ML16342D439
| ML16342D439 | |
| Person / Time | |
|---|---|
| Site: | Diablo Canyon  |
| Issue date: | 09/19/1996 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML16342D437 | List: |
| References | |
| 50-275-96-19, 50-323-96-19, NUDOCS 9609240249 | |
| Download: ML16342D439 (36) | |
See also: IR 05000275/1996019
Text
ENCLOSURE 2
U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
Docket Nos.:
License Nos.:
Report No.:
Licensee:
Facility:
Location:
Dates:
Inspectors:
Approved By:
5.0-275
50-323
DPR-82
50-275/96-1 9
50-323/96-1 9
Pacific Gas and Electric Company
Diablo Canyon Power Plant (DCPP), Units
1 and 2
7 1/2 miles NW of Avila Beach
Avila Beach, California
August 5-9, 1996
W. F. Smith, Senior Resident Inspector, River Bend Station
W. P. Ang, Senior Inspector, Engineering Branch, Division
of
Reactor Safety
F. R. Huey, Chief, Project Branch E
Division of Reactor Projects
ATTACHMENTS:
Attachment 1:
Partial List of Persons Contacted
Inspection Procedure
Used
List of.Documents Reviewed
List of Items Opened
List of Acronyms Used
9609240249
960919
ADOCK 05000275
8
l
EXECUTIVE SUMMARY
Diablo Canyon Power Plant, Units
1
&. 2
NRC Inspection Report 50-275/96-19, 50-323/96-19
This special inspection included aspects of plant operations.
The report covers an
assessment
of procedures
and procedure compliance, and followup on selected issues
identified on licensee action requests.
~Oerariona
~
Based on brief observations of control room activities, the inspectors noted that the
operators conducted business
in a professional manner; however, improvement
items were identified in access controls and communications (Section 01.1)
~
Operators interviewed by the inspectors demonstrated that they had'a clear
understanding of management's
expectations with regard to procedure compliance,
based on recent effective efforts by management to communicate those
expectations
(Section 01.2).
~
During refueling outages the licensee used the practice of delegating the shift
foreman's authority by having a second senior reactor operator approve clearances
on his behalf, without documenting that delegation of authority.
Consequently,
clearance approvals were performed by an improperly authorized person.
A
violation of Technical Specification (TS) 6.8.1.a was identified (Section 01.2)
Several licensee procedures were reviewed and appeared to be reasonably clear and
concise.
The licensee was taking appropriate corrective action to improve DCPP
procedures
on a priority basis, thereby facilitating improved procedure compliance
(Section 03.1).
The licensee performed significant preparation, evaluation, review, planning, and
oversight for'he Unit 1, Refueling Outage 7 (1R7) replacement of the Unit 1 main
bank transformers.
The licensee performed the replacement activities during periods
of relatively higher risk of reactor coolant system (RCS) boiling, and chose not to
delay the activities three days to a period of relatively lower risk. The inspectors
determined that the licensee actions were acceptable,
in that TS requirements for
available A.C. sources were met, and additional precautions and compensatory
actions were planned and performed (Section 08.1).
The licensee identified violations of regulatory requirements regarding the improper
removal of grounding devices on November 12, 1995, after it was documented
on
an Action Request
(AR) that procedures were not followed. Corrective actions were
appropriate to the circumstances,
however, actions taken in response to the
October 1995 failure of AuxiliaryTransformer 1-1 should have prevented this
incident.
A violation of TS 6.8.1.a was identified (Section 08.2).
Operations control over ground buggies was lost through a series of inappropriate
management
decisions, coupled with weak procedures
and a tendency to work
around the procedures.
The inspectors concluded that lessons learned from the
N
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October 1995 transformer failure event resulted in thorough and reinforced
communication of management expectations,
and resulted in comprehensive
controls over grounding device activities
(Section 08.3).
~
Turbine siding installation activities were poorly coordinated during a period when
only one offsite power supply was available.
The problem was exacerbated
by an
apparent communications breakdown between the shift foreman and the siding job
foreman fSection 08.4).
Re ort Details
Summar
of Plant Status
Both units were operating at essentially 100 percent power for the duration of this
inspection.
