ML18150A198
| ML18150A198 | |
| Person / Time | |
|---|---|
| Site: | Surry  |
| Issue date: | 06/12/1987 |
| From: | Belisle G, Russell Gibbs, Moore L, Runyan M, Wright R NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML18150A195 | List: |
| References | |
| 50-280-87-06, 50-280-87-6, 50-281-87-06, 50-281-87-6, NUDOCS 8706300886 | |
| Download: ML18150A198 (30) | |
See also: IR 05000280/1987006
Text
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UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTA STREET, N.W.
ATLANTA, GEORGIA 30323
Report Nos.:
50-280/87-06 and 50-281/87-06
Licensee:
Virginia Electric and Power Company
Richmond, VA
23261
Docket Nos.:
50-280 and 50-281
Liceri~; Nos.: DPR-32 and DPR-37
Facility Name:
Surry 1 and 2
Inspection Conducted:
March 23-27 and April 6-10, 1987
Inspectors:
.~v~At:\\.-:-
M. * F. Runyan
{u14 .~,ft
R.
'. G"bbs
rd. t2 Wc?/'1f._
. Moore
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Assurance Department.
It is the total sum of all efforts to achieve
quality results.
This was a performance-based rather than compliance-based inspection.
Instead of verifying compliance to programmatic requirements, the prin-
cipal effort was to determine whether the results that the Quality
Assurance program were designed to accomplish were actually achieved.
The inspector reviewed trending indicators tracked by various groups and
any other information deemed pertinent to the overall evaluation of
quality performance.
In addition, a detailed review of ~ocumentation and
observation of activities in progress was conducted where applicable.
The inspection effort was divided into the following areas:
Operations and Surveillance
Design Control
Maintenance and Procurement
Quality Assurance Department
Each area is addressed separately in this report.
Included in this
assessment is an evaluation of licensee actions to correct situations
where performance has not met stated goa 1 s or where trends have been
adverse.
a.
Opera ti ans and Survei 11 ance
Quality assurance assessment of the operations functional area was
based on plant performance as reflected by management trending
indicators, improvement in previous SALP ratings, and effectiveness
of plant problem identification and correction processes.
The
following operations related management indicators were reviewed:
Forced outage rate
Safety system actuation
Emergency generators (starts, failures to start)
Indicator trends were identified based on 1986 li~ensee performance
relative to previous performance in 1985.
Forced outage rate
reflects the inability of a unit to-operate when required for service
due to forced outages, thereby indicating the effectiveness of the
licensee to identify and correct problems at a; stage before major
corrective actions are mandated.
The industry average for 1986 was
projected to be 17.4 percent.
Surry Unit 1 was at less than 5
percent forced outage and Unit 2 at less than 15 percent.
A major
factor contributing to Unit 2 outage was the feed system piping
rupture which occurred late in* 1986.
With the exception of the
Unit 2 pipe rupture outage, the 1985 and 1986 forced outages for
Surry were approximately constant, although the industry average
increased by 5.5 percent.
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The unplanned reactor trips (while critical) indicator provides a
measure of the effectiveness of licensee training programs,* opera-
ti on s and maintenance procedures, and corrective action programs.
The annual goal established by the licensee for 1986 was 2 trips per
unit and the industry average was 4.3 trips per unit.
Unit 1 and
Unit 2 experienced two and three trips respectively in 1986, as
compared to seven and one trips for 1985. It was noted that the goal
for 1985 was three trips per unit which reflected the licensee's
effort to improve operations by attempting to achieve increasingly
ambitious goals.
Unplanned safety system actuations is also a broad scope indicator of
plant performance.
This indicator identifies unplanned actuation of
High Head Safety Injection, Low Head Safety Injection, and Cold Leg
Accumulator discharge which occurs when an actuation setpoi nt is
reached or a spurious or inadvertent actuation signal is generated.
This indicator also includes the start and load of an emergency
diesel due to an actual degraded bus voltage.
The licensee goal was
zero actuations per unit and the industry 1986 average was 1.3
actuations per unit. The licensee did not meet the established goals
in this area, nor the industry* average.
Unit 1 received three
actuations and Unit 2 received one actuation.
The actuations of
Unit 1 were caused by inadequate design change procedures (LERs 86-
014 and 86-018) and by maintenance personnel error (LER 86-017). The
Unit 2 actuation was caused by equipment failure due to improper
installation of a component (LER 87-001).
Safety system actuations*
were not trended by licensee management in 1985.
Emergency generator reliability for 1986 was trended by management.
Only one start-failure occurred of approximately 78 start-demands
made on the diesels. This indicator includes start-only demands and
start-and-load demands whether by automatic or manual initiation.
With the exception of safety-system actuations which were not fully
attributable to the operations functional area, the management
trending parameters indicate good performance by the licensee.
Operations performance trends can also be identified in the licensee
Quality Assurance Executive Summary and the previous SALP ratings.
In 1986, the licensee QA findings in operations-related areas such
as; procedures not followed, inadequate procedures, and personnel
errors, have shown a decrease from the first to fourth quarters. The
executive summary additionally identified the major area for con-
tinued management attention as inadequate procedures.
The SALP
rating in this area improved from category 2 to category 1 indicating
that management attention and involvement was aggressive and oriented
toward nuclear safety .
Discussions with operations management and review of activities in
this area demonstrated various factors and programs contributing to
improved
operations performance.
The basic factors for this
improvement were procedure upgrades, training, and
management
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attention in the plant.
Procedure rev1s1ons were performed by
personne 1 who utilize the procegur,es and are familiar with the
evolution and associated systemi.
A full time position was
established to perform the procedure review function.
The
Executive
Summary
for
1986
reported that
adverse
findings
identified by the licensee's QA Department which related to
inadequate procedures, decreased from 20 in 1985 to 13 in 1986. The
executive summary highlights this area for .continued elevated
management
attention
in
1987.
Training,
both licensed and
non-licensed, appeared to be a contributing factor to effective
operations
performance.
The
training program
received
accreditation in November 1985. Maintenance personnel received basic
systems training which provided some awareness of plant operating
conditions and some degree of knowledge as to the impact of mainte-
nance activities on plant operations. Operations events occurring as
a result of operations and maintenance personnel errors have
decreased from 1985 to 1986.
