IR 05000397/1990027
| ML17286A520 | |
| Person / Time | |
|---|---|
| Site: | Columbia  |
| Issue date: | 11/30/1990 |
| From: | Huey F NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V) |
| To: | |
| Shared Package | |
| ML17286A519 | List: |
| References | |
| 50-397-90-27, NUDOCS 9012210171 | |
| Download: ML17286A520 (19) | |
Text
U.
S.
NUCLEAR REGULATORY COMMISSION Repor t No.:
50-397/90-27 Docket No.:
50-397
REGION V
Licensee:
Washington Public Power Supply System P.
0.
Box 968 Richland, MA 99352 Facility Name:
Mashington Nuclear Project No.
2 (WNP-2)
Inspection at:
WNP-2 Site near Richland, Mashington Inspection Conducted:
October 29 through November 15, 1990 Inspectors:
D.
L. Gamberoni, Reactor Inspector M. J.
Wagner, Reactor Inspector Approved by:
uey, gineering Section e
ne
~Summar:
Ins ection Durin the Period of October 29 throu h November
1990 Re ort o.
Areas Ins ected:
An unannounced routine inspection by two regional based inspectors o
icensee action on previous inspection findings, inservice inspection, and an evaluation of the licensee s root cause analysis program.
Inspection Procedures 30703, 35702, 73753 and 92701 were used as guidance during this inspection.
Results:
General Conclusions on Stren ths and Weaknesses Areas of Stren ths:
A dedicated, independent, root cause analysis group that are actively involved in the identification of root causes to plant problems.
Strong management support of the root cause analysis program.
Areas of Weaknesses:
Lack of supportive documentation for root cause determinations.
NRC inspection report followup information is not being utilized when performing actions to address previously identified NRC inspection items.
90i22i0i7i 90i205 PDR ADOCK 0 000397
I
l'
I'
'-2-Si nificant Safet Matters:
None Summar of Violations and Deviations:
None 0 en Items Summar No new items were opened.
Two enforcement items, one followup item, and one Licensee Event Report (LER) were close tI f
DETAILS 1.
Persons Contacted AJ kJ
- J AG
- 0
- 0 J.
D.
T.
L.
L.
p.
K.
J.
S.
Baker, Plant Manager Peters, Administrative Manager Harmon, Maintenance Manager Gelhaus, Plant Technical, Assistant Manager Pisarcik, Health Physics Supervisor Schuman, Operating Experience Assessment (OEA) Engineer Rhoads, OEA Manager Kidder, OEA Manager Ahon, OEA Engineer Grumme, Nuclear Safety Assurance Manager Harrold, Assistant Plant Manager Macbeth, Acting Manager, Nuclear Systems and Analysis Pisarcik, Generation Aide III Stacks, System Engineer Kirkendall, Generation Engineering Supervisor
,
The inspectors also interviewed other licensee employees during the course of the inspection including quality assurance and plant files personnel.
- Denotes those attending the Exit Meeting on November 9, 1990.
Previousl Identified NRC Ins ection Items 92701 a.
(Closed)
Enforcement Item No. 50-397/86-12-02:
Limitor ue 0 erator u>
men ua
>ca son This enforcement item concerned the Supply System's failure to document equipment qualification of Limitorque motor operators and containment cooling fan motors important to safety.
The qualification was not performed prior to the 10 CFR 50,49 deadline of November 30, 1985.
Specific items of concern were:
(1)
Twenty seven Limitorque motor operators inside the containment and steam tunnel; some without T-drains installed, some with taped splices applied to the motor leads, and some with both of these deficient conditions.
(2)
Nine fan motors inside the containment with taped splices applied to the motor leads.
The licensee response identified the reason for the violation as personnel failure to implement select directives during plant construction.
Based on the belief that these directives had been accomplished, the discrepancies were not identified until 1986 during the performance of the Supply System Integrated Limitorque qualification Progra The following corrective actions were performed during the'.Spring 1986 refueling outage:,
(1)
Replacement of questionable splices with qualifieg configurations.
(2)
Installation of T-drains where appropriate.
(3)
Detailed walkdowns to confirm that there were no additional deficiencies.
NRC Inspection Report 50-397/89-23 discussed these corrective actions.
The Integrated Limitorque qualification Program appears to have adequately addressed the equipment qualification problem.
