2-9351A, "hot leg loop
1
'solation,"
be closed with its control switch in the re'mote position.
A caution tag
had been hung on the valve control switch which indicated, contrary to the initial
valve lineup, that the valve should be left in the open position.
The valve had been
tagged
as a compensatory
measure following identification of a concern for the
potential overpressurization
of the line following a LOCA in response
to NRC Generic Letter 96-06, "Assurance of Equipment Operability and Containment
Integrity During Design Basis Accident Conditions."
The inspectors questioned
both the technician and supervisor after the valve lineup
.
was completed with the valve being left in the open position.
The caution tag had
been hung'n January
15, 1997; however, the procedure
had not been revised at
0
-20-
the time of the sample to reflect the altered system alignment.
Following this issue
being raised by the inspectors, the licensee initiated a change to revise this step of
the procedure
as well as the restoration step following the sample to recognize that
the valve may need to remain open.
During performance of the procedure the inspectors noted that at Step 6.6.4 the
chemistry technician operated Valve V-2 at the chemical analysis panel when the
procedure required operation of RC-V-2 at the liquid sample panel.
Following
questioning by the inspectors the technician corrected his mistake and contin'ued
with the sample.
There were no adverse consequences
as a result of this action
and had the inspectors not pointed out the error, it would have been apparent to the
technician, following completion of the next step in the procedure,
due to the
inability to establish flow through the sample line.
During the gas stripping operation, the inspectors noted that the procedure required
that Valve RC-V-9 be closed, which per the procedure
required that the valve be
positioned from the 3 o'lock position to the 6 o'lock position.
When performing
the procedure, the technician closed the valve by turning it in the counterclockwise
position to.the 12 o'lock position.
The labeling on the panel indicated that the
closed position for the valve corresponded
to the 6 o'lock position.
Subsequent
investigation of questions
raised by the inspectors regarding the procedure,
revealed
that the valve could not physically be repositioned
as specified by procedure,
and
that the label on the mimic system diagram was incorrect.
The licensee inspected the valve installation and found that the valve handle had
been altered and the valve could no longer. be positioned
as specified in the
procedure.
The licensee has evaluated the current installation as acceptable
and
has revised the procedure
and the system mimic diagram to be'consistent
with the
required valve positioning.-.
'I
PASS E ui ment Availabilit
Technical Specification 6.8,4.e requires that.the licensee establish
a program which
will ensure the capability.to obtain and analyze reactor coolant, radioactive iodines
and particulates
in plant gaseous
effluent, and containment atmosphere
samples
under accident conditions.
The inspectors reviewed the availability of the PASS
equipment for the time period between September
1 and December 31, 1996.
During portions of this time period, for each unit, from
1 to 3 of the 10 principal
methods of analysis were out of service.
Overall, for Unit 1 at least one of the
principal methods of analysis was inoperable 30 percent of the time, however,
qualified alternate methods analysis were available.
For Unit 2, at least one of the
principal methods of analysis was inoperable 50 percent of the time and 30 percent
of the time there was not a qualified backup method available.
0
'
-21-
E ui ment Condition
The containment hydrogen analyzer Cell 82 was out of service for calibration during
the time the inspectors observed the PASS sample analysis.
In addition, following
the sample, the Unit 2 reactor coolant dissolved hydrogen monitor (Cell 1109) was
declared inoperable since the sample results deviated greater than 5 cc/kg from
other sample results.
It was also noted that the licensee was utilizing a pressure
gage that had been overranged.
Conclusions
P1
The chemistry technician demonstrated
detailed knowledge of the maintenynce
and
operation of the PASS system.
Several material problems and procedural
inaccuracies
were noted that had either not previously been identified by the
licensee or had existed fora significant period of time without being corrected.
These findings indicated
a need for increased
management
attention to the
operation and maintenance
of the PASS system,
as well as t';ie need for a
questioning attitude when valve position indication'is not working properly.
Conduct of Emergency Planning Activities
Emer enc
Plannin
Durin
Rainstorms That Im acted Site Access
Ins ection Sco
e 71750
The inspectors observed the response
of the licensee's emergency
response
organization during rainstorms that resulted in mudslides that blocked access to the
site for approximately 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br />. Licensee response
was noted also when the
deterioration of the access
road threatened
vehicle access
and buried
communication lines utilized for offsite communications
and emergency response.
b.
Observations
and Findin s
On January 3, 1997, a mudslide on Hartford Drive (outside the plant boundary)
interrupted normal vehicle access to the site for a period of approximately 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br />.
During.the time the road was secured, the licensee declared an Unusual Event due
to the loss of capability to evacuate
plant personnel,
loss of California Department
of Forestry firefighting access,
and the inability to staff, the emergency operations
facility with the required plant staff. The licensee worked closely with outside
organizations to take actions to clear the road as quickly as possible.
In addition,
emergency planning personnel closely coordinated with operations management
to
develop contingency plans for dealing with the blocked road.
During that same time
pe'riod, licensee emergency planning personnel
made contact with NRC emergency
planning personnel to discuss the situation and planned response.