I. ~Oerations
01
Conduct of Operations
01.1
General Comments
71707
The inspectors briefly observed Unit 1 and Unit 2 control room activities.
The
operators performed their duties in a professional manner, annunciated
alarms were
properly attended to and communicated to other control room watchstanders,
and
the Shift Foremen demonstrated
good command and control. The inspectors noted
that the licensee had not implemented specific controls over non-operator access to
the at-the-controls area; however, no abuse was apparent.
The inspectors also
noted that operators used two-way, versus three-way communications.
The
licensee explained that they were in the process of implementing a three-way
communications policy.
01.2
Mana ement Ex ectations on Procedure
Com lienee
'ns
ection Sco
e 71707
The inspectors reviewed documentation of the various methods used by the
licensee to ensure procedure-compliance
at DCPP.
Also, the inspectors interviewed
seven operations personnel including the Operations Director, a shift supervisor,
a
shift foreman, a control operator,
a shift technical advisor, and two nonlicensed
nuclear operators to help determine the effectiveness of licensee actions to
communicate and reinforce management
expectations
regarding procedure
compliance.
b.
Observations
and Findin s
In August 1995, in preparation for Unit 1 Refueling Outage 1R7, the licensee placed
much focus on management expectations for employees to follow procedures.
Senior management
conducted all-employee sessions
emphasizing the proper use of
and adherence to procedures,
and the need to stop and resolve problems where
procedures
appeared to be in error, or did not provide adequate
guidance for the
tasks at hand.
The 1R7 Handbook included a section that reinforced this
expectation.
The 1R7 Outage Incentive Program criteria included incentive awards
for eight key evolutions performed without personnel errors.
Following the failure of AuxiliaryTransformer 1-1 on October 21, 1995, the Senior
Vice President and General Manager issued
a memorandum to all employees
reflecting on the transformer failure, and reinforcing the expectation that procedure
compliance was essential.
In November 1995, the Senior Vice President addressed
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all employees on the causes of the transformer, failure, with procedure adequacy
and compliance being one of the three key contributors.
In a memorandum dated
December 28, 1995, the Senior Vice President again addressed
the importance of
procedure adherence.
By February 1996, plant managers
held detailed discussions
with all supervisors on management
expectations with regard to procedure
adherence,
using simplified written handouts.
The Unit 2 Refueling Outage 2R7
Outage Incentive Program criteria differed from the 1R7 criteria, in that nearly
double the award was offered for safe and error-free key evolutions.
Additional
initiatives for procedure compliance included distribution of laminated cards that
summarized expectations for procedure adherence,
booklets emphasizing important
requirements
in commonly used administrative procedures,
and an article in the
"D-Crier," a DCPP recent industry events publication dated May 17, 1996.
Interviews with operations personnel indicated that the licensee had effectively
communicated management's
expectations that procedures must be followed, and
procedure problems resolved prior to proceeding.
All interviewed employees
expressed
satisfaction with their individual knowledge of administrative procedures
affecting their day-to-day activities, and with the refresher and update training they
'eceived.
When discussing procedure compliance weaknesses,
the general
consensus
was that an occasional lack of attention to detail had resulted in missed
steps, or incorrect understanding of procedure requirements.
The interviewees
generally indicated that management's
messages
regarding procedure compliance,
had contributed to improved performance.
While discussing equipment clearances with the interviewees, the inspectors noted
that during outages, the licensee had delegated
some of the shift foreman's
authority to an additional senior reactor operator.
In particular, this additional
person, referred to as a "Screen," had approved equipment clearances
on behalf of
the designated shift foreman.
While this practice was successfully used at DCPP
and other nuclear power plants, it was inconsistent with existing Diablo procedures
because there was no written policy or procedure delegating that authority to the
Screen.
As a consequence,
clearances
were repeatedly approved by other than the
shift foreman, as designated
by Inter-departmental Administrative Procedure
OP2.ID1, "DCPP Clearance
Process,
"Revision 5, Section 4.5.1.
Licensee Program
Directive OM1, "Organization," Revision 2A, Section 4.2.2 required, in part, that
such delegations
shall be documented,
and the documentation shall clearly describe
the scope and limits of the work being delegated.
