ML20148H214
| ML20148H214 | |
| Person / Time | |
|---|---|
| Site: | Sequoyah  |
| Issue date: | 03/04/1988 |
| From: | Branch M, Mccoy F NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20148H201 | List: |
| References | |
| 50-327-87-73, 50-328-87-73, NUDOCS 8803290355 | |
| Download: ML20148H214 (51) | |
See also: IR 05000327/1987073
Text
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UNITED STATES
,
NUCLEAR REGULATORY COMMISSION
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REGION il
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101 MARIETTA STRE ET, N.W.
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ATLANTA, GEORGI A 30323
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.....
Report Nos.:
50-327/87-73 and 50-328-87-73
Licensee: Tennessee Valley Authority
6N11 B Missionary Place
1101 Market Street
Chattanooga, TN 37492-2801
Docket Nos.:
50-327 and 50-328
License Nos.: DRP-77 and ORP-79
Facility Name:
Sequoyah Units 1 and 2
- pection Conducted:
October 26-30, 1987 through January 4-14, 1988
Inspector:
.
[bd
O
/88
M. Branch, Inspection Teampader /
Date Signed
Team Members:
W. Bearden
(1)
H. Bibb
(3)
J. Brady
(3)
P. Burnett
(3)
R. Carroll
(1 & 2)
R. Compton
(1 & 2)
P. Harmon
(1 & 2)
G. Hubbard
(2)
G. Humphrey
(1 & 2)
J. Lenahan
(1)
P. Taylor
(1)
L. Watson
(1)
R. Wescott
(2)
J. York
(2)
1.
Participated in first phase of inspection October 26-30, 1987.
2.
Participated in second phase of inspection January 4-8, 1988.
3.
Contributed input by e'ther in office review or site assessment during
t
period fro 1ct $ 26, 1987
rough January 8, 1988.
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Approved by-
,I
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88
F."McCoy'; Ct04f
d'atV5igned
SUMMARY
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Scope:
This special announced inspection was conducted to assess TVA'S
readiness to support Sequoyah Unit 2 entry into Mode 4 and Mode 3.
The areas
reviewed included status of MC94300 items associated with heatup, testing
activities, plant heatup procedure, TVA's operational readiness assessment,
compensatory measures, and control of operations.
h,fN05000327
5 880309
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Results:
In areas inspected, one violation was identified that involved the
failure to perform or adequately perform a written safety evaluation for
modifications to the facility which involved compensatory action for defeated
safety functions.
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REPORT DETAILS
1.
Licensee Employees Contacted
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H. Abercrombie, Site Ofrector
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- J. La Point, Deputy Site Director-
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- S. Smith, Plant Manager
- B. Willis, Operations Superintendent
B. Patterson, Maintenance Superintendent
R. Pierce, Radiological Control Superintendent
M. Harding, Site Licensing
L. Martin, Site Quality Manager
J. Hosmer, Project Engineer
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R. Olson, Modifications Manager
- J. Anthony, Operations Group Supervisor
R. Prince, Mechanical Maintenance Supervisor
0. Jeralds, Electrical Maintenance Supervisor
H. Elkins, Instrument Maintenance Supervisor
- R. Fortenberry, Technical Support Superintendent
- G. Kirk, Compliance Supervisor
D. Craven, Quality Assurance Staff Supervisor
- J. Sullivan, Plant Operating Review Staff Sunervisor
- H. Rogers}z,lantReportingSectionSuperviso'r
P
- R.
Buchho
Sequoyah Site Representative
M. Cooper, Compliance Licensing Manager
- G. Gault, Acting Compensatory Measures Program Manager
Other licensee employees contacted included technicians, operators, shift
,
engineers, security force members, engineers and maintenance personnel.
NRC Resident Inspectors Contacted:
K. Jenison
P. Harmon
D. Loveless
W. Poertner
- Attended exit interview
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2.
Exit Interview
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The inspection scope and findings were summarized with the 31 ant manager
and members of his staff on October 30, 1987 and January it 1988.
One
violation described in this report's summary paragraph was d}scussed.
No
deviations were discussed.
The licensee acknowledged the inspections
findings.
The licensee did not identify as proarietary any of the
material reviewed by the inspectors during this inspection.
During the
inspection period, frequent discussions were held with the Site Director,
Plant Manager and other managers concerning inspection findings.
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The following new items were discussed:
a.
- Unresolved item (327,328/87-73-01), unreliability of containment
sump level instrumentation,
b.
Unresolved item (327,328/87-73-02), inadequate cooling capabilities
of equipment space coolers.
c.
Unresolved item (327,328/87-73-03), training weakness identified
while performing compensatory measures.
d.
Unresolved item (327,328/87-73-04), minimum operating staffing
required considering performance of compensatory measures,
e.
Violation (327,328/87-73-05), failure to
perform or adequately
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perform a written safety evaluation for mod fications to the facility
which involved compensatory actions for defeated safety functions.
- Unresolved items are matters about which more information is required to
determine whether they are acceptable or may involve violations or
deviations.
3.
Readiness For Heatup Inspection (Hold-Point #1, Mode 5-4)
This insaection is being performed, in part, to provide the basis for
determin ng the readiness of Sequoyah Unit 2 to commence plant heatup
(ie. , Mode 5-4 change). Since the issuance of the Sequoyah Nuclear
Performance Plan (SNPP) the NRC has been performing program improvement
inspections which are documented in numerous Inspection Reports.
Additionally, Inspection Report 327,328/87-60 documented the portion of
the overall readiness for heatup inspection, which was directed toward the
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plant's operational readiness assessment discussed in the SNPP and
Operational Readiness Report. This report documents an independent NRC
assessment in the areas of conduct of operations, plant material
conditions, Mode 4-3 OPERABILT"
determination, and the use of
compensatory measures to allow sant heatup with degraded equipment.
The inspections performed, along with the inspector's findings are grcuped
using the format of the overall inspection plan discussed in Inspection
Report 327,328/87-60.
a.
Review of Licensing Activities Needed to Support Mode 5-4 Change
(1) Resolution of items needed to support plant heatup.
This issue is being addressed separately by OSP projects staff
and will be closed in accordance with standard operating
practices for handling of licensing issues by the projects
staff.
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b.
Review of Outstanding Employee Issues
(1) Review open NRC allegations for issues which may effect heatup.
RESULTS
None were identified.
This element is documented in MC 94300
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letter dated January 15,.1988.
(2) Review TVA's new employee concern program backlog and evaluate
for, one selected system,- any open issue that could effect
heatup.
RESULTS
During the lowest mode determination review discussed in
paragraph f.(5) the inspectors included a sample of open correc-
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tive actions associated with issues identified by TVA's new
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employee concerns program.
This review determined that for the
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system reviewed (ie, containment saray) no outstanding issues
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remained that would effect plant
1eatup.
Additionally, the
inspector determined that TVA had properly categorized those
items reviewed.
(3) For one selected system, review the status of open corrective
action that resulted from the old employee concern program and
assess open issues that may effect heatup.
RESULTS
During the lowest mode determination review discussed in
paragraph f.(5) the inspectors included a sample of open
corrective actions associated with issues identified by TVA's
old employee concerns program.
This review determined that for
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the system reviewed (ie. containment spray) no outstanding
issues remained that would effect plant heatup.
Additionally,
the inspector determined that TVA had properly categorized those
items reviewed,
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c.
Review Status of NRC Identified Issues
(1) Review NRC outstanding items and verify that items effecting
heatup are either closed or scheduled to be closed prior to
heatup.
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MC 94300 letter dated January 15, 1987 documents 30 items
requiring resolution prior to Mode 4 entry.
In addition, for
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inspections not yet covered by that letter an additional five
items associated with this report, two items associated with
Report 327, 328/87-66 and three items associated with Report
327, 328/88-06 were identified as requiring completion pr'or to
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heatup.
These items will be closed and/or confirmed to be
resolved
arior to hold point number 1 release and be so
documentec on a Hold Point #1 (Mode 5-4) release punch list.
(2) Review status of any pending escalated enforcement items that
could effect heatup.
RESULTS
None were identified.
This element is documented in MC 94300
letter dated January 15, 1988.
(3) Review licensee assessment of defeated safety functions for FSAR
chapter 15 systems and ascertain adequacy of-licensee review and
established compensatory measures.
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RESULTS
An inspection in October 1987, was performed which included a
review of the licensee's method for incorporating compensatory
measures (cms).
cms arte measures required to be taken to
compensate for defeated safety functions or the lack of an
adequate desic'n and are required to mitigate the consequences of
accidents eva' uated in chapter 15 or other significant events
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presented in the FSAR.
During that inspection the inspectors determined the licensee's
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ef forts in this area were not adequate.
The licensee then
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issued a section instruction letter, SIL-19, rev. O, "Sequoyah
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Nuclear Plant (SQN)-Compensatory Measures (cms) Initial
Evaluations" approved 11-19-87, from the the Technical Support
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Services Group, as an interim instruction to identify and
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evaluate cms and establish a tracking data base for the cms.
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On January 4,1988, the licensee issued a permanent plant
,
instruction Administrative Instruction AI-49, rev. 0 ' Control
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and
Tracking
of
Compensatory
Measures"
to define
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responsibilities and tracking requirements to control the
implementation of future Compensatory Measures.
Many questions resulting from the October inspection were left
unanswered at the conclusion of that inspection.
As a result,
follow-up inspection during the week beginning on January 4,
1988, was performed.
Theobjectives,ofthisre-inspectionwere
to review Unresolved Item 327, 328/86-52-04 and to:
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Evaluate the licensee's program
established to control
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cms, AI-49 "Control and Tracking of Compensa'7ry Measures."
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Ensure that 50.59 safety evaluations have been performed to
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allow auto design functions to be compensated by
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Administrative controls and/or personnel action and to
ensure procedure changes were supported by safety
evaluations.
Ensure that the licensee has scheduled, with priority, the
modification / maintenance necessary to correct problem area
requiring cms.
Ensure that personnel are properly trained on actions
needed to implement the cms.
Ensure that the licensee has properly grouped the cms and
that ^
one-for-one correlation of event to response had
' a performed.
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Evaluate the cumulative effects of CMS on the operating
personnel and to ensure that a 50.59 safety evaluation has
been performed to evaluate inpact on the plant Technical
Specifications (TS).
Evaluate operating personnel performance of cms and to
ensure that each CM can be performed within the essential
time frames.
Evaluate for one system /or major test, the resolution of
preoperational
test
exceptions
and
deficiencies,
specifically those dispositioned using compensatory
measures.
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(Closed) URI 327, 328/86-52-04, Control of Compensatory
Measures.
This item was reviewed as part of this inspection.
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OBJECTIVE NO 1:
To evaluate the licensee's program established
to control cms, AI-49 "Control and Tracking of Compensatory
Measures."
The inspectors reviewed AI-49, Rev. O, dated January 4,1988.
The procedure gives a specific definition for compensatory
measures (CM). A CM is defined by the licensee as a measure
required to be taken to compensate for a defeated safety
function or the lack of an adequate design and is required to
mitigate the consequences of accidents evaluated in chapter 15
or other significant events presented in the FSAR.
The procedura defines the single point contact for cms,
establishes uniform definitions
for cms use, outlines
responsibilities for individuals evaluating cms, specifies
minimum requirements associated with unresolved safety question
determination screening reviews associated with cms , and
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outlines actions to track activities for eliminating cms.
The
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inspectors had no unanswered questions about the procedure and
its intent, and considers the procedure adequate to control-
these type of issues in the future.
OBJECTIVE NO 2:
To ensure that 50.59 safety evaluations have
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been performed to allow auto design functions to be performed by
Administrative controls and/or personnel action and to ensure
procedure changes were-supported by. safety evaluations.
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There were 148 potential compensatory measures (cms) identified
to the licensee s task force for evaluation.
At the time of
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this re-inspection, the task force had determined that: 24 met
the specific definition of a CM; -77 did not meet; the CM
definition; 39 were duplicates of others; 1 was cancelled; and-7
were indeterminate due to lack of sufficient information at the
time of the evaluation.
The inspectors reviewed the 24 cms
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identified by the-licensee (listed in the Attachment to this
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report), the 77 non-cms, and the duplicates, and found the
licensee's determinations to be acceptable.
The inspectors did,
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however, express the following concerns:
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Item 1 (Source:
Memo 845870402254); Inoperability of
hydrogen analyzers.
This item concerned the TVA Division
)
of Nuclear Engineering (ONE) request that operators not use
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the hydrogen analyzers to perform any action, due to large
errors in the instruments.