Motor operated valves will be addressed in a subsequent followup inspection for Generic Letter 89-10.
This item is closed.
(Closed)
Enforcement Item No. 50-397/89-06-09:
Inade uate lca ion 0
"
.
rovlslons 1n or nstruc lons This enforcement item concerned the lack of step-by-step instructions of work activities to be performed when implementing Maintenance Work Requests (MWR's).
Licensee corrective actions included issuinq a revision to Plant Procedures Manual (PPM) 1.3.7, "Administrative Procedures, Conduct of Operations, Maintenance Work Request",
dated July 31, 1990.
This revision requires MWR instructions to contain step-by-step instructions with blocks in the right hand margin for the performer's initials.
The inspector reviewed MWR's AR0385, AR0678, AR0709, AR0733, AR0765, AR0842, AR1033, AR1052, AR1055, AR1190, and AR1196.
No deviations from PPM 1.3.7 were noted.
These MWR's covered a sampling of electrical, instrumentation and co'ntrol, and maintenance work areas during the period from August 1990 through October 1990. It appears that all shops have implemented the new requirements satisfactorily.
NRC Inspection Report 50-397/90-11 discussed additional corrective actions.
This item is closed.
(Closed Followu Item No. 50-397/89-06-15:
Standb Li uid Control ressure e
>e a ves e
o>n ri This followup item concerned a problem with setpoint drift on SLC relief valves, SLC-RV-29A and SLC-RV-29 ~
)l I
,t
In a Supply System memo (J.A. Stacks to S. L.
Scammon, dated. July 24, 1989) the author identified a poor surveillance test procedure for the SLC system pump as the root cause for the relief valve setpoint drift.
The licensee modified the surveillance test procedure to allow a higher test tank level during recirculation.
This minimized the final water temperature which was increasing as a result of pump heat.
This also minimized the pressure modulat)ons experienced by the relief valves'uring the surveillance test.
In reviewing the relief valve data, the inspector noted an incorrect setting of SLC-RV-29B which resulted in the SLC system pump being inoperable for longer than the seven-day period allowed by Technical Specification requirement 3. 1.5.a. l.
This occurred from January 26, 1988 to February 4, 1988.
Further investigation revealed that the licensee also identified this problem (LER 88-04)
and has taken appropriate actions to prevent it from reoccurring.
The inspector reviewed the latest relief valve bench test data and found it to be well within the technical specification range of 1400 to 1540 psi.
The-system engineer is continuing to monitor this issue.
This item is closed.
Closed)
LER 89-26:
Potential Failure of Fire Penetration Seals in t e team unne This item concerned the potential failure of fire penetration seals in the steam-tunnel following a postulated design basis steamline break.
Eleven penetrations required modification to resist the postulated design basis pressures.
All were modified prior to plant restart (July 2, 1989) from the refueling outage.
Further licensee corrective actions included:
(1)
Notifying the Architect/Engineer of 10 CFR 21 reportability.
This action was completed August 10, 1989 in a letter to Burns and Roe Company.
(2)
Reviewing other areas of the plant with the potential for pressurization to identify and modify penetration seals that do not satisfy the design basis requirements.
This action is in progress; all plant areas have been identified in a matrix, differential pressures between areas have been calculated, and areas of concern have been determined.
Review of differential pressure versus penetration seal design is scheduled for completion Harch 1, 1991 and is being tracked by Supply System Plant Tracking Log (PTL) number 27412.
Based on the actions completed to date and the actions being tracked by the PTL, this item is close e.
I 0 en) Enforcement Item 50-397/89-06-06:
Three Pi e
Su orts ns a
e u
s>
e esl n
o erances This enforcement item dealt with three pipe supports t$at were not installed in accordance with prescribed installation tolerances, nor were the as-installed dimensions resolved with applicable pipe stress calculations.
Inspection Report 50-397/90-11 addressed the corrective actions for the specific problems and did not close this item because the licensee had not addressed generic implications.
The inspector was unable to verify that any further action had taken place on this item.
For example, no additional PTL items/commitments were generated as a result of
Inspection Report
50-397/90-11.
Further investigation revealed that the root cause of the licensee
lack of action was the failure of compliance engineering to use
additional information from NRC followup inspection reports.
In
these
followup reports,
NRC inspectors
addressed
previously opened
items, but did not close
them because
the corrective actions
were
incomplete.