For example, the number of licensee QA
findings attributable to personnel error has decreased from six to
two for these years, respectively.
Management attention in the plant appeared to be a positive contri-
butor to plant performance. Management focused attention directly by
management plant tours or indirectly through a QA inspector-at-large.
The NRC inspector reviewed the QA IOD program and accompanied the
licensee inspector on a plant tour.
The IOD surveillance consisted
of direct observation of activities, discussions with plant
personne 1, review of facility records to obtain information con-
cerning plant status, and general overview of ongoing activities in
the plant.
A checklist was utilized and a trending system had been
developed to identify recurring problems.
This program provided a
useful tool in identifying potential problems in the plant and
reinforced personne 1 adherence to admi ni strati ve contro 1 s during
plant activities. Additional contributors to operational performance
was effective root cause analysis within the post trip review process
and HPES actions such as clear labeling of equipment and systems with
respect to train and unit identification.
Several factors have
contributed
to
the
improvement
and
quality
of
operational
performance, the broad scope of which was to establish a heightened
awareness and sensitivity of all plant personnel on the impact of
their individual activities on plant performance.
Administrative controls and performance of TS surveillance activities
provide verification of the reliability of safety-related systems
and components.
Based on reviews of periodic test procedures,
documentation of previous tests, and observation of test perfor-
mances, the licensee surveillance program appeared adequate in
providing this verification.
The inspector reviewed the following
periodic test procedures to determine if procedures met the intent of
the associated TS requirements, were current, and had received the
required periodic review:
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2-PT-2.8
2-PT-18. 7
2-PT-2.5
2...;PT-17.2
2-PT-15.18
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Turbine First Stage Pressure, November 4, 1986
Charging Pump Operability and Performance Test,
February 11, 1986
Steam Generator Level, August 21, 1986
Containment Spray Inside Recirculation Pumps,
January 23, 1986
Motor Ori ven Auxiliary Feed Pump February 18,
1987
These procedures appeared to contain adequate detail and acceptance
criteria to meet the requirements of the associated TS.
No
deficiencies were identified. Test documentation for the previous 13
months was reviewed for completeness, timeliness, deviations, review
cycle, and retrievability.
The following periodic tests were
reviewed:
2-PT-2.5
2-PT-17.2
1-PT-17.1
1-PT-17.3
Steam Generator Level
Containment Inside Recirculation Spray Pumps
Containment Spray System
Containment Outside Recirculation Spray Pumps
All tests were adequately documented and performed in accordance with
specified periods of the surveillance test schedule.
Deviations
associated with specific periodic test performances appeared to be
adequately assessed, reviewed, and documented.
The inspector observed performance of a Steam Generator Level .
Periodic Test, 2-PT-2.5, and a Charging
Pump Operability and
Performance Test, 2-PT-18.7.
The- Shift Supervisor was notified prior
to initiation of test activity and communication was maintained with
the control room throughout the test. The tests were performed in a
professional manner and the procedural
sequence was* followed.
Personnel were knowledgeable of *the procedure and systems/equipment
associated with the test. At the point of a procedural deviation,
the test was stopped and a deviation request was processed as
required by the periodic test administrative procedure. The test was
then completed with the deviation documented and attached to the data
package.
The inspector's review of surveillances encompassed
procedure review, scheduling, and performance.
No adverse find1ngs
were identified, which indicates that management attention in this
area has been effective.
The inspector noted the management initiative to verify a safety-
related system's functional operability.
The licensee performed a
multi~disciplined review/inspection of the Auxiliary Feedwater
System. This SSFI was based on a similar NRC inspection performed at
the Turkey Point Nuclear Station. The inspection was completed late
in 1986 and the findings were entered into the commitment tracking
system.
Corrective action responses from responsible departments
were incomplete at the time of this QA assessment inspection.
The
licensee SSFI findings were generally significant, identifying weak
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areas with respect to design, maintenance, and operation of the
Auxiliary Feedwater System although the system was determined capable
of fulfilling its design function.
Providing the identified findings
are conscientiously- tracked and resolved, the licensee SSFI repre-
sents a* significant contribution from management -attention and
resources towards safety-related system operational confidence.
Based on these reviews, performance in the operations and surveil-
lance areas was assessed as above average.
b.
Design Control and Engineering
The licensee 1 s quality assurance effectiveness in the area of design
control and engineering was assessed through an overview and analysis
of information reflecting recent performance in this area, and an
in-depth review of one recent design change. Other sampling reviews*
were conducted to supplement this inspection effort.
E&C is designated the design authority for the licensee.
E&C is a
corporate department with a percentage of personnel located on site~
led by the Site Engineering Officer. A small portion of engineering
is performed on site; _a greater percentage is accomplished at the
corporate offices.
The licensee also frequently employs architect/
engineers and consul tan ts that are contracted on an ongoing or
j~b-specific basis.
The hired design organizations are responsible
for implementing the design control program as delineated in the
licensee 1s procedures.
The NOD has overall responsibility for the operational and safety ,
elem~nts of the design control program through review of design
outputs to ensure that plant safety and operability are not adversely
affected.
NOD 1 s site-based Design Control Engineer coordinates this
effort.
The. ultimate indicator of the performance achieved by a design
control organization is the frequency and severity of adverse plant
events which are caused by design errors. The inspector reviewed all
plant DRs and LERs since January 1, 1986,. for which the licensee 1 s
analysis concluded that design problems were the root cause:
The
following LERs fell into this classification:
1-86-07; the failure of bolting material in valve flanges was
caused by stress corrosion cracking.
The -bolting material was
installed as part of a valve bolting material design change
issued in 1979.
1-86-11; involving inoperable high-range radiation monitors .
1-86-32; a loss of service water was caused by lost pump suction
due to air in the system. The newly-installed alternate supply
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p1p1ng design did not include provisions for venting the line
prior to placing it in service.
- 1~86-36; missed testing requirements on containment recircula-
tion spray heat exchangers after pressure retaining rubber
gaskets were installed without provision to perform Type B
containment testing.
2-86-14; inside and outside containment sump trip valves had
excessive leakage due to erosion of globe type trip valves.
They were replaced by ball type valves which should prove to be
an improved design.
1-87-01; -PORVs were declared inoperable due to excessive stroke
times caused by undersized air supply lines to the valve
operators.
