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| ML17325A521 | |
| Person / Time | |
|---|---|
| Site: | Cook  |
| Issue date: | 11/23/1987 |
| From: | Burgess B NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML17325A519 | List: |
| References | |
| 50-315-87-29, 50-316-87-29, NUDOCS 8712110312 | |
| Download: ML17325A521 (27) | |
Text
U.S.
NUCLEAR REGULATORY COHHISSION
REGION III
Reports No. 50-315/87029(DRP);
50-316/87029(DRP)
Docket Nos. 50-315; 50-316 Licenses No. DPR-58; DPR-74 Licensee:
Indiana Hichigan Power Company 1 Riverside Plaza Columbus, OH 43216 Facility Name:
Donald C.
Cook Nuclear Power Plant, Units 1 and
Inspection At:
Donald C.
Cook Site, Bridgman, Hichigan Inspection Conducted:
September 29 through November 10, 1987 Inspectors:
Bruce L. Jorgensen James K. Heller Approved By:
Reactor rges
, Chief Proj cts Section 2A Date Ins ection Summar Ins ection on Se tember 29 throu h November
1987 (Re orts No. 50-315/87029(DRP)
No 50-316/87029(DRP))
Areas Ins ected:
Routine unannounced inspection by the resident inspectors of:
actions on previously identified items; plant operations; reactor trips; radiological controls; maintenance; surveillance; fire protection and cleanliness; security; Steam Generator Repair Project; and Information Notices and Generic Ietters.
Results:
Of the ll areas inspected, no violations or deviations were identified in ten areas.
One violation was identified (Level IV - failure to perform required reviews and approvals for substitute repair material - Paragraph 6.h)
in the remaining area.
8712110312 871204 PDR ADOCK 05000315
1.
Persons Contacted DETAILS W.
"A
'L AB T.
K.
AJ E.
T.
J J T.
L.
"M.
A.
D.
AJ Smith, Jr., Plant Manager Blind, Assistant Plant Manager - Administration Rutkowski, Assistant Plant Manager - Production Gibson, Assistant Plant Manager - Technical Support Svensson, Licensing Activity Coordinator Kriesel, Technical Superintendent
- Physical Sciences Baker, Operations Superintendent Sampson, Safety and Assessment Supervisor Morse, equality Control Superintendent Beilman, ISC/Planning Superintendent Droste, Maintenance Superintendent Postlewait, Technical Superintendent
- Engineering Matthias, Administrative Superintendent Horvath, (}uality Assurance Supervisor Tetzlaff, Performance Engineer Loope, Radiation Protection Supervisor Kauffman, Construction Manager The inspector also contacted a number of other licensee and contract employees and informally interviewed operations, maintenance, and technical personnel.
"Denotes some of the personnel attending Management Interview on November 10, 1987.
2.
Actions on Previousl Identified Items (Closed) Unresolved Item (315/86005-06):
the containment airlock door seal material needed to be changed, as the original seals were beyond the manufacturer's stated service life.
With seals of the original material no longer available, a design change (RFC-DC-2768)
was processed to install an acceptable substitute.
Action was completed on the last (Unit 1) airlock doors as of September 4,
1987.
b.
(Closed)
Open Item (315/86035-02; 316/86035-02): electrical shorting appeared coincident with hydro-lasing activities to decontaminate area surfaces.
Further review showed no circuits designed to be unaffected by water/steam had failed.
Improved controls of the activity were apparently effective in that no subsequent problems occurred despite widespread decontamination activities using both hydro-lasing and steam-cleaning techniques.
(Closed)
Open Item (315/86041-03; 316/86041-02):
the safety evaluation review sheet for lifted pressurizer heater leads determined remaining capacity was adequate by deducting lost capacity from total installed rather than from capacity accessible
to emergency power.
The emergency powered capacity establishes safety.
The licensee revised its evaluation, showing adequate capacity remains after deducting the disabled heaters from the emergency powered total.
d.
(Closed)
Open Item (315/87003-01; 316/87003-01):
the Component Cooling Water (CCW) system operating procedure contained a
precaution against operation below 70 degrees F., but the low temperature alarm setpoint
.was reduced to 60 degrees F. because alarms were common/continuous at the higher setpoint.
The licensee addressed this inconsistency by revising the operating procedure precaution to 60 degrees F, based on the facts that 70 degrees is not achievable during winter conditions and that no detriment to plant equipment had occurred in a number of years'xperience with colder operating periods.
No violations, deviations, unresolved or open items were identified.
3.
0 erational Safet Verification Routine facility operating activities were observed as conducted in the plant and from the main control rooms.
Plant startup, steady power operation, plant shutdown, and systems)
lineup and operation were observed as applicable.
The performance of licensed Reactor Operators and Senior Reactor Operators, of Shift Technical Advisors, and of auxiliary equipment operators was observed and evaluated including procedure use and adherence, records and logs, communications, shift/duty turnover, and the degree of professionalism of control room activities.
Evaluation, corrective action, and response for off normal conditions or events, if any, were examined.
This included compliance to any reporting requirements.
Observations of the control room monitors, indicators, and recorders were made to verify the operability of emergency systems, radiation monitoring systems and nuclear reactor protection systems, as applicable.