Since the licensee is not usinq the reports to take
action on the open items,
inspectors
reviewing open items are
finding it difficult to close
them.
The inspector
reviewed
inspection reports from 1988,
1989,
and 1990
and could not find any
indication that followup inspection information had been
used.
This
appears
to be
a problem with followup inspection information only;
new open items,
new enforcement
items,
and
new LER's are acted
upon
in a timely manner.
This item remains
open pending further inspection of licensee's
actions to address
generic implications.
(0 en
LER 90-06:
CFR 50
A
endix
R Cable Fire'Protection
This item concerned
licensee identification of twelve problem cables
that could prevent
an orderly plant shutdown in the unlikely event
of a Design Basis Fire.
A plant modification will be implemented during an outage of
sufficient duration to correct these deficiencies.
The inspector
understands
that this will likely be during the 1991 refueling
outage.
Currently, the problem cables
are
on an hourly fire watch.
The inspector verified this by reviewing the "Fire Tour Log" sheets.
Due to the safety significance of this item, it will remain open
until the plant modification is complete
and reviewed during a
future inspection.
No violations or deviations
were identified in the areas
reviewed.
3.
Root Cause
Anal sis
(RCA) Pro
ram (35702)
The licensee's
RCA program was reviewed
and evaluated for effectiveness
in identifying and correcting
causes
of plant events
and problem II
H
I
hi
I
l
~PAA
The licensee's
formal
RCA program was established
in December
1988
with implementation
as of January
1989.
The top tier documents that
establish
the requirements
and responsibilities pertaining to plant
problems are addressed
in the following Nuclear Operation Standards
(NOS):
NOS-8, "Nuclear Safety Assurance
(NSA) Assessment
Program";
NOS-14, "Operating Experience
Review"; and NOS-30, "Control of
Nonconformances
and Corrective Action."
These-standards
have been,
as
a minimum, concurred with by the Director, Licensing and
Assurance
and the Assistant
Managing Director for Operations;
approval
was by the Managing Director.
Implementation of these
standards
are described
1n the following sub-tier procedures:
PPM No. 1.3. 12, "Plant Problems - Problem Evaluation Request"
PPM No. 1.3. 15, "Plant Problems - Plant Problem Reports"
PPM No. 1.3.48,
"Root Cause Analysis"
Nuclear Safety Assurance
(NSA) No. 01,
"NSA Program Organization
and
Administration"
NSA-02,
"NSA Program Indoctrination and Training"
NSA-04,
"NSA Evaluation of Internal Operating Experience"
NSA-05, "External Operating Experience
Review Process"
NSA-06,
"NSA Technical
Assessment
Process"
These procedures
allow anyone
knowledgeable of an existing or
potential plant problem to document their concern
on a Problem
Evaluation Request
(PER) form.
PERs are brought to the attention of
the Plant Manager
during the daily Management
Review Committee
(MRC)
meeting.
The problem is reviewed by the
MRC and dispositioned
as
a
nonconformance,
a material deficiency,
a plant deficiency, or other
resolution
method
as designated
by the Plant Manager.
A root cause
analysis is required to be performed
on a Nonconformance
Report
(NCR), Material Deficiency Report
(MDR) or a Plant Deficiency Report
(PDR).
The Operating
Experience
Assessment
(OEA) Department is the
dedicated
RCA group.
The Management
Review Committee
(MRC) is
currently assigning approximately
70 percent of the
RCAs to OEA; the
remaining are assigned
to other organizations
possessing
specific
expertise
required to resolve the problem.
However, all
RCAs are
required to be reviewed by the Technical
Review Committee
(TRC) of
which OEA is a voting member; this results in a 100 percent
review
of RCAs by OEA.
OEA appears
to be adequately
staffed at this time to implement the
RCA program.
Staffinq consists of four engineers
dedicated to
related to investigat)on of in-house
(MNP-2) events
and conditions,
and five engineers
dedicated
to the review and handling of external
nuclear industry events.
Dversiqht
The licensee's
RCA program is structured
so that management
has
a
direct role in the resolution of plant problems.
The Plant Manager
is chairman of the
MRC, whose function is to provide initial
assessment
and the method to disposition the plant problem.
After
the
RCA is performed, to determine
the corrective actions
the
chairman
convenes
the
NRC for review of each
(NCR/NDR/PDR) package.
The Plant Manager's
approval is obtained prior to implementation of
the corrective action plan.
