ML20057E772
| ML20057E772 | |
| Person / Time | |
|---|---|
| Site: | Big Rock Point File:Consumers Energy icon.png |
| Issue date: | 10/04/1993 |
| From: | Phillips M NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20057E754 | List: |
| References | |
| 50-155-93-15, EA-93-233, NUDOCS 9310130134 | |
| Download: ML20057E772 (17) | |
See also: IR 05000155/1993015
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U.S. NUCLEAR REGULATORY COMMISSION
REGION III
Report No. 50-155/93015(DRP)
Docket No. 50-155
License No. DPR-6
Enforcement Action No.93-233
Licensee: Consumers Power Company
1945 West Parnall Road
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Jackson, Michigan
Facility Name:
Big Rock Point Nuclear Power Plant
Inspection At:
Big Rock Point site, Charlevoix, Michigan
Inspection Conducted: August 24, 1993, through September 14, 1993
Inspectors:
R. Leemon
C. Brown
D. Desaulniers
G. Bryan
Approved By:
/o/V/f.7
M. P. Phillips, Chief
Date
Reactor Projects Section 2B
Inspection Summary
Inspection from August 24. 1993, through September 14. 1993
(Report No. 50-155/93015(DRP)
Areas Inspected: A special, unannounced safety inspection by the resident
inspectors and inspectors from Human Factors Branch of NRR to evaluate the
conditions surrounding the hydrostatic primary system test and a breach of
containment integrity with a concurrent mode change that occurred at your Big
Rock facility.
Results: Of the areas inspected, seven examples of apparent violations were
identified. These concerned an inadequate switching and tagging order
(section 2.B), failure to determine that the containment was being removed
from service and that this was acceptable prior to authorizing the
implementation of the switching and taggiing order (section 2.B),
inappropriately approving implementation of control rod withdrawal interlock
test (section 2.B), an inadequate containment isolation surveillance procedure
(section 2.B), inadequate corrective actions for similar violations (section
2.B), failure to maintain test pressure below 1535 psig during the primary
system pressure test (section 3.B), and failure to provide sufficient
proficiency to personnel performing hydro test (section 3.B).
Both of the
recent events (loss of containment integrity and the hydro over pressure) have
similarities to an earlier loss of containment event involving the escape
hatch doors interlock.
9310130134 931005
ADOCK 05000155
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These recent events have a similarity in the loss of control of plant
evolutions.
Root causes for both of these events involve a failure on the
part of shift management to maintain an awareness of overall plant conditions.
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This recent case of an inadequate sv. itching and tagging order, resulting in a
loss of containment integrity, was similar to a switching and tagging order
violation in 1992 regarding the removal of the battery charger from service.
The 1992 event was discussed during a July 1992 enforcement conference.
The
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hydro overpressure event was almost identical in its .causes to the recent
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Palisades control rod withdrawal event.
Common causes that led to both events
involved inadequate job briefings, the tendency of shift supervision to.get
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involved in troubleshooting and lose focus on the overall status of the plant,
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inadequate communications between the job site and control room, and
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inadequate work practices in the performance of the respective tasks.
After
the Palisades control rod withdrawal event, the lessons to be learned were
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published at Big Rock Point. Given that the Palisades event occurred in June
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1993, corrective actions for Consumers Power should have been developed and
implemented regarding the above commonalities to preclude similar events at
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Big Rock Point.
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DETAILS
1.
Persons Contacted
- P. Donnelly, Plant Manager
D. Hughes, Executive Engineer
- E. Bogue, Chemistry / Health Physics Manager
- G. Boss, Systems and Project Engineering Manager
R. Scheels, Planning and Scheduling Administrator
W. Trubilowicz, Operations Manager
- D. Turner, Maintenance Manager
- G. Withrow, Plant Safety and Licensing Director
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- M. Bourassa, Senior Licensing Technologist
D. Lacroix, Nuclear Training Administrator
G. Petitjean, Senior Staff Engineer
L. Darrah, Operations Supervisor
- D. Moeggenberg, Engineering Supervisor
R. Burdette, Senior Health Physicist
- J. Horon, Acting Operations Manager
- G. Hausler, Shift Supervisor
R. Flowers, Shift Supervisor
- W. Merwin, Operating Experience Coordinator
- Denotes those attending the exit meeting on
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September 14, 1993.
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The inspectors also talked with and interviewed several other licensee
employees, including reactor and atixiliary operators; shift supervisors;
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electrical, mechanical, and instrument maintenance personnel; and
licensing personnel.
2.
Loss of Containment Sphere Intearity Event
A.
