ML16342D491
| ML16342D491 | |
| Person / Time | |
|---|---|
| Site: | Diablo Canyon  |
| Issue date: | 12/04/1996 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML16342D489 | List: |
| References | |
| 50-275-96-21, 50-323-96-21, NUDOCS 9612100275 | |
| Download: ML16342D491 (60) | |
See also: IR 05000275/1996021
Text
ENCLOSURE 2
U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
Docket Nos.:
50-275, 50-323
License Nos.:
DPR-SO, DPR-82
Report No.:
50-275/96021, 50-323/96021
Licensee:
Pacific Gas and Electric Company
Facility:
Diablo Canyon Nuclear Power Plant, Units
1 and 2
Location:
Dates:
7 1/2 miles NW of Avila Beach
Avila Beach, California
September 29, 1996, to November 9, 1996
Inspectors:
Approved By:
M. Tschiltz, Senior Resident Inspector
S. Boynton, Resident Inspector
M. Runyan, Reactor Inspector, Region IV
C. Myers, Reactor Inspector, Region IV
D. Allen, Reactor Inspector, Region IV
R. Huey, Acting Chief, Branch E
Division of Reactor Projects
ATTACHMENT:
Supplemental Information
9612100275
961204
ADQCK 05000275
8
)
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EXECUTIVE SUMMARY
Diablo Canyon Nuclear Power Plant, Units
1 and 2
NRC Inspection Report 50-275/96021; 50-323/96021
~Oeretione
PGRE failed to perform safety evaluations,
in accordance with 10 CFR 50.59 when
revising the emergency operating procedure
(EOP) for transferring the emergency
core cooling system (ECCS) from the injection to recirculation mode following a loss
of primary coolant.
As a result, no evaluation was performed to determine if the
differences between the EOP and the Updated Final Safety Analysis Report (UFSAR)
constituted an unreviewed safety question.
An apparent violation was identified
(Section 01.2).
Operators failed to recognize, for existing plant conditions, that removal of a
centrifugal charging pump (CCP) from service required entry into a Technical
Specification (TS) action statement for the charging pumps approximately 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />
into the allowed 72-hour action time. This was considered to be an example of
operator inattention to detail.
Although no violation of (TS) requirements occurred,
insufficient corrective actions were taken to address this issue until questioned by
the NRC (Section 01.3).
Maintenance
Operators did not document a sticking solid state protection system test reset
switch, following identification of the problem during routine surveillance testing.
A
noncited violation was identified (Section M1.2.1).
Performance criteria established for main steam safety valves (MSSVs), in
accordance with the maintenance
rule, did not adequately define the valve
performance necessary to assure that the MSSVs were capable of performing their
intended safety function. A violation was identified (Section M8.1).
The licensee identified that MSSVs were incorrectly set during periodic testing due
to setpressure
inaccuracy introduced by the use of valve specific correction factors.
As a result, on 53 different occasions,
MSSV's were returned to service set outside
of the a1 percent tolerance required by TS. A noncited violation was identified
(Section M8.1).
Enrnineering
~
Three examples of a weakness
in the licensee's
procedure review and revision
process were identified. The examples involved conflicting requirements for control
of charging pumps in the Unit 2 procedure for cooldown to cold shutdown (Section
0
-3-
01.3), inaccurate reference to TS requireme'nts
in a local leak rate testing procedure
(Section M1.2.2), and inappropriate deletion of steam flow/feed flow mismatch
setpoint calibrations from a surveillance procedure (Section M1.2.3).
~
The Plant Staff Review Committee (PSRC) inappropriately approved
a TS
interpretation which, although meeting the intent of the TS, allowed measured,
controlled leakage in excess of the 40 gpm limit specified in the TS (Section E8.1).
Careful monitoring of residual heat removal (RHR) pump oil additions by the system
engineer identified oil leakage which identified a pump operability problem that was
effectively evaluated and corrected (Section E1.1).
0
Re ort Details
Summar
of Plant Status
Unit
1 began this inspection period at 100 percent power.
On November 3, the unit was
curtailed to 50 percent to clean the main condenser waterbox.
The unit was returned to
100 percent power on November 4, and remained there for the balance of the inspection
period.
Unit 2 began this inspection period at 100 percent power.
On November 2, power was
reduced to 50 percent, when several of the reheat stop valves failed to reopen during
periodic surveillance testing.
Following associated
repairs, the unit was returned to
100 percent power on November 3, and remained there for the balance of 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.
Operators were knowledgeable of the status of plant
equipment.
Inspectors noted that there continues to be approximately 190 Action
Requests
(ARs) written on monitored equipment, controlled and/or operated from
the control room.
In discussions with licensee management,
the inspector
confirmed that PGSE has an ongoing initiative to reduce the number of outstanding
control room ARs. The licensee's
planned actions to actively monitor and track the
backlog of control room deficiencies, appeared to be both warranted and
appropriate.
01.2
EOP E-1.3 Transfer to Cold Le
Recirculation
a.
Ins ection Sco
e 71707 37551
F
As part of a review of the RHR system, the inspector reviewed the licensee's
emergency procedure for transition from the injection mode to the cold leg
recirculation mode following a loss of primary coolant.
The review included the
following documents:
UFSAR, Section 6.3
Procedure
E-1.3, Rev. 14, "Transfer to Cold Leg Recirculation"
Design Criteria Memorandum S-9, Safety Injection System
NUREG-0675, Safety Evaluation Report related to the operation of Diablo
Canyon Nuclear Power Station Units
1 and 2, Supplement 9.
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Observations
and Findin s
Regulatory Guide (RG) 1.70, Revision 1, "Standard Format and Content of Safety
Analysis Reports for Nuclear Power Plants," specifies that the UFSAR include a
discussion of the ECCS capability to meet functional and performance requirements
over both the short and long term duration of an accident, including specific
features (e.g. switchover to different coolant delivery paths) provided to meet such
requirements.
In addition, RG 1.70 specifies that (1) the UFSAR shall identify all
manual actions required to be taken by an operator in order for the ECCS to perform
properly; and (2) a discussion shall be included in the UFSAR to describe the
information available to the operator, the time delay during which the operator's
failure to act properly will have no unsafe consequences,
and the consequences
if
the action is not performed.
Section 6.3.1.4.4.2 of the UFSAR, describes the changeover of ECCS from injection
mode to recirculation mode after a loss of primary coolant.
The section describes
that upon receipt of the refueling water storage tank (RWST) low level alarm
(33 percent),
a signal is provided to trip both RHR pumps.
The remainder of the
changeover sequence
is accomplished manually by the operator from the control
room. The sequence
of steps for the manual changeover
and the approximate times
to complete those steps are provided in Tables 6.3-4 and 6.3-5. As shown in
Table 6.3-5, the total time required to switchover to the cold leg recirculation mode
is approximately 10 minutes, based upon the sequence
of steps delineated
in
Table 6.3-4.
The time available to the operators is also described by the timing
difference between reaching the RWST low level alarm and the low-low level alarm.
Table 6.3-5 states these times as 17 minutes and 39 minutes, respectively, for an
available time of 22, minutes.
In Supplemental Safety Evaluation Report 9, dated June 1980, the NRC reviewed
the licensee's
analysis of available time for operator response
and the switchover
actions required for cold leg recirculation.
The NRC concluded that the proposed
manual procedure,
as described
in the UFSAR, with the automatic trip of the RHR
pumps was acceptable.
The inspectors noted the staff's acceptance
of the manual switchover was
conditional in that it required the licensee to more fully automate the switchover
process.