Reviews of surveillance, equipment condition, and tagout logs were conducted.
Proper return to service of selected components was verified.
'a
~
Unit 1 was taken critical at 6:42 p.m.
on October 4, 1987, ending a
scheduled refueling, maintenance, modification and testing outage which began on June 26.
I,ow power physics testing was completed on October 6 and power escalation for return to normal power operation commenced.
NRC review of low power physics testing is documented in I.E. Inspection Reports No. 315/87028(DRS);
No. 316/87028(DRS).
The Unit tripped (see Paragraph 4) on October 13, 1987 upon loss of one of two main feed pumps.
A restart followed later the same day and the Unit remained in normal power operation through the remainder of the inspection perio Unit 2 was taken critical at 1:52 a.m.
on October 10, 1987, ending an approximate six week maintenance and testing outage.
At 12:13 p.m.
the same day, the Unit tripped (see Paragraph 4) from about eight percent power.
A restart followed on October ll, and the Unit remained in normal power operation the remainder of the inspection period with a single substantial power reduction, as described below.
Following startup, the Unit experienced excessive leakage through the pressurizer spray system.
Pressure control required essentially all the pressurizer heaters be continuously energized.
Valve NRV-164 was suspected as the leak source, though the other valve (NRV-163) could not be excluded.
When attempts to rectify the situation from outside the containment failed, the licensee developed a preliminary plan to enter containment, inspect the situation, and (if no other course suggested itself) apply limited external mechanical force on the suspect valve with a jacking device.
The entry necessitated a power reduction to about 20 percent for radiation protection considerations, which was performed on October 28.
Upon entry, the inspection team found NRV-163 to be cycling erratically through a repetitive partial stroke cycle, while NRV-164 was found fully closed with operating (opening) air isolated by a local manual valve.
NRV-163 was secured and air valved in to NRV-164, restoring essentially normal pressure control with small controlled spray system leakage.
A return to normal power operation then followed.
The condition of the isolated air supply to NRV-164 was unexpected and the licensee is continuing to investigate the causal factors.
Items identified on plant tours for which some corrective action appeared appropriate were referred to plant management.
On some occasions, such items were noted during tours conducted with management representatives.
Examples noted during this inspection period included:
i)
an unsecured ladder left in an auxiliary feedwater pump room; ii)
vent lines/hoses attached to each Unit 2 RHR heat exchanger; plus, general clutter in the heat exchanger rooms.
Each of the above was noted prior to Unit startup and was expeditiously corrected.
iii) the inspector noted a lack of insulation on a line to a Unit 2 pressure instrument isolation valve, 2-MPI-lO-V1.
The line to the identical Unit 1 valve is insulated.
The Maintenance Superintendent initiated a review to determine which configuration is correc de A number of operating procedures were reviewed with results as described below:
01-OHP 4021.003.001
"Operation of I,etdown, Charging and Seal Water Systems",
Revision 9 dated 7/25/86 through Change Sheet
dated 8/28/87.
This procedure requires certain valve lineup checks, verification of oil level, flow and pressure, and verification of cooling water supply to auxiliaries.
These checks are made in the pump room and partially duplicate prior checks documented on an attached lineup sheets For those which exceed the scope of the lineup sheet, no provision exists to document they were done.
In fact, the procedure is not an "in hand" procedure, which is inconsistent with the concept of specifying local checks at the pump.
The procedure implies it is not necessary to run the associated auxiliary oil pump while -a centrifugal charging pump (CCP) is in service.
The auxiliary oil pump is to be run at least a
minute before starting an idle CCP and for at least five minutes after a
CCP is secured.
A caution tag was serving in lieu of specific procedure instructions for one of the pumps; e.g.
"operate the oil pump on the 1E CCP continuously while the CCP is in service".
This use of a caution tag in lieu of procedure instructions is inconsistent with the intent of the licensee's own administrative controls for caution tags.
The procedure is also either silent or provides ambiguous information concerning the single reciprocating charging pump in the Unit.
This is discussed further at iii) below.
01-OHP 4021.003.006
"Changing from a Reciprocating to a
Centrifugal Charging Pump", Revision 5 dated 10/9/54 through Change Sheet 1 dated 9/11/85.
iii) 01-OHP 4021.003.007
"Changing from a Centrifugal to a
Reciprocating Charging Pump", Revision 5 dated 8/14/84 through Change Sheet 1 dated 9/ll/85.
This procedure establishes an initial condition that the reciprocating charging pump (RCP) be filled, vented and available for standby operation per 1-OHP 4021.003.001.
This referenced procedure (003.001)
however, does not provide specific instructions for achieving standby readiness.
The text is silent with respect to the RCP.
The associated (003.001)
"Valve Lineup Sheet" does not specify valve positions as "open" or "closed", but says
"as required".
This does not achieve the objective presumed in (003.007) of preparing the RCP for operatio iv)
12-OHP 4021.005.001,
"Boron Makeup System Operation", Revision 9 dated 10/22/87.
v)
01-OHP 4024.109,
"Annunciator No.
9 Response:
Revision 3 dated 5/8/86 through Change Sheet 1 dated 8/28/87.