Event Description
At 10:06 p.m. on June 27, 1993, TR-391, "Feedwater Check Valve
Leak Rate Test," was completed for the feedwater isolation check
valve (VFW-305) and immediately afterward switching and tagging
order No. 93-0375 was implemented to allow removal of the
feedwater regulating valve (CV-4000) and feedwater check valve
(VFW-304) from service. The operator closed the inboard drain
valve (VFW-185) to allow signoff of the step as complete per the
surveillance procedure and immediately re-opened the valve to
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impleinent the switching and tagging order.
The decision had been
made to leave the feedwater line isolated, vented, and drained for
both personnel protection and ALARA (as low as reasonably
achievable) considerations to allow operators to work on the
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feedwater regulating valve.
The switching and tagging order
resulted in a 1-inch drain valve (VFW-185), located inside
containment, and 1-inch vent (VFW-140) and 1-inch drain (VFW-125)
valves, outside containment, being open at the same time under the
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same tagging order.
This created a direct path to the atmosphere
from inside containment.
On June 29, 1993, between 12:45 p.m. and 6:09 p.m., the key-lock
mode selector switch was moved from the shutdown position to the
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refuel position and back several times as specified in the
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implementation of surveillance TR-96/T7-29, " Control Rod
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Withdrawal Interlocks Test." The Shift Supervisor had signed off
prerequisites 3.0.a of this procedure, indicating that plant
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conditions were such that the mode switch could be placed in
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REFUEL for the procedure to be implemented. Although containment
integrity was one of the prerequisites per Technical Specification
(TS) requirements, it was not specifically called out on the
procedure.
The facility exited the T.S. cold shutdown condition
for 4-1/2 hours over a period of about 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> during this time
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for the performance of the surveillance.
At 6:50 p.m. on June 29, 1993, valve .VFW-185 was shut and caution
tagged by switching and tagging order No. 93-0375e, re-
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establishing containment
Containment was not recognized as
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breached for a period of about 2 additional days.
B.
Inspector's Review and Findinas
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Big Rock Point technical. specification (TS) 3.6 requires that
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containment sphere integrity shall be maintained during power
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operation, refueling operation, shutdown, and cold shutdown
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conditions, except as specified by a system of procedures and
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controls to be established for occasions containment must be
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breached during cold shutdown.
The cold shutdown condition is
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further defined as a reactor condition involving no fuel in the
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reactor, or a reactor condition meeting with the following
requirements: all of the control rods are fully inserted in the
core and withdrawal is prevented by means of the key-lock. selector
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switch, the key to which is in the possession of the shift
supervisor and the reactor coolant system is at atmospheric
pressure.
Big Rock Point had implemented the TS requirement for a
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system of procedures and controls through the use of a specific
prerequisite in the appropriate procedures that Plant Manager
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approval be obtained prior to breaking containment integrity.
As noted above, switching and tagging order 93-0375 opened the
drain valves both inside and outside containment and the vent
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valve outside containment on the feedwater line. The switching
and tagging order contained no indications that containment
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integrity would be breached.
The switching and tagging order used
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to breach containment was developed using the leak rate test
surveillance procedure rather than the facility piping and
instrumentation diagrams (P& ids).
That procedure failed to
identify VFW-185 as a containment isolation valve, although P&ID
0740G40121, Sheet 1, clearly showed this valve as a containment
isolation boundary.
10 CFR Part 50, Appendix B, Criterion V,
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requires, in part, that activities affecting quality be prescribed
in documented instructions or drawings of a type appropriate to
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the circumstances.
The failure of the switching and tagging order
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to adequately specify the appropriate review for breaching
containment integrity or identify how containment integrity would
be breached indicated that the procedure was not adequate for.the
circumstances. This is an apparent violation of Criterion V and
TS 3.6 concerning the provisions for procedural controls
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(155/93015-01).
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Although it was the intent of the shift supervisor implementing
switching and tagging order 93-0375 to drain the feedwater line,
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he did not identify that he intended to breach containment
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integrity and leave it in that condition. As a result, this
information was not logged in the control room nor consunicated to
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other shifts after the tagging order was implemented.
Section
6.8.1 of the Technical Specifications requires, in part, that
written procedures shall be established, implemented, and
maintained for all structures, systems, components, and safety
actions defined in the Big Rock Point Quality List.
Section 5.2
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of Chapter 13 of Volume 17 of the quality list requires procedures
for maintenance and operations activities.