The details of the requirement to automate the transfer to cold leg
recirculation were specified in a letter from A. Schwencer, Chief, Licensing Branch
No. 3, Office of Nuclear Reactor Regulation, to M. Furbush, Vice President and
General Counsel, Pacific Gas and Electric Company, dated May 7, 1980.
The
licensee responded
in a letter dated May 28, 1980, requesting clarification on the
requirement and a meeting with the NRC staff.
Subsequent
to the May 28 letter,
no action was taken by the licensee to more fully automate the ECCS transfer to
cold leg recirculation.
To date, the licensee has been unable to locate
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documentation regarding any further action on this matter.
The licensee has been
requested to address this matter in the predecisional enforcement conference.
Desi
n Criteria Memorandum
Design Criteria Memorandum (DCM) S-9, Safety Injection System, states that during
the licensing process, the information in the UFSAR Tables 6.3-4 and 6.3-5 were
developed to demonstrate that the manual switchover could be performed before
the operating ECCS pumps lost suction from the RWST. The DCM further states
that PGRE calculation N-095 determined the minimum time available for switchover
to cold leg recirculation.
The calculation determined that with both ECCS trains
operating, the RHR pumps trip on RWST low level at 13 minutes and the RWST
low-low level is reached
in 28 minutes.
This provides a minimum available
switchover time of 15 minutes.
Although these timeframes differ from those in
Table 6.3-5, the table was never updated to reflect the current calculation.
Emer enc
Procedure
Another procedure,
EP OP-1.3, which was also entitled "Transfer to Cold Leg
Recirculation," was implemented in 1984 to incorporate the Westinghouse Owner's
Group Emergency Response
Guidelines for the transition of ECCS systems from
injection to cold leg recirculation.
Although the procedure history sheet for
Revision 0 of EP OP-1.3 identified that the procedure was described in the UFSAR,
the differences between the procedure described
in the UFSAR and EP OP-1.3 were
not evaluated
in accordance with 10 CFR 50.59.
In 1985, EOP E-1.3 was issued and superseded
Procedure
EOP E-1.3
is the current implementing procedure for the transition of ECCS from the injection
mode to the cold leg recirculation.
A review of Procedure
EOP E-1.3 found that it
differed in content and sequence
from the procedure described
in the UFSAR.
Review of the procedure history sheets,
associated with the original version of
Procedure
EOP E-1.3 and its 14 subsequent
revisions, identified that evaluations of
the changes were required in accordance with 10 CFR 50.59, although none had
been performed.
Based upon other previously raised concerns regarding the accuracy of the UFSAR,
the licensee had previously initiated a programmatic review of all sections of the
UFSAR. Although this review was completed and areas requiring change identified,
it failed to identify the differences between Section 6.3 of the UFSAR and
EOP E-1.3.
The significance of the licensee's failure to evaluate the changes against the
licensing basis in the UFSAR, is that several of the changes increased the time it
would take operators to complete the switchover from injection to recirculation
following a loss of coolant accident (LOCA). This reduced the time margin available
before the ECCS pumps would lose suction from a low-!ow water level condition in
the RWST (4 percent level). That time margin was, in part, the basis for the NRC's
acceptance
of the manual switchover procedure
as documented
in SSER 9.
The inspector questioned the licensee on the impact of the changes to Procedure
EOP E-1.3, upon the times listed in Table 6.3-5 of the UFSAR.
In response to this
question, the licensee performed a prompt operability assessment
(POA) that
evaluated the differences between the UFSAR and EOP and analyzed the time
available to the operator to complete the switchover.
The evaluation noted that
changes
had been made which added steps to the EOP and changed the sequence
of some steps.
The POA, documented
in AR A0416238, determined that with the
conservatisms
in the UFSAR removed, it would take 16.2 minutes to empty the
usable volume of the RWST following the automatic trip of the RHR pumps.
The
POA noted that gas binding of the CCP, containment spray pumps, and safety
injection pumps would occur if the RWST were to empty before the transfer to cold
leg recirculation was completed.
This condition could potentially damage the pumps
and would necessitate
venting of the pumps suction piping.
Corrective Actions
In response to the inspectors'oncerns
regarding the differences between
Procedure
EOP E-1.3 and the UFSAR, and the impact of the differences on the
operator's ability to transfer to cold leg recirculation prior to reaching
a low-low
level condition in the RWST, the licensee initiated several corrective actions.
To
ensure the transfer could be performed in an acceptable
period of time (i,e. prior to
receiving the RWST low-low level alarm), the Operations Director issued
a standing
order directing that the transition to EOP E-1.3 not be delayed for the conduct of a
tailboard, and that stroking of valves need not be completed prior to proceeding to
the next step.
The guidance in the standing order for valve stroking is consistent
with the Westinghouse
Owners Group Emergency Response
Guidelines Users
Guide.
Utilizing the guidance, several operating crews demonstrated,
on the plant
simulator, that the switchover could be performed in approximately 10 minutes.
Based upon the questions and concerns raised by the inspector, the licensee has
initiated another comprehensive review of the UFSAR to determine what other
operational procedures
or tasks are described therein, and to evaluate their
consistency with existing plant procedures,
as applicable.
The licensee performed a
10 CFR 50.59 review of the changes
and determined that an unreviewed safety
question does not exist.
Additionally, the licensee is conducting
a review of EOP
E-1.3 in order to r'evise the procedure
as needed.
Conclusions
The compensatory actions taken by the licensee, for the implementation of
Procedure
EOP E-1.3, adequately ensured that the transfer to cold leg recirculation
could be completed in a time frame consistent with the UFSAR. However, the
multiple failures (from 1984 to 1996) of the licensee to evaluate the impact of the
revisions to Procedure
EOP E-1.3 on the plant's licensing basis, is indicative of a
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potentially significant problem with the implementation of the requirements of
Additionally, as a result of differences between the EOP E-1.3 and
the UFSAR, an extensive evaluation was required for the licensee to establish
a
reasonable
expectation that an unreviewed safety question did not exist.
This is an
apparent violation of 10 CFR 50.59 (EEI 50-275;323/96021-01).
01.3
Confi uration Control of CCPs
Ins ection Sco
e 71707
The inspector reviewed the licensee's controls of CCPs during shutdown conditions.
This review included the following procedures:
STP l-1A, Revision 58, Routine Shift Checks Required by Licenses.
OP L-5, Revision 24, Plant Cooldown From Minimum Load to Cold
Shutdown.
OP1.DC17, Revision 2A, Control of Equipment Required by the Plant TS.
OP1.DC37, Revision 4B, Plant Logs.
OM7.ID1, Revision 6, Problem Identification and Resolution.
b.
Observations
and Findin s
Technical Specification 3.1.2.4 requires two charging pumps to be operable while
the plant is in Modes 1-4. TS 3.1.2A also requires that one of the CCPs be
rendered inoperable when the lowest reactor coolant system (RCS) cold leg
temperature
is equal to less than 270'F.
TS 3.1.2.3 requires one charging pump to
be operable with an operable emergency power source when the plant is in Modes
5 and 6. When in Modes 5 and 6, the TS further requires that all CCPs, other than
the required operable pump, be rendered inoperable.
Both TS surveillance
requirements 4.1.2.3.2 and 4.1.2.4.2 require all of the CCPs, other than the
required operable charging pump(s), to be verified inoperable every 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> by
verifying that the motor breaker DC control power is deenergized.
Operating Procedure
(OP) L-5 describes the sequence
of steps necessary to bring
the plant to a cold shutdown condition. Instructions in OP L-5 provide for removing
the charging pumps from service in accordance with TS 3.1.2.3 and 3.1.2.4 to
ensure low temperature overpressure
protection.