This alarm response procedure contained three apparent typographical errors in identification of relay numbers associated with the West Centrifugal Charging Pump motor instantaneous (drop 16)
and overload (drop 17) trips.
Three alarms (drop 31, 32 and 33) involve abnormal conditions associated with the "middle" Boric Acid Storage Tank ("M" BAST).
Though the tank can be aligned to either Unit, its conditions are monitored and alarmed only in the Unit 1 control room.
The alarm procedure lacks'instructions to check with or notify the Unit 2 control room concerning abnormal conditions for this tank.
vi)
02-OHP 4024.209
"Annunciator Response No. 9: Boric Acid",
Revision 2 dated 8/7/86 through Change Sheet 1 dated 8/28/87.
The inspector discussed observations from procedure reviews as described in i) through vi) ab'ove with the Operations procedure group.
Procedure change requests were initiated for deficiencies where deemed appropriate.
e.
Prior to the Unit 2 Mode change from MODE 5 to MODE 4'he inspector verified that containment integrity was established as required by the Technical Specifications.
The inspector verified the proper position of the valves associated with at least ten containment penetrations, observed that the Unit 2 upper airlock containment penetration was tested per plant procedure and that the ice condenser was maintained in accordance with plant procedures.
No violations, deviations, unresolved or open items were identified.
4.
Reactor Tri s or ESF Actuations a
Unit
Unit 1 tripped from about 69 per'cent power at 8:18 a.m.
on October 13, 1987, following loss of the 1E main feed pump.
The feed pump had tripped unexpectedly when an associated oil pump was secured per normal practice.
Operators immediately commenced pump recovery and reopening of the pump discharge valve, which closed as designed on the pump trip, but they were unable to maintain required steam generator levels and flow balances.
The reactor subsequently tripped on steam generator (No.
11) low level with steam/feed flow mismatch.
Control response of one feedwater regulating valve (FRV-210) was "ragged" and contributed to the event.
A detective circuit card was replace The inspector was onsite at the time of the trip and went to the control room to observe initial operator post-trip recovery actions and equipment performance.
All post-trip system responses were normal, and operator response was orderly, professional and "by the book".
b.
Unit 2 Unit 2 received a Train A safety injection actuation on October 2, 1987, at 4:57 p.m. while the Unit was in MODE 5 (cold shutdown).
Instrument and Control personnel had been performing surveillance testing of the Solid State Protection System (SSPS)
when a test failure occurred.
Investigation identified a faulted circuit board, which was replaced.
During the evolution of performing maintenance in the middle of testing, an error was made in the sequence for repositioning SSPS switches such that the "block" was not in effect for the streamline isolation signal input to safety injection.
In MODE 5, this signal is normal, so when the input error inhibit switch was returned to "normal" the Safety Injection signal act'uated.
No actual injection occurred because equipment was tagged out for low temperature overpressure protection as required.
The Train A emergency diesel (2 CD) started and the containment isolated as designed.
Upon assessment of the situation, operators terminated the signal and restored pre-event conditions.
The remaining instrument testing was then completed without further incident.
The resident inspectors will review adherence to applicable procedure controls during followup of the anticipated LER.
Unit 2 received a reactor trip/turbine trip signal at ll:28 p.m.
on October 8, 1987 while the Unit was in MODE 3 (hot shutdown)
with the reactor trip breakers closed but no control rods withdrawn.
Instrument and Control personnel were performing testing on excore nuclear instrument channels when, due to an error, channel 43 was placed in "Test" instead of channel 44.
The latter channel already had its bi-stables tripped in preparation for the testing, so two-of-four logic was satisfied and the trip signal resulted.
Both reactor trip breakers opened as designed.
Upon determination and discussion about what had happened, operators restored the. breakers and the remaining test was completed.
Unit 2 tripped (turbine trip/reactor trip) from about eight percent nuclear power at 12:13 p.m.
on October 10, 1987.
Operators were in the process of rolling the main turbine up to speed through about 1550 rpm when it tripped from an unknown cause.
Setpoint P-13 (establishing turbine/reactor trip off first stage pressure)
had been set rather low and had been blinking in and out with nuclear power around eight percen It happened to be instated when the turbine tripped, so reactor trip followed instantly.
Trip response was completely normal.
When the licensee was unable, despite extensive investigation and testing, (and consultation with a turbine vendor representative who witnessed the event) to determine the exact cause of the turbine trip, the start-up decision was referred, as required, to the Plant Nuclear Safety Review Committee (PNSRC)
and the Plant Manager.
They authorized restart conditioned on reverification and adjustment, if necessary, of setpoint P-13, and of the Brown-Boveri (turbine manufacturer)
vacuum trip circuits.
The trip circuits, which seemed the only remaining candidate/suspect, checked satisfactorily without adjustment.
Setpoint P-13 was raised to 8.7 percent.
The inspector went to the site October 11 to review the original records concerning the trip event and system response, to review the licensee's investigative scope and results, and to observe the restart.
No discrepancies prohibiting a Unit restart were noted.
Subsequently, the restart was observed through turbine roll, synchronization, and initial power escalation to 20 percent power. It was completely uneventful.
This occurrence, within a week of two Instrument and Control personnel errors which caused inadvertent safety system actuations, is of some concern to NRC.