The air lines will
be replaced with larger
components.
In particular, LERs 1-86-07, 1-86-32, and 1-86-36 reflect avoidable
design change errors. The other LERs, with the exception of 1-86-11,
reflect problems associated with the original plant design.
The
bolting
material
problems described in
LER 1-86-07
suggests
inadequate material specification for the 1979
design change
requiring stud rep 1 acement in borated water systems.
LERs 1-86-32
and 1-86-36 were caused by a design change failure to anticipate
venting and testing requirements, respectively.
Of these two, only
LER 1-86-32 involved a recent design error.
For each LER, corrective
action appeared adequate. The design errors identified by these LERs
were considered neither numerous nor significant enough to suggest a
programmatic breakdown, and mostly pointed to inadequacies in the
original design or design changes incorporated more than five years
ago.
This information supports a conclusion made later in this
section that the design control program has improved since a period
of poor performance several years ago.
The following station DRs, for which design was designated as the
primary cause, were reviewed:
1-86-053
1-86-077*
1-86-083*
1-86-131
1-86-190*
1-86-328*
1-86-381*
1-86-559
1-86-586
1-87-012
1-87-074
1-87-135
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2-86-075*
2-86-259
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This sample involved approximately 60 percent of the DRs initiated
since January 1, 1987, for which design problems were determ,ned to
be the major cause.
The inspector judged the DRs denoted with an
asterisk to involve avoidable design problems.
Some of these DRs
were translated into the LERs discussed previously.
Most of the
others were mi nor in nature, such as inadequate lighting or the
retention of redundant controls.
The DR re*vi ew did not reveal any
major design control problems.
Another performance indicator used during this inspection was the
number and nature of field changes issued against a selected sample
of completed design change packages.
This effort provides informa-
tion concerning the completeness, precision, and attention-to-detail
afforded the original design effort. Although field changes are a
continuation of the design control process, excessive reliance on
them to validate the design effort brings the design organization one
step closer to actual installed errors. Excessive significant field
changes may also suggest the presence of other design errors which
are not recognizable in the field.
Field changes to the following
design change packages were reviewed:
84-34 (Unit 1) Main Steam Safety Valve Position Indication
84-40 (Unit 1) Pressurizer Instrumentation
84-58 (Unit 1) Boric Acid Transfer Piping Replacement
85-29 (Unit 1) Safety Injection System Leakage Monitoring
86-02 (Unit 2) Emergency Bus Undervoltage Relay Replacement
86-05 (Unit 1) PORV Modifications
86-06 (Unit 2) PORV Modifications
A total of 87 field changes were issued with these design packages,
an average of about 11 field changes per package.
The inspector
estimated that 54 of the 87 field changes could have been avoided
with increased management attention to the original design package.
These 54 avoidable field changes were classified in the following
categories:
Inconsistent with another field change
1
Incomplete materials list
5
No tagging instructions
3
Materials not available
3
Drawings incorrect
10
Inadequate modification procedures
12
Scope of DCP too limited
2
Testing matrix not complete
3
Configuration control problems - interference
6
Need support modification
4
Improper QC requirements
3
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Incorrect sign-off responsibility
Incorrect component designation
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The major problems appeared to be drawing errors and inadequate modi-
fication procedures.
Configuration control
problems were also
prevalent and could be indicative of ineffective or incomplete
pre-design system walkdowns.
However, taken as a whole, this field
change analysis did not reflect a design change process programmatic
breakdown; it merely suggested some minor problem areas.
The design change process management control effectiveness is
reflected in the status of back 1 ogged design changes and drawing
updates.
The design modification status is maintained in a five-year
plan that is issued annually.
The inspector reviewed the five-year
plan issued March 5, 1987, and concluded that satisfactory control is
being maintained on the completion of proposed design changes in
accordance with well-conceived priorities. For each design change a
numerical priority is established and dollar amounts are apportioned
for each of the next five years. There was no evidence that design
changes of safety concern were being unduly delayed.
The drawing update system has been upgraded recently and has practi-
cally eliminated previous drawing backlog problems.
Following a
design change package completion, certain drawings must be completed
within 15 or 90 days depending on their safety status. In 1986, out*
of 1081 committed drawings, 1058 met the applicable 15 or 90-day
requirement.
This effort exhibits on drawing update positive control
and commendable management effectiveness.
Closely related to formal design changes are temporary design changes
or temporary modifications, including jumpers.
The inspector
reviewed approximately 90 percent of the 44 outstanding temporary
modifications from a technical and administrative perspective.
All
technical issues were resolved, but some administrative problems were
noted.
In two cases (T~s 2-87-33, 2-87-29) the required engineering
reviews were not performed.
In two other cases (T_Ms 2"'.'-87-25,
2-87-29), the safety evaluation applicability was not assessed.- A
violation was not issued because the above examples did not involve a
compromise in safety, but these examples do point to a lack of
attention to detail. Other problems with the temporary modification
system were i dent ifi ed in a recent QA audit, S86-0l, Operations
Administration, issued February 12, 1987.
The findings of this audit
included the following:
SUADM-0-11, Function Bypass and Temporary Modification Control,
does not provide control_s for temporary modifications installed
for greater than three months.
As a result, required EWRs have
not been written.
SUADM-0-11 makes conflicting statements as to the review dead-
lines for SNSOC.
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The response to the findings included the assurance that SUADM-0-11
would be revised to address the.?e-issues.
The total number of
outstanding temporary modifications has trended downward from about
80 in the middle of 1986 to 44 currently.
In order to assess E&C's ability to identify and correct their own
problems, the inspector reviewed recent CTRs, the primary problem
reporting mechanism for design and modifications. ~CTRs are often a
precursor to design package field changes, an EWR, or new design
change. Their scope ranges from questions to flagrant discrepancies.
The CTRs tracked at the site are assigned to a single responsible
individual with a specific due date.* The inspector reviewed approx-
imately 200 CTRs issued since November 11, 1986.
The oldest out-
standing CTR was issued March 20, 1987, and only about 20 CTRs were
st i 11 open.
Corrective action documentation appeared adequate for
the problems identified.
Overall, the CTR system appears to be an
effective method to identify and correct problems within E&C.