Step 6.2.20 directs operators to
disable one of the CCPs upon entry into Mode 4 with RCS cold leg temperature
greater than 270'F.
Step 6.3.10 directs operators to disable a second charging
pump while in Mode 5 prior to RCS temperature falling below 161.9'F.
-6-
0 erator Reco
nition of Entr
Into TS Action Statement
A review of operating logs for the Unit 2 shutdown for refueling outage 2R7 found
that, prior to the commencement of the shutdown, the PDP was removed from
service for maintenance.
During the RCS cooldown in Mode 4, operators rendered
CCP 2-2 inoperable in accordance with Procedure
OP L-5 and TS 3.1.2.4, prior to
RCS cold leg temperature falling below 270
F. However, the operators failed to
recognize that with the PDP inoperable, they no longer met the limiting condition for
operation of TS 3.1.2.4.
Entry into the action statement for TS 3.1.2.4 was not
identified until two days later when a new operating crew came on shift. At that
time, a TS tracking sheet was initiated in accordance with Procedure OP1.DC17,
and appropriately backdated to the time the CCP was rendered inope'rable.
The
action statement for TS 3.1.2.4 allows 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> to restore
a charging pump to
operable status.
The plant entered Mode 5 prior to the 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> action time being
exceeded,
and therefore,
a violation of the TS did not occur.
The licensee initiated an event trending record (ETR) to track this issue for adverse
trends.
The ETR was evaluated by the Operations Director who determined that an
AR was not required.
Procedure OM7.ID1 provides guidance on what problems
require documentation in an AR. However, no specific examples are provided for
the failure of operators to recognize and enter into a TS action statement.
The
inspectors questioned the Operations Manager and Operations Director on the need
to utilize the AR process to ensure that the operators'ailure
to recognize entry into
a TS action was properly dispositioned for corrective action.
The Operations
Manager noted that, in hindsight, the issue should have been tracked through the
AR process recognizing that Procedure
OM7.ID1 did not specifically require it. He
further noted that it was his expectation that if there are similar occurrences
in the
future, an AR would be initiated.
The licensee recently implemented programmatic actions to improve operations
performance.
These actions, described in the operations quality plan, include 1)
improved formality in the control room, 2) development of crew performance
metrics, 3) reemphasis
on the need for attention to detail in the control of TS
required equipment, and 4) implementation of three-way communications.
These
actions address,
in part, the operators'ailure to enter into the action statement for
TS 3.1.2.4 and should preclude recurrence of similar problems.
OP L-5 Inconsistenc
with TS
During the review of Procedure
OP L-5, it was noted that Step 6.3.10 in the Unit 2
procedure differed from Step 6.3.10 in the Unit 1 procedure.
Specifically, the Unit
2 procedure contained an additional option for rendering the second charging pump
inoperable by closing the manual discharge isolation valve for the pump.
This
option, which was not provided in the Unit 1 procedure, was inconsistent with the
TS surveillance requirements of 4.1.2.3.2 which specify that the pump be rendered
inoperable by deenergizing
DC control power to the motor breaker.
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Step 6.3.10 also requires the inoperable pump to be caution tagged in accordance
with Attachment 9.4 of the procedure.
Attachment 9.4 of the Unit 2 procedure did
not provide an option for the operators to caution tag the manual discharge isolation
valve. Additionally, Procedure
STP l-1A, which implements the surveillance
requirements of TS 4.1.2.3.2, only directs the operator to verify that the breaker
DC control power is deenergized.
Therefore, it is likely that an operator who chose
the inconsistent option would have uncovered the problem during the course of
performing Attachment 9.4 or performing STP I-1A. The inspectors noted no
instances of power not being deenergized for past occasions requiring the charging
pump to be rendered inoperable.
During discussions with individuals in the operations department, it was noted that
the additional option in the Unit 2 procedure had been inadvertently added during a
recent revision, and was not identified as conflicting with the TS during the review
and approval process.
Since this issue was brought to the attention of PGRE management,
an on-the-spot
change to the Unit 2 Procedure
OP L-5 was written and issued to remove the option
of closing the manual discharge isolation valve.
Conclusions
Operators did not recognize entry into a TS action statement for the charging pumps
for approximately 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> during the unit shutdown for refueling outage 2R7. This
was considered by the inspectors to indicate inattentive watchstanding by both the
control room operators and operations shift management.
Although the licensee
has taken corrective actions to address the general area of inattentive
watchstanding,
actions taken in response to this specific event were considered
weak.
The incorporation of conflicting requirements into Procedure
OP L-5 for Unit 2 was
considered
a weakness
in the implementation of the licensee's
procedure revision
and review process.
08
lVliscellaneous Operations Issues (92901)
08.1
Closed
Violation 50-323 95018-02: failure to document the basis for the
operability of a degraded reactor cavity sump level indication.
The licensee
determined the root cause of the violation to be personnel error with regards to the
assessment
and handling of the degraded condition.
The licensee's corrective
actions included discussions of the event with other shift supervisors.
Expectations
for involving management
earlier in the operability determination process
and
making timely and conservative operability determinations were reemphasized.
The
licensee also implemented several other corrective actions, including a design
change to the level instrument, to improve the reliability of the sump level
indication.
The licensee's actions to address the root cause of the violation appear
to be adequate to prevent its recurrence.
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II. IVlaintenance
M1
Conduct of Maintenance
M1
~ 1
Maintenance Observations
Ins ection Sco
e 62707
The inspectors observed
all or portions of the following work activities:
C0146283
Replace Valve MS-1-100 (Unit 1)
R0164338
Routine Maintenance of Station Battery Charger 1-2 (Unit 1)
C0147463
Repair Seal Water Pipe to Pump Leak on Auxiliary Feedwater
Pump 2-1 (Unit 2)
C0147S02
Replace Pressurizer Heater Breaker 52-23E-05 (Unit 2)
b.
Observations
and Findin s
The inspectors found the work performed under these activities to be properly
accomplished
in accordance with procedures.
All work observed was performed
with the work package present and in active use.
Technicians were experienced
and knowledgeable of their assigned tasks.
The inspectors observed the system
engineer monitoring job progress during the replacement of the pressurizer heater
breaker.
The Technical Maintenance technician appropriately contacted the system
engineer to resolve problems encountered
during the testing of the replacement
breaker.
When applicable, appropriate radiation control measures were in place.
M1.2
Surveillance Observations
a.
Ins 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 P-CSP-12, Revision 3, Routine Surveillance Test of Containment Spray
Pump 1-2"
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STP V-313B, Revision 9, Full Stroke Exercise of Containment Spray Valve
CS-9001 B
STP P-RHR-11, Revision 4, Routine Surveillance Test of RHR Pump 1-1
b.
Observations
and Findin s
The inspectors found that the surveillances were scheduled
and performed at the
required frequency.
The procedures governing the surveillance tests were
technically adequate,
and personnel performing the surveillance demonstrated
an
adequate
level of knowledge.
The inspectors also noted that test results were
appropriately dispositioned.
M1.2.1
Solid State Protection S stem
SSPS
Train A Slave Rela
K645 Test
Unit 1
a.
Ins ection Sco
e 61726
The inspector observed the performance of STP M-16HA1, Revision 0, "Slave Relay
Test for Operation of Interposing Relay for Containment Spray Pump 2 (K645AX)."
The surveillance satisfies, in part, the licensee's commitment to test slave relays on
a quarterly basis.
b.
Observations
and Findin s
During performance of STP M-16AH1, SSPS test Reset Switch S821 stuck in the
test position and did not spring return to normal as required by procedure.