The'licensee
could not produce
any documentation, but stated that they were in the process of developing revisions
to procedures to properly delineate the Screen's responsibilities and authority.
The licensee stated that, although it had previously interpreted the Sere'en
as being
a second shift foreman, an employee concern about compliance with Procedure
OP2.ID1 had prompted the licensee to address this deficiency.
Failure to comply
with Section 4.2.2 of Program Directive OM1 is a violation of TS 6.8.1.a, in that
the licensee did not properly document delegation of the shift foreman's clearance
approval authority during Refueling Outage 2R7 (50-275, 323/96019-01).
-3-
The licensee was already in the process of correcting this deficiency during this
inspection, by processing revisions to Procedure
OP2.ID1 and Administrative
Procedure OP1.DC10, Revision 2, "General Authorities and Responsibilities of
Operating Shift Personnel."
Although the licensee stated that it inappropriately
interpreted the Screen as being a second shift foreman, the licensee responded to
employee concerns that procedures were not being followed by correcting the
appropriate procedures
in time for the next refueling outage.
However, consistent
with Section IV of the NRC Enforcement Policy, this violation is being cited because
actions taken as a result of previous violations should have prevented this problem
from occurring during 2R7.
c.
Conclusions
The licensee effectively communicated management
expectations with regard to
procedure compliance to DCPP personnel.
With regard to clearance
approval
authority, the shift foreman's authority was improperly delegated to another senior
reactor operator, without documenting the delegation of authority in accordance
with the appropriate procedures
and program directive. A violation of TS 6.8.1:a
was identified.
03
Operations Procedures
and Documentation
03.1
Review of Procedures
Ins ection Sco
e 71707
The inspectors reviewed the following operations-related
procedures to determine
whether the procedures appropriately and adequately communicated
DCPP and
Regulatory requirements such that they could be followed by DCPP personnel:
OP1.DC2,
"Verification of Operating Activities," Revision 6
OP1.DC12, "Conduct of Routine Operations," Revision 3
OP1.DC19, "Plant Status Controls," Revision 3
OP2.ID1,
"DCPP Clearance Process,"
Revision 5
b.
Observations
and Findin
s
The inspectors found that the above referenced procedures were reasonably clear
and concise, and provided DCPP personnel with the guidance they needed to meet
management
expectations.
An interview with the procedure services supervisor
revealed that this was not always the case.
In November 1993. the licensee
formed a task force of approximately 50 people from various levels to identify root
causes
and corrective actions for the problem of procedure compliance.
The task
force determined that: mixed messages
were delivered by management,
people
were not consistently held accountable for procedure compliance errors, the
procedure change process was difficultto follow, and many procedures were
cumbersome,
particularly in the areas of operations and maintenance instrument and
control.
The inspectors noted that the procedure change process had recently been
simplified, and based on the inspectors'eview of the above listed procedures,
some progress had been made in improving procedures.
However, vulnerabilities
still existed, in that there were over 460 administrative procedures
planned to be
consolidated or eliminated.
There were also over 500 maintenance
electrical and
mechanical procedures
planned for review and improvement to provide a better
match between the level of detail and the skill of the craft. The licensee stated that
they were targeting September 30, 1996, for the development of a plan and
schedule to complete these tasks.
These actions appeared
appropriate to the
circumstances.
C.
Conclusions
Several licensee procedures were reviewed, and appeared to be reasonably clear
and concise.
The licensee was taking appropriate corrective action to improve
DCPP procedures
on a priority basis, therefore facilitating improved procedure
compliance.
08
08.1
Miscellaneous Operations Issues
Re lacement of Main Transformers
a o
Ins ection Sco
e 71707
During Refueling Outage 1R7, the licensee replaced the Unit 1 main transformers
because of reliability concerns regarding the old transformers.
Licensee activity
associated with planning, preparations,
engineering, and performance of the
replacement were reviewed by the inspectors.
The inspectors reviewed procedures,
work orders, ARs, analyses,
memoranda,
and other records associated with the
replacement of the Unit 1 main transformers.
These documents
are listed in
Attachment
1 of this inspection report.
The inspectors discussed
the
documentation and the replacement activities with various licensee personnel from
engineering, outage management,
and quality assurance
organizations.
b.