This item was evaluated by TVA
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as a non-CM.
It was the inspectors' concern that the
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hydrogen analyzers are required by Technical Specifications
(TSs) to be operable in Modes 1 and 2; but, DNE's memo
indicated that they are totally unreliable.
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The issue with Hp analyzer operability has been an ongoing
concern with the NRC.
The inspectors met with TVA during
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this inspection and were provided the following information
by the licensee:
The H
analyzer, after completion of ongoing work,
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will be OPERABLE and will meet the current FSAR
accuracy requirement of + .5% H2 prior to entering
,
Mode 2 .
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The emergency operating procedures FR-Z.1 and E-1 have
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been rev' sed to instruct the operator to turn on H
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recombiners as a required action independent of H
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analyzer reading.
These procedures do require th$
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control room to use the H _ analyzers to determine if
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and when to turn off the H
recombiners.
TVA also
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plans to use grab samples to confirm H2 analyzer
2
readings as required by the hydrogen recombiner
operating procedure 50I-83.1.
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The above actions along with the NRC SER on H2 analyzer
operability will satisfy the inspectors' specific concerns.
Item 139 (Source: Memo 845860226218); Nonreliability of
containment sump level instruments.
This item concerned
the DNE request. for operators to not rely on the
containment sump level instruments for 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> following a
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loss of coolant accident (LOCA), then to verify level
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greater than 51% due to environmental qualifications (EQ)
error.
This item was evaluated by TVA as a CM.
It was the
inspectors' concern that TSs require the containment sump
level indicators to be operable in Modes 1-4; but DNE's
memo indicated that they are not reliable the first 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />
of a LOCA event.
The inspectors held discussions with TVA division of
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engineering personnel and were provided the following
information by the licensee:
The original memo from engineering to operations
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regarding the sump level transmitter inaccuracy was
based on information which used worst case vendor
information and design parameters.
However, the
current revision of DNE calculations SQN-05G7-0040
revision 6 has indicated that to ensure effective auto
swap over from RWST to suma and to ensure meaningful
indication for the controi room operator normal
instrument accuracies of +7.08%, -5.74% are accept-
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able.
However, during accident conditions accuracies
of +13.23%, -11.61% are assumed.
DNE is in the arocess of rescinding their original
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memo to operat'ons and instead will emphasize that
instrument accuracy is acceptable and the compensatory
measure should be voided.
The above memo has not been issued and the inspectors
consider this item unresolved pending receipt of the memo
and pending TVA's issuance of changes to the operating
procedures to void the compensatory measure.
Additionally,
the operations group is to issue a training memo to
operators to emphasize reliance on these indicators. (URI
327,328/87-73-01)
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Item 87 (Source: Preoperational Test PT-452); Excessive
vibration on the 28-8 RHR pump.
This item concerned a
preoperational test deficiency that indicated the 28-B RHR
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pump was not to be used during hot leg recirculation due to
vibration problems.
This item was evaluated by TVA as a
non-CM.
Evaluators from the TVA task force indicated that
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this was not the case at all, and the 28-B RHR pump could
be used in the hot leg recirculation mode if necessary.
It
was the inspectors' concern that revision 3 to the FSAR
reflected the use of the 2A-A-RHR pump during the hot leg
,
injection phase of the recirculation mode due to 2B-B-RHR
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pump vibration problems.
This item has now been resolved on Significant' Condition
Report, SCR SQN NE8 8708 rev. 1. and the reason provided by
TVA'for the FSAR statement about using the A pump over the
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B pump is that Westinghouse states that the A pump-is -
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preferred.
No prohibition in the emergency procedures to
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disallow use of the B pump could be found.
The inspector
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was satisfied with the licensee position on this issue.
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Item 68 (Source: Employee Concern 243.00); Overloading the
diesel generators.
This item concerned the possible
overload of diesel generators should a loss of offsite
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power,safetyinjection; phase 8containmentisolation,and
a loss of redundant class IE auxiliary power system occur.
Accordingly, operations was requested by DNE to ensure that
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all loads not essential to plant safety be manually removed
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should the diesel generator load exceed the continuous
rating.
This item was evaluated by -TVA to be a CM.
The
performance of such manual actions was referred to the
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OSP-Headquarters technical staff, and was found to be
acceptable.
The inspectors verified that appropriate
instructions, including preferred load removals, were
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provided in abnormal operating instruction A0I-35, "Loss of
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Offsite Power - Units 1 and 2.
The inspectors also reviewed the 7 indeterminate items and found
the task force preliminary CM evaluations to be appropriate.
However
item 145 (Source:
CAQR SQP871696) concerning
deficien,cies with the auxiliary feed water (AFW) / boric acid
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transfer (BAT) pump space coolers 2A-A and 28-8, was discussed
with the licensee. Apaarently, these space coolers don't meet
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the minimum design ad r flow nquirements.
Consequently, to
assure adequate cooling to their safety related equipment
spaces, a lower than design river temperature is required.
This
matter was brought to the attention of the OSP-Headquarters
technical
staff, since it could also involve a change to the
The licensee indicated that this was
still under evaluation.
This will be identified as unresolved
item 327,328/87-73-02 pending the licensee's final evaluation of
indeterminate items and development and implementation of
compensatory measures for all "yes" items.
OBJECTIVE NO. 3: To ensure that the licensee has scheduled, with
priority, the modification / maintenance necessary to correct
problem areas requiring cms.
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The inspectors reviewed
che licensee's schedules for
implementing corrective actions to eliminate cms.
After
preliminary resolution of the above indeterminate. items
twenty-eight items have been identified by the Licensee that
meet the definition of a CM.
However, only six of the cms
listed on Appendix "A" have a scheduled date for implementing
corrective actions essential for eliminating the cms.
The six reviewed with a scheduled completion date are listed as
follows:
"Overcurrent protection on electrical conductors
through containment" has been documented on CAQR
SQP871182, Rev. 1.
Actions to alleviate this CM are
scheduled to be completed by April 1, 1988.
"Unqualified flexible hose installed between essential
raw cooling water (ERCW) and diesel generator coolers"
has been documented on CAQR 871477I01, rev.0.
Actions
necessary to correct the condition and eliminate the
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need for the CM are scheduled to be completed during
the next refueling outage for this unit.
"Main control room air conditioners are not capable of
auto start of standby train when operating train
fails" is identified on CAQR SQP870217, Rev. O.
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Corrective actions are scheduled for completion by
March 1988.
"Normal feeder electrical cables for the turbine
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driven auxiliary feedwater pump control circuit are
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not sufficient to meet its voltage requ W ents during
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a loss of all AC power for a period o' wo hours".
Corrective Actions, except for post test ng, have been
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completed per ECN L6712. Post testing will be
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performed when the unit
reaches Mode 3, therefore
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eliminating any need for a CM.
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"Diesel generator electrical loading analysis does not
address fire pump loads".
Fire pumps may start from a
high temperature
signal
resulting from high
containment temperature due to a LOCA.
This condition
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was documented on CAQR SQT870649, Rev. O.
Completion
date for implementing corrective actions necessary to
eliminate the CM is scheduled for June 1, 1988.
"Inaccuracy in point xenon model will lead to maximum
- 600 pcm error for shutdown margin calculation."
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This issue is identified on CAQR SQP870083, Rev. O and
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corrections essential to incorporate the required
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conservatism into the calculation to ensure adequate
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shutdown margin was scheduled to be completed by May
29, 1987.
A review of Technical Instruction, TI-22
"Shutdown Margin Calculation", Revision 22 verified
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that the vendor recommendation for correcting xenon
worth calculations had been implemented.
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The inspectors will continually review schedules associated with
implementation of corrective actions essential to eliminate the
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need for the applicable compensatory actions.
The need to
schedule the additional items for resolution is discussed in the
cover letter to this report.
OBJECTIVE N0 4:
To ensure that personnel are properly trained
on actions needed to implement the cms.
Thepurposeofthisportionoftheobjectivewastodetermineif
personnel
responsible for taking action to accomplish
compensatory measures were adequately trained, were able to
properly perform the necessary actions and could perform these
actions in the time frames established and used for.FSAR event
evaluations.
The inspectors reviewed the licensee's evaluation of seven FSAR
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events during which compensatory measures would have to be taken
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and selected tornado and main steam line break events for
evaluation.
The TVA event evaluation and Unreviewed Safety
Question Determination (USQD), the related compensatory measures
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evaluations, and the implementina procedures were reviewed for
completeness, accuracy and overall adequacy.
Technical Support
Services Group (TSSG) and Operations personnel (the shift
engineer, one unit operator and two assistant unit operators)
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were interviewed concerning their perception of their
responsibilities, training provided related to compensatory
measures and their understanding of the actions required.
Walkthroughs of compensatory measure actions for blocking open
fire doors during a tornado warning and for placing lower
compartment coolers into service during a main steam line break
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event were conducted with the unit operator and assistant unit
operators.
Several weaknesses in implementation of compensatory measures
were identified during the inspection.
The training and
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instructions currently provided do not appear to be effective in
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assuring that Operations personnel can proficiently perform the
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necessary actions.
For example, startup of the lower
compartment coolers is required to meet EQ requirements during
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recovery from a main steam line break event.
The only current
implementing procedure for this activity is SQN Radiological
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Implementing
Procedures Document IP-6,
"Activation and Operation of the Technical Support Center".
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IP-6 degrites the responsibilities of the Technical Assessment
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Team (TAT) as providing support to the plant operations staff.
Accordingly, the shift engineer interviewed by the NRC
inspectors considered the TAT input to be recommendations only.
The NRC inspectors consider that in this case, actions required
to meet EQ requirements would be more appropriately put in
procedures used directly by Operations during event response.
In addition, the wording in IP-6 and the compensatory measures
summary did not provide sufficient details to Operations
personnel for the ERCW valve manisulations required to bring the
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lower compartment coolers on-line.
The motor operated
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containment isolation valves for the ERCW supply and return
lines to the lower compartment coolers are powered by
alternating electrical trains (ie., inboard and outboard valves
use different electrical trains with the train arrangement
reversed between "A"
and "B"
ERCW neaders).
This arrangement
allows valving in two of the four coolers without containment
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entry, even after a Phase B isolation and a loss of one power
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train.
If the
"A" power train was lost, the operators would
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have to manually open the two "B"
FRCW header discharge
isolation valves in the annulus, while the supply isolation
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valves, powered off the "B" electrical train, could be opened
electrically.
Tnis somewhat atypical configuration caused some
confusion with the operators during the walkdown, as they were
not able to determine which valves would have to be manipulated
and why.
In an emergency response situation, time would
probabiy have been unnecessarily wasted researching prints and
evaluating this condition.
03erator training on compensatory
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measures consisted of a "training letter" mandatory reading
handout of the compensatory measures summaries and a discussion
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of the measures with each operating shift crew during turnover
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meetings.
The required reading and turnover meeting discussions
did not provide sufficient detail for this compensatory measure.
Tne licensee was requested to validate procedures as to task
performance and upgrade procedures as necessary to provide
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additional details.
Additionally, the licensee was requested to
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provide augmented training above that already provided.
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licensee was also requested to provide a position on the use of
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IPs to control compensatory measures.
This item is unresolved
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pending completion of procedure validation and operator training
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(URI 327,328/07-73-03)
OBJECTIVE NO 5: To ensure that the licensee has proparly grouped
the cms and that a one-for-one correlation of event to response
has been performed.
After the TVA task force determined the existence of the 24 CHs,
,
they sorted them according to the FSAR event (s) they affected.
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Based on this sorting, TVA identified the following 7 FSAR
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events as being affected:
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(1) LOCA with loss of offsite power (LOOP)
(2) Main steam line break (MSLB) inside containment with LOOP
(3) Plant fire with LOOP
(4) Plant fire - Main control room abandonment with LOOP
(5) Tornado watch / warning with-LOOP
(6) Earthquake with LOOP
(7) Moderate energy line break
These cms and affected FSAR events were reviewed 'by OSP-
Headquarters technical staff inspectors.
The. inspectors
determined that all possible FSAR events affected were
considered and identified, as appropriate, by the TVA event
evaluations.
This determination was made based on ' feed back
from OSP-Headquarters and NRR, that it was not necessary for TVA
to evaluate major events such as a LOCA or MSLB, in conjuction
with occurrences such as an earthquake, tornado, or fire.
At the time of this inspection the licensee had prepared a draft
USQD (safety evaluation) for each of the 7 events, and had
determined that the associated cms and event . associated
emergency procedures could be accomplished with the minimum TS
required manning.