The inspector reviewed ER&SA reports for the following design
changes:
86-06-2
85-30-2
86-12-2
85-11-2
86-01-1
PORV Modifications
Safety Injection Leakage Monitoring
Snubber Leak Before Break Modification
Inadequate Core Cooling System Upgrade
Emergency Bus Undervoltage Relay Replacement
The ER&SA reports address the following items:
statement of problem,
identification of quality classification, proposed resolution, fire
hazards, seismic analysis, EQ concerns, ALARA, NRC concerns, impact
on other design changes, electrical system analysis, human factors
review, inservice inspection, security issues, setpoint review, TS
review, FSAR review, design basis document review, USQD, and safety
and operational implications. This formalized checklist approach to
each design change appears effective in ensuring that major
considerations will not be overlooked.
In each case, the report
appeared well-prepared and well-conceived.
Some of the USQD evalua-
tions, required by 10 CFR 50.59, were perhaps somewhat brief in
explanations of certain conclusions.
USQD evaluations have been a
continuing concern for the licensee and significant progress has been
made over the last several years, based on conversations with the
Supervisor, IDER group (which functions as an NSRB), and comparison
between the review referenced above and the review that was performed
and is documented by NRC Inspection Report Nos. 50-280, 281/86-19.
Nevertheless, the IDER group recognizes that further improvement and
standardization is needed for safety evaluations.
A task team is
forming with the goals of revising the NOD standard by the end of
1987, and developing a company policy on 10 CFR 50.59 evaluations.
This effort, coupled with the observed improving trend, should
resolve this problem area.
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Design Change 85-21-1 documented where plant drawings and the FSAR
were updated to reflect modifications prescribed in design change 73-106, despite the fact that the work was not actually performed.
Therefore, for 13 years the p 1 ant drawings and FSAR showed check
valves, trip valves, and relief valves in CCW .piping that were not
installed.
This situation did point to a potentially serious
configuration control problem.
The licensee had accomplished several
detailed critical system walkdowns in the early .J980s but the CCW *
system was not included.
The problem was not found until a plant
survey identified it in 1985. *Apparently; this unusual scenario was
an isolated incident involving an
unauthorized drawing change
performed during the construction phase, or a mixing of as-designed
with as-built drawings.
There is no evidence that a widespread
configuration control problem exists since any similar occurrences
would have been corrected in the previously mentioned system
walkdowns or plant surveys.
The
inspector
reviewed "Report on
Safety System
Functional
Inspection, Auxiliary Feedwater System, Surry Power Station," dated
November 6, 1986, for issues pertinent to the design control area.
Many programmatic and implementation problems ~ere* discovered from
design changes to the Auxiliary Feedwater System.
Most of the
significant design control problems occurred before 1981 and involved
documentation problems, missing calculations and analyses,* missing
justification for waivers, inadequate post-modification testing, etc.
This review and the current inspection would suggest that the
licensee's design control program experienced .significant problems
around 1981 and before, but since that time, a decided improvement
trend has occurred.
Corrective action on the Auxiliary Feedwater
inspection is still pending and is being tracked on a commitment
matrix which the inspector reviewed.
The second phase of this inspection involved an in-depth review of
one recent design change.
This small-sample approach was chosen to
evaluate each design change process element to a greater depth as
well as to examine continuity between the design control program and
other.related programs (such as special processes and testing).
The inspector reviewed DC-85-30-2, entitled "Safety Injection Leakage
Monitoring/Surry, Unit 2. 11
This design change, installed during the
Fall 1986 refueling outage, entailed the installation of 3/4 inch
leakage monitoring tubing between the two check valves in the six
inch SI piping leading to the RC system cold leg.
This tubing was
installed on each of the three reactor coolant loops of Unit 2.
The
design change was initiated to simplify leakage .testing of the SI
check valves and to reduce radiation exposure of personnel, who were
previously required to disassemble the second check valve to leak
test the first check valve.
The final design specified a 3/4 inch stainless steel pipe connected
by sockolet to the six inch SI pipe.
A 3/4 inch shutoff valve was
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installed close to the six inch header. After the shutoff valve, 3/4
inch tubing was run to the cubicle within containment nearest the RC
pump, and down vertically to elevation of one foot.
At this
location, two 3/4 inch drain valves were installed in series.
To establish the DC's conformity to design base documents, the
inspector reviewed documents referenced in the following sections of
the Surry Units 1 and 2 Design Base Document's, .dated August 15, 1984:
Sl Structural-General
S4
EM3
Pipe Stress Analysis
EMS
Pi~e and Duct Support Analysis
MSl
Applicability of System Description to Design Criteria
MS8
Leak Testing Requirements
MS9
Vents, Drains, and Test Connections
MSlO
General Design Criteria
In particular, the following sections in the FSAR and TS were
reviewed:
4.4
5.5
6.2
15.2.1
15.2.4
15.5.1.4
TS 3.1.*c.7.a
4.2
4.3
Tests and Inspections
Containment Tests and Inspections
Safety Injection System
Structural Design Criteria
Seismic Design
Containment Structures - Dynamic Analysis
Leakage Specifications
Reactor Coolant Computer Inspection
Reactor Coolant System Leak Tests
The base document reviews confirmed that the DCP was consistent in
intent and structure with the design bases and as-configured status
of the plant.
The only required FSAR change was to Figure 6.2-4,
where the safety injection leakage monitoring valves will be shown.
An FSAR Change Notification Form was initiated and attached to the
DCP to accomplish this rgvision.
The inspector studied various aspects of the design input and con-
curred in each case with the licensee analysis.
The quality
classification of the entire DCP was Category I, Quality Group A,
seismic.
The determination was made that materials for the modifi-
cation did not fall in the category of 10 CFR 50.49(b)(2),
environmental qualification; therefore, .electrical systems were not
affected. Precautions included in the design input for fire hazard
consideration and ALARA were included in the final design controlling
procedure (PI-U2):
This procedure appeared to be comprehensive and
complete, addressing all necessary considerations.
Of particular
note was the sign..:.off requirements for a wide spectrum of plant
personnel including HP, AN!, Loss Prevention Engineer, Station Shift
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Supervisor, Station Operations, QC, NOE, Advisory Operations, and
Station Engineering.
This multidiscipline review responsibility
offers a good checks and balances system -to reduce errors.