Observations
and Findin s
The replacement of the Unit 1 main transformers necessitated
the use of the startup
transformers for providing offsite power to the unit while the main transformers
were being replaced.
Offsite power was only available through the startup
transformers during that period. Two of three Unit 1 diesel generators were
operable during the replacement of the Unit 1 main transformers.
DCPP Unit 1 TS 3.8.1.2, "A.C. Sources," required that one circuit between the offsite transmission
network and the Onsite Class
1E Distribution System, and one diesel generator be
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available when the unit was in Modes 5 or 6. The inspectors determined that the
licensee met the TS 3.8.1.2 limiting condition for operation during the replacement
of the Unit
The licensee issued Temporary Procedure TP TD-9504, "Replacement of Unit 1
Main Transformers and Placement of Spare Main Transformer to Unit 2 Spare Pad,"
Revision 0, for the replacement of the main transformers.
The licensee prepared
and reviewed the temporary procedure
in accordance with Administrative Procedure
AD1.1D2, "Review Level 'A'rocedure Review, Approval and Notification of
Changes,"
Revision 6. Administrative Procedure AD1.1D2 required the performance
of cross discipline reviews, the performance of a "Licensing Basis Impact
Evaluation" screen,
and a Plant Safety Review Committee review, as part of the
temporary procedure review process.
The licensee's electrical engineering staff prepared and issued Temporary Procedure
TP TD-9504. The licensee's civil engineering, outage management,
and unit
operations staff reviewed the procedure, prior to approval, as part of the cross
discipline reviews that were performed for the procedure,
The licensee's civil
. engineering staff performed structural assessments
of the rigging for the loading
and unloading of the main transformers.
The licensee's civil engineering staff also
reviewed moving equipment to be used by the contractor for transporting the main
transformers,
and evaluated the load path for the transport of the main
transformers.
The L'icensing Basis Evaluation screen for Procedure TP TD-9504 determined that
the procedure did not involve a change to the facility design function or method, as
described in the Updated Final Safety A'nalysis Report (UFSAR). The Licensing
Basis Impact Evaluation determined that the movement of the main transformers
would not result in a condition that might affect safe plant operation that was not
anticipated, described, or evaluated in the UFSAR. The Licensing Basis Impact
Evaluation specifically stated, "A qualified electrical worker will assure adequate
clearance
is maintained from all energized lines to eliminate any potential for loss of
offsite power as a direct result of this move."
The inspectors determined that the procedure provided a proposed route for the
transport of the main transformers.
The procedure required verification of minimum
clearance requirements for overhead lines, and a minimum horizontal clearance
requirement from adjacent energized electrical equipment, as required by
Administrative Procedure OM6.1D7, "Control of Activities Near Plant High Voltage
Lines and Equipment," Revision 0. The maximum clearance
available in the vicinity
of the startup transformers was limited by an adjacent permanent building. The
minimum horizontal clearance from adjacent energized equipment was specified by
the procedure, but the clearance was less than the approximate height of the main
transformers.
The inspectors observed that the main transformers could impact and
disable the startup transformer, and result in the loss of offsite power to Unit 1, had
a main transformer tipped over during movement in the vicinity of the startup
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transformer:
The licensee informed the inspectors that no tipping calculations were
performed prior to the move.
However, the licensee also informed the inspectors
that tipping was not considered to be credible based on its evaluations of the
moving equipment, and the information available regarding the dimensions, center
of gravity and weight of the main transformers.
The licensee performed Calculation
5227.5530, dated February 15, 1996, subsequent to the move and confirmed the
engineering judgement that tipping was not credible.
The inspectors determined that Procedure TP TD-9504 was reviewed and approved
by the Plant Safety Review Committee on August 28, 1995. The Plant Safety
Review Committee members in attendance
included the Site Vice President and
Plant Manager, and other DCPP senior managers
and directors.
Administrative Procedure AD8.1D1, "Outage Planning and Management,"
Revision 2, assigned the responsibility for the preparation of an "Outage Safety
Plan" to the Outage Director. An Outage Safety Plan was prepared and issued on
September 26, 1995, for Refueling Outage 1R7.