The
operator, with the concurrence of the senior control operator, manually repositioned
the switch to normal.
Switch S821 is in a test circuit for testing a portion of the
SSPS circuitry and is only utilized during testing and, therefore, does not affect the
operability of the SSPS.
Operators were able to complete the test and restore the
system to normal by the operator manually repositioning the switch. Subsequently,
the day following the completion of the surveillance, the inspector noted that the
operators had not documented the test reset switch deficiency on an AR. After the
inspector brought this to the attention of the licensee,
an AR was written.
c.
Conclusions
The failure to write an AR is a violation of OM7.ID1, "Problem Identification and
Resolution - Action Requests."
This failure constitutes
a violation of minor
significance and is being treated as a noncited violation consistent with Section IV
of the NRC Enforcement Policy (NCV 50-275/96021-02).
M1.2.2 Containment Pressure
Vacuum Relief Penetration Leakrate Test
a.
Ins ection Sco
e 61726
The inspector observed engineering personnel perform Surveillance Procedure
,l
t
-1 0-
STP V-663, "Penetration 63 Containment Isolation Valve Leak Testing," for the
Unit 1 containment pressure
and vacuum relief penetration.
Observations
and Findin s
The test personnel were knowledgeable of the test requirements
and were
observed briefing onshift operators prior to starting the test.
They used the
current revision of the procedure which had been issued for use that
morning. The procedure was performed as written with no difficulties. The
Portable Leak Test Monitor was within its required calibration frequency.
The results of the test were well within the established
acceptance
criteria
and consistent with the results of previous test results on the same
The inspectors noted a problem involving Surveillance Procedure
STP V-663.
Procedure STP V-663 referenced TS 4.6.1.2.d as the applicable TS which
requires that containment isolation valves be tested with gas at P, of
47 psig. Technical Specification 4.6.1.2.d was deleted by TS
Amendment 110, approved March 1, 1996. Amendment 110 implemented
the new Option B - Performance
Based Requirements, of 10 CFR Part 50,
Appendix J, which have been incorporated into the licensee's Containment
Leakage Rate Testing Program.
A review of this program indicated that the
test requirements for containment isolation valves had not changed and,
therefore, the correct test was performed even though the incorrect TS was
referenced
in the surveillance procedure.
The inspector reviewed the licensee's computer based TS tracking system
entry made following the venting of the containment.
The TS tracking sheet
for this surveillance was reviewed by the inspectors and was also found to
reference the deleted TS surveillance.
As required by the administrative procedure for TS change process, the
licensee had initiated actions to change both the TS tracking sheet and the
surveillance procedure.
The reviews of the surveillance procedure and TS
tracking sheet had failed to identify the need to change the TS reference.
The licensee has since revised the surveillance procedure and the TS tracking
sheet to reflect the present requirements.
c.
Conclusions
The leakage rate test was performed correctly and the test results were
within the acceptance
criteria of the test procedure.
The technical
requirements contained in the current TS and the Containment Leakage Rate
Testing Program were satisfied, therefore, the correct test was performed
and there was no safety consequence
as a result of the incorrect reference
to TS 4.6.1.2.d.
However, the failure to identify the need to correct the TS
-11-
tracking sheet and surveillance procedure
is indicative of inattention to detail
during the review process.
M1.2.3 Main Steam Flow Instrumentation Surveillance
a.
Ins ection Sco
e 71707 61726
During control room observations, the inspectors observed the main control
board instrumentation and recorder traces for differences between channels
monitoring the same parameter
in order to detect inoperable channels.
b.
Observations
and Findin s
The inspector noted that the Unit 1 Loop 3 main steam flow indication in the
control room read approximately 10 percent less than the feedwater flow for
the same steam generator.
The steam flow and feedwater flow indications
on the other loops for both Units
1 and 2 were in close agreement.
The licensee investigated and determined the steam flow instrumentation had
not been normalized to the feedwater flow following the most recent plant
startup.
The normalization had previously been performed with the steam
flow/feedwater flow mismatch setpoint calibration performed in Surveillance
Procedure STP-42.
This setpoint had been deleted from the procedure as
part of the "Eagle 21" modification to the reactor protection system, and the
normalization of steam flow was not relocated to another procedure.
The licensee performed a POA and determined the low steam flow indication
had no impact on any safety system or safety function. These channels
provide indication and alarms only, and the normalization of the steam flow
instrumentation is desirable to provide useful indication to the operator.
The
steam flow indications are used by the operators in their abnormal operating
procedure for a loss of main feedwater pump.
Instrumentation in the Eagle
21 reactor protection system provides the input to accomplish the required
safety furictions and provide a redundant source of indication and alarms.
The licensee is preparing a procedure and plans to normalize all steam flow
instrumentation channels.
The inspectors reviewed the operability
assessment
and found it to be satisfactory and the proposed corrective
actions to be appropriate.
C.
Conclusions
The inappropriate deletion of requirements to normalize the steam flow
instrumentation is considered
a weakness
in the licensee's
procedure review and
revision process.
K ~ g
~
-1 2-
Miscellaneous Maintenance Issues (92902)
'8.
1
Closed
URI 50-275 96016-07: failure to set MSSVs in accordance with TS
requirements.
Following the dual reactor trip on August 10, 1996, three MSSVs,
two on Unit 2 (RV-4 and RV-8) and one on Unit 1 (RV-7), lifted below the lift
pressure at which they were thought to have been set.
Operators responded
by
adjusting the setpoint for the 10 percent atmospheric steam dumps to lower steam
generator
(SG) pressure to reseat the MSSVs.
These actions were not specifically
covered by procedure, but were considered to be prudent and warranted in order to
limitthe transient following the dual unit trip. The premature lifting of MSSVs did
not result in excessive cooldown.
Prior to the dual unit trip, maintenance
personnel had completed surveillance testing
of Unit 1 Lead
1 MSSVs using an hydraulic assist test device manufactured by AVK
Industries.
The testing was conducted in accordance with Maintenance Procedure
M-4.18, Revision 14, "Verification of Lift Point Using Ultra Star Assist Devise for
MSSVs." The TS requires that MSSVs set at 1065 psig must be set within -2
percent to + 3 percent of the nominal liftsetting and that MSSVs set at 1078,
1090, 1103, and 1115 psig be set within k3 percent of the liftsetting.
In
addition, the TS requires that the MSSVs be reset to within a 1 percent of their
specified liftsetting following main steam line code safety valve testing.
During
review of the MSSV test data the licensee identified that maintenance
personnel
had inadvertently utilized Unit 2 Lead
1 MSSV correction factors when testing Unit
1 Lead
1 MSSVs.
Use of the wrong correction factors resulted in the "as-left"
setting for three of the five valves being greater than +/-1 percent of the liftsetting
specified.
The licensee subsequently conducted MSSV surveillance testing on all MSSVs for
both Units
1 and 2 to ensure they were set to the TS required liftsettings. This
testing was conducted using Trevitest equipment in place of the AVK Ultra Star test
equipment.
Test results indicated that although the three Unit 1 Lead
1 MSSVs had
not been within the +/-1 percent of the required liftpressure, they were set close
enough to the liftsetpoints to preclude being outside of design basis.
After further
review, the licensee concluded, in Nonconformance Report N0001327, that "the
use of valve specific correction factors has been determined to be inaccurate."
The
safety consequence
of the improperly set MSSVs was low since the correction
factors for most valves were less than
1 percent.
The licensee later verified by
testing that the liftsetpoints were not set far enough out of tolerance to cause any
of the associated
design basis analyses to be exceeded.