The
controlled copy of the completed design control procedure was
reviewed and verified to be a complete modification process record.
The procedure was independently reviewed by Engineering to ensure
that each step had been satisfactorily completed.
The
regulatory requirements for independent verification were
apparently met.
This included an overa 11 independent review of the
DCP and independent verification of certain QC hold points in the
controlling procedure.
The
review included the Reviewing
Engineer, Lead Engineer, Design Control Engineer (from NOD), and
SNSOC.
The 10 CFR 50.59 safety evaluation concluded than an unreviewed
safety question did not* exist.
This was based primarily on the
assertion that if the 3/4 inch piping were to fail during unit
operation, an insignificant amount of leakage (within the FSAR
analysis) would result. Since the leakage monitoring line would not
be involved in normal system operations, the design change would not
affect the delivery rate of water to the RC system.
Although the
safety evaluation appeared adequate and justifiable, it was brief and
probably could have expounded more on the particular consequences of
a line break on the 3/4 inch piping.
The inspector performed an in depth review of the eight field changes
made to the DCP.
The field changes generally reflected administra-
tive errors such as incorrect sign-off responsibilities, drawing
errors, or design controlling procedure errors.
Taken as a whole,
this small group of field changes reflected favorably on the
attention to detail and precision afforded the original DCP.
The
inspector verified that the provisions of each field change were
accurately translated to the design controlling procedure or
applicable drawings.
Further, the inspector performed a spot check
of plant drawings identified as requiring revision and verified that
in each case the drawings were appropriately revised.
The inspector reviewed the materials list generated by E&C to procure
material for DC-85-30-2. The materials ordered appeared to meet the
specifications of NUS-20, Class 1502, for the stainless steel piping
and shutoff valve, and NUS-9115, Class I-C~N9, for the downstream
tubing, as specified in the design input. All vendors specified were
included on the safety-related vendors list with.the exception of the
anchor bolts manufacturer.
This procurement was justified by a CQE
written by E&C.
The inspector reviewed a sample of purchase orders,
receipt inspection reports, certificates of compliance, discrepant
shipment reports, and maintenance trouble reports which were filed
with the DCP.
This documentation was consistent and supported the
materials list specifications. In particular, the original materials
list stated that all valves would be hydrostatically tested after
/
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16
receipt but was later revised to require the manufacturer to provide
certificates of conformance stating that the valves were tested to
specification MSS-SP-61.
Each valve was verified to have a certifi-
cate of conformance stating that testing to this specification was
performed.
The inspector reviewed weld testing requirements per ASME XI, Table
IWB-2500-1, and determined that the surface inspection performed was
the proper testing method.
Weld maps and inspection records were
consistent and complete.
The inspector also reviewed hydrostatic
test records for each of the three lines. A discrepancy was noted i*n
the testing for the 3/4 inch branch connection to the 6 inch SI line.
The re qui red test pressure was 2335 psi g but the . hydrostatic test
record for each of the three branch connections stated that the line
was pressurized to only 2235 psig.
The licensee was able to
demonstrate that the test was actually performed at the required
2335 psig.
The test was performed during PT-11, RC Pressure Test,
performance which established RC pressure at 2335 psig, 100 psig
above normal operating pressure. The charging pump was turned on to
perform the SI hydrostatic test. There is no pressure gauge in the
SI line so the operators had to verify flow, which implies that
pressure in the SI line had to be at least 2335 psig.
The licensee
stated that documentation would be added to the test package
explaining the error.
The jnspector verified that Periodic Test Procedure 2-PT-18.11, SI
Check Valve Leakage -
Primary Coolant System Pressure Isolation_
Valves, was revised to reflect the new method of leak testing the SI
The overall assessment of the design control program and engineering.
is that QA effectiveness is above average. Clearly much improvement
has occurred in this area over the last several years.
Current
problems are mostly caused by lack of attention to detail as opposed
to generic or programmatic issues.
c.
Procurement Quality Assurance and Maintenance
( 1)
Procurement
Qua 1 i ty Assurance
The .Procurement Qua 1 i ty
Assurance area was inspected to eniure*that**the licensee is in
compliance with applicable NRC.requirements and licensee commit-
ments.
Additionally, the area was reviewed to determine if
adequate actions are being taken with ~endors to prevent defec-
tive material from being received on site *at Surry and North
Anna which minimizes the possibility of material being installed
in safety-related systems. The inspection included a review of:
The Virginia Power Safety-Related Vendors list, vendor audit
scheduling and schedule adherence, and a vendor audit and the
associated audit deficiency corrective action follow-up.
The
inspection also included a discussion of the use of site receipt
inspection deficiencies to influence the vendor evaluation
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17
process.
The inspector determined that the licensee was in
compliance
with
applicable
requirements and
commitments.
However, a program weakness was noted concerning the use of
receipt inspection data to influence the vendor selection and
control process. Neither the QA Engineering and Vendor Division
in Richmond nor the site QA organization have a system to
formally track vendor performance as a result of site receipt
inspections.
Data, such as an overall rejection rate for each
vendor, and details concerning the kinds of deficiencies being
encountered with each vendor, is not readily available.
Therefore, this data is not being utilized to accomp 1 i sh the
following actions which are considered to be an integral part of
an effective vendor evaluation program:
(a)
Receipt inspection data .is not used in establishing the
Virginia Power Safety-Related Vendors list.* The list is
established based on vendor audits which primarily deter-
mine if the vendor has an approved QA program meeting the
requirements of 10 CFR 50, Appendix B.
(b)
The data is not used to influence vendor audit scope or
in-process inspection by the licensee or co-ntract personnel
at the vendor's facility.
(c)
The data is not used to change purchase order requirements
to require specific vendor verification of acceptability of
attributes found to be previously deficient.
(d)
No action is taken to adjust site receipt inspection
requirements considering the vendor which is supplying the
materials.
(e)
No action is taken to formally advise vendors of rejects
and to request specific vendor corrective actions to
prevent recurrence of the deficiency.
The overall evaluation concluded that the licensee's vendor
evaluation program is average.
(2)
Maintenance - This QA assessment included a detailed review of
the maintenance area. This review was to determine maintenance
program status, review initiatives being taken to improve the
program, and determine the ability of the 1 i cen see to identify
their own problems and take adequate corrective action in
resolving those problems.