As previously stated,
OEA is dedicated to performing
RCAs, but not
all dispositions
requirinq an
RCA are performed by OEA.
About 32K
of plant problems
are assigned,
by the
MRC, to other organizations
having expertise
more germane to the event.
OEA's role in the
review of RCAs helps to provide an overall consistency
in the
product.
Regarding
management
oversight,
the licensee
obtained the services
of two consultants
to provide an independent
technical
assessment
on
the effectiveness
of the
RCA product.
The consultant's
report of
April 1990 concluded that the
RCA program was
good and provided
recommendations
for improvement.
Trainin
Re uirements
RCA training requirements
are addressed
in
PPM No. 1.3.48 which
includes,
but is not limited to, Management
and Oversight Risk Tree
(MORT) methodology, fault tree analys>s,
barrier analysis
and,
event
and causal
factors methodology.
The
OEA event assessment
engineers
are trained in these
techniques
and on one occasion this year
provided two individuals as instructors for a joint RCA training
program with the Department of Energy.
All personnel
performing
RCAs are required to meet minimum training
requirements
depending
upon the level of RCA.
For example,
a
Category
RCA, the lowest level, requires
"Basic Root Cause
Determination Training" whereas
the highest level, Category
1 RCA,
requires
more advanced training such
as
a
MORT course.
Root Cause - Events/Year
According to the Licensing and Assurance
Annual Report for Fiscal
Year 1990,
issued
August 1990, the
number of plant problems
(NCRs,
PDRs,
MDRs) opened
has
decreased
steadily. from 662 in 1988, to 212
in 1989,
and
74 through second quarter
1990.
A formal
RCA is
required for an
NCR,
MDR or PDR.
Other plant problems dispositioned
by lower tiered documents
may also generate
a
RCA if management
chooses
based
on trends
such
as increased
equipment failure rate i
f
Pro
ram
Im lementation
The
OEA monthly report for September
1990 listed thirty-five RCAs as
being in progress;
five of the six investigations
closed during the
month were from the backlog.
The backlog of RCA corrective actions
has
been
a major area of management
concern.
Quality Assurance
Surveillance
Report
No. 2-90-032 addressed
the backlog issue
as
a
program weakness
which resulted in a management
commitment to
establish
a goal for reducing the backlog.
The Management
Commitment Tracking System interoffice memorandum of October 5, 1990
reports that plant management
has established
a backlog reduction
goal.
The inspector's.review of current problem reports
revealed
that the
NCR/PDR backlog is trending down; the
HDR backlog however,
is trending upward.
One of OEA s event assessment
initiatives for
fiscal year (FY) 1991 is to continue their,"effort to reduce the
backlog through prioritization and affective utilization of
resources.
The licensee's
success
in accomplishing their goals will
be evaluated
during a future inspection.
Another
OEA initiative is to reduce the time to perform a
RCA and
define corrective actions
from an average of 210 days to within an
average of 90 days for FY91.
This effort also includes completion
of all FY89 and
FY90 problem report root cause
evaluations
by
January
1, 1991.
Current procedural
requirements for MDRs and
are for QA closeout within 90 days.
However,
NCR close out is
dependent
upon corrective action completion which normally is over
90 days.
Disposition of NCRs is required within 14 days,
MORs and
PDRs within 30 days; corrective actions are to be approved within 30
days for NCRs and
60 days for MDRs and
PDRs.
The following Plant Problem Reports
(NCRs,
MDRs,
PDRs) were reviewed
by the inspector for procedural
compliance
and adequacy of the
associated
root cause analysis:
NCR289-0065,
NCR289-0179,
NCR289-0181,
MDR289-0054,
MDR289-0166,
MDR289-0284,
HDR289-0026,
HDR289-0258,
HDR289-0108,
MDR290-0014,
PDR289-0004,
PDR289-0020,
PDR289-0075,
PDR289-0579
and
PDR290-519.
The root cause
determination for these plant problems
ranged from "inadequate
procedures"
to "unknown".
The root cause
analyses
appeared
to
provide adequate
corrective actions to prevent recurrence.
The inspector,
noted that the resolution to a number of plant
problems failed to provide any supportive documentation for the root
cause
determination.
This weakness
in the
RCA program was also
recognized
by the licensee
which resulted in Revision
2 to
PPM No.