The licensee also reviewed past test results for testing conducted with AVKtest
equipment.
Past AVKtest results were adjusted in order to correct for the effect of
valve specific correction factors.
Based upon these adjusted test results, the
licensee determined that during testing conducted between September 1995 and
August 1996, there were 53 instances where an MSSV had been returned to
-1 3-
service following main steam line code safety valve testing without being set to
within +/-1 percent of the TS required liftpressure.
The licensee plans to revise
Licensee Event Report 323/96-007to report this information. The licensee's
use of
valve specific correction factors were found to have been based upon limited
testing, and, therefore, there was insufficient conclusive data to derive correction
factors using statistical analysis.
The inspectors reviewed a prior violation of TS 3.7.1.1 (refer to EA 96-180) which
identified that two MSSVs were returned to service following testing without being
reset to within +/-1 percent of the TS required liftpressure.
The inspectors noted
that the cause of the prior violation was different from that of the current violation.
The inspectors concluded that the corrective actions in response to the prior
violation could not have been expected to prevent the current violation. The failure
to set MSSV liftsettings within +/-1 percent of their liftsetpoint following main
steam line code safety valve testing is a violation of TS 3.7.1.1
~ This licensee-
identified and corrected violation is being treated as a Non-Cited Violation,
consistent with Section VII.B.1 of the NRC Enforcement Policy (NCV 50-
275/96021-03).
MSSV Lifts Followin
Se tember 1995 Unit 2 Reactor Tri
Review of similar events indicated that following a Unit 2 reactor trip on
September 26, 1995, four MSSVs (relief valves (Rvs) 3, 7, 8, and 11) lifted
prematurely.
Operator response to the event was similar to that following the
August 10, 1996, dual unit trip in that operators reduced steam pressure
using the
10 percent atmospheric steam dump valves.
Prior to the reactor trip, MSSV testing
was in progress.
RV-7 had been tested and the valve liftsetpoint was in the
process of being adjusted in that the locknut for the liftpressure adjustment had not
been fullytightened.
As a result, following the reactor trip, RV-7's liftsetpoint
locknut loosened due to vibration causing the liftpressure to decrease
until
operators gagged the valve.
The licensee attributed the premature lifts on the three
remaining MSSVs to low liftpoints.
Following the September 1995 event, the
licensee suspected that the AVKtest methodology was introducing a bias, and the
valves that lifted low had been set at the low end of their characteristic curve.
Prior
to restart of the unit, the licensee conducted AVKtesting of unit 2 MSSVs and
conducted multiple lifts following valve liftpressure adjustment to ensure that the
valves were accurately set.
During subsequent
testing conducted at a safety valve test facility, the licensee
noted that MSSV test results using AVKtest equipment varied from results obtained
during valve testing with live steam.
Based upon the differences, the licensee
developed valve-specific characteristic curves and correction factors.
Based on the September 1995 and August 1996 events involving early lifting
MSSVs, the licensee performed insitu tests to compare the AVKtest methodology
with the industry accepted Trevitest methodology.
Differences were observed for
~
~
-14-
some MSSVs between liftsetpoints determined with the AVKmethod versus the
Trevitest method.
The correction factors were later suspected
to be inaccurate and
to introduce additional uncertainty in the valve liftsetting.
The licensee
subsequently discontinued the use of correction factors and the AVK Ultra Star test
equipment and started performing testing using Trevitest equipment.
Verification of Maintenance
Rule Re uirements
The inspector reviewed the licensee's
program for implementation of the
maintenance
rule for MSSVs. The licensee had determined that the MSSVs were
within the scope of the maintenance
rule and had included them as a component of
the portion of the turbine steam supply system upstream of the main steam
isolation valves (hereafter referred to as turbine steam supply system).
The licensee
scoping of the function of the turbine steam supply system determined that the
MSSVs were required for the following functions:
1) limiting primary system
temperature
and acting to maintain the system temperature below safety limits to
ensure fuel integrity and limit exposure to plant workers; 2) removing heat from the
primary system and providing for auxiliary feedwater addition for station blackout
conditions; and 3) maintaining integrity of portions of the main steam system
necessary to prevent a sudden cooldown that would add large amounts of positive
reactivity and could result in a brief return to criticality following a reactor trip. The
licensee determined the third function to be risk significant, since its contribution to
the core damage frequency was greater than 0.5 percent.
The licensee established
performance criteria for turbine steam supply system
components that were required for the system to fulfillits functions.
For the
MSSVs, the performance criteria was less than two maintenance
preventable
functional failures (MPFFs) during a 24 month period.
During discussions with the
system engineer, an MSSV MPFF was defined as a failure that caused the turbine
steam supply system to be unable to perform its safety function.
In review of the past 36 months of MSSV test results, the licensee concluded that
Test results that indicated the MSSVs were
outside of the +/-3 percent tolerance required by TS were not considered by the
licensee to be MPFFs.
Specifically, during Unit 1 MSSV testing conducted on
September
14, 1995, the licensee identified high lifts for MSSVs associated
with
SG 1-1 that placed the unit outside of design basis, since the "as-found" test
results indicated the potential during an accident for SG pressure to have exceeded
110 percent of design pressure.
The licensee evaluated this occurrence
as not
constituting an MPFF, since the SG would have remained intact and performed its
function of removing primary system heat.
This condition was reported by the
licensee in Licensee Event Report 275/95-011-00.
Since the licensee established
the threshold for an MSSV MPFF at the point where
the turbine steam supply system would no longer perform its safety function, the
use of MPFFs for MSSV performance trending was ineffective and did not provide a
-1 5-
true indication of component reliability. The system level performance criteria
resulted in too high a threshold for MSSV performance deficiencies.
Therefore, the
established
MSSV condition monitoring did not provide an appropriate basis for
determining satisfactory performance of the MSSVs to fulfilltheir intended safety
function. The failure to establish appropriate performance criteria for the MSSVs
that adequately demonstrated
effective maintenance
is a violation of 10 CFR 50.65
(VIO 50-275;323/96021-04).
During the review, it was noted that the licensee had initiallyplaced the MSSVs in
condition monitoring (i.e. Category A(2)); however, the reviews performed to
evaluate the turbine steam supply system for the past 36 months had not been
documented.
This action appeared to be in conflict with the guidance provided in
paragraph
13.2.1 of NUMARC 93-01 Revision 2, "Industry Guidelines for
Monitoring the Effectiveness of Maintenance at Nuclear Power Plants," which
specifies that the basis from the initial scoping for placing a structure, system or
component in Category A(2) should be documented.
Further investigation of this
issue, revealed that the licensee did not require formal documentation of the
reviews.
Actions Initiated b
the Licensee Followin
Dual Unit Tri
On August 29, 1996, the licensee's maintenance
rule expert panel met and, based
upon the MSSV performance problems, placed Units
1 and 2 MSSVs in goal setting
and monitoring (i.e. Category A(1)) until December 1997. The goal the licensee has
established for the valves is no TS violations due to improper or drifted setpoints.
Conclusions
The maintenance
rule program performance criteria established for MSSVs was
ineffective in detecting unsatisfactory MSSV performance.
The licensee's decision
to not require documenting the basis for initial scoping decisions is considered to be
a weakness
in the licensee's implementation of the maintenance
rule.
Due to
improper use of correction factors, MSSVs had not been reset to within +/-1
percent of the TS required liftsetpoint following main steam line code safety valve
testing prior to returning the valves to service.
Closed
IFI 50-275 323 91039-02: periodic verification of motor-operated valve
switch settings.