The inspection was conducted through
interviews with personnel, observation of a maintenance activity
in progress, and a review of completed maintenance work orders
and their associated maintenance procedures. The detailed scope
of this part of the assessment and conclusions reached are as
follows:
-
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18
(a)
Management Initiatives and Program Controls
Scheduling of mai ntenan*ce work by
the
WPTS
Computer
Planning System, although a relatively new system, *is
rapidly becoming a very va 1 uab 1 e management too 1 for
planning and control of maintenance.
The
system is
currently being used to generate a daily work p 1 an* (The
Plan of the Day), a ten day work schedule, and will also be
used
in
long
range maintenance and refueling outage
planning.
The*system has the capability of sorting an
entire maintenance work package in many different ways
which provides management practically any information they
may require concerning a particular package.
During the entrance meeting for this inspection, licensee
personnel gave a presentation to the inspection team which
included brief discussions of several management programs/
initiatives which are being undertaken to improve overall
performance.
The programs/i nit i at i ves which affect the
maintenance area were investigated in greater detail by the
inspector while on site.
One of these programs, Predictive
Analysis, is aimed at detecting and correcting component
failures before they actually occur.
The program consists
of three techniques/tests for arriving at the stated
purpose of the program:
Vibration analysis, oil analysis,
and motor operated valve testing (MOVATS).
Vibration
analysis is used on rotating equipment to predict bearing
failures,
component misalignments,
etc.
Oil
analysis
emp 1 oys the use of a private contractor to analyze oil
samples for foreign particulate matter.
The particulate
concentrations are tracked and trended to predict internal
component failures.
MOVATS is used to predict failures in
motor operated va 1 ves.
There is an addi ti ona 1 testing/
analysis technique to predict check valve failure.
The
licensee is just beginning to utilize this area of predic-
tive analysis.
The maintenance program at Surry now
consists of approximately 90 percent corrective maintenance
and 10 percent preventive maintenance.
The predictive
analysis program discussed above is aimed at changing this
ratio to 50/50 by the end of 1987:
Review of one of the licensee's primary trending indicators
in the maintenance area ( the tota 1 number of work orders
outstanding) concluded that little progress is being made
toward reducing the totals.
At the beginning of 1985,
there were approximately 5000 work orders outstanding.
During the middle of 1985 this
number
dropped
to
approximately 3000.
During 1986, this number stayed about
the same.
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19
Discussion of this area with the maintenance superintendent
led the inspector to the conclusion that a primary reason
for the lack of progress was the large amount of outage
time for both units in 1986.
(b)
Observation of Maintenance in Progress
During the assessment very 1 itt le safety related ma i nte- -
nance was being performed.
However, the inspector was able
to observe a periodic surveillance test and pump packing
adjustment on motor driven auxiliary feed pump 2-FW-P-3B.
This work was accomplished in accordance with site
procedure 2-PT-15.lB and work order number 050818.
The
test/work involved the monthly TS required checks of pump
flow, check of oil levels, oil strainer condition, oil
flow
to the bearings, temperature of the bearings,
recording of the bearing vibration analysis data, and
adjustment of pump packing.
One concern was noted during
the packing adjustment. The work order did not provide any
acceptance criteria for the packing leak rate.
Personnel
were performing the packing adjustment solely based on
their
past
experience.
Otherwise,
personne 1
were
knowledgeable of both the procedural requirements and the
equipment.
(c)
Review of Completed Maintenance Work Packages
The inspection included a detailed review of 12 completed
work order packages.
The rev; ew was conducted to verify
that maintenance of safety-related equipment is being
performed in accordance with technical requirements for the
equipment, and to assure that maintenance activities are
being properly completed and documented.
This review
determined that deficiencies exist in the licensee 1s
maintenance program.
Concerns were
raised
by
the
inspector in 11 out of the 12 work packages reviewed.
Fo 11 ow-up of these concerns with maintenance personnel
resulted in eight examples (Paragraphs 1-8) which were
collectively combined
to constitute a violation of
10 CFR 50, Appendix B, Criterion V, for failure to follow
procedure.
These items are identified as violation 280,
281/87-06-01.
1)
Work Order #45674, Containment Spray Pump Suet ion
Valve Mark #02-CS-MOV-200A,
Maintenance Procedure
- EMP-C-MCC-152
(Corrective
Maintenance
Procedure
for Replacement of Thermal
Overload Devices
in
Safety-Related Motor Control Centers, dated May 8,
e
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20
1986):
Paragraph 6. 3 of the maintenance procedure
required that three phase currents on the valve motor
be recorded while the valve was being cycled in the
open and in the closed direction and compared to the
full load current. Data on these measurements and the
full load current were recorded after maintenance.
Acceptance criteria in paragraph 6.3 stated that the
currents should not exceed the ful 1 1 oad current by
more than 15 percent.
The ful 1 1 oad current was
recorded as
2.1 amps;
consequently,
the maximum
current should not exceed 2.42 amps.
All three phase
currents in the open direction were recorded as
2.8 amps, which exceeded the acceptance criteria, yet
no
corrective action was
taken
concerning
the
out-of-tolerance readings.
2)
Work Order #33856, Safety Injection System Flange
Mark
- Ol-SI-FE-1940:
The
work
order
required
that the subject flange be disassembled, the orifice
in the flange reversed, and the flange reassembled.
This action was accomplished by maintenance personnel
without_ using the approved procedure for flange joint
make-up (MMP-C-G-201, Corrective Maintenance Procedure
for Flanged Joints in General, dated February 3, 1986).
This resulted in the bypassing of site requirements for
alignment of the flange and also the required torque
verification on the flange fasteners.
Additionally,
the flange fasteners were rep 1 aced by maintenance
personnel without authorization of the work order.
3)
Work Order #38498, Safety Injection Accumulator Drain
Valve Mark #Ol-SI-HCV-18528, Maintenance Procedure
MMP-C-G-001
(Corrective Maintenance Procedure for
valves
in
General,
dated
September 26,
1985):
Paragraph 5.5.1.8 of
the
maintenance
procedure
required that the valve be repacked using site Mainte-
nance Procedures MMP-C-G-156 ~r MMP-C-G-156.1 and that
the procedure used be attached to the work order.