In addition, the licensee performed
an "Outage Risk Assessment
and Management" study to determine the core
damage risks and RCS boiling risks during the outage.
The studies showed that the
risks for core damage and for RCS boiling were approximately 1E-06 and 1E-05,
respectively.
These were the two highest risks when the main transformer moves
were planned due to the concurrent lowering of RCS level to below the reactor
vessel flange.
The studies further showed that the risks diminished significantly 3
days later to approximately 1E-11 and 1E-07 respectively, when the refueling cavity
was filled.
The Outage Safety Plan specifically noted that main bank transformers were being
replaced very early during the outage, and noted the plant limitations associated
with the conditions during the replacement.
The safety plan specifically recognized
electrical power source limitations and provided associated
contingency plans.
The
safety plan noted, "The likelihood of loss of AC power to the vital busses
is
minimized because
Diesel Generators
1-1 and 1-2 will be operable; however, there
is a small probability that the startup p'ower source could be lost while transporting
the main transformers under the 230 kV lines and around the startup transformers.
The loss of startup power would cause
a loss of all nonvital AC power, which
would affect some important plant equipment, including the containment polar
crane."
The safety plan further stated, "Liftingof the reactor vessel head and the
upper internals will be limited to a time when no movement of transformers or
heavy equipment is being done under the 230 kV lines or around the startup
transformers in order to minimize the risk of physical damage to the reactor core."
The inspectors determined that the Independent Safety Engineering Group
performed an assessment
of outage safety planning, scheduling and management
during Refueling Outage 1R7 higher risk periods, and documented the assessment
in
report number 95-012.DDC. The report observed that main bank transformer
movement around the 230 kV system represented
additional undefined risk to
~
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ensuring core decay heat removal during the first higher risk period.
The report
noted that additional assessments
were requested
by the Independent Safety
Engineering Group.
The concern was discussed
during a September
15, 1995,
meeting with Manager, Operations Services and representatives
from Op'erations,
Outage Services, Scheduling and Nuclear Site Engineering.
As a result of the
meeting, several actions were identified to ensure availability of the 230 kV system
and operable diesel generators.
The increase
in outage risk was discussed
and
determined to be acceptable.
The inspectors determined that both the Independent Safety Engineering Group and
Quality Assurance performed oversight activities during portions of the main bank
transformer moves.
The oversight activities were documented
in Assessment
Reports95-026.BEW and 960260002,
respectively.
The inspectors determined that the actual movement of the main transformers was
performed approximately as scheduled
on October 2, 1995, through October 5,
1995.
The transformer moves were performed without consequence
to the offsite
power sources,
The inspectors were informed by the licensee that during the move
of the first replacement transfo'rmer, one of the wheels of the contractor's trailer
moving the replacement transformer unexpectedly lowered into a soft spot on the
move path.
The transformer did not tip over, and the licensee informed the
inspector that the trailer leveling and safety equipment maintained the transformer
relatively steady, and the contractor was able to safely correct the condition and
complete the move.
C.
Conclusions
The inspectors concluded that the licensee performed significant preparation,
evaluation, review, planning, and oversight for the replacement of the Unit 1 main
bank transformers.
The licensee performed the replacement activities during periods
of relatively higher risk of RCS boiling, and chose not to delay the activities three
days to a period of relatively lower risk. The inspectors determined that the
licensee actions were acceptable,
in that TS requirements for available A.C. sources
were met, and additional precautions and compensatory actions were planned and
performed.
08.2
Followu
on AR A0391 742
Sco
e of Ins ection 71707
The inspectors followed up on AR A0391742, dated January 25, 1996, to
determine whether the licensee identified any violations of NRC requirements,
and
to verify that corrective actions were implemented appropriate to the
circumstances.
~
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ff
V
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Observations
and Findin s
AR A0391742 identified a problem involving a November 12, 1995, installation of
"ground buggies" installed for Clearance 49800 at the 4 kV auxiliary feeder
breakers to Buses D, E, F, G and H, which were removed without shift foreman
approval.
"Ground buggies" are grounding devices installed in place of breakers to
facilitate personnel and equipment safety while performing maintenance
on the
buses.