This item involved the licensee's motor-operated valve program, in
response to Generic Letter 89-10, specifically in the area of periodic verification of
motor-operated valve switch settings.
The licensee submitted additional information
in a letter dated May 5, 1995, as requested
in NRC Inspection
Report 50-275;323/95001.
This information was reviewed by the inspectors and
found to be adequate for closure of the licensee's
Generic Letter 89-10 program.
The licensee was notified of the results of this review in a letter dated August 3,
1995.
l
-1 6-
M8.3
Closed
IFI 50-275 96016-03'50-323
96016-03installation of improper
auxiliary saltwater (ASW) pump shaft key.
During refurbishment of an
ASW pump, the licensee discovered one of the pump shaft coupling keys
missing and, subsequently,
determined that a key, made of a material
different from that specified, had been installed and had dissolved in the
saltwater environment.
Following discovery of the problem, an inspection
followup item was created to assess
the licensee's evaluation of the ASW
pump's past operability and long term corrective actions.
The shaft appeared to have galled to the coupling, allowing the pump to
continue to operate and pass its surveillance tests.
The shaft coupling joint
was removed by cutting the upper and intermediate shafts a distance away
from the coupling to preserve the joint. The shaft coupling assembly was
then sent to a test laboratory for testing.
The testing subjected the coupling
to. torsional loads.
Based upon the results of the tests the licensee
determined the joint would not yield at less than the breakdown torque of
the ASW pump.
Therefore, since the seismic load to the joint is small, the
licensee concluded the pump would have remained functional during design
basis seismic events.
The proposed barriers and corrective actions include changing the descriptor
for the shaft key to clarify its proper use and the addition of a discussion of
this event to the outage maintenance
worker orientation training. Other
administrative changes that have occurred since the installation of the
improper key have sensitized maintenance
personnel to the need for "like for
like" replacements.
The inspector concluded the past operability evaluation
and long term corrective actions appeared to adequately address the issue.
III. Engineering
E1
Conduct of Engineering
E1.1
RHR S stem Review
a 0
Ins ection Sco
e 71707 37551
The inspectors conducted
a review of the design, maintenance,
and operation of the
RHR system which included its normal function of decay heat removal and its
emergency core cooling function.
The review included the following documents:
~
UFSAR: Chapter 5.5, Chapter 6.3, Chapter 15
~
DCM S-9, Safety Injection System
~
DCM S-10, Residual Heat Removal System
~
Il
,g(
-1 7-
~
Plant Technical Specifications
~
Design Change Packages:
~
EP-46408, Revision 1, Pipe Support Modification
~
EN-49118, Revision 0, Upgrade RHR Pump and Heat Exchanger Design
Pressure
EP-45955, Revision 0, Modify RHR Miniflow Check Valve Disc
EE-46046, Revision 0, Reset Time Delay for RHR Pump Low Flow Alarm
EM-44172, Revision 1, Install RHR Miniflow Check Valves
SJ-45237, Revision 0, Replace RHR Pump Motor Upper Bearing Oil
Sightglass
EE-41602, Revision 0, Replace Safety Injection Signal Timing Relays
EM-41490, Revision 0, Remove MELB Spray Guards on Seal Water Cooler
Lines
PGSE Calc. SQE-46, Seismic Evaluation of Replacement Motor for RHR
Pump
PGRE Calc. PG-1049, RHR System Cooldown Capacity
RHR Pump/Motor Vendor Manual
RHR System Operating Procedures
Procedure
EOP E-1.3, Transfer to Cold Leg Recirculation
PGSE RHR Safety System Functional Audit and Review, November 1993
The inspector also conducted
a detailed walkdown of the accessible
portions of the
RHR system and interviewed the system engineer.
Observations
and Findin s
The RHR system is a dual-purpose system in that it provides for core decay heat
removal during shutdown/refueling conditions and during accident conditions.
It
also provides a redundant means of coolant injection during the initial phase of a
large break LOCA. The bases under which the system is designed to perform these
functions are described
in the UFSAR and in DCMs S-9 and S-10.
~
~
LQ
-1 8-
The licensee's
procedure for transferring the'CCS from injection to recirculation
mode is described
in Table 6.3-4 of the UFSAR. The licensee's
EOP Implementing
Procedure,
E-1.3, Transfer to Cold Leg Recirculation, was noted to cont'ain several
deviations from that described
in UFSAR. This issue is more fully discussed
in
Section 01.2.
The engineers involved with the system were knowledgeable on system design and
operation, historical design issues and system changes,
and current system
deficiencies.
A detailed walkdown of the accessible
portions of the system found
only one deficiency that had not already been identified by the licensee
(a
yoke-to-bonnet dry boric acid leak on a system valve).
The system engineer agreed
that the deficiency should be evaluated during routine system walkdowns and
considered including the valve in the RHR system tracking AR for dry boric acid
leaks.
During the inspection period, the system engineer identified that the upper motor
bearing on RHR Pump 1-1 had increased
oil consumption.
The system engineer had
been tracking the oil consumption through an AR. The system engineer evaluated
the increased consumption and determined that the pump may not have been able
to perform its function over the entire postaccident
period for which it would be
required.
Consequently, the engineer recommended that operations declare the
pump inoperable while repairs to the upper bearing sight glass, the source of the oil
leak, were effected.
This demonstrated
appropriate monitoring of equipment
performance and sensitivity to the impact of equipment deficiencies on the ability of
a component to perform its design basis function.
A discrepancy was noted between the UFSAR and DCM S-10 with regard to the
design cooldown capability of the RHR system.
Section 4.3.1 of DCM S-10 states
that the RHR system is capable of cooling the RCS from 350
F to 140
F within
10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> based upon two trains operating at design flow and RHR initiated 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />
after reactor shutdown.
Additionally, the DCM states that valve interlocks prevent
initiation of RHR until RCS pressure
is less than approximately 390 psig.
Section 5.5.6.1 of the UFSAR states that the RHR system is designed to perform
the same function within 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br /> and at an initial pressure
less than 425 psig.
These design parameters
are also provided in Table 5.5-8 of the UFSAR. It was
noted that the licensee's initiative to review and update the FSAR, which was
completed and scheduled to be submitted in November 1996, also identified these
discrepancies
and has revised Section 5.5.6.1 to be consistent with the DCM.
However, Table 5.5-8 in the FSAR update had not been revised to reflect the DCM
values.
The inspector reviewed PGSE calculation SQE-46 for qualification of the RHR pump
replacement motor to be installed with RHR Pump 1-1. The evaluation concluded
that the replacement motor was acceptable with the limitation that the material of
motor holddown bolts be ASTM A-193, Grade B7, and that they be torqued to
124 ft-lb. Adequate documentation could not be found in the work package
~
~
-19-
associated
with the motor's installation to determine that these limitations were
implemented.
An inspection followup item is being initiated to track resolution on
the actual torque applied to the RHR Pump 1-1 motor holddown bolts and its
consistency with the motor's seismic qualification evaluation
(IFI 50-275/96021-05).
C.
Conclusions
Several discrepancies
were identified in FSAR update with regard to the RHR
system design parameters.
These discrepancies
illustrated a weakness
in the
licensee's program to update the FSAR to reflect current design and operation of
the plant.
System engineering for the RHR system was considered strong.
This was
supported by both the knowledge of the system engineer and the active role the
engineer has played in identifying, tracking, and correcting system deficiencies.