Members of the inspection team reviewed these
draft event USQDs and found them to be adequate.
However, the
tornado with loss of offsite power event needed to be modified
to specify time needed to carry out all action.
OBJECTIVE NO 6: To evaluate the cumulative effects of CMS on the
operating personnel and to ensure that a 50.59 safety evaluation
has been performed to evaluate impact on the plant Technical
Specifications (TS).
A review of the associated USQD event time lines, which outlined
the actions the shift crew would be taking in response to each
,
of the events, indicated accort.pi'shment with minimum TS required
'
manning.
All but 2 of the USQDs assumed an ultinte situation
(i.e. , Units 1 and 2 both operating at the time of the event).
The other 2 USQDs (LOCA with LOOP and MSLB with LOOP) were done
assuming only Unit 2 was operating at the time of the event.
Under minimum staffing, should Unit 1 be involved (i.e. , trip at
power the same time as the Unit 2 event), the reactor operator
(RO) in Unit 1 would be left to handle the situation on his
unit.
Accordingly, the licensee indicated that they were
considering the administrative requirement for an additional
.
assistant shift engineer to assist the Unit 1 R0.
This item is
also discussed in the transmittal letter for this report and is
identified as unresolved item 327,328/87-73-04 pending
resolution by the licensee.
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It was also revealed during the evaluation that out of the 24
cms identified,15 of them had either an inadequate USQD or a
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documented USQD evaluation could not be found.
Such matters
i
included:
Item 3 (Sourca: CAQR SQF 870022): Manual actions necessary
)
for a tornado watch.
Due to changes in the- plant
]
configuration and incorrect models used during original
tornado analysis, DNE requested operations to block open 24
doors during a tornado watch.- No USQD could be found.
Item 136 (Source: CAQR SQP 870217); Main control room t.nd
electrical board cir conditioning systems not capable of-
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automatic start of the stand-by train when the operating
train fails.
Due to design deficiencies, ERCW control
valv6s to the stand-by train air handling unit do not
throttle.
Consequently, manual operation of the valves is
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necessary to prevent the stand-by train from tripping due
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to excessive ERCW cooling.
- USQD did not address affects/
acceptability of this CM.
Item 138 (Source: CAQR SQP 870031); Unreliability of ERCW
supply valves to Emergency Diesel Generators (EDGs).
When
EDG ERCW supply valves are hand tightened to prevent
leakage, an auxiliary unit operator must be stationed in
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the EDG building to provide assurance that valves
immediately open when the EDGs start.
This manual.CM is
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required until valve operators can be changed out.
- USQD
did not address the affects or acceptability of this CM.
Item 92 (Source: CAQR SQT 870649); Fire pumps 2A-A and 2B-B
aligned to start only by manual actuation.
It was
postulate- that containment post LOCA conditions (ie. ,
temperatu.a, air particulates, etc. ,) could set off
I
containment fire detectors and cause the auto start of fire
pumps.
Therefore, to prevent possible EDG overload during
a safety injection, the 2A-A and 28-8 fire pumps were re-
quired by DNE to be aligned for manual operation only.
- No USQD could be found to support this action.
These 4 examples, which are representative of the 15 identified
USQD deficiencies,
illustrate
inadeouate 50.59 safety
evaluations, and are considered to be a violation (327,-
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328/87-73-05).
This does not meet the 10 CFR 2, Apaendix C,
Section V.G.
requirements as licensee identified since ARC
findings during the October 26-30, 1987 inspection prompted such
actions by the licensee,
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OBJECTIVE NO 7:
To evaluate operating personnel performance of
cms and to ensure that each CM can be performed within the
,
essential time frames.
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The inspector identified a weakness involving the failure to
indicate on the event evaluation time line all of the activities
required by procedures to be performed by the Technical
Specification minimum shif t crew.
Approximately 16 operating
shift crew actions specified in Abnormal Operating Instruction,
A0I-8, "Tornado ' Watch / Warning" were not referenced on the
tornado event evaluation time line.
These required Operstions
,
actions ranged from notification of site personnel by the shift
engineer (SE) or assistant shift engineer (ASE), to securing 37
)
ventilation fans in the control room by an R0, to closure and
'
dogging of over 30 tornado doors by auxiliary unit operator
(AU0).
Personnel responsible for preparation of the event
evaluations indicated that these operator actions were either
i
assumed to have been previously accomplished during a tornado
"watch" condition (such as AVO surveys of seven plant areas) or
had been included (but not referer:ced) in the time lines for
various compensatory measures activities.
However, the time
line and A0I-8 are both titled "Tornado Watch / Warning" and the
A0I does not assume that a tornado "watch" always precedes a
"warning".
In fact, it specifies a number of specific action
items under the actior listings for both scenarios.
Although a
walkthrough with the operators demonstrated that the
,
compensatory measures to block open 24 fire doors could be
accomplished " the allotted time, the NRC inspectors do not
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consider tha
I of the other required actions specified in
A0I-8 could ai,
be accomplished by the AU0s in that time.
The NRC inspectors also identified two additional concerns
related to the response procedures for a tornado event.
Neither
A0I-8 nor the compensatory mecsures event evaluation specify any
time restriction on performance of required actions, any
prioritization of the numerous actions involved, or any design
assumptions regarding the time available between issurce of a
tornado warning (with concurrent loss of offsite power in event
evaluation) and impact at the plant.
The assumption is that a
warning is issued when a tornado is sighted in the Hamilton
County Area (A0I-8, paragraph I) and it is assumed to move at 60
miles per hour (FSAR section 3.3.z.1).
It does not appear that
these assumptions have been adequately addressed in the time
line analysis for operator actions.
In addition, AOI-8 steps
for verification of communications (paragraph V.0)
and for
manual operation of four control building dampers are only
listed as subsequent actions to be taken after a "watch" has
been issued, but not after the more urgent and significant
tornado "warning".
In summary, it appears that TVA should review the event
evaluations for complete and accurate input of all required
operator actions, evaluate the required time lines for tornado
warning responses and review training and implementing
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instruction details to assure that Operations personnel can
proficiently perform all compensatory measures.
Subsequent discussions with the TVA compensatory task force
indicated that all actions needed to be taken by the operator
were assumed in the event response time line. However, they did
indicate that the lack of specific time and the actions
necessary to perform. the required tasks during a tornado would
be re-evaluated.
Resolution of this item is being included as part of the
corrective actions discussed in objective 4 above and is being
tracked as part of URI 327,328/87-03-03.
OBJECTIVE NO 8:
To evaluate for one system /or major test, the
resolution of preoperational test exceptions and deficiencies,
specifically those dispositioned requiring cms.
The inspector reviewed the Residual Heat Removal (RHR) system
preoperational tests to- evaluate. test exceptions and test
deficiencies that were resolved based on incorporating a
compensatory measure and to evaluate the disposition of those
remaining open after completion at the tests for possible cms.
The tests reviewed were:
Test No. W-6.1A1, "SIS Integrated Flow Testing"
Test No. W-6.1E, "SIS Residual Heat Rercoval Pump and
Related Injection System"
Test No. W2.2, "Residual Heat Removal System"
Test Deficiency Notice, DN-17, associated with test
no. W-6.1A1 was issued as a result of an identified
problem with a unit 2 flow indicator, 2-FI-72-34,
indicating a flow at a system no-flow status.
The
deficiency was resolved based on utilizing the
maintenance program
for correction
and
the
surveillance program to monitor this instrument on a
periodic basis.
A follow-up on the issue verified that this instrument
was incorporated into the surveiliance program.
SI-203, Rev. 3, " Periodic Calibration of Containment
Spray System" requires that this instrument be
calibrated on a 18 month frequency.
A review of the
calibration data dating back to 1981, revealed that
the instrument had been found within acceptable
,
tolerances each time that is was calibrated.
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Step 5.10 of SI-203, requires that if any instruments
were found outside their desired tolerances during
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calibration, an evaluation must be performed using
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Test
Instruction
(TI)-54.2,
which
provides
instructions
for reporting and evaluating the
deficiency.
The instrument surveillance program, based on review
of the issue above,. appeared to be adequate.
Test exception, EX-2, is listed in the preoperation
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test, W2.2 data package as remaining open.
This
exception identified RHR- valves FCV-74-12 and
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FCV-74-24 as having stem leakage. 'This issue. was
resolved without the need for a CM based on observing
these valves at a later date and determining that stem
leakage was no longer prevalent.
This resolution
appeared acceptable.
1
Test deficiency, DN-35, preoperational test W2.2,
states that not all RHR pump vibrations were within
acceptable ifmits.
This deficiency was later resolved-
by an engineering evaluation which determined that the
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pump vibrations were within acceptable limits.
There
'
was no need for a CM and the resolution appeared
acceptable.
d.
Review of Testing Activities
The inspector initiated a review of NRC inspections cenducted in the
areas of testing activities to access the completion ststus of these
inspections and that concerns in the inspection reports ha.>e and/or
are being addressed.
The results of these inspections are s amarized
below.
(1) Review results of local leak rate test (LLRT) inspection.
RESULTS
Inspection Report 327,328/87-51 conducted a review of the LLRT
program and its implementing procedures to ascertain that they
were of the quality to ensure that type "B" and C" testing met
the requirements of 10 CFR 50 Appendix J and Technical
Specifications.
The review of the program concentrated on
implementing procedures as to their technical content, clarity,
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system alignment, and adequacy of the provided acceptance
criteria.
In addition, the scheduling of LLRT was reviewed to
ensure that Appendix J LLRT frequency had been established.
Electrical penetration tests in progress during the inspection
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were also witnessed. Within the areas reviewed no issues or
followup actions were identified.
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(2) Restart Test Program Implementation
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RESULTS
The Restart. Test Program (RTP) is described in SNPP Volume II,
Section III, Paragraph 11.
The RTP commitments are to ensure
that the design and safety functions of selected plant systems
'
have been properly tested prior to restart or scheduled during
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restart as required.
Several inspections have been performed to
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verify that the restart test program has been implemented as
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committed.
]
Inspection Report 327,328/87-30 documented a review by the
inspector of program scope as to selected systems.
Additionally, functional review analysis; RTP administrative
controls and implementing procedures; restart test group
engineer qualifications and training; and program controls that
i
describe interface requirements between the restart test group,
plant manager and surveillance instruction upgrade program were
reviewed.
The results of this inspection indicated adequate
program controls and implementing procedures, however, certain
items identified required that:
-
The licensee needed to add additional systems (eg., rod
control and flood mode boration) to the functional review
process.
The licensee further clarify the system functions that
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would be identified and reviewed by the restart test-
program.
Clarification was provided in a letter to the NRC
dated May 26, 1987
to include normal system functions as
well as the design /' safety functions of the system.
The licensee improved procedures for conducting test
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activities and training test directors.
Initially, these
issues were addressed in a letter from the plant manager
dated June 18, 1987, and the subsequent issuance of AI-47,
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Conduct of Testing.
The licensee issue a letter of understanding between the
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restart test group (RTG) and the SI uagrade program
managers to ensure that any problems identified with
surveillance instructions by the RTG would be resolved.
The RTP manager issued a letter dated May 29, 1987, to
address this concern.
Inspection Report 327,328/87-43 and 327,328/87-50 performed
inspections of licensee functional review analysis on plant
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systems and components to determine whether the identified
functions had been adequately tested.
The inspections
concentrated on assessing the depth of the licensee's review,
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effectiveness of implementing procedures and adequacy of
documentation to ensure that system / component functions had been
tested and not degraded by post maintenance, modifications, test
procedure inadequacies, etc.
In general the inspectors found the licensee's system functional
review process to be detailed, with participation by the restart
test engineer and restart test group supervision.
It included a
committee review prior to submitting the system functional
review package to the Joint Test Group for final review and
approval.
The inspection identified two systems (system 32,
Control Air and system 92, Nuclear Instrumentation) where the
functional analysis report (FAR) for the system was incomplete.
j
Subsequent review of the approved FAR for these systems has been
conducted and the inspectors were satisfied with the licensee's
disposition of open issues.
The disposition of other unresolved
issues during the inspection is as follows
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UNR 327,328/87-43-01, interlocks which prevent discharge
valves from opening until Containment Spray Pump is started
j
has not been tested since preop.
The licensee issued
revision 4 to SI-68 which incorporated testing of the above
pump interlock.
The frequency for this test is every 18
months.
This item was closed in Inspection Report 327,
328/87-54.