The situation will be monitored carefully for a recurrence or for other related occurrences.
This was discussed at the management interview.
No violations, deviations, unresolved or open items were identified.
5.
Radiolo ical Controls During routine tours of radiologically controlled plant facilities or areas, the inspector observed occupational radiation safety practices by the radiation protection staff and other workers:
a.
proper wearing of personnel dosimetry; b.
correct use of step-off pads for contamination control; c.
adherence to assigned Radiation Work Permit; d.
proper Auxiliary Building exit, i.e. entering self reading dosimeter data to the REM computer and correctly using the high-sensitivity personnel contamination monitors.
Effluent releases were routinely checked, including examination of on-line recorder traces and proper operation of automatic monitoring equipmen Independent surveys were performed in various radiologically controlled areas, using a licensee-issued E-130 G-M detector.
No violations, deviations, unresolved or open items were identified.
6.
Maintenance Maintenance activities in the plant were routinely inspected, including both corrective maintenance (repairs)
and preventive maintenance.
Mechanical, electrical, and instrument and control group maintenance activities were included as available.
The focus of the inspection was to assure the maintenance activities reviewed were conducted in accordance with approved procedures, regulatory guides and industry.codes or standards and in conformance with Technical Specifications.
-The following items were considered during this review: the Limiting Conditions for Operation were met while components or systems were removed from service; approvals were obtained prior to initiating the work; activities were accomplished using approved procedures; and post maintenance testing was performed as applicable.
The following activities were inspected:
a
~
b.
The licensee recently named Mr.- J.
B. Droste to the position of Haintenance Superintendent.
This position is equivalent to the position of "Maintenance Hanager" as described in ANSI N18.1-1971, to which the licensee is committed.
Mr. Droste's training and experience were reviewed against the criteria of the ANSI standard with no deficiencies noted.
As part of a review of testing activities associated with containment isolation valves (see Paragraph 7.a) the inspector reviewed procedure PMI-2290 "Job Orders" and held discussions with Maintenance Department representatives concerning
"as found" testing of such valves before performance of work which could affect their performance as a leakage barrier.
The procedure contains a
generalized instruction to identify all required testing during the job order development process.
This is taken to include "as found" testing for containment'isolation valves.
The personnel who prepare the job orders have been informed and, reportedly, trained to include this testing for work on any containment boundary valve.
Specific written and/or computerized cross-check procedures to identify required testing as a function of the component being worked do not currently exist.
The licensee has an ongoing project to develop such a tool using the computerized plant equipment database, which is anticipated will be ready sometime around the middle of next year.
c
~
Procedure PMI-2160 "Control of Chemical Materials and Cleaning Agents" was reviewed and compliance to several of its attributes were verified during routine in-plant inspection activities.
No particular problem areas were noted by the inspector, although the
licensee's Quality Assurance audit/surveillance program has identified some problems in this area which the licensee is addressing.
RFC-DC-4033:
preliminary w'ork for relocating P-250 computer room
., exhaust vents.
RFC-DC-.2962:
preparatory grinding/cleaning activities in support of the project to strengthen the auxiliary building'rane and associated support structures; a subsidiary project of the Steam Generator Repair Project (SGRP)
on Unit 2 - see Paragraph 10.
Job Order JO 021122:
rebuild/retest of snubber.
A snubber located at the top of the pressurizer next to valve 2-NRV-152 was found leaking oil.
The snubber was removed and a replacement installed.
The removed snubber subsequently failed a functional bench test.
During discussion of the matter with licensee representatives, the inspector verified the test failure was being properly factored into the scheduling process for the next visual inspection period.
Job Order JO 726879:
repair post-accident sample sink.
Job Order JO 012282:
weld repair of the Unit 2 Component Cooling Water (CCW) return pipe from the West RHR heat exchanger.
This repair involved cutting out a rectangular piece atop the pipe to capture a through-wall crack which had developed in the heat-affected zone adjacent to a pipe weld.
The intent was to obtain a specimen perhaps representative of several cracks which developed in the Unit 2 CCW system and to perform metallurgical analysis on the specimen in an effort to determine the cause of the cracking.
The CCW investigatory project and the technical safety considerations associated with this repair are discussed in I.E.
Inspection Report
No
~ 50-315/87023(DRS);
50-316/87023(DRS).
Based
on questions
raised during the referenced
inspection it was learned
the licensee
had replaced
the cut out piece with a piece of ASTM
A-36 structural steel in lieu of the
ASTM A-106 Grade
B material of
which the pipe is made,
because
no A-106 material
was available.
Belated evaluation/documentation
concerning
the substitution
concluded
the repair
was satisfactory
from the standpoint of
strength
and weld compatibility.
This inspection
focused
on the administrative processes
established
to control substitutions
or other changes
to approved
design
conditions of plant safety systems.
The inspector
determined all
such
changes
are governed either by procedure
PMI-2140 "Temporary
Modifications" or (for permanent
changes)
by procedure
PMI-5040
"Design Change Control Program".
The former procedure at Paragraph
3.4.1,
requires prior evaluation
and approval
be performed
and
documented
before performing an activity which (temporarily) alters
a plant system,
component or structure
from its existing approved
condition.