Section 5.6.1 of
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Administrative Procedure 2.1.4, " Plant Status and Equipment
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Control," provides operational requirements for removing equipment
from service, and states, in part, that prior to giving his
permission, the shift supervisor shall verify that the equipment
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or system to be removed from service can be removed and that the
method used to remove it from service is proper.
The failure to
determine that the containment was being removed from service and
that this was acceptable prior to authorizing the implementation
of the switching and tagging order on June 27, 1993, is an
apparent violation of procedure 2.1.4 (155/93015-02).
Subsequent to the breach of containment, surveillance TR-96/T7-29,
" Control Rod Withdrawal Interlocks Test," was performed. This
surveillance procedure contained step 3.0.a, which required, that
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plant conditions be such that the mode switch could be placed in
REFUEL or RUN. The Shift Supervisor authorized the performance of
the surveillance and signed the step that plant conditions were
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appropriate when this was not the case. Therefore, beginning at
12:45 p.m. on June 29, 1993, the mode selector switch was moved
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from the shutdown position to the refuel position, then returned
to the shutdown position several times to accommodate performance
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of this surveillance procedure.
The refuel position allows
control rod withdrawal and does not meet the TS definition for
cold shutdown. Therefore, the facility was removed from the cold
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shutdown condition for 4-1/2 hours during the 2 day period
identified above when containment integrity was breached.
To enter the refueling mode, containment integrity was required by
Technical Specification (TS) 3.6 as noted above. However, this
specific requirement was not clearly specified in the procedure.
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- The shift supervisor would be required to remember this as part of
the " plant conditions are such that the mode switch may be placed
in REFUEL or RUN." ' His signoff indicated that containment
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integrity was present, although it was not.
Section 6.8.1 of the
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Technical Specifications requires, in part, that written
procedures shall be established, implemented, and maintained for
all structures, systems, components, and safety actions defined in
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the Big Rock Point Quality List.
Section 5.2 of Chapter 13 of
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Volume 17 of the quality list requires procedures for surveillance
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activities. The cause for this improper implementation of the
surveillance procedure step was not intentional, but due to the
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lack of knowledge that containment integrity had been breached.
Previous shifts had been unaware of the breach and had not
informed him, and he did not review the implemented switching and
tagging order. The failure to properly implement step 3.0.a of
surveillance procedure TR-96/T7-29 is an apparent violation of
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procedure (155/93015-03).
Procedure 0-TGS-1, Checklist A-9, " Containment Isolation
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Surveillance," identifies the valves and penetrations that must be
isolated to effect containment integrity.
Of the three valves
involved in the breach of containment, VFW-125 and 140 are covered
in this procedure. Valve VFW-185 is not contained in this
procedure.
This could have contributed to the failure to
recognize that containment was breached by the switching and
tagging order allowing VFW-185 to remain open.
Criterion V of
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Appendix B to 10 CFR Part 50, requires that activities affecting
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quality shall be prescribed by documented instructions,
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procedures, or drawings of a type appropriate'to the
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circumstances. The failure of this checklist to include a
required isolation valve to effect containment integrity indicates
that the procedure was not of a type appropriate to the
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circumstances, an apparent violation of Criterion V (155/93015-
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04).
On July 9, 1992, and enforcement conference was held with
representatives from Consumers Power and Big Rock Point concerning
an event that occurred on January 10, 1992, where the shift
supervisor released procedures for work without determining the
affect implementation of those procedures would have on the plant.
At that time, the result was to effectively make the diesel
generator inoperable.
During that same enforcement conference,
another example of an inadequate switching and tagging order was
identified, where the tagging order developed resulted in loss of
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DC power, when what was intended was to isolate the battery
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charger.
During the enforcement conference, corrective actions
specified were to introduce a self-checking program, train
operators on diesel generator breaker logic, and revise the
battery charger procedure. These corrective actions were limited
in scope to the specifics of the individual events and failed to
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address the broader picture concerning the development of
switching and tagging orders or steps to ensure cognizance of
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plant conditions prior to implementation of switching and tagging
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orders.
In addition, Licensee Event Report 91-011 concerned a similar
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breach of containment integrity that occurred in 1991.
The root
cause investigation for that event was insufficient and possibly
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contributed to this incident.
The event involved an auxiliary
operator-(AO) reporting to the shift supervisor (SS) that
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containment was established through the emergency escape airlock
by visually observing that both airlock doors were shut.
He did
not actually check that the interlock was operational and the SS
did not question if containment was formally established by the
use of a procedure.
The lack of a questioning attitude by both
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the A0 and the SS and the non-formal containment establishment
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were not cited as a possible root cause of this incident.