1.3.4. 8 on August 30, 1990.
Attachment
B to
PPH No. 1.3.48
now
requires the
RCA summary to "List and attach all supportive
information and evidence
used to arrive at the conclusions
and root
causes
of the problem."
A sampling of recent
RCAs indicated that
this corrective action was effective; however,
a future
NRC
inspection will determine whether all responsible
organizations
are
complying with this requirement.
In reviewing NCR289-0179 it was found that the Justification for
Continued Operation
(JCO) was not included in the documentation
as
required
by procedure.
NCR289-0179 addressed
the.failure to follow
Regulatory Guide 1.3 while performing calculation NE-02-88-27
on
control
room habitability.
The licensee's
explanation for not
having a JCO for this
NCR is provided in an Interoffice Memorandum
(IOMSS2-PE-90-1099)
dated
November 15,
1990.
The conclusion
was
that since
WNP-2 was operating
under
a Technical Specification
action statement
during this time,
no JCO beyond the Immediate
Disposition provided with NCR289-0179
was necessary.
This
IOM was
placed in the subject
NCR file for future reference;
this action
closes
out any concerns
regarding the necessity
to.have generated
a
JCO for NCR289-0179.
f.
~Tr endin
OEA is responsible for RCA trending of data provided
on the Trend
Coding Report which is included in the
RCA report.
The most recent
conclusions
from RCA trending are addressed
in the "Licensing and
Assurance
Annual Report for Fiscal
Year 1990," dated August 1990.
Section 4.7 of the Annual Report provides
a summary of problems
resulting from the generation of an
NCR,
MDR or PDR, all of which
require
a formal
RCA.
The Annual Report states that the total
number of plant problems
has decreased
because
of the
PER process,
and that equipment problems
were the most frequently reported
problem over the past
5 quarters.
Information on plant problems is
also provided in the Plant Problem Report Weekly Summary
and the
OEA
Department's
monthly report.
The latter addressed
such topics
as
RCA activities and backlog action items.
No violations or deviations
were identified in the areas
reviewed.
4.
Inservice Ins ection (73753
The licensee's
investigation into the high pressure
core spray system
(HPCS) drain line crack was reviewed by the inspector.
A small crack in
a
HPCS three-quarter
inch diameter drain line was discovered
during
routine nondestructive testing.
An unusual
event
was declared
and the
plant was shut
down to determine the cause of the crack and to repair the
problem.
The engineering investigation included
an examination of the pipe crack
surface performed
by Battelle-Northwest with the scanning electron
microscope.
This effort concluded that
a pre-existing defect initiated
the failure mechanism of high load,
low cycle fatigue.
To support this
conclusion tests
were performed utilizing placement of accelerometers
on
the surrounding
equipment to identify the source of the cyclic loads
which caused
the crack.
The results
revealed that
HPCS valves could
produce
enough force, during an injection full flow test, to cause
a
pre-existing crack to propagate.
The inspector
reviewed the original field welding records
associated
with
fabrication of the cracked drain line to verify that the minimum gap was
maintained during fit-up of the socket weld.
An improperly gapped joint
could cause
weld cracking
due to contraction.
The equality Control
Inspection
Record indicated that the required
gap was verified prior to
welding on July 31, 1982.
The two conditions necessary
to cause
the cracking and liceqsee
actions
to prevent their occurrence
are
as follows:
a.
A pre-existing defect to initiate the failure mechanism.
Fluorescent liquid penetrant testing
was performed
on similar
critical piping locations
on the
HPCS and other
systems
for any
pre-existing cracks;
none were detected.
b.
Rapid actuation of the motor operated
valve with a high differential
pressure
produces
loads capable of propagating
a crack.
These
conditions were proven to exist when surveillance testing the valves
in the injection full flow method.
The air operated testing method
does not produce
these
loads
and will be used in all future testing
. until the drain line is replaced with a new weld design.
Licensee actions taken to resolve this problem were aggressive,
thorough,
and provide assurance
that the problem will not recur under normal
operating conditions.
No violations or deviations
were identified in the areas
reviewed.
5.
Exit Meetin
(30703
The inspectors
met with the licensee
management
representatives
denoted
in paragraph
1 on November 9, 1990.
The scope of the inspection
and the
inspector's
findings were discussed
as described in this report.
The
inspection report also includes the inspector's
review of information
received in Region
V on November 15, 199