A like requirement is contained in the latter procedure
(for permanent
changes)
at its Paragraph
4.4.3.
Thus, appropriate
controls exist to provide that alterations
to plant safety systems
receive
advance
review and approval.
In the subject repair, neither
of these controlling procedures
were applied.
Relatively concurrent with NRC inspection of this matter,
the
licensee's
onsite equality Assurance
(gA) Department
performed
an
audit of the maintenance
area which included the subject
Job Order
among many.
The gA audit report
(QA-87-26) was provided to and
reviewed by the inspector.
It contains
the
same finding that
administrative procedures
were violated when no documented prior
evaluation
and approval of the substitute
repair were completed.
Since Technical Specification 6.8.l.a requires
implementation of
such procedures
via reference
through Regulatory
Guide 1.33 Appendix
A, this matter is considered
a violation of the referenced
Technical
Specification (Violation: 316/87029-01).
Prior to the conclusion of the inspection,
both on the basis of the
gA audit finding and considering
an earlier Condition Report
initiated on the
same repair activity by the equality Control
Supervisor,
corrective actions
were implemented
as follows:
i)
a documented
safety analysis
was performed;
ii)
applicable
reviews
and approvals
were obtained;
iii) the applicable
documents
were updated
to show the current
modified condition.
Preventive
actions included:
iv)
requiring site Haintenance
Engineers
to have
documented
Engineering Evaluations vs. verbal instructions
from the
corporate
engineering
group for use in the development of work
packages;
v)
briefings/training for all welders
and supervisors
concerning
the need for documented
vs. verbal instructions;
and,
vi) utilization of a "traveler" form in preparation of Code weld
repair packages
to provide for specific advance identification
of the precise repair intended/required,
the applicable
Code,
the necessary
procedures
and the required testing.
The
"Traveler" is to receive prior review by equality Control and
Inservice Inspection personnel.
The last item is presently being implemented pursuant to an
instructional
memorandum
from the Haintenance
Engineer in charge of
this discipline.
A decision to make the process
permanent
has not
yet been
made
as the licensee is still considering if this system is
the most efficient one or whether
a better
(and perhaps
more
generic) alternative
may exist.
Also, subsequent
to the improper repair, but before its discovery,
the licensee
revised his procedure
PHI-5075,
"ASHE Section XI
Repair/Replacement
Program",
which governs
weld activities of this
type.
The new revision contains clearly stated
requirements
that all
materials
must conform to D.
C.
Cook plant specifications
and that
replacement
of any part or section requires
appropriate
reference
to
PHI-5040.
One violation (no licensee
response
required)
and
no deviations,
unresolved
or open items were identified.
7.
Surveillance
The inspector
reviewed Technical Specifications
required surveillance
testing
as described
below and verified that testing
was performed in
accordance
with adequate
procedures,
that test instrumentation
was
calibrated,
that Limiting Conditions for Operation were met, that removal
and restoration of the affected
components
were properly accomplished,
that test results
conformed with Technical Specifications
and procedure
requirements
and were reviewed by personnel
other than the individual
directing the test,
and that deficiencies identified during the testing
were properly reviewed
and resolved
by appropriate
management
personnel.
The following activities were inspected:
'<1
THP 4030 STP.203
"Surveillance Test Procedure
Type
BSC Leak
Rate Test" Revision
10 dated 5/28/87 through
Change
Sheet
13 dated
8/7/87.
Particular attention
was given to testing of valves in the Chemical
and Volume Control system
(CVCS) and the
Component
Cooling Water
(CCW) system,
to provide
some focus to the review, since the
procedure is an integrated
one (several
hundred pages,
counting
attachments)
covering all containment isolation valves.
Concerning
CVCS, the inspector verified:
i)
stipulated valve lineups
appeared
appropriate;
ii)
leakage
action guides
and limits were reasonable;
iii) data
and instructions
were consistent
among the various
attachments
and the procedure
body concerning
and,
iv) justification/authorization
was provided for valves tested
by
"reverse direction" pressure,
consistent with 10 CFR 50,
Appendix J.
Concerning
CCW, attributes i) through iii) above were checked.
The
inspector noted
an apparent
inconsistency
between
the body of the
procedure
(Paragraph
5.9.3.3.C.2)
which excludes
ten
CCW valves
from
as-found vs. as-left "penalty" calculation, while Appendix I
includes
the valves.
Further discussion with Performance
Engineering established
the
CCW calculations, if performed,
are not
added into the total "penalty" applied to the subsequent
integrated
leak test.
Evaluation against criteria of 10 CFR 50 Appendix J,
considering function and design of the lines in question,
determined
the licensee's
practice is acceptable.
Some review was conducted
on
a licensee
Problem Report
(No.87-0846)
addressing
a failure to perform an "as-found" Type
C test
on
letdown valve gCR-300 prior to maintenance.
The inspector verified
Procedure
STP.203 calls for an "as-found" leak rate test prior to
any piping or valve modifications or repair.
This is
a
Precaution/Limitation stated in Step 4.13 of the procedure.
As
noted in Paragraph
6.b above,
however,
the licensee
currently relies
on the knowledge
and experience
of the personnel
preparing job order
packages
to recognize, the need for such testing
so the Performance
Department is notified and can perform STP.203 before repairs begin.