Personnel error was the only root cause established and this was
considered to be an isolated incident. Although corrective
actions to address this event specified a review of areas of
potential containment integrity breaches to ensure that a " flag"
exists for each case, the review concerned only procedures, and
focused solely on the adequacy of each individual procedure
involving a breach of containment integrity to ensure that
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approval was received and plant _ conditions allowed for the test.
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Even in this limited corrective action, the affected procedure
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noted above still failed to identify the VFW-185 valve as a
containment isolation boundary.
Similarly, no mechanical items
were caution tagged inside containment and no general statements
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about extra attention being required when performing unusual
evolutions or when changes were made to procedures were specified.
Criterion XVI of Appendix B to 10 CFR Part 50 requires, in part,
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that the cause of significant conditions adverse to quality be
identified and corrective action taken to preclude repetition.
The failure to implement sufficient corrective actions to preclude
repetition of violations involving the loss of containment
integrity, inadequate control of switching and tagging orders, and
cognizance of shift management on the conditions of the plant is
an apparent violation of Criterion XVI (155/93015-05).
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C.
Analysis of Root Causes
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There were several contributing causes to this event.
There was
inadequate attention to detail in the development of the switching
and tagging order. The order was not developed using approved
P& ids, but rather, a surveillance procedure drawing that was used
to perform a leak rate test.
This procedure failed to clearly
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identify the containment boundary on the drawing; and although the
test procedure contained all the steps to ensure containment
integrity were re-established after performance of the test, these
were not carried over to the switching and tagging order.
The
leak rate test procedure would have shut VFW-185 if it had been
completed.
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'There was a loss of command and control over the status of
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containment integrity when the tagging order was implemented. The
shift supervisor who released the tagging order for implementation
failed to provide sufficient review to determine the effect of the
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tagging order on plant status.
Given this lack of adequate
review, he was unaware that containment had been breached.
There was inadequate work planning concerning the implementation
of the control rod withdrawal interlocks test.
The procedure
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itself was not specific in what plant conditions were required for
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implementation. When the shift supervisor approved the procedure
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for implementation, he was expected to know all plant conditions
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that were required and be in a position to verify them.
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The containment isolation test procedure did not call out valve
VFW-185 as being significant for containment integrity, while it
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did address valves VFW-125 and -140.
This could have contributed
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to the failure to recognize that containment was breached by the
switching and tagging order allowing VFW-185 to remain open.
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There was an insufficient root cause investigation for a previous
loss of containment incident involving the interlock on the escape
hatch (LER 91-011). The lack of a questioning attitude by both
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the Auxiliary Operator and the Shift Supervisor and the non-formal
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containment establishment were not cited as a possible root cause
of this incident.
Personnel error was the only root cause
established and this was considered to be an isolated incident.
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The corrective actions implemented for the 1991 LER and the
violations discussed above during the 1992 Big Rock Point
enforcement conference were insufficient to preclude repetition
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due to the narrow focus taken to-implement corrective actions.
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For example, after the 1991 LER there were no mechanical items
caution tagged inside containment and no general statements about
extra attention being required when performing unusual evolutions
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or when changes were made to procedures.
D.
Safety Sionificance
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The safety significance of the consequences of this event is
relatively minor because of the condition of the facility at the
time of the occurrence. The reactor had been shut down June 26th
to commente a scheduled refueling outage: the primary coolant
system was at atmospheric conditions ard temperature was less than
212 F, no control rods were moved, and no fuel handling was
performed. However, the conditions that led to this event were
significant in that they demonstrated a less than adequate
attention to detail on the part of plant personnel, an
insufficient questioning attitude towards the development of
abnormal lineups, and a loss of command and control of a plant
evolution.
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Licensee Initial Corrective Actions
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Upon realization that containment integrity was breached, VFW-185
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was immediately closed and caution tagged.
The licensee initiated
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a corrective action board and assigned this as a deviation report
event to be completed within 30 days of the event.
Licensee Event
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Report 93-002 was issued on July 23, 1993, addressing the event.
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The licensee planned to determine other lines entering and exiting
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the containment building that have a potential for breaching
containment integrity by October 1, 1993.
Further corrective
actions were to place warning labels on the valves located in the
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containment building that have the potential to breach containment
integrity and not!fy operations procedure sponsors of the
potential for breaching containment integrity and instruct them to
add caution statements within the applicable procedures they
sponsor. These latter actions were to be completed prior to the
1994 refueling outage.
Specific corrective actions to address the
other causes identified above, such as the lack of a questioning
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attitude, had not been developed as of the end of this inspection.