E1.2
ASW S stem Review
a ~
Ins ection Sco
e 71707 37551
The inspectors reviewed documentation related to the ASW system,
including:
UFSAR Section 9.2.7 Auxiliary Saltwater System
~
System Engineer Quarterly Reports
Ars: A02217,50, A0275649, A0312240, A0330165,
A0344300,A0365445,A0366935,A0374286,A0390005,
A0397706,A0399769,A0400931,A0401616,A0401949,
A0403369,A0404763,A0410203
~
Nonconformance Reports N0001814 and N0001992
~
PSRC TS Interpretation 95-08, Revision
1
~
Operability Evaluation 95-11, Operability of Component
Cooling Water System (CCW) with Analyzed CCW Water
Temperatures
Higher Than Current Design Basis
~
EOP E-0 Reactor Trip or Safety Injection, and E-1.3 Transfer to
Cold Leg Recirculation
The inspectors walked down portions of the system in both Units
1 and 2
and observed equipment operation, valve alignments and seals, AR tags and
overall material condition of the equipment.
'0
-20-
Observations
and Findin s
ASW S stem Walkdown
A walkdown of portions of the system was performed for both Units
1 and 2
and found the valve alignment to be correct and seals installed on specified
valves.
The oil levels for the pumps were within their required bands.
The
operating pumps had adequate
seal leakoff flow and the room coolers were
in service.
The system instrumentation was indicating properly.
The backup
air bottles were properly pressurized
and aligned to the heat exchanger inlet
isolation valves.
The overall material condition of the equipment was good
with few open AR tags noted.
ASW TS Re uirements
The TS Limiting Condition for Operation 3.7.4.1, requires at least two ASW
trains shall be OPERABLE, with an ACTION statement that with only one
ASW train OPERABLE, restore at least two trains to OPERABLE status within
72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or be in at least HOT STANDBYwithin the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and in
COLD SHUTDOWN within the following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />.
The PSRC has interpreted that to comply with the ACTION statement the
following conditions must exist: 1) two ASW pumps and one CCW heat
exchanger,
or 2) one ASW pump and two CCW heat exchangers,
or 3) one
train (ASW pump and CCW heat exchanger) with the capability to restore at
least one additional ASW pump or CCW heat exchanger within 20 minutes of
receipt of an Sl, or 4) one train (ASW pump and CCW heat exchanger) with
an engineering evaluation for single train operation without the restriction of
Item 3 above.
The interpretation resulted from an RHR heat exchanger test which predicted
overheating of CCW during the cold leg recirculation phase following a
LOCA, under certain limiting conditions of a single train failure and most
conservative fouling factors in the RHR heat exchanger,
CCW heat
exchanger and CFCUs.
The additional requirements
in the TS interpretation
ensure that adequate
equipment is available to prevent overheating the
CCW.
The inspectors reviewed and verified that the EOPs contained the appropriate
directions to satisfy the additional restrictions of this interpretation.
The licensee agreed with the inspector's conclusion that this TS
interpretation was not consistent with the UFSAR, which describes the ASW
system as comprised of fully redundant active components, with two 100
percent capacity pumps, with piping system arranged to provide two
separate,
redundant supply headers,
either of which can supply the minimum
required flow for ESF operation, and each pump sized to provide water for
(
w
Q)
-21-
one CCW heat exchanger.
Subsequent to the end of the inspection period,
the licensee revised the UFSAR to be consistent with the TS interpretation.
The inspectors plan to review the licensee's
10 CFR 50.59 evaluation of this
change.
The conditions which resulted in this TS interpretation imply that the Limiting
Condition for Operation and its ACTION statement do not define the lowest
functional capability or performance levels for the ASW system.
Therefore,
the potential need for a TS amendment has been questioned by the
inspectors.
This issue and the inspectors'eview of the licensee's
10 CFR 50.59 evaluation remain an unresolved item (URI 50-275;323/
96021-06).
C.
Conclusions
The ASW system was found in proper configuration to support its safety
function, and overall material condition of the equipment was satisfactory.
E8
IVliscellaneous Engineering Issues (92903)
E8.1
Closed
IFI 50-275 323 96020-02: PSRC interpretation of TS 3.4.6.2.e. allowed
for controlled leakage measured
at 2235 a 20 psig to slightly exceed 40 gpm.
The
inspectors questioned the validity of this TS interpretation since it appeared to be in
conflict with the TS specified limit of 40 gpm for controlled leakage.
The licensee
provided information that although the surveillance allowed for the controlled
leakage to exceed 40 gpm that the measured controlled leakage had never
exceeded the 40 gpm value.
'he
TS requires that controlled leakage be measured
at least once every 31 days at
nominal RCS pressure of 2235 psig with the modulating valve fully open.
This
limitation ensures that in the event of a LOCA, the safety injection flow willnot be
less than that assumed
in the safety analysis.
The PSRC's basis for allowing
controlled leakage to exceed 40 gpm at 2235 psig was that the corresponding
calculated total leakage during the safety injection phase would be (40 gpm.
The
licensee's
surveillance procedure for measuring controlled leakage calculated the
total line resistance
of the reactor coolant pump (RCP) seal injection lines, and
verified through calculation, that the flow resistance was above a specified value in
order to ensure,
in the event of a LOCA, that the controlled leakage would not
exceed the TS limit. The inspectors reviewed STP M-54, Revision 18, "Verification
of RCP Seal Injection Flow by Resistance
Measurement,"
and concluded that the
licensee's method of calculating the RCP seal injection line flow resistance,
and
then utilizing that resistance to calculate controlled leakage, was an acceptable
method for ensuring the TS requirement was met.
However, PSRC TS
interpretation 96-08 and STP M-54, which both allowed measured,
controlled
leakage to be in excess of the limit specified in TS 3.4.6.2.e., did not appear to be
acceptable to the inspectors.
~
r
J
~
-22-
Based upon the concern for compliance with the TS as written, the licensee revised
STP M-54 to no longer accept measured,
controlled leakage in excess of 40 gpm.
Additionally, the PSRC rescinded TS interpretation 96-08.
The inspector concluded that the PSRC had inappropriately approved
a TS
interpretation which, although meeting the intent of the TS, allowed a condition that
appeared different from the TS wording.
Since the licensee has reinstated the
40 gpm limit, this item is closed.
E8.2
Closed
IFI 50-275 323 93019-02:pressure
locking and thermal binding of motor-
operated valves.
This item involved the licensee's efforts to complete reviews of its
Generic Letter 89-10 motor-operated valve population for susceptibility to pressure
locking and thermal binding and 'to take corrective actions, where necessary,
to
ensure valve operability.
Subsequently, the NRC issued Generic Letter 95-07,
"Pressure Locking and Thermal Binding of Safety-Related Power-Operated
Gate
Valves." The licensee's
response to this generic letter is currently under review by
the NRC Office of Nuclear Reactor Regulation.
This issue will be fully resolved
under Generic Letter 95-07; therefore, this item has been closed.
IV. Plant Su
ort
V. Mana ement IVleetin s
X1
Exit Meeting Summary
The inspectors presented the inspection results to members of licensee management
at the
conclusion of the inspection on November 8, 1996.
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.