Since the licensee identified this apparent
procedure violation,
corrected it, and it was neither safety significant nor repetitive,
only preventive actions
remain to be verified to establish
whether
a
NRC Notice of Violation should be issued.
Pending this review, this
is considered
an Unresolved
Item (315/87029-01).
- "12 HHP 5050 SPC.005
"Hydrostatic Test Procedure"
Revision
through
Change
Sheet
1 dated ll/3/87.
Setup for this procedure
to hydrostatically test essential
service
water to the containment
spray heat exchanger
was observed
on
November 3,
1987.
The test procedure
had just been revised to
incorporate
a
Code interpretation involving low temperature
(below
200 degrees
F.) systems with installed safety/relief valves.
It is
a generic procedure for testing multiple systems,
with the
applicable
system test pressure
calculated at the time the test is
done.
- -12 THP 4030 STP.246
"Inspection of Ice Condenser Floor Drain
Valves".
Condition Report No. 2-10-87-1473 identified that two of twenty-four
Unit 2 floor drain valve gates
were not sealing properly during the
performance of STP.246.
The immediate corrective action documented
that the seating
surface
was sealed with grease
and
a Job Order
written to make permanent
repairs.
The inspector questioned
the use
of grease
as
a sealing
mechanism.
During discussion with cognizant
engineers
the inspector
was informed that the grease is routinely
applied,
by procedure,
to decrease
hot air inleakage,
during plant
operation,
from the lower containment to the ice condenser.
Thus,
all the gates
have greased
seating surfaces.
Air tightness is not
a
test criterion, however,
so grease is not required to pass
the test.
The inspector also found that the licensee
was aware of problems
encountered
by another utility when containment isolation valves
were greased prior to leak rate testing.
In addition, the inspector
verified that the grease
was compatible with the ice condenser
environment.
STP.246 at Step 4.4 states,
"Procedure test steps
can be performed
in any order".
The inspector questions if this is appropriate,
since
a primary objective of the procedure is to verify each drain
valve gate
opens within a specified opening force.
Since other
steps
involve exercising
the valve gates, it appears
inappropriate
to perform these
steps prior to determining the "as-found" opening
force.
This was discussed
with the cognizant engineer
who committed
to review/revise (if needed)
STP.246
':1
OHP 4030 STP.027AB
"AB Diesel Operability Test".
The Unit
1 AB
diesel generator failed
a start test under this procedure
on July
19,
1987.
The licensee
had intended to use
a successful
test to
declare
the machine "operable". Investigation
showed
fuses for the
generator field flashing circuits had been pulled by Instrument
and
Control personnel
on about July 15.
The purpose for pulling the
fuses
was to prevent
damage
during
a planned series of slow-speed
(non-synchronous)
runs of the engine.
The governing Haintenance
Department procedural instructions
were deficient in that they
neither specifically recognized
the actual pulling of the fuses
would be by the Instrument
and Control (ISC) group, nor were there
instructions to assure re-installation
on completion of the
slow-speed
runs'.
The ISC group
was not called upon in the interim
between July
15 and
19.
The licensee
issued
a Problem Report
(No.
87-0614)
on this matter which noted the above procedural
problems,
as well as other contributing factors.
The inspector
considered
the
evolution to reflect poorly on communication/co-ordination
among
plant departments,
but also to contain
some valuable lessons
learned.
The licensee identified this apparent
procedure deficiency and
corrected it, and the problem was neither safety significant nor
repetitive.
Pending final inspector review of preventive actions,
to determine
whether or not
a
NRC Notice of Violation should be
issue,
this matter is considered
an Unresolved
Item (315/87029-02).
12 MiP 4030 STP.029
"Functional Test of Hydraulic Snubbers".
-':1
OHP 4030 STP.004
"Centrifugal Charging
Pump Operability
Test-HODE
5 or 6".
As previously noted, Unit
1 was in an outage
throughout
September,
1987.
When this test
was run on September
4, acceptance
criteria in the form of updated differential pressure
graphs
were
not present in the Tech Data Book.
The pump could not be determined
to meet surveillance criteria on the basis of this test. Its condition
f'ollowing an earlier maintenance activity to modify the discharge
orifice remained indeterminate.
When updated
graphs
were received
by operators
on September
6, they showed the
pump failed with pressure
differential too high.
The
pump
was declared
Subsequently,
investigation
showed
the pressure
was reading
slightly high,
and
a retest after calibration (with no work on the
pump itself) succeeded
in qualifying the
pump for "operable" status
as required prior to
a
MODE change.
Retrospective
reviews also
showed
the other centrifugal charging
pump had remained
while the subject
pump was unknowingly in a failed status.
A
licensee
Problem Report
(No. 87-0812)
documents
these
circumstances
which, in the view of the inspector,
resulted in inadvertant
compliance to requirements.
This was discussed
at the Management
Interview.
No violations, deviations,
unresolved
or open items were identified.
8.
Fire Protection
Fire protection program activities, including fire prevention
and other
activities associated
with maintaining capability for early detection
and
suppression
of postulated fires, were examined.