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Conclusions
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There were five apparent violations associated with this event
that revolve around lack of a questioning attitude on the part of
plant personnel and failure to look broadly at problems that occur
to ensure that corrective actions will address the cause of
deficiencies and not the specific examples presented in the event.
Had the events described in LER 91-011 and the July 1992
enforcement conference been broadly evaluated and corrective
actions implemented, this event would probably not have occurred.
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3.
Hydrostatic Test Event
A.
Event Description
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On August 23, 1993, at 6:25 p.m., pressure increase for the hydro
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test is initiated.
At approximately 7:00 p.m., leakage is
identified on reactor water clean-up blowdown line valves. At
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7:18 p.m., CV-4047 is closed per request by the evening shift
supervisor (SS-1) to stop the leakage.
Closure of this valve
prevents the control room from being able to control pressure
during the rest of the test.
During latter part of shift, SS-1
requests volunteers from shift crew to holdover to assist in
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conduct of hydro test. No one volunteers.
The Hydro test
pressure of 1475 psig is reached at 8:30 p.m.
Shift supervisor of oncoming shift (SS-2) arrives early for
turnover and to discuss implementation plans for hydro test.
SS-1
and SS-2 agree to use the auxiliary operator (AO) assigned to
monitor the hydro pump to also conduct visual leak inspections in
upper and lower accumulator room.
SS-1 stays over to assist in
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conduct of hydro test inspections as no other VT2 (visual test,
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level 2 certification) qualified personnel from first shift are
willing to stay and assist in hydro. The shift supervisor was of
the opinion that two or three VT2 qualified personnel were needed
for the test, but only one had been assigned originally to that
shift.
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SS-1 goes to the health physics station to get health physics
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support for hydro test leak inspections. At 00:15 a.m., SS-2
conducts combined shift turnover and pre-job brief for_ hydro-test.
The pre-job briefing was rushed, lacked discussion of solid plant
operations, and didn't fully assign all responsibilities,
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SS-2 and three auxiliary operators (AO-1, A0-2, A0-3) leave the
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control room - technical support center (CR/TSC) area to begin
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hydro-test leak inspections.
A0-1 arrives at the hydro pump in containment to relieve A0 from
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evening shift. He checks the hydro pump operation and proceeds to
upper accumulator room to inspect vents and drains for leakage.
He observes local reactor coolant system (RCS) pressure indication
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steady at 1500 psig.
A0-1 returns to hydro pump to obtain protective clothing in
preparation for entry to lower accumulator room (contaminated).
A0-1 leaves radio near hydro pump at this time.
Control Room Operator (CO) hears relay click and observes pressure
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increasing at a rate of about 1 psig per 3 seconds. As pressure
is approaching upper boundary of test pressure range, C0 makes
several attempts by radio and public address system to contact
various members of the crew in containment to direct pressure
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decrea:;e.
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A0-1 observes local pressure indication (on rod drive header) in
upper accumulator room oscillating between 1450-1500 psig, but
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does not contact contro; room.
He then returns to hydro pump and
observes that the pres',ure indication on hydro pump gage appears
to be below 1500 psig. A0-1 hears chattering noise, apparentl/
emanating from the lower accumulator room. A0-1 then returns to
upper accumulator room and completes putting on protective
clothing.
By this time SS-1, SS-2, and A0-2 (AO-2 was performing door
watches for SS-1), have arrived in upper accumulator room in
response to chattering noise.
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A0-1 proceeds down to the lower accumulator room and hears the end
of a request on the public address system that he interprets as a
request to call the control room.
A0-1 calls the control room from the lower accumulator room and is
told that pressure is in excess of 1560 psig and rising.
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A0-1 yells up to SS-2 with this information.
SS-2 runs to the
hydco pump and attempts to decrease pressure by adjusting the
hydro-pump regulator.
SS-2 calls control room and is informed
that pressure is approximately 1568 psig and is continuing to
rise. He proceeds to make additional adjustments to .the hydro-
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pump regulator and hears apparent sound of steam-drum safety-
relief valve lifting.
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SS-2 adjusts the hydro pump regulator and decreased pressure to
approximately 1350 psig.
At 04:30 a.m., hydro test is completed, approximately 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />
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1ater.
(Chattering noise from lower accumulator room did not
recur during the remainder of the test.)
B.
Inspectors Review and Findinas
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Section 6.8.1 of the Technical Specifications requires, in part,
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that written procedures ., hall be established, implemented, and
maintained for all structures, systems, components, and safety
actions defined in the Big Rock Point Quality List.