This paragraph was marked
11N/N1
by
maintenance
personne 1 without authorization, the va 1 ve was not
repacked, and the applicable procedure was
not
attached to the work order.
4)
Work Order #38401, Charging Pump Reci rcul at ion Line
Isolation Valve Mark #02-CH-MOV-2373,
Maintenance
Procedure #CH-MOV-M/R (Mechani ca 1 Preventive Main-
tenance Procedure for Motor Control Centers, dated
February 28, 1985):
Page 1, Attachment 2, and para-
graph 5 .11 of the procedure* required maintenance
personnel to inspect the valve for packing 1 eakage.
The inspection noted the valve had packing leakage,
yet the
II leakage corrected 11 b 1 ock of the attachment
was annotated that the leakage was not corrected, and
e
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21
additionally paragraph 5.11 for adjustment of packing
if necessary was marked
11 N/A
11 *
5)
Work Order #45674, Containment Spray Pump Suction
Valve Mark #02-CS-MOV-200A,
Maintenance Procedure
- EMP-C-MCC-152 (Corrective Maintenance Procedure for
Replacement of Thermal Overload Devices in Safety-
Related Motor Control Centers, dated May 8, 1986):
6)
Paragraph
3.7 of the maintenance
procedure
in
part, required that the manufacturer, part number,
stock number, or purchase order number for the newly
installed thermal overload heaters be recorded on the
work order and in blanks provided below the paragraph.
This paragraph was initialed as being complete and the
data was not recorded as required.
Work Order #38498, Safety Injection Accumulator Drain
Va 1 ve Mark #Ol-SI-HCV-18528, Maintenance Procedure
MMP-C-G-001
(Corrective Maintenance Procedure for
Valves
in
General,
dated
September 26,
1985):
Paragraph 5.5.2 of the procedure required that
the torque wrench ca 1 i brat ion contra 1 number and
torque values to verify compliance with paragraph
5.5.1.12, be recorded on the Maintenance Inspection
Report, which is attachment ( 6) of the procedure.
This paragraph was initialed as being complete with
the data not having been recorded as required.
7)
Work Order #39354, Charging System Flow Control Valve
8)
Mark
- Ol-CH-FCV-1160,
Maintenance
Procedure
- MMP-C-G-001 (Corrective Maintenance Procedure for
Valves
in
general,
dated
September 26,
1985):
Paragraph 5.5.2 of the procedure required that
the torque wrench calibration control number and
torque values to verify compliance with paragraph
5.5.1.12, be recorded on the Maintenance Inspection
Report, which is attachment (6) of the procedure.
This paragraph was initialed as being complete with
the data not having been recorded as required.
Work Order 35553, Unit 1 Reactor Coolant Pump Mark
- Ol-RC-P-18,
Maintenance
Procedure
MMP-C-RC-009.1
(Corrective Maintenance Procedure for Reactor Coolant
Pump Sea 1 s, dated June 18, 1985):
Severa 1 paragraphs
in the procedure require the reading of dimensions.
Paragraph 4.6 requires that these readings be recorded
on
the Maintenance Inspection Report, which is
attachment (3) of the procedure.
Paragraph 4.6 was
initialed as being complete with the readings not
having been recorded as required.
9)
Severa 1 ex amp 1 es were noted where a procedura 1 step
- should have obviously been marked
11 N/A1 1 , yet this
action was not accomplished:
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22
Examples:
a)
Work Order #47194, Mark #Ol-RH-HSS-22,
Maintenance Procedure #MMP-C-HSS-130,
Paragraphs 5.3 and 5.4
b)
Work Order #39354, Mark
- Ol-CH-FCV-1160, Maintenance Procedures
- MMP-C-G-156, Paragraph 7.2. and
- MMP-C-G-001, Paragraphs 5.5.1.6,
5.5.1.J and 5.5.3.
Of speci a 1 concern is the fact that a 11 of the above
completed work packages received a final review by the
maintenance foreman;
personnel
from
operations,
and
personnel from QA, yet none of these reviews were able to
detect and correct the deficiencies noted.
Six concerns, which originated out of the review of com-
pleted work packages, remained unresolved at the completion
of the assessment. These concerns were discussed in detail
with
licensee management at the exit meeting and
responsible licensee personnel were identified to obtain
resolution.
Prompt attention to these concerns during the
week of April 13, 1987, by 1 icensee personnel, the site
resident inspectors, and the regional inspector obtained
the following resolution to these concerns:
-
1)
Maintenance
procedures
require
the
cognizant
maintenance foreman to determine and record the
required torque values for various system- closure ,
fasteners. The inspector requested that the technical*
source for this information be provided for work
orders 38498, 47484 and 39354.
The source of these
requirements
was
determi~ed to
be
Maintenance
Procedures
MMP-C-G-201,
MMP.;.C-RH-015
and
MMP-C-G-001.2, respectively.
Investigation of this item determined that the
practice of requiring maintenance foremen to determine
torquing requirements by researching vendor manuals,
computer printouts and other maintenance procedures,
is very cumbersome and time consuming for the foremen.
The fact that the requirements are located in many
different references, while not resulting in incorrect
torquing for the three specific examples above, could -
result in the incorrect torque being applied.
Licensee management
should consider centralizing
torquing requirements into one procedure or requiring
maintenance engineering to provide these requirements
to the foremen, as an a 1 tern at i ve to the current
practice. This item is resolved.
- ~ ..... , _\\ ..
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23
2)
The tradesman description of work performed on Work
Order 38401 i ndi ca_ted that he had overhauled the
Limitorque operator of valve Mark #02-CH-MOV-2373.
The work order referenced Maintenance Procedures
CM-MMP-C-MOV-178
and
CH-MDV-MR-PMS.
Procedure
CH-MDV-MR-PMS only authorized preventive maintenance
on the Li mi torque and the record copy of Procedure
CM-MMP-C-MOV-178 could not be located during the
inspection. Subsequent to the inspection the record
copy of Procedure* CM-MMP-C-MOV-178 which authorized
the work was found.
The resident inspector was
provided a copy of the completed procedure. This item
is resolved.