Plant cleanliness,
with
a focus
on control of combustibles
and
on maintaining continuous
ready
access
to fire fighting equipment
and materials,
was included in the
items evaluated.
a.
The licensee
reported
on October
12,
1987, that
a preplanned
maintenance activity to replace
a valve in the outside fire
suppression
water rising header necessitated
isolation of a portion
of the header.
Provision of backup suppression
capability and
followup written notification were both accomplished in accordance
with fire protection Technical Specifications.
b.
The inspector
informed the licensee
concerning discovery,
during
fire protection "safe shutdown" reviews at another plant, of a
potential
common mode postulated fire which could disable presumably
independent
emergency
power sources.
The licensee initiated
a
review of the matter to determine its applicability, if any, to the
D.
C.
Cook Units.
No violations, deviations,
unresolved
or open items were identified.
9.
~Securit
Routine facility security measures,
including control of access
for
vehicles,
packages
and personnel,
were observed.
Performance
of
dedicated
physical security equipment
was verified during inspections
in
various plant areas.
The activities of the professional
security force
in maintaining facility security protection were occasionally
examined or
reviewed,
and interviews were occasionally
conducted with security force
members.
No violations, deviations,
unresolved
or open 'items were identified.
10.
Re air Pro'ect
(SGRP)
a.
Briefin
Meetin
The licensee visited
NRC Region III on October 23,
1987 to make
a
presentation
covering several
areas
of interest in the upcoming
(probable Spring 1988) project to replace
the Unit 2 steam
generators.
Specific topical areas
included
a schedule
overview,
which addressed
outage activities
and milestones.
,A presentation
was given on the radiological protection aspects
of the project,
as
were presentations
addressing
quality assurance
both from the
licensee
and from the primary contractor
(M-K Ferguson)
perspectives.
A scale
model was used to demonstrate
major aspects
of the physical disassembly,
component
movement,
and reassembly.
The licensee
also addressed
a variety of questions
from the
NRC
representatives.
A followup meeting is tentatively being considered
for March 1988.
b.
Or anization
and Staff
The inspector visited and toured the onsite offices for the
SGRP,
which occupy
somewhat
expanded facilities at the South
end of the
site formerly used
as the site training center.
Brief general
introductory meetings
were held with contractor,
licensee
corporate
and licensee site representatives.
c ~
Plant
Se re ation and La u
Plans
It will be necessary
while the
SGRP is ongoing to maintain clear and
positive segregation
of construction activities associated
with the
project from affecting the operating Unit
1 and those portions of
Unit 2 not involved with the project.
Licensee planning to
precisely identify the desired
boundaries
and to develop controls to
assure
compliance with the boundaries
were reviewed.
The licensee
has detailed
some experienced plant personnel
to the
SGRP primarily
to focus
on segregation
and
(as discussed
below) return to service.
The segregation
requirements
identified to date appeared
logical and
consistent.
Division of responsibilities
has
been established,
primary turnover preparation
milestones identified,
and individual
systems
reviewed.
A preliminary but quite detailed
clearance
setup
and valve position list has
been prepared.
During the layup portion of the
SGRP outage,
some current Technical
Specification testing will be impossible or illogical.
The licensee
intends,
however,
to maintain many Unit 2 systems
under appropriate
administrative controls to provide continuing "operability" by
performing applicable testing
and required maintenance.
A listing
of proposed
Technical Specifications
exemptions,
to omit impossible
or illogical testing,
has
been prepared
and submitted for NRC review
and approval.
Return to Service Plans
Preliminary Start-up
Program development,
for the return of Unit 2
to normal service after the
SGRP, is underway.
Organizational
responsibility and milestone
assignments
have been
made.
The
licensee
has
committed to complete Start-up
Program development,
including identification of applicable existing system performance
tests,
by the end of March,
1988, which is prior to commencement
of
the
SGRP outage.
This subject is likely to be addressed
in more
detail in future licensee/NRC meetings.
New Facilities
The inspector toured the newly constructed
temporary storage
facility which was completed during this inspection period.
Tours
were also conducted in a new radiation area
access
control facility
and
a
new security site access
control facility.
Each of these
facilities remained
under construction at the conclusion of the
inspection.
Both will be dedicated solely to
SGRP functions through
the completion of that project.
Details of their potential
utilization thereafter
have not yet been decided.
ll.
Information Notices
and Generic Letters
The inspector
reviewed the
NRC communications listed below and verified
that: the licensee
has received
the correspondence;
the correspondence
was reviewed by appropriate
management
representatives;
a written
response
was submitted if required;
and, plant-specific actions
were
taken
as described in the licensee's
response.
a.
(Closed) Information Notice (IN) 87-41, "Failures of Certain
Brown-Boveri Electric
(BBE) Circuit Breakers".
By memorandum
dated October 27,
1987,
the
NRC Region III requested
the inspector to review IN 87-41.to determine if the generic
implications had been considered
and (if necessary)
resolved
by the
licensee.
The IN identified two problems:
i)
The "close" latch in the breakers
should
be modified by
addition of a light spring.
The licensee's file on IN 87-41
states
this item is applicable for breakers
at D.
C.