4
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UNR 327,328/87-50-03
(CAQR-SQP870860)
Preoperational
Testing of Containment Spray Pumps and Ice Condenser Doors.
The licensee's evaluation of the CAQR for the ice condenser
door issue was reviewed and found to be acceptable.
This
portion of the unresolved item is closed.
The containment
spray pump portion of the unresolved item was reviewed and
!
found acceptable and is discussed in detail in Inspection
Report 327,328/87-76.
Inspection Report 327,328/87-54 initiated a review of the
Special Test Instructions (STIs) issued by the RTP for the
purpose of testing specific system functions that were
identified during the system function review process as being
deficient.
The licensee has issued 15 STIs.
Eleven of these
STIs have been reviewed for technical adequacy and compliance
with TVA implementing procedures and administrative controls.
Items identified during these reviews were resolved prior to
test performances.
Several STIs in progress have been witnessed
by the inspectors primarily to ensure proper conduct of testing
in the areas of establishing test prerequisites, use of test
logs, pretest briefings, handling of test deficiencies, and test
interruptions. In general, only minor concerns were identified
except for those related to conduct of testing for STI-65, as
noted in Inspection Report 327,328/87-60. The inspector's issues
were brought to licensee management attention and CAQR SQP871481
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was written to address these concerns.
The review and
witnessing of STIs will continue during the restart of Unit 2.
The review and completion status of the restart test program is
planned prior to various plant modes.and hold points.
The completion of the restart test program is currently tied to
the Mode 3-2 change.
However, the-inspector held discussions
with the RTP manager and reviewed JTG minutes and approved test
1
analysis reports (TAR) to determine RTP completion status and
preparation for the Mode 4 heatup.
As a result of these reviews
the inspector determined that:
RTP functional reviews and functional analysis reports have
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been completed for all systems.
Punchlist items and functional review matrix (FRM) items
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generated as a result of the system functions review
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process had been identified by the RTP by either an
applicable mode or a date for completion of the required
action.
The majority of these items were assigned for
completion prior to mode 4 for the heatup of Unit 2 .
Restart engineers responsible for each system will be
conducting an operability review of those punch list items
or FRM items with input from the plant operations review
staff (PORS).
Those items not required for operability
will be deferred until prior to Mode 2.
The results of
these reviews along with applicable justification will be
presented to the JTG for review and approval.
(3) Review status and inspection results for mode 5 SI test
witnessing.
RESULTS
Approximately 35 sis that were in progress were witnessed by
inspectors during team inspections associated with the SI
program review.
Additional sis have also been witness as part
of the normal resident program.
Although minor problems have
been identified,
the inspectors have determined that
surveillance testing is generally being conducted in accordance
with the written procedure.
During the restart test program review, TVA determined that
approximately 125 surveillance tests were required to be
reperformed to establish confidence in the system functions.
The tett directors were assigned responsibility to follow the
performance of their required test.
To date approximately 100
SI tests have been performed.
This testing has resulted in
identification and correction of problems associated with
several functions which included room cooler problems, diesel
generator problems and control room ventilation problems.
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Testing that remains open is currently scheduled to be complete
i
prior to the appropriate mode change.
(4) Review quality of special test procedures that will be used
during Mode 4 and 3 testing
REdVLTS
Review of Thermal Expansion Measurement Procedures
The licensee has committed to conducting thermal expansion tests
as part of the Unit 2 restart test program.
The purpose of the
thermal
expansion testing is to identify interferences
associated with piping thermal movements as a result of piping
and pipe support modifications which have been completed since
the preoperational thermal expansion tests.
The inspector
reviewed special maintenance instruction, SMI-2-317-42 revision
'
0,"RTP Inspection Procedure For Potential Thermal Interference"
and STI-62 Revision 0, "Hot Thermal Expansion Verification".
SMI-2-317-42 lists pipe supports which have been modified where
predicted thermal movements are more than 0.25 inches.
This
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instruction also requires inspections be made to verify that no
obstructions exist at these points which might restrict thermal
movement of
p' ping during heatup to normal operating _
temperature.
Licensee engineers have concluded that in areas on
piping systems where predicted movement are less than 0.25
inches the movements could be restricted without adverse
increase in pipe stresses.
This inspection has recently been
completed at ambient temperatures (mode 5).
SMI. 2-317-42
i
contains instructions for documenting inspection results,
recording and evaluating potential interferences.
i
STI-62 contains instructions for performance of the pipe thermal
expansion test during heatup to normal operating temperature
(547F).
The incpector verified prerequisites (including the
completion of SMI-2-317-42) specified, test methods and
objectives were clearly stated and appropriate acceptance
criteria were specified.
The inspector reviewed the results of inspections conducted by
the licensee in the Unit 2 reactor building in accordance with
SMI-2-317-42 to identify pctential interferences which could
restrict thermal movement of piping systems during heatup to
normal operating temperature.
The inspection results are
documented in TVA memorandum to L. M. Nobles from J. B. Hosmer,
dated November 4,1987, Subject: Sequoyah Nuclear Plant-Restart
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Test Program-Test Requirements for System Thermal Expansion
during Unit 2 startup.
The licensee's inspections covered 460
nodes and are listed in attachment 3 to procedure SMI-2-317-42,
35 potential interferences with pipe thermal movement were
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21
identified.
These potential
interferences and proposed
resolutions to correct the interferences are documented in
attachment 1 to the November 4, 1987 memorandum.
Discussions with licensee engineers disclosed that interferences
have been evaluated and resolved in preparation for plant
heatup.
The inspector will examine licensee corrective actions
and witness portions of the thermal expansion test in progress
during a future inspection.
(5) Review status and inspection results for mode 5 SI procedure
upgrade.
RESULTS
Inspection Reports 327,328/87-30, 87-36 and 87-50 conducted in
depth reviews of sis that had been upgraded during the
licensee's SI review and revision program.
The SI program for
upgrading instructions is being conducted in two phases. -The
short term review will upgrade those Technical Specification sis
and supporting sis required for startup operations and safe
shutdown of the Unit.
The long term SI program should address
administrative consistency,
achieve standard format ' and
organization, and make enhancements.
sis selected for review
included safety related system and components required by
Technical Specifications, the- inservice inspection-(ISI)
program, inservice test (IST) program for pumps and valves, and
Approximately 95 sis were reviewed
for technical adequacy.
Based on these inspections, TVA's SI program, as submitted to
the NRC, has produced adequate sis in the short term.
The
present sis are adequate to support the startup of either unit.
Long term control of SI upgrades are not adequately described in
present licensee's submittal.
The submittal of a detailed long
term SI program with completion dates and milestones is
currently being addressed by the Sequoyah Unit 2 restart SER.
s.
(6) Review primary leak rate calculation and ensure acceptable
primary leakage.
RESULTS
Reactor Coolant System Leak Rate Measurements (61728)
,
Documents Reviewed
SI-137.1 Reactor
Coolant
System
Unidentified
Leakage
Measurement (Revision 14)
SI-137.2 Reactor Coolant System Water Inventory (Revision 18)
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SI-137.3 Measurement of The Controlled Leakaga to The Reactor
Coolant Pump Seals (Revision 4)
Final Safety Analysis Report (Updated), Chapter 5
TI-28, Curve Book - Units 1 and 2
TI-41-68, Scaling and Setpoint Document
IMI-99 CC 5.528
Offline Calibration of Pressurizer Level.
Evaluation of Procedures
i
No questions arose from the review of SI-137.1 and SI-137.3.
However, SI-137.2 required considerable discussion before its
effectiveness could be evaluated.
The procedure appears to
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require more training than a more straight forward presentation
of facts and requirements would demand.
The procedure allows
the measurement to be performed in one hour, but experience at
other facilities indicates that test periods of at least two
hours greatly reduce measurement uncertainty and improve test
reproducibility.
The licensee is considering improvements to
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the procedure.
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Independent Measurement of RCS Leakage
Plant specific data were obtained for both units to develop the
parameters necessary to customize the microcomputer program
j
RCSLK9 for use on each unit.
The program is fully described in
RCSLK9:
Reactor Coolant System Leak Rate
Determination for PWRs.
Once Unit 2 is at rated temperature and
pressure, comparison calculations between the licensee's
,
procedure and RCSLK9 will be performed.
(7) Review shutdown margin determination for rod movement or boron
dilutions associated with heatup.
RESULTS
Originally TVA was planning to pull shutdown banks to the to) of
the core for plant heatup to have reserve shutdown reactiv' ty
available in the event of a dilution of boron concentration in
the core.
Had TVA withdrawn their shutdown banks for this
heatup they would have also had to pull all control banks out 5
steps to prevent thermal binding during the heatup.
The NRC
reviewed the Westinghouse recommendation to prevent thermal
binding and determined that the preferred method is to keep
reactor trip breakers open during heatup/cooldown evolutions.
After further discussions with TVA it was decided that reactor
breakers would remain open and rods would remain on the bottom
during plant heatup.
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TVA does plan to move rods for rod timing tests and rod position
calibration but this evolution will be performed in mode 3 after
this hold . point release.
The inspectors .will monitor- rod
testing during the heatup phase and shutdown margin calculation
will be reviewed for that evolution.
To ensure that procedures
currently being used by the licensee for shutdown margin
determination are correct and reflect current core data the
inspector conducted a review of'recently performed tests.
Procedures reviewed were SI-38, "Shutdown Margin", and TI-21,
"Shutdown Margin Calculation".
The inspector also compared
TVA's
arocedures to raw source data from Westinghouse core
!
analys's for this cycle on Unit 2 and determined that the.above
procedures reflected . correct -vendor information and satisfied'
the requirements of Technical Specifications.
1
As stated above the inspector will review shutdown margin
calculations associated with rod motion for the heatup.
(a) Independent Review of Core Characteristics
Operability of Source Range Nuclear Instruments
(61705)
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With the extended shutdown of both units, the regen-
erable neutron sources in each unit -could not be
,
maintained at optimum levels.
To assure that- the
sources and cores are =still producing.a detectable
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level of neutrons and that the source range nuclear
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instrument channels are responding primarily to
neutrons, a statistical. analysis was performed on each
operating channel.
Twenty-five, 200-second-duration counts were obtained
from each operating channel: on Unit 1, nuclear
1
instrument channel N32 (SIN 32), and on Unit 2,
channels N31 (S2N31) and N32 ($2N32).
Each set of.
observations (counts) was subjected to a chi-squared
analysis or test. ~ The chi-squared test compares the
variance of the data set with the expected variance,
in this case that of a Poison distribution, and
assesses the probability (in percent) that the
expected Poison distribution would yield a larger
value of the statistic.
For this test, the best
result is 50% probability and' the farther the result
is from 50% the more likely the channel is not
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functioning properly, which includes responding to a
signal source not the' product of a nuclear decay
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process.
Many text books on pulse counting systems
1
define the acceptable range of probabilities as 5 to
90 percent, and that is the acceptance criterion used
here.
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Test results are given in Table 1 below.
It should be
noted that the results for.52N31 are based upon 25 of
26 observations.
One observation was rejected by
virtue of being more than 10 standard deviations
larger than the mean of the other 25 observations.
Possible sources of the discrepant datum . include the
failure of the scaler to recycle properly at the end
of a 200 second period or a burst of electrical noise.
The problem appeared to be an anomoly and was
appropriately dispositioned.'
All other results in the
'
table are based upon 25 sequential observations.
'
TABLE 1:
Statistical Analysis-of Source Range Nuclear Instruments
1
CHANNEL
CHI-SQUARED
PROBABILITY
COUNT
RATE (cps)
SIN 32
26.5
33%
290.1
1.45 +/-0.09
S2N31
20.4
67%
483.9
2.42 +/-0.10
S2N32
22.8
53%
351.2
1,76 +/-0.09
From the results given above, the inspector concluded
that a detectable source of neutrons exists in each
reactor and that the operating source range instrument
channels are responding primarily and appropriately to
those sources.
,
,
Instrument maintenance instruction (IMI) 92-SRM-CAL,
Nuclear Instrumentation System Source Range Calibra-
tion, (Revision 11 in process) was re awed.
It
i
appears the procedure and planned revisions are
'
adequate to accomplish the refueling interval sur-
veillance required by Technical Specification Table
4.3-1, Item 6.
The channel functional tests required
by this same item are addressed in IMI-92-SRM-FT.
The
inspector had no questions following review of this
procedure.
-l
By review of the surveillance log, the inspector
confirmed that the required source range channel
surveillances and channel checks had been performed
with the required frequency during 1986 and 1987.
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.
.
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.
.