The licensee investigated the incident and found that corrective actions following
the October 1995 AuxiliaryTransformer 1-1 failure were ineffective.
For example,
one key action was to implement an interim policy for installing and removing
grounding devices and energizing dead buses and transformers.
This policy was
dated October 25, 1995, and was revised on November 3, 1995.
Section A.3.b of
the policy clearly stated, in part, that prior to removing grounding devices, the
clearance holder must report off, or report off for test in accordance with Procedure
OP2.!D1. The licensee also identified that Maintenance Procedure
MP E-57.11B,
"Installing and Removing Grounds from Deenergized Power Plant Electrical
Equipment," Revision 12, Seotion 7.2, was violated, in that the clearance
holder
failed to properly report off the clearance before removing the ground buggies.
In
addition, the licensee identified a violation of Procedure OP2.ID1, Revision 4,
Section 5.9, in that shift foreman approval was not obtained to modify the
clearance.
Failure to report off the clearance prior to ground buggy removal, as required by
Procedure
MP E-57.11B is a violation of TS 6.8.1.a.
In view of the multiple
corrective actions implemented by the licensee in response to the Auxiliary
Transformer 1-1 failure, the inspectors considered that the corrective actions should
have prevented this incident.
Therefore, in accordance with Section IV of the NRC
Enforcement Policy, this licensee-identified and corrected violation is being cited
(50-275, 323/9601 9-02).
As of this inspection, the licensee has addressed
major apparent causes of this
incident, involving procedure quality and procedure compliance.
The licensee
implemented detailed guidance to the clearance coordinator by issuing a Clearance
Coordinator Instruction, "Grounding Devices," Revision 3, dated April 1, 1996.
Procedure
MP E-57.11B was revised on April 6, 1996, to clarify the requirements
related to grounding devices for maintenance
personnel.
The licensee informed the
inspectors that efforts were underway to clarify and simplify the clearance
process,
by revision of Procedure OP2.ID1.
Based on interviews, employees involved with
the control of grounding devices appeared confident that the licensee had
implemented good controls with the new and revised guidance.
The inspectors also
considered the licensee's efforts to communicate procedure compliance
expectations to plant personnel were effective, as discussed
in Section 01.2 above.
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Conclusions
The licensee identified violations of regulatory requirements regarding the improper
removal of grounding devices, after it was documented
on an AR that procedures
were not followed. Corrective actions were appropriate to the circumstances;
however, actions taken in response to the October 1995 failure of Auxiliary
Transformer 1-1 should have prevented this incident. A violation of TS 6.8.1.a was
identified.
08.3
Followu
on Groundin
Device
Ground Bu
Controls
a 0
Sco
e of lns ection 71707
.The inspectors reviewed the Clearance Coordinator Instruction titled, "Grounding
Devices," Revision 3, dated April 1, 1996, to determine whether lessons learned
from the October 1995 transformer failure event resulted in clarified or revised
management expectations.
b.
Observations
and Findin s
Based on interviews conducted by the inspectors, it became apparent that in past
years, controls over grounding devices were indefinite, procedures left room for
interpretation, and the lack of procedure compliance expectations allowed
deviations from the procedures.
The inspectors were informed that a series of
decisions made by management
reduced operator involvement in the installation and
removal of ground buggies in the interest of better efficiency during maintenance
activities.
The October 1995 transformer failure event enabled the licensee to focus
on the inadequacy of grounding device controls, as well as on procedure compliance
expectations.
The licensee implemented comprehensive
actions to communicate management
expectations to DCPP personnel as described
in Section 01.2 above.
In addition,
Revision 3 to the Clearance Coordinator Instruction on grounding devices, coupled
with Revision 5 of Procedure OP2.ID1, and Revision 13 to Procedure
MP E-57.11B,
appeared to establish the level of controls needed to prevent future losses of control
over ground buggies.
Conclusions
Operations control over ground buggies was lost through a series of inappropriate
management decisions, coupled with weak procedures
and a tendency to work
around procedures.
Lessons learned from the October 1995 transformer failure
event resulted in thorough and reinforced communication of management
expectations,
and resulted in comprehensive controls over grounding devices.