Cook and
springs
are being added per design
change
RFC 12-2739,
"Modifications to BBE Circuit Breakers to Prevent Inadvertent
Opening".
The
RFC is complete for Unit
1 and is scheduled
for
the next refueling outage for Unit 2.
The inspector
reviewed
the
RFC file and verified a Brown-Boveri instruction (1B-8307,
"Installation of a Close Latch Anti-shock Spring in the
Mechanism" ) was incorporated.
ii)
A breaker failed to close because
of insufficient torquing of
the charging motor mounting bolts.
Maintenance
Procedure
MHP 5021.082.001,
"Maintenance Inspection
and Repair of 4 KV
Power Circuit Breakers",
was revised by Change
Sheet
2, dated
July 16,
1987, to require specific checks of the closing spring
charging motor mounting bolts.
b.
(Closed)
Generic Letter 81-21, "Natural Circulation Cooldown"
By memorandum
dated
May 15,
1987 and Temporary Instruction 2515/86,
Region III requested
that the inspector
review the licensee's
actions
taken to resolve
Generic Ietter
(GL) 81-21.
describes
a
1980 natural circulation cooldown event at the St. Lucie
Unit
1 power plant which resulted in liquid flashing in the reactor
vessel
upper head region.
The Generic I,etter required
a response,
which was provided
on July 2,
1983 (Licensee file number
AEP:NRC:044A).
The
NRC Office of Nuclear Reactor Regulation
evaluated
the licensee's
response
and
Owners
Group
review of natural circulation and issued
a site specific Safety
Evaluation Report
(SER) dated
November
17,
1983.
The
SER discussed
different cooldown rates
and hold points
as they applied to the
availability of reactor vessel
head forced air cooling.
In
addition,
the
SER concluded that implementation of the NRC-approved
Owners
Group Emergency
Response
Guidelines,
with
appropriate plant specific modifications,
would be adequate
to
perform
a safe natural circulation cooldown.
The inspector
reviewed the emergency procedures
listed below and
verified that the cooldown limits discussed
in the
SER are
addressed:
i)
Ol OHP 4023 ES-0.2
ii)
OHP 4023 ES-0.3
Natural Circulation Cooldown
Natural Circulation Cooldown
With Steam Voids in the Vessel
(with RVLIS)
iii) 01
OHP 4023 ES-0.4
Natural Circulation Cooldown
with Steam Voids in the Vessel
(without RVLIS)
The inspector interviewed the November 5,
1987 Unit
1 and Unit 2 day
shift operations
crew and determined that natural circulation
cooldown training had been performed
and that crew members
were
~ cognizant. of the St. Lucie event.
In addition, the inspector
confirmed that training had been p'erformed by review of natural
circulation lesson plans
RQ-C-EOPO;
RQ-C-EOP2;
RQ-R-1231;
RQ-R-1289,
and,
RQ-C-1291.
c.
(Open) Generic Letter 87-06, "Periodic Verification of Leak Tight
Integrity of Pressure
Isolation Valves"
This Generic Letter, dated
March 13,
1987,
was
one of two identified
for inspector followup via memorandum
from the Region III Director,
Division of Reactor Projects.
It identified information to be
submitted within 90 days; i.e. by about June ll, 1987.
During the
current inspection,
no record could be found that the requested
information had been provided.
The licensee is investigating
and
will develop
and provide the requested
information as
soon
as
possible.
Subsequent
to the exit interview, the licensee
confirmed
that the response
was not sent,
would be sent by November
11,
1987
and that
a Condition Report (internal corrective action document)
would be issued.
No violations, deviations,
unresolved
or open items were identified.
20.
Unresolved
Items
Unresolved
items are matters
about which more information is required in
order to ascertain
whether they are acceptable
items, violations, or
deviations.
Unresolved
items disclosed
during the inspection
are
discussed
in Paragraphs
7.a
and 7.d.
21.
Mana ement Interview
The inspectors
met with licensee
representatives
(denoted in Paragraph
1)
on November
10,
1987 to discuss
the scope
and findings of the inspection.
In addition,
the inspector
asked
those in attendance
whether they
considered
any of the items discussed
to contain information exempt from
disclosure.
No items were identified.
The following items were specifically discussed.
a
~
The inspector questioned
the review status
concerning
problems
experienced
with Unit 2 pressurizer
spray valve leakage
and
indicated it had been unclear
a safety evaluation would be performed
to justify a plan to apply force to
a valve with a jack.
,The
licensee
stated his investigation of the matter is continuing, that
use of a jack in the circumstances
discussed
was considered
analogous
to any other use of a tool but that it was understood
(and
some review actions
were initiated) that
a safety evaluation would
be required to justify leaving anything foreign in place
on or at
the valve (Paragraph
3.6).
Some of the observations
derived from operating procedures
reviews
were summarized
(Paragraph
3.d)
The inspector indicated close
NRC attention is being and will
continue to be paid to errors
by Instrument
and Control personnel
(Paragraph
4.b)
The apparent violation of administrative control requirements
in the
Maintenance
area
was reviewed
(Paragraph
6.h)
Poorly coordinated
charging
pump testing resulting in inadvertent,
rather than intentional,
compliance to
MODE change
requirements,
was
discussed
(Paragraph 7.f).
20