Q
25
l
. Measurement of Thermal Power (61706)
,
,
Documents Reviewed
Final Safety Analysis Report (Updated), Chapter 5
Westinghouse Technical Manual 1440-0224, In-
structions for Vertical Steam Generators
Westinghouse Technical Manual 1440-0225/C229,
Pressurizer for Sequoyah Unit 1/2
TI-2 (Revision 14), Calorimetric Calculation,
Units 1 and 2
Confirmatory Calculations
Using information from the documents above, most of
.the plant specific data necessary to adapt the
microcomputer program TPDWR2 for use with either unit
were obtained, and the loading of unit-specific data
into of the program was started.
The program is
described fully in NUREG-1167, TPDWR2: Thermal Power
Determination for Westinghouse Reacters, Version 2.
Once the unit specific data loading process is-
complete, the parameter lists for each unit will be
provided in an subsequent routine inspection report.
Once a unit is at rated thermal power, comparison
calculations between the licensee s procedures and
TPDWR2 will be performed.
(8) Review effectiveness of controls that were established for the
conduct of testing (ie., administrative procedure AI-47)
RESULTS
Several specific observations of test control were discussed in
section (d)(2) above.
The purpose of this discussion is to
provide additional information regarding conduct of testing.
After the NRC expressed concerns regarding the conduct of
testing and as part of a commitment made by TVA in the June 18,
1987 enforcement conference to improve operations performance,
TVA determined that better controls after testing were needed.
The changes made by TVA was the establishment of a site
administrative procedure AI-47, "Conduct of Testing", which
consolidated the numerous testing requirements from several
procedures.
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AI-47 established the test director. concept and specified
required qualifications for both test directors and test
performers.
The procedure also specified responsibilities as
well as establishing the needed authorization and notification
requirements to allow better control by the operations
department.
Although specific testing problems have been noted by the
inspectors since the establishment of AI-47, most occurred soon
after the establishment of the procedure and appeared to be more
associated with familiarization of test directors to the new
program rather than a lack of procedure control problem.
Approximately 800 people received training on the procedure
since issuance and TVA is factoring this training-into the power
operation training center curriculum.
The inspector has also
discussed with operations shift supervisors their perspective on
how well the controls are working to improve their knowledge of
ongoing testing that may effect their unit.
They indicated that
they had more control over activities since the procedure was
1
established and were very supportive of its development.
The inspector considers that adequate controls are currently in
.
place to control testing covered by AI-47 and implementation of
'
its requirements will be monitored during heat up and power
operations.
e.
Review of Plant Procedures Needed for Heatup
(1) Review any changes to G0I-1 & 2 and ensure that procedures were
validated and operating personnel were trained.
RESULTS
This item was evaluated and is discussed in Inspection Report
327,328/87-71, which stated that training had been conducted by
the licensee on GOI-2, "Plant Startup from Hot Standby to
Minimum Load," and RTI-3, "Initial Criticality," but that no
training had been conducted on G01-1, "Plant Startup to Hot
Standby .
Since that time the licensee has conducted training
on GOI-1.
An inspector reviewed the applicable lesson plan and
training records to determine adequacy of the training.
The
inspector determined that 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> of formal classroom training
was held for licensed operators and STA personnel to cover
significant changes to G01-1, including the following:
Interface with Restart Test Instruction, RTI-1.1, Master
-
Test Sequence and completion of the Restart Checklist
during heatup of Unit 2.
.
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27
Responsibility associated with designated holdpoints agreed
-
to by TVA and NRC and required tasks / actions including
Plant Manager approval prior to_ leaving holdpoints.
Description of various testing to be performed in conjunc-
-
tion with Mode 4.
-
Use of precautions and prerequisites.
j
Test requirements for performance of Rod Drop and RTD Cross
-
Calibration Tests, SI-43 and SI-488/TI/60
Additionally the inspector determined that the licensee has
committed to INP0 to conduct additional training on GOI-2 prior
to reactor startup.
This training will be conducted to ensure
correct utilization and understanding of the source count rate
"doubling method" and when shutdown margin needs. to be
4
calculated.
'
)
(2) Review special procedures for control of heatup/startup and
ensure
agreed NRC holdpoints have been. established.
Additionally, verify that proper levels of licensee review and
management involvement have been established for mode change
decisions.
RESULTS
This item was evaluated and discussed in paragraph-18.a of
inspection report 327,328/87-60
f.
Review of Licensee Operational' Readiness Assessment
(1) Review the closure of several SAL packages and verify compliance
to SQA 190.
i
4
(2) Review second interim operational readiness (OR) report and
ensure TVA is resolving open issues.
(3) Review TVA's assessment of special project closure contained in
i
OR report.
(4) Review status of department performance criteria assessment and
ensure personnel staffing goals have been met.
RESULTS
The above 4 items were evaluated and discussed in paragraph 18.b
of inspection report 327,328/87-60
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(5) Review TVA's Lowest Mode Determination
RESULTS
In early 1987 TVA established and implemented SQA-190 to 3rovide
the necessary guidelines for identification of restart items.
These guidelines were bread in scope, considering such things
for restart as Technical Specification (TS) operability, NPP
programs and commitments, NRC inspection findings, etc..
In
conjunction with SQA-190, RTI-1.1 was implemented to assure
_
accountability by each of the responsible managers for. the
completion of all their identified restart items.
This restart
determination process was inspected by NRC in March 1987, and
found to be conditionally acceptable.
j
In late September 1987, TVA discussed with NRC
e desire for a
shakedown heatup of Unit 2 to identify potential equipment
1
problems and get operators use to functioning in a hot plant
environment.
In short the shakedown heatup is to be approx-
imately 5 weeks long, after which the plant may be returned to
Mode 5 to fix any identified equipment problems, and complete
1
any deferred corrective actions. Since this shakedown heatup may
j
be separate from the heatup associated with plant restart, those
items identified under the broad scope guidelines as restart
items per SQA190 are being screened for Mode 4 and 3 TS
operability only.
Those restart items not meeting this
operability call will be completed prior to the subsequent
heatup/ restart.
Consequently, part of the NRC heatup readiness
inspection was to establish the necessary confidence in TVA's TS
operability evaluation.
TVA's lowest mode determination is being driven by a modified
RTI-1.1 and accomplished under 3 basic processes:
(1) the P-2
lowest mode determination list under the plant operational
review staff (PORS); (2) WR/MR punchlist under maintenance
planning; and (3) surveillance instructions controlled as usual
under the general operating instructions (GOIs).
The NRC
inspection in this area consisted of:
(1) a review of TVA's
overall processes being used to identify those items necessary
to support shakedown heatup, ensuring NRC commitments were
j
included appropriately; and (2) a test of the processes using
open items listings associated with the containment spray (CS)
,
system.
Lists used included:
corporate commitment tracking
system (CCTS) commitments; tracking and reporting open items
1
(TROI) listing of CAQRs, PR0s, etc; design baseline verification
program (DBVP) punchlist; restart test group (RTG) punchlist;
work requests (WR)/ maintenance request (MR) listing; and a
listing of employee concerns from both the special and new
programs.
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The P-2 lowest mode determination list under P0RS was originally
limited in scope to identify mode 4 and 3 TS "hardware" items to
the plant manager and input to the P-2 restart schedule.
The
scope has recently been expanded to include both "hardware" and
"paper" issues.
Inputs to the P-2 lowest mode determination list are taken by
P0RS from the P-2 restart schedule and responsible managers make
TS operability calls on those items they have identified as
"restart" per SQA-190.
The TS operability items, identified on
lowest mode determination sheets, are given to PORS for their
review and evaluation.
Each mode determination sheet is also
route
to the site director's office for concurrence.
P0RS
d
subsequently revises the P-2 lowest mode determination list
accordingly.
Since TVA is not planning to close out any program related'
startup activites list (SAL) items prior to the shakedown
heatup, the inspectors reviewed the status of TVA's Division of
Nuclear
Engineering
(DNE)
programs
(eg.. . mechanical
calculations, electrical calculations, etc.).
It appears that
except for the program related areas of the NRC IDI, civil
calculations, and silicone rubber cables, all open issues have
been identified, with a restart and lowest mode determination
call being made.
A review of the overall lowest mode
determination process indicated that very little guidance, other
than "evaluate for TS oaerability", was provided.
Consequently,
this resulted in such :nconsistencies as listing field complete
items with their lowest mode identified as "N/A , or with their
lowest mode provided and indicating "work complete".
Other
findings include:
-
Cases of duplicate items found with different mode
determinations (i.e. , one may say mode 4 and dher N/A,
usuall
work.)y due to updated inputs reflecting completed field
Prior to the announcement of NRC inspection intentions the
-
week of 10/19/87 listed items were not identified with a
system.
Subsequent review by TVA after this system
identification process, resulted in changing a CS ' restart"
commitment item from the indicated mode 2 determination to
the appropriate mode 4 determination on 10/16/87.
CAQR 871559 concerning the inability of CS pump 2A-A to
-
meet its pump curve was not identified by TVA as a restart
item.
It was also noted that the latest 4 commitments on CS were
-
not included in the review process-(Not on CCTS yet).
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30
The above problems were identified to the licensee for
correction.
In general, the expansion of the P-2 lowest mode determination
list was still in progress during the October review.
P0RS was
in the process of identifying any P-2 restart items not yet
captured in their review and also identifying / correcting
inconsistencies like the ones mentioned above.
Once the
expansion process is completed, the system should be~ easily
manageable by P0RS.
,
A review of the MR/WR punchlist process revealed that TVA's
.
maintenance planning section evaluates all MRs and WRs for
"restart" and "mode applicability".
Operations personnel are
used to perform second checks on the mode applicability calls.
The MRs and WRs are classified under one of four categories.
The four categories are defined as follows
WR/MRs required to be worked prior to Mode 4 shakedown.
-
WR/MRs that should, or could be worked prior to mode 4
-
shakedown and must be worked to support shakedown.
(Mode 3
primary equipment, mode 4 and 3 secondary equipment, and
other items wanted by operations).
WR/MRs required to be worked prior to mode 2 (criticality).
-
WR/MRs that should be worked prior to mode 2 but do not
-
impact mode change.
At the time of this inspection, there were 463 Mode 4 WRs
outstanding (category 1: 285; category 2: 178).
In general, the MR/WR punchlist process appeared to have good
program implementation.
One item (MRB212568) dealing with
leakage from a CS transmitter was considered by the inspector to
be a category 1 instead of the category 2 indicated.
'
Maintenance planning indicated a re-evaluation of this item
would be performed.
,
i
Conclusion:
Based on the limited sampling using CS _as a test case, it is
felt TVA's lowest mode determination processes (driven by
RTI-1.1) will support the shakedown heatup of Unit 2.
(6) Review licensee safety evaluations which justify continued
operation despite degraded conditions or outstanding evaluations
(e.g. , cable testing, component cooling water heat exchanger
performance, room cooler performance, cable routing, civil
,
N
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31
calculations, pipo support modifications, ets.).
Assess impact
on operability.
RESULTS
This area was addressed within section c.(3) of this report
which involved review of licensee assessment of defeated safety
systems.
g.
Review results of walkdown inspection on 5 safety systems
(1) Verify effectiveness of independent verification process.
(2) Verify procedure adequacy and adherence.
(3) Verify correct use of configuration control log.
(4) Verify shift engineer and control room operator demonstrate
adequate control of valve position changes and the valve lineup
4
process in general.
(5) Verify that any deviations identified are properly evaluated and
j
resolved.
(6) Verify system drawings used for walkdown reflect the results of
DVBP.
RESULTS
This area was initially reviewed during the valve lineup
inspection documented in Inspection Report 327,328/87-66. During
i
that inspection the NRC identified conditions that resulted in
the licensee stopping work to rewrite procedures and retrain
personnel. The licensee's corrective actions and the NRC
followup inspection are documented in Inspection Resort 327,-
328/88-06 and are summarized at the end of this sect 1on.
i
The objective of the first inspection was to verify the adequacy
of the Sequoyah Unit 2 system alignment process for unit heatup.
This was accomplished by using portions of modules 71707, 71710
and 71715 to verify the following:
The effectiveness of the independent verification process
-
(AI-37).
-
The adequacy of system operating instruction (S0I)
checklists.
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The effectiveness and adequacy of the configuration control
log and its interaction with the S0I checklists (OSLA-58).
i
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The adequacy of control for valve position changes and the
valve lineup process by the shift engineerand the control
room operator.
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32
The procer evaluation and resolution of any identified
-
deviations from the S0I checklist.