-10-
However, the occurrence of the event described
in Section 08.2 indicates that
continuing management attention is warranted.
08.4
Followu
on AR A0399461
a.
Sco
e of Ins ection 71707
The inspectors followed up on AR A0399461, dated April 17, 1996, to determine
whether the licensee identified any violations of NRC requirements,
and to verify
that corrective actions were implemented appropriate to the circumstances.
b.
Observations
and Findin s
During Refueling Outage 2R7, new siding was installed on the turbine building, near
Startup Transformer 2-2. The project was planned to be'orked at a time when the
startup transformer was the only source of offsite power.
This was necessary
because
of the close proximity of the 500 kV power lines and, therefore, the work
was scheduled to occur during the Unit 2 main bank outage window.
Administrative Procedure ADB.DC51, "Outage Safety Management Control of
Offsite Power Supplies to Vital Buses," Revision 4, had a check list that required the
operators to verify that there were no physical interferences
or inappropriate
activities in progress,
in the area of the startup transformers. The verification was to
include items such as mobile vehicles, and scaffolding or rigging which was located
too close to energized systems.
Procedure AD8.DC51, Section 5.1 also stated, "All
work that has been identified as a potential to directly or indirectly affect the single
operable offsite power source shall not'be allowed at any time without the
authorization of the outage director and the approval of the shift foreman."
On April 17, the job foreman in charge of the turbine building siding work
coordinated with the shift foreman to obtain approval to resume the work, but was
told that the job was on hold pending a change to Procedure AD8.DC51 to add
appropriate requirements for compensatory measures.
Based on interviews, the
inspectors were informed that the work commenced without the shift foreman's
approval, and when the shift foreman became aware of the resumption of work, the
job was halted, but not without difficulties in communications.
Subsequently,
the
shift foreman granted approval to secure
a partially installed siding panel so that it
would not fall off in a high wind. However, work resumed with additional panels
until the shift foreman again stopped the work.
The inspectors found no evidence that the job foreman or outage management
had
deliberately proceeded with the turbine building siding work without the shift
foreman's approval.
Rather, it appeared to involve ineffective communications and
a lack of understanding
on the part of the job foreman that,he was not to install
additional siding until Procedure AD8.DC51 was changed to allow the work in the
vicinity of the transformer.
At the time, the resident inspectors observed that
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appropriate compensatory measures
were in place to protect the energized
transformer, and thus there was no safety concern.
Later on April 17, Procedure ADS.DC51.was changed, allowing the work to
proceed, and the outage director documented the following compensatory
measures:
A structure was built over the top of the transformer and over the isophase
duct work between the transformer and the turbine building to provide
protection against impact from sheet metal siding and any tools that were
used in the installation process.
Men were to be hoisted by a hydraulic manlift that in some instances would
be over the top of the transformer; however, the liftboom would lock up
upon loss of power.
An electrical safety person was on the job site watching for any problems
.that could endanger the men or the transformer.
Wind speed was to be continuously monitored and the job secured if the
wind speed exceeded
25 miles per hour.
The job foreman would contact the shift foreman at the beginning of each
shift to discuss the work for his shift.
Shutdown safety caution signs were posted and barricades placed around
the area.
The inspectors considered it a strength for the shift foreman to demand that
procedures
be followed, or properly changed prior to proceeding.
c.
Conclusions
The disposition of AR A0399461 was appropriate to the circumstances,
however,
poor performance was demonstrated
by the licensee in coordinating the safe
progress of the turbine siding installation while there was one offsite power supply
available.
This was exacerbated
by an apparent communications breakdown
between the shift foreman and the siding job foreman.
Ci
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ii. Encnineering
E2
Engineering Support of Facilities and Equipment
E2.1
Review of Facilit
Conformance to UFSAR Descri tions
The recent discovery of a licensee operating a facility in a manner contrary to the
UFSAR description highlighted the need for a special focused review that compared
plant practices, procedures and/or parameters to UFSAR descriptions.
While
performing the inspections discussed
in this report, the inspectors reviewed the
applicable portions of the UFSAR that related to the areas inspected.
The
inspectors verified that the UFSAR was consistent with the observed plant
practices, procedures and/or parameters.