0'r
'
-22-
On January 27, 1997, following more rainstorms,
a section of the site access
road
at approximately the 0.7 mile point shifted causing cracking of the pavement
and
settling of a section of the road bed.
Continued shifting of the hillside under the
road. created the potential to interrupt normal access to the site via the access
road
and threatened
buried telecommunications
lines.
Emergency planning supervisors
worked closely with plant management
to assess
the potential issues associated
with the loss of the use of the access
road.
Contingencies for communications
were also considered
in the event of the loss of the buried communications
lines
and, efforts were undertaken to relieve as much stress on the lines as possible.
Work on the road was performed continuously until the road area was stabilized by
diverting the hillside drainage and the addition of fill.
c.
Conclusions
Emergency planning supervisors worked closely with plant management
and outside
organizations
on two separate
occasions to develop contingency actions for dealing
with the interruption of the normal access route to and from the >'ite. Actions for
dealing with an isolated site were prudent and well thought out and demonstrated
an appropriate level of concer'n and consideration for the impact on the site
Plant'ousekeeping
H1.1
Paintin
and Preservation
a.
Ins ection Sco
e 71750
The inspectors toured the areas both inside and outside of th'e radiologically
controlled area and in the turbine building during normal inspection activities.
b.
Observations
and Findin s
The overall painting and preservation of both equipment spaces
and equipment has
improved.
The licensee has put forth a substantial effort to improve the
preservation
and cleanliness
in a number of different areas throughout the pfant
including the Unit 1 emergency
diesel generator rooms.
This effort has resulted in
the improved appearance
of the facility. Continued efforts are needed to improve
equipment material condition and reduce the backlog of equipment deficie'ncies.
c.
Conclusions
Efforts to improve the cleanliness of the facility and paint equipment rooms and
equipment have improved the appearance
of the facility; however, no significant
change
in the overall condition of safety-related
equipment has been noted.
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V. Mana ement Meetin
s
X1
Exit Nleeting Summary
The inspectors presented
the inspection results to members of licensee management
at the
conclusion of the inspection on February 4, 1997.
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.
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ATTACHMENT
PARTIAL I IST OF. PERSONS CONTACTED
Licensee
M. J. Angus, Manager, Nuclear Safety Assessment
and Licensing
J. R. Becker, Director, Operations
T. L. Grebel, Director, Regulatory Services
J. A. Hays, Director, Chemistry and Environmental Services
D. B. Miklush, Manager, Engineering Services
J. E. Molden, Manager, Operations Services
M. N. Norem, Director, Mechanical Maintenance
D. H. Oatley, Manager, Maintenance
Services
R. P. Powers, Manager, Vice President
DCCP and Plant Manager
R. L. Thierry, Acting Director, Licensing and Design Basis
D. A. Vosburg, Director, Nuclear Steam Supply Systems
Engineering
E. S. Wessel, Chemical Engineer, Chemistry and Environmental operations
B. A. LoConte, Engineer, Primary Systems
Engineering
NRC
S. D. Bloom,
Diablo Canyon Project Manager
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INSPECTION PROCEDURES USED
IP 37551:
IP 61726:
'IP 62707:
IP 71707:
IP 92901:
IP 92902:
IP 92903:
Onsite Engineering
Surveillance Observations
Maintenance
Observations
Plant Operations
Plant Support
Followup - Plant Operations
Followup - Maintenance
Followup - Engineering
ITEMS OPENED, CLOSED, AND DISCUSSED
~Oened
50-275;323/96024-01
appropriateness
of EOP decision point to direct
operators to an ECA
50-275;323/96024-"02
failure to evaluate revision to design criteria
memorandum
. 50-323/96024-03
failure to perform a 50.59 evaluation prior to changing
Unit 2 reactor trip setpoints
50-275(323)/96024-04
Closed
performance of primary flow determination at the end'of
cycle
50-275(323)/96023-04
50-275;323/9201 6-01
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change of RCS flow determination from beginning of
~
cycle to end of cycle without formal safety evaluation
loading of rigging equipment beyond its safe working
load
50-275/96005-00
Discussed
LER
potential for flashing in containment fan cooler units
50-275;323/96021-07
non-conservative'ssumptions
in timing of switchover
to cold leg recirculation
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LIST OF ACRONYMS USED
."-CV
FSARU
LBIE
LER
'OCA
LOF
MMF
PAMS
POA
PSRC
RV
SCMM"
.SSER 9
TS
safety evaluation report
action request
chemical analysis procedure
chemical and volume control system
design criteria memoranda
emergency contingency action
emergency operating procedure
flow control valve
Final Safety Analysis Report Update
licensing basis impact evaluation
licensee event report
level indicator
loss of coolant accident
loss of flow
minimum measured flow
maintenance
procedure
postaccident
monitoring system
postaccident
sample system
public document room
prompt operability'ssessment
plant staff review committee
relief valve
refueling water'storage
tank
subcooling margin monitor.
supplement
9 to the,Diablo Canyon
Technical Specification
.
work order.
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