The adequacy of system drawings used for the valve lineups.
-
.The adequacy of training for people performing valve lineup
-
and equipment operation.
During the system alignment walkdowns the general condition of
the plant was evaluated adequate to support plant heatup (ie. ,
fire hazards, housekeeping, meltable materials, etc.). However,
due to the transient nature of this item the NRC will re-inspect
this area during the followup valve lineup inspection, currently
scheduled prior to heatup.
Additional Sequoyah procedures and instructions which were used
during this inspection are listed below:
G01-6, Apparatus Operation
AI-3, Clearance Procedure
AI-2 (portion pertaining to authorized deviations from SOI
checklists)
AI-16 (portion pertaining to fuse replacement)
Independent Verification
In general, the licensee's program for independent verification
is considered adequate.
One discrepancy was observed and
'
pertained to differences between the working copy of a checklist
and the final copy in the status file.
The discrepancy
indicated 'a misunderstanding on the part of some licensee
personnel conducting the system alignments about the reason for
using working copies of checklists and that initials between the
l
working copy and final copy of the checklists should match.
The
NRC team believes that the problem relates to inattention to
detail and was properly handled when reported to licensee
management.
Procedure Adequacy and Adherence
SOI Checklists; The licensee identified a number of problems
with their chec'klists.
The NRC also identified some checklist
problems independently of the licensee.
The licensee is
currently fixing problems that are necessary to complete the
checklists.
Items that are needed only for clarity will be
revised at a later date.
An NRC review of SOI checklists
against drawings revealed a number of ECCS valves and flanges
shown on the print and installed in the plant that were not on
the checklists.
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33
OSLA-58 Adequacy; This procedure was determined to be a jeopardy
to the adequacy of the entire system alignment process.
The
procedure only requires configuration control measures to be
invoked after a checklist is complete, rather than at the start.
The licensee has committed to revisions of this document and a
remedial program prior to reverification of the valve lineups.
Procedural Adherence; Only minor problems were encountered with
SOI checklist performance.
Compliance with OSLA-58 is a hard
task since the procedure has ambiguities, conflicts, and errors.
In addition, procedural compliance may result in invalidation of
50I checklists as noted above.
Configuration Control-Log
This log is intended for use as a paper status board.
The log
is not always used in mode 5 since not all systems are required
to be operable in mode 5.
When being used with SOI checklists
for deviating item; that can not be positioned per the required
checklist position, minor problems occurred.
Major problems
have occurred in the time frame after checklists are finished
due to the complacency created by not having to keep configura-
tion control on most systems during mode 5.
Scven valves were
discovered out of position by the NRC inspectors with respect to
the position documented in the SOI checklists and the
configuration log.
This indicates a deficiency in either the
procedures describing the use of the configuration log, or the
ease of use of the log, or both.
Shif t Engineer / Unit Operator Control
Control of evolutions such as changing valve and equipment
configurations appears to be satisfactory.
A problem does exist
pertaining to compliance with the adninistrative requirements
for logging equipment configuration changes.
Valves were found
by the NRC team out of the documented position in the S0I
checklist and configuration log.
These valves appeared to have
been repositioned after completion of the checklists.
This
clearly indicates a breakdown in the administrative controls for
configuration control required by AI-30 and 0$LA-58.
Deviations From SOI Checklists
All deviations reviewed by the NRC appeared to have been
properly evaluated for mode change.
Problems with checklists
were properly evaluated, clarifief, or revised as appropriate.
The NRC did identify that the date the item was deviated was not
being included on the 50I checklist as required by OSLA-58.
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34
System Drawings
Some minor drawing discrepancies- were noted.
In general
drawings are considered adequate ~
l
Training
Training appeared adequate except -for how to perform category
"A" S0I checklists.
Certification that management considered
the training adequate to perform double verification -on S0I
checklists was missing.
TVA has committed to certify the
individuals.
Results of the followup system alignment inspection -(IR
327,328/88-06):
The licensee upgraded system alignment procedure OSLA-58 to an
administrative instruction, (AI-58) and changed the deviation
method to agree with procedure change requirements in the
-
Technical Specifications.
Some additional' changes to this
,
procedure were required to ensure clarity as to when
configuration control should start.
Several breakers for PASS
valves were found out of position due to a misunderstanding of
AI-58.
The configuration control system was changed so that
items controlled by procedures that returned systems to normal
need not be logged in the configuration log.
In addition,-
equipment controlled from the control room. control boards are
not required to be logged in the configuration log.-
This system
appears to be less complicated and easier to use.
A further
example of not properly initialing a deviation on a checklist
was found.
An additional number of examples of breaker
positions not specified on the checklist were also found.
Overall, the licensee had much ~ better control 'of system
alignment than during the previous inspection.
Training
certifications were found missing again- for individuals in the
system alignment team.
Follow up actions :by the licensee 'to
correct the above items is ongoing and completion of heatup
actions will
be reviewed by the inspector prior to
recommendation of hold point release.
h.
Plant Material Condition
(1) Conduct containment walkdown and verify that general condition
will support plant heatu
fire hazard, housekeeping,
meltable materials, etc.) p (ie
'
(2) Conduct plant tour and assess general material condition -and
housekeeping.
(3) Review primary and secondary chemistry and discuss secondary
system chemistry with chemistry supervisor.
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35
(4) Review results of plant security inspection / verification.
(5) Review backlog of work requests and ensure that TVA has
completed their review of this area per their operational
readiness program.
'
(6) Review results of maintenance program inspection and ensure that
any open items identified as prior to heatup have been resolved.
RESULTS
The inspectors reviewed the condition of plant equipment and th
status of corrective action programs in the maintenance area
One purpose of these inspections was to determine if the
licensee was adequately managing maintenance of plant equipment.
The inspectors reviewed the licensee's actions to identify plant
equipment deficiencies, initiate maintenance requests (MRs) to
correct the deficiencies, tag the deficient equipment, review
maintenance requests and categorization of MRs that affect
equipment operability as restart, and review the licensee's
progress in working MRs and correcting p' ant equipment
deficiencies.
The inspectors conducted tours of the plant, in
some cases accompanied by plant auxiliary unit operators (AV0s),
to determine the condition of plant equipment.
The inspectors
selected a sample of MRs hung on-plant equipment and determined
if the MRs affected operabilit
These results
were compared to the licensee'y of the equipment.
s determination'of restart MRs.
'
The inspectors identified the following conditions which
resulted in the licensee issuing MRs to correct the conditions:
Missing bolt on discharge flange on relief valve 2-67-5820
-
CCS vent valve 2-70-5508 plugged with rust and had no cap
-
Boric acid buildup on pump shaft of RHR pump 28-8
-
Excess boric acid crystal buildup on valves
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1
Fire extinguisher in EL 653 pipe chase with no holder and
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last inspection on July 31, 1985
On centrifugal charging pump 2A-A pump flange cocked and
'
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boron residue present, dirt buildup on motor filter
The inspectors also identified six examples of broken flex
conduit, three examples of missing condulet covers and two
examples of missing conduit support clamps.
Additional examples
of minor equipment upkeep problems were brought to the
licensee's attention.
These examples did not appear to
represent significant problems in maintaining equipment.
The
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36
i
licensee indicated that walkdowns of plant equipment would be
conducted during the heatup/ shakedown to confirm equipment
operability.
During the plant tours, the inspectors selected 22 MR tags
placed on safety-related equipment for followup review to
determine if MRs were being appropriately categorized as restart
or non-restart items.
Of the 22, six of the MRs had not been
entered into the computer tracking system. 'One of these MRs had
been cancelled, four were new MRs and not yet entered, and no
reason could be explained for the last one.
Seven MRs had been
completed, but tags had not been removed from the equipment.
One item on the 2A-S turbine driven auxiliary feed pump,
involving seal leakage, was recategorized from a category 3
heatup item to a category 2 item and from a priority 4 MR to a
priority 1 MR.
The inspectors agreed with the restart
determination on the remaining MRs.
The inspectors made the following recommendations:
Action should be taken to correct lighting deficiencies in
-
several areas including lower containment and in the EL 653
pipe chase
Although most MR tags had descriptions of the problem
-
identified, some MR tags did not contain any information on
why the MR was written.
The licensee .,,iould emphasize that
descriptions of problems identified should be entered on
the MR tag placed on the equipment.
This practice would
assure that appropriate personnel could readily determine
the deficient condition and initiate an MR if additional
deficiencies were identified.
-
The licensee does not require that tags be placed on
equipment, particularly in contaminated zones.
The
inspectors believe that placement of tags directly on the
i
defective equipment assists the operator in recognizing-
what deficiencies exist and assure initiation of MRs. if
additional problems are identified.
Currently,' individuals
have to research the MR list to determine if an MR as been
written to cover a deficiency.
The licensee is evaluating these rccommendations
for
consideration.
i
The inspectors observed general cleanliness and physical
condition of rooms, equipment, valves, supports / restraints,
piping, etc.
The inspectors found that with few exceptions, the
areas and equipment not being worked were in good condition.
Excellent housekeeping and equipment condition were exhibited'in
the diesel generator building and the spent fuel pool cooling
i
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37
equipment area.
The inspectors also noted the housekeeping had
improved significantly.in pipe chases.
Other areas were in good
to average condition.
Two areas where housekeeping could be
improved (a portion of the EL- 653 pipe chase and the ERCW
-
platform on EL 714) were brought. to the attention of the
ifcensee.
The ir.spectors noted that additional cleanup would be
required in areas where work was ongoing, including the ERCW
pumphouse, lower containment and the accumulator and fan rooms
inside containment.
R
The inspectors discussed- actions taken in the areas of primary
ar.d secondary plant chemistry with the chemistry group manager.
NRC Inspection Report 327,328/87-33, dated June 3, 1987, had
requested that the licensee provide an assessment of the
condition of the steam and power conversion systems of each
unit.
The report also stated that the NRC understood that the
licensee was to implement dry layup of Unit 1 to minimize
further exposure to potentially degrading environments.
The
licensee stated in a response dated July 29, 1987,_ that an
erosion / corrosion assessment progran had been implemented.
This
program evaluated the condensate, feeawater, extraction steam,
heater drain and vent lines, and turbine drain and vent lines.
The licensee ctated that the damaged 16-inch elbows and
16x18-inch reducers in the feedwater piping were replaced with
'_
stainless steel piping and the damaged high pressure vent line
had also been replaced.
The licensee also stated that a program
had been implemented to retain the inspection data base and
monitor suspect areas.
The inspector also reviewed a report,
dated April 20, 1987, which indicated that the ifcensee had
reviewed the layup methods for each major system, identi11ed
i
potentially corrosive conditions, and had made recommendations
i
to improve the areas.
The licensee stated that action had been
taken to address these recommendations.
The licensee provided a
'
scaedule indicating actions to be taken to assure maintenance of
appropriate primary and secondary chemistry during heatup and
startup activities.
The licensee provided a schedule for
completion of the dry layup of Unit 1 which is expected to be
i
completed in early 1988.
The licensee has recently placed a
manager with sixteen years of experience-in the chemistry group
manager position.
The chemistry group manager indicated that
significant improvements had been made in the chemistry programs
1
and procedures, and further improvements were planned.
The
licensee had added additional experienced staff, provided
i
additional emphasis to technicians and operations on the need to
strictly maintain chemistry parameters, and plans to provide
training on corrosion / erosion control for the steam generators
and secondary side components.
The licensee is evaluating
chemistry parameters to assure that appropriate limits have been
'
set and is establishing administrative limits to assure that
4
m,--
.,w.,-.
- , ,,- - --
.,
- , , - , .
, _
,
--
++,ne--
- , + -- - - .
(
-
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38
action is taken prior to exceeding set limits.
The licensee.has
,
assigned one of the assistants to the plant manager to oversee
improvement efforts in the chemistry and radwaste areas.
The inspector also reviewed the status of the pre-startup
security inspections with the site security manager.
As a
result of an NRC violation, the licensee conducted a vital area
barrier walkdown during the week of October 12, 1987.
The
walkdown identified three barrier problems which have been
repaired.
After valve alignment and prior to heatup, the
licensee intends to conduct an additional detailed vital area
walkdown using security officers and operations personnel.
The
licensee stated that checklists were being developed for each
area to assure complete walkdown coverage.
Additionally, the
following open items were reviewed:
(0 pen) Inspector Followup Item 327,328/86-18-06; Review of
l
maintenance instruction (MI) enhancement program.
The inspector
reviewed the statas of the maintenance instruction enhancement
effort.