Section 5.2
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of Chapter 13 of Volume 17 of the quality list requires procedures
for surveillance activities.
Step 2.2.3.b of surveillance
procedure TV-10, " Pressure Test of Nuclear Steam Supply System,"
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requires that when flange and wall temperatures are above 130 F,
hydrostatic test pressure shall not exceed 1535 psig.
As noted
above, the maximum pressure reached was 1570 psig, which occurred
at 1:00 a.m. on August 24, 1993, where it was reduced by a steam
safety relief valve lifting.
This is an apparent violation of TS
6.8.1 (155/93015-06).
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Personnel performing this hydro evolution were not in control of
the activity. As a result, test pressure rapidly increased while
the hydro pump was running.
The pre-job briefing was rushed and
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combined with the shift turnover.
There was no discussion of
solid plant operations and all responsibilities were not properly
assigned. The operating crew did not expect a sudden rise in the
hydro test pressure, indicating a lack of understanding of the
thermal hydraulic principles during solid plant operations. They
failed to recognize that if the system were truly leak tight, the
running pump would send pressures very high very quickly. Neither
shift supervisor appreciated the need to have the A0 in constant
attendance at the hydro pump to be able to quickly adjust the
output of the positive displacement pump; thus, adjusting the
hydro test pressure.
Given that previous hydro tests had utilized
a bumping on and off of the control rod drive pumps, the potential
for a sudden pressure rise in the past had been non-existent.
Although the test procedure, TV-10 contained a prerequisite that
blowdown capability be available, the ability to utilize the
blowdown pathway was severely restricted. The blowdown system had
been removed from service by closing the CV-4047 valve due to
known leakage past the CV-4114 and CV-4040 valves.
The CV-4047
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valve could not be operated from the control room, only locally;
however, the local operator (the A0) was unaware that he could
operate the valve. The affect was that although the pathway could
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be used from an equipment standpoint, in actuality it could not be
used due to a lack of knowledge on the part of the A0. Criterion
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II of Appendix B to 10 CFR Part.50 requires, in part, that
training and indoctrination of personnel shall be provided as
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necessary to personnel performing activities affecting quality to
assure that suitable proficiency is achieved and maintained.
Given the fact that personnel were not proficient in the effects
of a running hydro pump on test pressure, and that the A0 was not
proficient in his ability to establish a blowdown pathway if
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necessary to reduce pressure, the inspectors concluded that
personnel performing the test did not have . suitable proficiency in
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the performance of this safety-related activity.
This is an
apparent violation of Criterion II of Appendix B (155/93015-07).
During the performance of the test, the control room attempted to
contact the A0 and SS's in the containment on several occasions
through the plant paging system, but were initially unsuccessful.
The licensee has no surveillance program to ensure operability of
the paging system. After considerable prompting by the
inspectors, the licensee performed a review of the plant paging
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system to ensure that the speakers in the plant were working and
set to a level that was audible. This review determined that 25
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percent of the speakers were either inoperable or inaudible,
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including the speaker in the control rod drive room, where the A0
had gone to look for leaks.
The shift supervisors did not maintain oversight and ensure
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communication with the control room, especially when a loud
chattering noise was heard in the control-rod-drive room.
Instead, they became involved in trouble shooting activities and
lost the oversight perspective of the overall plant.
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The ability of the A0 to control pressure at the hydro pump was
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severely limited. There was no relief valve at the pump, and the
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pressure gauge installed at the pump was in increments of 200
pounds, while he was required to control pressure within a 50
pound band.
Although they relied on communication with the
control room to maintain pressure, both the A0 and SS failed to
keep their radios with them.
C.
Analysis of Root Causes
The primary root cause of the event was failure to maintain
adequate command and control over the evolution. There were
several contributing causes associated with the event. These
included insufficient knowledge of the evolution, inadequate job
planning, communications difficulties, inadequate man-machine
interface, and procedural weaknesses.
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insufficient Knowledae of the Evolution
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Personnel performing the evolution lacked an adequate
understanding of the process or required actions.
Based on past
experience, all but one crew member interviewed indicated that
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they did not expect a sudden or significant pressure increase in
pressure during the test.
Test pressure decreases were expected.
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This expectation was founded on past experiences, where the
control rod drive pumps had been used to perform the test, and
appeared to affect actions taken by the operators. The
differences to be expected from the old methodology using the
control rod drive pumps, which were bumped on and off to control
pressure versus the recent methodology to utilize a continuously
running hydro pump, were insufficiently explained to plant
personnel. As a result, the shift supervisor did not appreciate
the need to have the A0 in constant attendance at the hydro pump
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to be able to quickly adjust the output of the positive
displacement pump; thus adjusting the hydro test pressure.