III. Mana ement Meetin s
X1
Exit Meeting Summary
'he
inspectors presented the inspection results to members of licensee management
at the
conclusion of the inspection on August 8, 1996.
The licensee acknowledged the findings
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presented.
The inspectors asked the licensee whether any materials examined during the inspection
should be considered proprietary.
No proprietary information was identified.
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ATTACHMENT1
SUPPLEMENTAL INFORMATION
PARTIALLIST OF PERSONS CONTACTED
Licensee
J. Becker, Operations Director
W. Blunt, Human Performance Engineer
M. D. Brewer, Supervisor, Procedure Services
W. G. Crockett, Manager, Nuclear Quality Systems
T. McKnight, NRC Coordinator, Regulatory Services
D. H. Oatley, Manager, Maintenance
R. P. Powers, Vice President and Plant Manager
INSPECTION PROCEDURE USED
Plant Operations
LIST OF DOCUMENTS REVIEWED
1.
Diablo Canyon Unit 1 TS 3.8.1.2, "A.C. Sources,"
Amendment No. 109.
Temporary Procedure TP TD-9504, "Replacement of Unit 1 Main Transformers and
Placement of Spare Main Transformer to Unit 2 Spare Pad," Revision 0.
Administrative Procedure AD1.1D2, "Review Level "A" Procedure Review, Approval
and Notification of Changes,"
Revision 6.
4.
Calculation No. 5227.5530, pages 29-32, "Transporter," dated February 15, 1996.
5.
Plant Safety Review Committee meeting minutes for August 28, 1995 meeting.
6.
Administrative Procedure AD8.1D1, "Outage Planning and Management," Revision
2.
7.
Administrative Proce'dure OM6.1D7, "Control of Activities Near Plant High Voltage
Lines and Equipment," Revision 0.
8.
AR AO364513, Main Transformer, February 16, 1996.
9.
AR AO364415, Main Transformer, March 7, 1995.
10.
AR AO380048, Administrative System, December 12, 1995.
11.
Work Order C0135135, Replace Unit 1A Main Bank Transformer, August 21, 1995.
J
e
j
12.
Independent Safety Engineering Group Assessment
Report 95-012.DDC, Outage
Safety Planning, Scheduling and Management,
November 28, 1995.
13.
Independent Safety Engineering Group Assessment
Report 95-026.BEW,
Replacement of Unit 1 500 kV Main Transformer Bank, November 15, 1995.
14.
Quality Assurance Assessment
Report 960260002,Main Transformer Bank Move
and Related Security Plan Enacted During 1R7, August 15 through October 3,
1995.
15.
Procedure OP1.DC2, "Verification of Operating Activities," Revision 6
16.
Procedure OP1.DC12, "Conduct of Routine Operations," Revision 3
17.
Procedure OP1.DC19, "Plant Status Controls," Revision 3
18.
Procedure OP2.ID1, "DCPP Clearance Process,"
Revision 5
19.
AR A0399461, Procedure Question, April 17, 1996
20.
AR A0391742, Ground Buggy Controls, January 25, 1996
21.
Procedure ADB.DC51, "Outage Safety Management Control of Offsite Power
Supplies to Vital Buses," Revision 5
22.
Procedure AD2.ID1, "Procedure Use and Adherence," Revision 4
23.
Procedure OP1.DC10, "General Authorities and Responsibilities of Operating Shift
Personnel,"
Revision 2
24.
Program Directive OM1, "Organization," Revision 2A
I
25.
Clearance Coordinator Instruction on Grounding Devices, Revision 3
26.
Procedure
MP E-57.11B, "Installing and Removing Grounds from Deenergized Power
Plant Electrical Equipment," Revision 13
LIST OF'ITEMS OPENED
50-275, 323/9601 9-01
Failure to document delegation of shift foreman's
authority (Section 01.2)
50-275, 323/9601 9-01
Failure to follow ground buggy procedures
(Section 08.2)
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LIST OF ACRONYMS USED
Icv
LER
TS
1R7
2R7
Action Request
kilovolt
Licensee Event Report
Technical Specification
Updated Final Safety Analysis Report
Unit 1, Refueling Outage 7
Unit 2, Refueling Outage
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