In response to commitments documented in NRC Inspection
Report 327,328/87-37, the licensee submitted a schedule and
1
program description for the maintenance instruction enhancement
program by letter dated August 14, 1987.
The letter indicated
that high priority maintenance instructions (mis) would be
i
,
revised by May 30, 1988.
The inspector discussed the status of
'
the program with the cor) orate maintenance coordinator and the
instruction revision profect manager (IRPM).
The licensee has
established a separate group under the IRPM structured to handle
'
electrical, mechanical and instrumentation revisions.
The
licensee plans to expand the group in the future to handle
j
procedure revisions for all plant procedures.
The IRPM reports
to the plant manager.
The group currently has 13 contract
procedure writers and 4 craft procedure writers.
Three licensee
employees are assigned to manage each of the three discipline
areas.
The inspector was provided a copy of the corporate writer's
guide for maintenance organization instructions which is
attachment 2 to ONP-STD-4.4.7, Administration of Site Instruc-
tions.
The writer's guide, issued on August 28, 1987, is beirg
used to write the enhanced instructions.
Training haa also been
conducted on the writer's guide for the writers.
The licensee
indicated that the validation / verification' methods were being
evaluated and procedures would be revised to address validation /
4
verification by November 20, 1987.
The inspector also reviewed the status of the restart procedure
revisions.
The licensee has completed all but one of those
procedure revisions designated as restart items.
The inspector
determined that a significant nortion of the restart items
identified in the equipment con' ition evaluation reports, dated
d
n
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39
February 11, 1987 and March 9,1987, had been completed.
The
inspector determined that significant progress had been made in
completing the restart items in the maintenance area.
(Closed) Unresolved Item 327,328/86-69-03; Eberline post
accident monitor (PAM) RM-90-450, printer drawer maintenance.
The inspector had determined that an upgrade kit had been
installed in the drawer under a maintenance request rather th"
as a modification.
The licensee evaluated the use of the
maintenance request for this repair and indicated that the
upgrade kit, although different from the installed model, was
supplied by the vendor as a direct replacament.
The function of
the equipment was not changed, the equipment was not class 1E
and no plant drawings were required to be updated.
In this
instance it appeared that use of the maintenance process instead
of the modification process would not have compromised the
quality of the installation.
The inspector discussed the need
to maintain the proper threshold for use of the modification
process when plant equipment was altered with the licensee.
This item is closed,
i.
Conduct of Operations
(1) Review level of management involvement in day-to-day operations
RESULTS
Interviews with approximately 15 operations personnel (AU0s,
U0s, ASEs and SEs) revealed no weaknesses in operational
capabilities, knowledge of the plant and systems, or use and
familiarity with procedures.
The personnel interviewed were
knowledgeable in all phases of their duties.
Communications within the operations department were not
considered by the large majority of those interviewed to be
adequate.
In particular, complaints of a lack of feedback from
their supervisors above the shift engineer level.
Several
operators related incidents of requesting or suggesting changes
to improve plant operations.
None of them had ever received a
reply as to the disposition of their requests.
No formal system
for tacking or dispositioning such items exists and each is
handled in an informal, handwritten note manner.
Management support of the shift personnel is minimal or
nonexistent in the view of 15 of 17 individuals who were
interviewed on this topic.
Most felt that their management
above the SE level did not provide support for them either
internal to the operations department or external in dealing
with other departments.
This was expressed in responses that
indicated the respondents did not feel they could establish
p
.
.
40
i
their authority to personnel reporting to them and that any
l
confrontation involving such authority would only be settled by
management attempting to mollify both parties in a dispute.
)
With a single exception, none of those persons interviewed felt
that the operations staff in general or the shift licensed
operators in particular were in control of the plant to a level
they considered sufficient.
Most did concede that this had been
marginally improved in recent months, and would probably improve
dramatically once the plant entered Mode 4.
This lack of
control was also attributed to a lack of support of the shift
personnel by their own management.
Several operators and ASEs were unable to relate a single
instance of interaction with any management personne.1 above the
,
operations supervisors while on shift.
In fact, one ASE said he
4
hadmoreconversationswithMr.Whitethanwithanyoftheplant
management.
Management is perceived as "showing the flag' by
)
making quick tours of the control room rather than walking down
panels, reviewing logs or talking to the operators to determine
conditions, attitudes or problem areas.
During the initial review of control room activities, the
inspector determined that management involvement with day-to-day
activities had not reached the desired level.
Specifically, TVA
l
had indicated in an enforcement conference on June 18, 1987,
l
that an increase in management involvement was necessary to
improve the control of plant activities.
The inspectors
discussed this observation with TVA during an interim exit on
October 30, 1987.
Since that time, the NRC has increased their
sensitivity to this issue and the following improvements / changes
have been made:
.
New plant manager has been assigned, and during meetings
i
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'
where he was present management involvement was emphasized.
"War Room" meetings have been restructured to emphasize the
-
need for all organizations to support the operations
department.
"Operations Hot List" has been initiated to allow
-
operations an additional vehicle to prioritize their needs.
Although the inspectors have not seen a large increase in
face-to-face contact within the control room the above
i
observations are considered positive indicators.
The inspectors
consider the present level of involvement acceptable to support
,
plant heatup.
4
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41
This area will be closely monitored by the NRC during control
room observations as part of the heatup shift monitoring and
will be used as an additional decision point for authorizing
plant restart.
(2) Review - the effectiveness of the daily work list (DWL) and
determine if it has reduced the administrative borden on the R0,
ASE and SE.
RESULTS
Although not reviewed in detail during this portion of the team
inspection, the inspectors have monitored on a continued basis
the effectiveness of the DWL in reducing the administrative
burden on the shift operating crew.
Additionally, several SEs
have expressed a feeling that the DWL has improved operations
- ontrol over plant activities.
Initially, the DWL contained
approximately 350 activities which did little to reduce the
.
operations work load and reflected an initial lack of commitment
on the part of maintenance / maintenance planning.
The number of
given items on the list fluctuates from day-to-day.
However,
the licensee has concluded that approximately 130 items reflect
an acceptable mix between getting work done and still allowing
operation control over activities.
This area is considered acceptable to support plant heatup and
will continue to be assessed by the inspectors during shift
observations.
(3) Review conduct of control room personnel (ie., shift operations,
logs, turnovers, communications, formality, etc.) NOTE: this
assessment is ongoing and will include sustained control room
i
observations.
RESULTS
The primary items covered during the conduct of control room
personnel portion of this inspect #on are addressed below:
I
Control Room Behavior
-
The SE, ASE, and RO's appeared to maintain a professional
atmosphere in the control at all times.
(It makes it
particularly difficult to do this in a two-unit control
room.)
Control Room Housekeeping
-
Housekeeping was excellent.
'
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42
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Control Room Access Control
-
Access control appeared to be well handled by the SE and
,
properly placed signs.
The plant craft seemed to be well
trained in lining up and waiting their turn to discuss work
requests,
j
Control Room Operator Knowledge / Awareness
-
The inspector did a walk-thru of G0I-1 plant startup from
cold shutdown to hot standby - Units 1 and 2 with R0. The
operator first verified that both parties had the correct
revision of the procedure. He then read all prerequisites
and precautions.
He followed the procedure methodically
i
going to the control board to simulate various operations
as well as simulating phone calls to various departments to
confirm operational readiness of systems, etc.
He appeared
.
to be confident, competent and comfortable with the
procedure.
This is particularly reassuring since the
inspector later determined that the operator being coserved
has not yet operated the plant in real-time.
This is
indicative of good training and an effective site-specific
simulator.
The operator was courteous and professional
throughout the walk-through and, as expected, interrupted
contact with the inspector several time: to handle routine
control room business.
Plant Heatup Procedures Technical / Practical Accuracy and
-
Ease of Use/ Understanding
The inspector conducted an in-depth review of G0I-1 and
GOI-2 and found both to be technically accurate and easy to
,
follow.
The inspector had questioned the R0 during the
'
walk-thru about the sign-off spaces next to each paragraph.
The R0 responded that this space did not require a formal
,
sign-off, but merely a check mark to signify progress
j
through the
Subsequent review of AI-4,
"Preparation, procedure.
Review, and Use of Procedures," revealed that
initials are required in these spaces.
This information
i
was then conveyed to the R0 and his management for
'
dissemination.
(4) Review the use of procedures, by operations, for evolutions
conducted outside the control room.
I
RESULTS
The use of procedures by operations personnel outside the
control room is an area that is closely monitored by the
resident inspectors as part of their routine program.
A review
of recent inspection reports as well as discussions with site
i
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43
NRC personnel indicated that improvements in'this area have been
>
noted.
Additionally, the use of SI procedures by operations
personnel in the conduct of testing .has been reviewed and is
discussed in this report.
!
This area is considered. acceptable to support plant heatup.
It
'
will continue tof be assessed by the inspectors during shift
observations and will be used as an additional decision point
for authorizing plant restart.
Attachment:
-List of Compensatory Measures
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ATTACHPfENT
COMPENSATORY FfEASURES
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IMPLEMENTING
DESCRIPTION OF COMPENSATORY MEASURE
ACTIONS REQUIRED
PROCEDURES
System design is deficient to mitigate a moderate
Until modifications are complete, manual
SOI-55-2M15-
Energy Line Break (MELB) in the annulus,
operation of NCV-77-920 is required within IS
XA-55-15
Modification is required to provide detection and
sinates to drain the annulus to the suaillary
sitigation. (Ref: Sargent and Lundy MELBA
building sump. Detection of annulus flooding is
SOI-55-lM15
repet; SCR SQNNE88617)
provided by annunciator: LS-40-12
XA-55-15A
DRAIN SUMP
IIVEL HIGH
Reanalysis of main steam line breaks inside
In the eveat of a non-LOCA high energy line break
IP-6
containment shows temperatures fi some areas of
inside containment, the following items need to
Iower containment excreding enviconsental
be addressed:
qualifications limits. To mitigate, additional
a. Cooldown RCS to less than 350 degrees F within
bea t removal capacity is required. (Ref: CAQR
12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and continue as conditions allow
507870 % 9)
b. In case of failure of FCV-74-1, continue
cooldown using S/Gs.
c. Within I to 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />, place at least 2 LCC in
service. Ensure ERCW is aligned. If one
train of power is lost, entry into the annulus
ta manually open ERCW valves may be
necessary. Preferably all LCCs should be.
placed in service.
d. If a RCP is running, then at Icast 3 IICs
should be in service,
c. Evaluate ERCW flow to LCCs and, if required,
consider reducing flow to other equipment,
such as the containment spray beat exchanger.
.
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2
DESCRIPTION OF CortPENSATORY ?!EASURE
At'fl0NS REQUIRED
PROCEDURES
f. In case of failure of both the CVCS and escess
let%vn flow paths, evaluate the use of the
re .: tor vessel head vest system or pressurizer
PORV.
NOTE: These actions are to be considered and
recosmiendations made by the TSC.
In the event of the failure of the heating
Requires manual action to shutdown supply fans
G01-6H
clements in the ERCW pumping station supply
when space temperatures in the ERCW pumping
ventilation, the supply fans would continue to
station drop to 65 degrees F or less to ensure
run, potentially dropping room temperature to the
adequate frecae protection.
point instrumentation or sense lines could
freeze. (Ref. IDI D2.2-7, Vertical slice
analysis of ERCW system).
The containment penetration used for response
Electrical Maintenance has placed a sign on the
N/A
time testing inside containment does not have
appropriate junction boses which requires
overcurrent protection. Supervisory and
contseting ME supervisor prior to attaching test
procedural controls have been put in place to
embles. Use of the penetrations are to be
administratively control the use of the
limited to mode 5.
In addition, response time
penetration. (Ref: CAQR SQP871182)
testing procedures require double party
verification of remaval of test Icads.
The flex hose between ERCW and the D/G coolers
The fles hoses must be visually inspected on a
Night
order was purchased without scianic qualification.
routine basis to ensure no degradation has
(OSLA-99
An evaluation has been performed to justify
occurred.
revised)
continued use of the hosea until they can be
seismically qualified or new hoses installed.
(Ref: CAQR SQP8716771DI)
.-
The Control Room and Electrical Board Room air
In the event that tbc operating system fails.
SOI-30.1
conditioning Lysteme are not cepsble of automatic
manual startup of the STANSY train is required.
swapover to the standby unit if the operat.ing
train fails. This is due to the installation of
manuni valves in the ERCW lines in place of TCVs.