He
concluded that he could utilize the A0 in the search for leaks
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once pressure was reached and initially stabilized.
This appeared
contrary to the decision process he utilized to close the CV-4047
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valve.
The shift supervisor had concurred in the decision to use
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the hydro pump A0 to conduct leak checks in the upper and lower
accumulator rooms.
Since the lower accumulator room would require
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dressing out, the A0 would not be readily available to operate
local valves elsewhere. However, the shift supervisor had
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concluded that blowdown would still be available because the A0
would be at the hydro pump and could _ operate the valve at the
local reactor water cleanup (RWCU) panel, thereby allowing the
control room to access blowdown.
He failed to pass this
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information on to the A0, who was unaware that he could provide
blowdown capability by manually opening the CV-4047 valve.
In
addition, by not passing this information on to the AD, the A0 was
not given the opportunity to recognize that the activities he was
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directed to do would interfere with a timely response to a
pressure increase or to recognize the importance of closely
monitoring hydro pressure.
Inadeauate Job Plannina
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The shift complement for the leak dctection portion of the hydro
evolution did not contain sufficient personnel who were VT2
qualified. Work planning for the evolution did not evaluate what
work would be performed and then determine if the correct people
were available on the assigned crews to do the work. As a result,
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during the afternoon shift, the shift supervisor stayed over to
the night shift to complete the test.
There were no other
volunteers, and the shift supervisor did not direct anyone to stay
over. The decision to use the hydro pump A0 for leak detection
activities was based in part on an effort to relieve SS-1 as
quickly as possible.
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Although there was a management expectation that pre-job briefings
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and shift turnover would not be combined, they were combined and
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the shift turnover rushed so that SS-1 could go home as soon as
possible. There was a sense of urgency noted by several members
of the crew to get the job done as quickly as possible, with some
of the crew noting the turnover as being quick in pace. The
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briefing failed to include:a discussion on solid plant operations,
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such as the potential for rapid increases in pressure over a very
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short time period, and didn't assign the A0 with the
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responsibility to lineup the blowdown pathway, if needed.
Although the hydro evolution was only implemented once per
refueling outage and the licensee had developed a format for the
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conduct of " infrequent activity" briefings, this format was not
utilized for this briefing.
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Communications Difficulties
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The plant paging system, or Gai-Tronics was inadequate at the time
of the event.
A subsequent check determined that 25 percent of
the Gai-Tronics were either inoperable or inaudible.
Unintelligible communications over the Gai-Tronics in containment
was known historically by the licensee, yet there were no
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provisions to ensure that the speakers in the plant paging system
were working properly and set at a level that was audible.
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Uncontrolled methods to reduce speaker volume, such as stuffing
materials in the speakers or turning down the volume control had
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been observed in the past.
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A0-1 left his radio at the hydro pump and SS-1 left his radio in
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the next contaminated area to be inspected while he was undressing
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from anti-c's.
SS-2 had previously staged his radio outside the
steam drum area.
None of-these individuals had their radios with
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them so that they could be contacted.
In addition, neither SS nor
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the A0 took a radio to the upper accumulator room while trying to
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investigate the chattering sound.
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It was not clear to the operators when communications should
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occur. The A0 who found the oscillating CRD header pressure
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failed to contact the control room.
The control room failed to
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initially respond to the pressure increase because they assumed
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that it was the result of the A0 adjusting the hydro pump
regulator. This may have been due to the fact that they felt an
uncontrolled increase in pressure was unlikely. When it became
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clear that pressure needed to be reduced, the control room
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operators could not communicate with the hydro pump A0 or the
shift supervisors due to the failure of them to have their radios
with them and the fact that the volume of the Gai-Tronics speakers
in the upper accumulator room had been turned down.
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Inadeouate Man-Machine Interface
Their were inadequate provisions provided to ensure that the hydro
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pump operator could ascertain and control system pressure.
Although the vendor manual had a caution that a relief valve
should be used, none was installed. This forced the plant to rely
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on the steam drum safety valves to relieve a pressure transient,
since the control room could not control pressure through the
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blowdown pathway given the planning deficiencies noted above.
In
addition, the pressure gauge for the pump was of such a wide
range, with gauge increments of 200 psig.
This was inadequate to
read at the level of precision required for the operator to
effectively control pressure within a 50 pound band.