0
ATTACHMENT
SUPPLEMENTAL INFORMATION
PARTIALLIST OF PERSONS CONTACTED
Licensee
S. D. Allen, Supervisor, Mechanical Engineering Valve Group
T. R. Baldwin, Supervisor, ECCS Systems
J. R. Becker, Director, Operations
K. H. Bych, Director, Nuclear Quality Services
'. F. Fetterman, Director, Instrumentation and Control Engineering
L. L. Fusco, Engineer, Predictive Maintenance
T. L. Grebel, Director, Regulatory Services
C. D. Harbor, Supervisor, Regulatory Services
T. L. McKnight, Engineer, Regulatory Services
D. B. Miklush, Manager, Engineering Services
J. E. Molden, Manager, Operations Services
M. N. Norem, Director, Mechanical Maintenance
D. A. Vosburg, Director, Nuclear Steam Supply Systems Engineering
L. F. Womack, Vice President,
Nuclear Technical Services
INSPECTION PROCEDURES USED
IP 37551: Onsite Engineering
IP 61726: Surveillance Observations
IP 62707: Maintenance Observations
IP 71707: Plant Operations
IP 71750: Plant Support
IP 92901: Followup - Plant Operations
IP 92902: Followup - Maintenance
IP 92903: Followup - Engineering
ITEMS OPENED
CLOSED AND DISCUSSED
~Oened
50-275;323/96021-01
50-275/96021-02
50-275;323/96021-03
50-275;323/96021-04
50-275/96021-05
50-275;323/96021-06
failure to perform 10 CFR Part 50.59 evaluation when
revising EOP E-1.3
failure to document an equipment problem
failure to set MSSVs within a1'/0 of TS liftsetpoint
establishment of inadequate
performance criteria
IFI
RHR pump 1-1 motor hold down bolt torque
ASW TS interpretation
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Closed
50-275;323/9601 6-03
IF I
50-275/9601 6-07
50-275;323/96020-02
50-275;323/9301 9-02
IFI
IFI
50-323/9501 8-02
50-275;323/91 039-02
IFI
improper shaft key utilized for assembly of ASW pump
shaft
failure to set MSSVs in accordance with TS
requirements
periodic verification of motor-operated valve switch
settings
PSRC interpretation of TS 3.4.6.2.e
pressure locking and thermal binding of motor-operated
valves
reactor cavity sump level indication and recorder
LIST OF ACRONYMS USED
ASW
IFI
LCO
OP
POA
PSRC
RV
SSPS
TS
action request
American Society of Testing and Measurement
auxiliary saltwater
centrifugal charging pump
component cooling water
emergency operating procedure
inspection followup item
limiting condition of operation
loss of coolant accident
maintenance
preventable functional failure
operating procedure
.Pacific Gas and Electric
prompt operability assessment
public document room
plant staff review committee
reactor coolant pump
relief valve
refueling water storage tank
structures, systems or components
solid state protection system
surveillance test procedure
Technical Specification
Updated Final Safety Analysis Report
unresolved item
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ENCLOSURE 3
V. PREDECISIONAL ENFORCEIVIENT CONFERENCES
Whenever the NRC has learned of the existence of 'a potential violation for which escalated
enforcement action appears to be warranted, or recurring nonconformance
on the part of a
vendor, the NRC may provide an opportunity for a predecisional enforcement conference
with the licensee, vendor, or other person before taking enforcement action.
The purpose
of the conference
is to obtain information that willassist the NRC in determining the
appropriate enforcement action, sucn as: (1) a common understanding of facts, root
causes
and missed opportunities associated
with the apparent violations, (2) a common
understanding of corrective action taken or planned, and (3) a common understanding of
the significance of issues and the need for lasting comprehensive
corrective action.
If the NRC concludes that it has sufficient information to make an informed
enforcement decision,
a conference will not normally be held unless the licensee requests
it. However, an opportunity for a conference willnormally be provided before issuing an
order based on a violation of the rule on Deliberate Misconduct or a'civil penalty to an
unlicensed person.
If a conference
is not held, the licensee will normally be requested to
provide a written response to an inspection report, if issued, as to the licensee's views on
the apparent violations and their root causes
and a description of planned or implemented
corrective action.
During the predecisional enforcement conference, the licensee, vendor, or other
persons will be given an opportunity to provide information consistent with the purpose of
the conference,
including an explanation to the NRC of the immediate corrective actions (if
any) that were taken following identification of the potential violation or nonconformance
and the long-term comprehensive
actions that were taken or will be taken to prevent
recurrence.
Licensees,
vendors, or other persons will be told when a meeting is a
predecisional enforcement conference.
A predecisional enforcement conference
is a meeting between the NRC and the
licensee.
Conferences
are normally held in the regional offices and are not normally open
to public observation.
However, a trial program is being conducted to open approximately
25 percent of all eligible conferences for public observation, i.e., every fourth eligible
conference involving one of three categories of licensees
(reactor, hospital, and other
materials licensees) will be open to the public. Conferences will not normally be open to
the public if the enforcement action being contemplated:
(1) Would be taken against an individual, or if the action, though not taken against
an individual, turns on whether an individual has committed wrongdoing;
(2) Involves significant personnel failures where the NRC has requested that the
individual(s) involved be present at the conference;
(3) Is based on the findings of an NRC Office of Investigations
report; or
(4) Involves safeguards
information, Privacy Act information, or information which
could be considered proprietary;
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In addition, conferences will not normally be'pen to the public if:
(5) The conference involves medical misadministrations or overexposures
and the
conference cannot be conducted without disclosing the exposed individual's name; or
(6) The conference will be conducted by telephone or the conference will be
conducted at a relatively small licensee's facility.
Notwithstanding meeting any of these criteria, a conference may still be open if the
conference involves issues related to an ongoing adjudicatory proceeding with one or more
intervenors or where the evidentiary basis for the conference
is a matter of public record,
such as an adjudicatory decision by the Department of Labor.
In addition, with the
approval of the Executive Director for Operations, conferences willnot be open to the
public where good cause has been shown after balancing the benefit of the public
observation against the potential impact on the agency's enforcement action in a particular
case.
As soon as it is determined that a conference will be open to public observation, the
NRC willnotify the licensee that the conference will be open to public observation as part
of the agency's trial program.
Consistent with the agency's policy on open meetings,
"Staff Meetings Open to Public," published September 20, 1994 (59 FR 48340), the NRC
intends to announce open conferences
normally at least 10 working days in advance of
conferences through (1) notices posted in the Public Document Room, (2) a toll-free
telephone recording at 800-952-9674,and
(3) a toll-free electronic bulletin board at 800-
952-9676.
In addition, the NRC will also issue
a press release and notify appropriate State
liaison officers that a predecisional enforcement conference
has been scheduled
and that it
is open to public observation.
The public attending open conferences
under the trial program may observe but not
participate in the conference.
It is noted that the purpose of conducting open conferences
. under the trial program is not to maximize public attendance,
but rather to determine
whether providing the public with opportunities to be informed of NRC activities is
compatible with the NRC's ability to exercise its regulatory and safety responsibilities.
Therefore, members of the public will be allowed access to the NRC regional offices to
attend open enforcement conferences
in accordance with the "Standard Operating
Procedures
For Providing Security Support For NRC Hearings And Meetings," published
November 1, 1991 (56 FR 56251).
These procedures
provide that visitors may be subject
to personnel screening, that signs, banners, posters, etc., not larger than 18" be permitted,
and that disruptive persons may be removed.
Members of the public attending open conferences will be reminded that (1) the
apparent violations discussed
at predecisional enforcement conferences
are subject to
further review and may be subject to change prior to any resulting enforcement action and
(2) the statements
of views or expressions of opinion made by NRC employees at
predecisional enforcement conferences,
or the lack thereof, are not intended to represent
final determinations or beliefs.
Persons attending open conferences will be provided an
opportunity to submit written comments concerning the trial program anonymously to the
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regional office. These comments will be subsequently forwarded to the Director of the
Office of Enforcement for review and consideration.
When needed to protect the public health and safety or common defense
and
security, escalated
enforcement action, such as the issuance of an immediately effective
order, will be taken before the conference.
In these cases,
a conference may be held after
the escalated enforcement action is taken.
t