(Refr CAQR SQP8702I7)
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3
DESCRIPTION OF COMPENSATORY MEASURE
ACTIONS REQUIRED
PROCEDURES
Failure of either of two hand switches
Power must be restored to these dampers in the
AOI-8
(RS-31A-180A or 181A) can cause the total
event of a tornado watch / warning in order to
isolation and disabling of the redundant Control
close the dampers. (0-FCO-31-486, 488,493, 502)
.
!
Building pressurization systems by cis.ing the
I
tornado dampers. Corrective action is to remove
power from the handswitches. Also required that
the airlines to the solenoid valves for the fifth
vital battery room tornado dampers be reversed
and their associated aormally open BRN-3 relay
contacts be changed to normally closed. This
will allow the dampers to fail closed. (Ref:
DNE has determined that, due to errors introduced
6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> after switchover to containment sump.
IP-6
into containment sump level instrumentation by
ensure sump level is stable at a greater than or
elevated temperatures followius a DBA, this
equal to SI percent.
instrumentation should not be relied upon until 6
If level increases or decreases, investigate for
hours af ter switchover to the containment sump.
possible leakage.
Analysis shows that there will be at least 13.2
If level is less than 51 percent, monitor RhR and
feet of water in the sump at the time of
containment spray operation for cavitation and
switchover, therefore relatively large instrument
consider reduction of sump flow rate to inhibit
errors are acceptable. Based on creditable
vortex formation.
Inventory loss mechanisma, it is not necessary to
monitor containment sump level until 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />
after switchover. (Ref: Memo B45860226218)
The ice condenser air handling units need to be
la the event of a LOCA, trip the ice condenser
E-1
turned off to prevent the accumulation of
air handling units.
hydrogen and hot gases in the air handlir4
- , , .
ducts. This will minimize the possible
pyrolyzing of the foam insulation that would
result in an additional heat load in containment.
Although the analysis for containment is not
invalidated by the heat addition, the
consequences would be minimized by turning off
the air handling units.
(Ref. Memo
A27830919018
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_ _ _ _ . _ _ _ _ _ _
_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
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4
DESCRIPTION OF COMPENSATORY MEASURE
ACTIONS REQUIRED
PROCEDURES
Design deficiencies exist in the differential
Monitor ERCW screens and strainers. Within 3
IP-6
level transmitters for the ERCW strainers, the
hours after an operating basis carthquake (1/2
S01-67.1
automatic control system for the travelling
SSE), a loss of downstresa dam, a stage I flood,
,
f
screens, and the sodium hypochlorite injection
or at 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> following LOCA, then perform the
/
system. Manual operation of the ERCW travelling
following actions per S01-67.1:
screens and strainers and manually halting
a.
Stop chlorination to ERCW.
hypochlorite injection before placing the screens
b.
Inspect ERCW traveling screens and place
and strainers in continuous backwash is required.
screens into continuous backwash.
(Ref: CAQR SQP871263IDI)
c.
For non-LOCA events, inspect ERCW
strainers. Continuously staff the ERCW
pumphouse to locally monitor ERCW strainers.
Start cIcaning the strainers when pumphouse
initially manned and repeat cleaning based on
differential pressure across strainers,
d.
For LOCA events, manually clean the strainers
and repeat cleaning once per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />
thereafter.
The TSC may increase or decrease the above b,
e.
c, and d cleaning frequencies based on the
ERCW requirements and the river conditions.
For accidents other than those listed above,
maintain the normal monitoring and cleaning
frequency of the screens and strainers.
Due to the potential for spurious actuation of
In the event of a line break on the ERCW or CCS
AOI-13
certain ERCW and CCS valves in the event of a
systems, power must be restored to certain valves
AOI-15
fire, power was removed from the effected valves
so that they may be operated. These actions may
In the event of a pipe break (MELB), power must
be necessary to isolate the break and mitigate
'
be restored to these valves in order to operate
the event.
them and mitigate the consequences of the event.
(Ref: Appendix R analysis)
In the event of the loss of A-train power, manual
In the event of a loss a A train power, entry
AOI-15
action is required to realign CCS to the SFP
into the aux building would be required to
A01-35
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cooling system. Manual operation is required due
manually operate valves to provide B train
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5
DESCRIPTION OF COMPENSATORY MEASURE
ACTIONS REQUIRED
PROCEDURES
to the fact that certain valves requiring
cooling to the SFP. In the event that the loss
operation receive A train power. Analysis shows
of A train is ( > incident with a LOCA resulting in
that given the design SFP heat load, boiling will
degraded core conditions, analysis shows that the
,
i
not occur for at least 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> after loss of
/
cooling. Therefore, CCS must be realigned within
building is approximately 1200 mr/br. Under
average dose rate for general areas in the aux
10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br />. (Ref: SCR SQNMEB8677 Memo -
B44861009005)
these conditions, individuals could be sent into
the aux building for short periods of time to
perform these manual valve operations.
Inaccuracles in the computer model used to
No operator action required.
generate Xenon concentration data could result in
51-38 and TI-22 were revised to incorporate
71-22
SI-38
errors of up to 600 p :m.
This could result in
additional conservatism into the calculation to
nonconservative calculations of Shutdown Margin.
ensure adequate shutdown margin for all
(Ref: CAQR SQP870083)
conditions.
If hand tightened to prevent Icakage, the ERCW
supply valves to the Diesel Generators may not
The ERCW valves to the D/G may be hand tightened
OSLA-III
open on demand. It has been determined that the
only with the permission of the Shift Engineer.
SOI-82
installed Rotork operators are not sized
If the SE gives permission to handtighten any of
these ERCW valves, an ADO must be stationed at
adequately to open the valvea if they have been
the D/G building to ensure the valves open on any
hand tightened. (Ref: CAQR SQP870031)
D/G start. An ADO will remain at the D/6
,
building until such time that the valve can be
operated closed without handtightening. Anytime
an AUG is required to be stationed at the D/G
building he shall be briefed by the lead unit
operator as to his responsibilities.
Certain fi;e dampers may not fully close when
closure is initiated by a fire due to normal
Certain ventilation systems specified in 50I-26.2
A01-30
must be shutdown to allow fire dampers to fully
SOI-26.2
ventilation flow through the damper. (Ref:
close. These systems may be left out of service
Employee Concern EC-230.01)
or restarted at the discretion of the Fire
Brigade Leader after he assesses the effect this
would have on affected areas and the potential
for spreading the fire to adjacent areas.
s
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%
0
6
DESCRIPTION OF COMPENSATORY MEASURE
ACTIONS REQUIRED
PROCEDURES
Diesel generators may be overloaded in the event
In the event of an $1, phase B containm*nt
AOI-Ja
of a loss of offsite power, SI, phase B
isolation, coincident with a loss of oficite
containment isolation, and loss of redundant
power and loss of a train of a redundant c!=ss IE
class 1E power system. D/G analysis shows that
power system, non-safety related loads must be
the continuous rating may be exceeded for this
manually stripped if the D/C continuous rating is
scenario. However, the 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> rating is not
exceeded. Appendix B of A01-35 provides a list
expected to be exceeded. (Ref: Employee Concern
of d/G loads which should be evaluated to be
EC-243.00)
removed if D/Gs are overloaded.
Fire pumps 2A-A and 2B-B should be maintainea in
Fire pumps 2A-A and 28-8 are to be maintained in
S01-26
manual so that they will not load onto the
manual. In the event these pumps are required,
shutdown boards in the event of a loss of offsite
they will need to be manually started.
power. D/G Ioading analysis did not consider
these pissps. However, during a LOCA,
temperatures in coctainment may reach the
setpoints of the fire detectors, resulting in a
fire pump start. (Nef: CAQR SQT870649)
The weight indicating system for the hydraulic
On low hydraulic accumulator pressure indication.
Night
accumulators on the UNI isolation valves does not
the hydraulic pumps must be used to restore
' order
function as designed. Therefore, to ensure that
proper hydraulic pressure. Each use of the
the accumulators remain operable, the hydraulic
hydraulic pumps to restore pressure is to be
pumps will be used to pump up the accumulators on
legged. This will provide data for trending to
low pressure indication. (Ref: ECN L6073)
help monitor the condition of the accumulators.
The ERCW piping to the station air compressors is
Following a seismic event, check for pipe breaks.
A01-9
not seismically qualified. Therefore, following
If high ERCW flow to the station air compressors
a seismic event, the piping must be visually
is indicated (0-XI-67-206 or 209 lit, or
checked for degradation if high ERCW flow is
0-XA-55-278-D vindow 15 or 22 in ala re), then
,
indicated. (Ref: IDI D-2.09)
check the turbine building for pipe break. If
pipe break is verified, then close FCV-67-205 and
208 and stop all station air compressors.
The SQN tornado analysis has become outdateo duc
In the event of a tornado warning, 24 doors must
AOI-8
to both changes made in the plant configuration
be blocked open for this compensatory measure.
and incorrect configurations used as a model when
A01-8 has an appendix identifying each door and
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7
DESCRIPTION OF COMPENSATORY MEASURE
ACTIONS REQUIRED
PROCEDURES
the calculations were originally generated. The
its location. Door blocks have been manufactured
outdated calculation results in an unanalyzed
and are avaisable in the A01-27 supply cabinet
plant configuration for the effects of
outside the auxiliary control room,
depressurization from a design basis tornado.
Note: Some of these doors are fire barriers and
With the configuration unanalyzed, it must be
must be breached per Tech Specs.
assumed that safety-related equipment and
secondary containment integrity could be
(Note: Pending resulta of the USQD presently
endangered by r ".. e depressurization or
being prepared associated with this
structural is:
Opening of doors prior to a
compensatory measure, AOI-8 may be
x.
tornado will relieve pressure and prevent
revised to require this compensatory
overstressing of walls, thus compensating for
measure to be inplemented in the event of
lack of sufficient structural design for
a tornado watch instead of a tornado
withstanding tbc design base tornado. (Ref:
wa rning. )
CAQR SQF870022)
Appendix R (fire) analysis identified potential
la the event of a fire in the plant, A01-30
A01-30
equipment interaction problems which cold cause
references S0I026.2, which specifies required
SOI-26.2
spurious .ctuation of equipment required for the
actions to take in response to a fire in specific
safe shutdown of the plant. For those
areas of the plant.
interactions which have not been corrected, a
procedure was written to provide guidance as to
what equipment could be effected 11 the event a
fire occurred in certain areas of the plant, and
specify actions to take to mitigate the potential
ef fects of a fire. (Ref: CCTS N00 85-0086-020)
It has been identified that some instrument sense
No operator action is required.
N/A
lines were not installed with the proper slopes.
Proper instrument acnse line slope ensures that
Maintenance procedures have been developed to
,.
the sense line is properly filled, which in turn
periodically backfill sense lines to ensure
ensures that the instrument will accurately
proper operation of instrumentation.
Indicate the process parameter. (Ref: Employee
Concerns EC-17301)
Operator action may be required to restart the
In response to MCR fadication that the MCR A/C
S01-30/1
control room A/C in the event of a high energy
unit has failed, manual action would be required
line break inside containment. This is due to
to return an A/C unit to service.
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DESCRIPTION OF COMPENSATORY HEASURE
ACTIONS REQUIRED
PROCEDURES
the potential for a conson mode failure of the
aux air system as the result of Snadequate
separation of air lines and potential interaction
with the pipe break. The operating A/C unit
would trip as the result of the loss of ACA and
the standby unit would try to start.
If ACA is
not available, the standby unit would then fail.
If ACA is then restored, the MCR A/C units would
have to be manually restarted. (Ref: NRC
observation 6.22,87-4)
The cables for the normal and alternate DC supply
la the event of loss of all AC, the TDAIVP
Not yet
to the control circuitry and room vent fan motor
control circuit must be supplied by the normal
idectified.
and starter for the Turbine Driven Auxiliary
feeder. ECN L6712 will revise applicable
Feedwater Pump were determined to be undersized.
schematic and connection diagrams to include a
la the event of loss of all AC power, within
note to this effect. This ECN also replaces the
two hours the vital batterier would be discharged
normal feeder cable to the control circuitry and
to approximately 105 volts. Based on electrical
the cables to the vent fan motor and starter.
losses from the battery boards to this TDAIV pump
This ECN must be complete prior to unit 2
equipment, due to the undersized cable, the
entering mode 3.
voltage at the TDAFV pump controller and vent fan
would be less than the required 100 volts to
ensure proper operation. It is estimated that
the voltage at the TDAfvP ECM would be 95 volts
and that the voltage at the vent fan motor would
be 88 volts. (Ref: ECN L6712)
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