Procedural Weaknesses
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Other than the step in the precautions and limitations of the
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procedure, there were no cautions in the text of the procedure to
provide guidance to the users as to what to do if a pressure
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excursion was encountered.
In addition, the procedure contained
no cautions to address the potential for a sudden and rapid
increase in pressure due to an operating hydro pump with the
system solid.
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toss of Command and Control
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Although the training of licensed personnel generally emphasized
maintaining positive control of plant evolutions, this did not
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occur.
When the chattering sound was heard in the control rod
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drive room, the Shift Supervisor became involved in
troubleshooting and did not maintain effective overview of the
plant, nor did he communicate the local problems to the control
room.
D.
Safety Sionificance
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The RCS hydro over-pressure with the resultant safety relief valve
operation constituted an unnecessary challenge to plant safety
systems.
The safety significance of this event was minor given
the capacity of the pump and the capacity and number of relief
valves. However, There are six 3-inch diameter safety relief
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valves and the hydro pump capacity was 10 gallons per minute.
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Therefore, there was minimal potential to over pressurize the
primary piping beyond design.
The primary system temperature was
approximately 249 F throughout the test, well above the reactor
vessel brittle failure curve for 1600 pounds pressure. Therefore,
this over pressurization and challenging of the primary-system
boundary was of minimal safety consequence.
However, the
conditions that led to this event were significant in that they
demonstrated a failure to adequately plan for the evolution, less
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than sufficient knowledge of potential problems during the test,
significant communications weaknesses, and a loss of command and
control of this plant evolution.
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E.
Licensee Initial Corrective Actions
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Once informed.by the control operator of increased primary system
pressure, the shift supervisor returned to the hydro pump and
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reduced system pressure to approximately 1350 psig.
When the
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event was under control, system pressure was raised to 1500 psig
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and the hydro was successfully completed 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> later.
Since the
chattering noise did not recur, it was considered not to be a
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problem.
As a result of the event, the licensee had a corrective action
board and assigned this as a deviation report event to be
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completed within 30 days of the event.
Also, the licensee
performed a surveillance on all paging speakers at the inspectors
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request and found four that needed repair and four that needed
their volume increased.
These speakers were then adjusted or
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repaired.
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F.
Conclusions
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There were two apparent violations associated with this event that
revolve around inadequate command and control of the evolution,
inadequate job planning, an inadequate pre-job briefing, failure
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to ensure adequate communications.between the control room and
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inplant personnel, and insufficient knowledge of plant performance
during solid operations. The RCS hydro over-pressure with the
resultant safety valve operation constituted an unnecessary
challenge to plant safety systems. The fundamental problem was a
pervasive lack of sensitivity to potential pressure excursion.
This resulted in a lax approach to conducting the test and
consequently other weaknesses were revealed (e.g., problems with
test configuration (no relief valve at the pump), inadequate
maintenance of PA, and procedure weaknesses). Management
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expectations and policy were not effectively understood, as a
result, a test which appeared " routine" but was only performed
once per outage and involved an abnormal operating condition,
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namely a solid plant, was implemented without sufficient
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discipline or preparation.
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Prior deficiencies in valve performance contributed to the
problem.
Prior to shutdown, the licensee was aware of leakage
through the CV-4114 and CV-4040 valves. At the beginning of the
hydro, CV-4047 was open; however, during the test this valve was
closed to preclude leaking through the -4114 and -4040 valves,
thus removing the potential for blowdown from the' control room.
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4.
Common Root Causes
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Both of the recent events (loss of containment integrity and the hydro
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over pressure) have similarities to the earlier loss of containment
event involving the escape hatch doors interlock. All have a basic root
ca_se in lack of sufficient attention to detail to prevent the loss of
command and control. The loss of containment integrity event has many
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similarities to the events discussed during the July 1992 enforcement
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conference. The timing of the hydro event is also disturbing in that
the lessons from the Palisades control rod withdrawal event were not
learned at Big Rock Point. Common causes between the Palisades event
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and these events were ineffective procedures, inadequate control of work
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prcctices, poor organization, weak communications, and ineffective
management involvemeri. Given that the Palisades event occurred in June
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1993, corrective actions for Consumers Power should have been developed
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and implemented to preclude similar. events at Big Rock Point.
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5.
Exit Interview
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The inspectors met with the licensee representatives denoted in
paragraph I during the inspection period and at the conclusion of the
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inspection on September 14, 1993.
The inspectors summarized the scope
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and results of the inspection and discussed the likely content of this
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inspection report. The licensee acknowledged the information and did
not indicate that any of the information disclosed during the inspection
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could be considered proprietary in nature.
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