3)
Review of Work Order 38401 raised a concern over
whether the valve operator had been lubricated using
the correct environmentally qualified lubricant. The
note fo 11 owing paragraph 5. 9 of Procedure CH-MOV-
MR-PMS required the use of an incorrect lubricant, and
at the time the inspection was completed, the descrip-
tion of stock #0214701 (which was the lubricant used)
had not been provided to the inspector. Subsequent to
the
inspection the
record
copy
of
Procedure
CM-MMP-C-MOV-178 was found (see item #2 above).
Review of this procedure and information provided
concerning stock #0214701 determined that the correct
lubricant had been used.
Additionally, the error in
the note after* paragraph 5. 9 of Procedure CH-MOV-
MR-PMS has been corrected in the generic procedure for,
preventive maintenance of Limitorque operators.
Thi~
item is resolved.
4)
Review of Work Order 39354 indicated that the valve
packing had been replaced using Garlock packing in
lieu of the Crane packing re qui red by the vendor
drawing.
Subsequent discussion of this item with
maintenance personnel revea 1 ed that a 11 va 1 ves at
Surry are repacked using Garlock packing.
The
inspector ask to see the authorization for this
deviation.
An engineering evaluation in this area
which was performed due to this concern, indicates
that no credit was taken for packing in the original
specifications for maximum stem leakage requirements.
It further states that design stem
leakage is
contra 11 ed in most cases by stem back seats.
The
evaluation also discusses
the. design
operating
characteristics of the packing and the plant.operating
history utilizing this type of packing. Based on this
evaluation, this item is resolved.
- -
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24
Review of the record copy of Work Order 35553 revealed
that the materiat-identification and control tags for
the RC pump sea 1 s- and runners which are used by the
site for material traceability, were missing from* the~
work order package.
Search of records did not produce
these tags.
However, subsequent discussion with site
personnel verified that the correct material was used.
Additionally, these component parts are not subject to
material mixing due to their size and unique configu-
ration.
This item is resolved.
During the review of Work Order 35553, a concern was
ra i sect over the 1 ubri cant and torquing requirements
for the RC pump seal closure fasteners on pump Mark
- 01-RC-P-lB.
The concern was that the fasteners had
been torqued to the same va 1 ues as shown on the
Westinghouse drawing utilizing a different lubricant
(Felpro N5000) in lieu of Neolube as shown on the
drawing.
Subsequent investigation determined that the
different lubricant was authorized by the licensee 1 s
response to I. E.Bulletin 82-02. As a result of the
inspector 1 s concern resolution to the issue of using
the same torque values with a different lubricant was
obtained via telecon
between
the licensee and
Westinghouse and was documented in Virginia Power
Maintenance Engineering memorandum of April 15, 1987.
This item is resolved.
This inspection noted deficiencies in the licensee 1s maintenance
program
concerning
adherence
to
procedures.
Addi ti ona 1
management attention is needed to correct this problem area.
The overall evaluation of the maintenance area is below average.
d.
Quality Assurance Department
The purpose of the inspection was to assess the effectiveness of the
Station Quality Assurance Department to prevent,
identify,
and
correct problems.
To
accomplish this,
the station 1s audit,
surveillance, inspection programs, nonconformance trending programs,
and associated reporting and overview activities were reviewed.
Interviews were conducted with responsible management personnel.
Strengths and weaknesses were identified in all areas. The overall
evaluation of the QA organization 1 s current effectiveness in these
areas was identified as average to good.
( 1) Auditing
The inspector reviewed the licensee 1 s audit schedule for 1986
and the proposed 1987 audit schedule.
In 1986, the SQAD
initiated, but did not complete, their required 17 scheduled
e
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25
Technical Specification audits.
As of January 15, 1987, four of
these audits were still in the administrative review cycle and
two were still in progress. Two of these audits have not been
issued to date. The average time taken to complete most of the
1986 scheduled audits appears excessive considering the audit
group size and experience level of the site auditors . .Excessive
time to complete audits may signify issues that may be hindering
the QA organization. These delays are not a .. good practice in*
that they promote the potential for loss of auditor independ-
ence.
The QA Manager* acknowledged thfs weakness and is placing
more emphasis on meeting schedules without a reduction in audit
quality.
In addition to performing- a cursory review of the scheduled TS
audits and the annual Operational QA Program Effectiveness audit
QA 86-03, a deta i 1 ed i ndepth review was performed on two
recently completed audits, one with findings (S86-08, Corrective
Action, issued October 10, 1986), and one without findings
(S87-03, Technical Specification Compliance, issued April 2,
1987).
These audits were found to be well planned, of suffi-
cient scope and depth to verify compliance with TS and the QA
program, and capable of determining effectiveness of the program
in the areas audited. Interview~ with the responsible auditors
and review. of audit documentation indicated sound auditing
principles were applied, findings identified a relatively
significant
problem
for
management
correction,
timely
appropriate corrective action was instituted, and follow-up
verification assured proper closeout of the findings. The
subject findings were included in the QA trend analysis process.,
Discussions with personnel and examination of the involved
auditor training and certification records indicated they were
qualified to perform audits.
The inspector accompanied auditors in the field performing an
audit-in-progress, Audit Number S87-16, Fire Protection Program.
Emphasis was initially placed on a special portion of this audit
concerning 10 CFR 50, Appendix R requirements.
The audit
preparation,
methodology
employed,* and auditor. expertise
appeared satisfactory for the area being audited. The inspector
observed that the auditors did not blindly follow a checklist
when obvious problems were apparent outside the scope of the
audit.
For example, vendor documentation (which should. have
been in the QA records vault) supporting the acceptability of
Exide batteries and battery racks was discovered in a desk
located in Vital Battery Room 28.
The circumstances that caused
the discrepancy were thoroughly investigated _and assessed.
Findings identified within the scope of the audit involving the
presence of combustible material, poor housekeeping, missing
Appendix R locker items, improper storage of a spare Appendix R
pump, fire damper identification weakness, and the lack of a
(2)
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26
surveillance procedure, were properly handled and safety hazards
were expeditiously corrected.
The audit protess appears to be adjusting to a favorable balance
between procedural review and actual work performance audits.
The licensee has strengthened their audit/surveillance program
by occasional use of vendor technical consultants as part of the
team when their expertise was -deemed necessary .. Discussions
with the Station QA Manager rev ea 1 ed that the licensee has
considered using this approach more often/ as well' as the
possible occasional use of other utility audit personnel to
provide an independent viewpoint to the audit process.
The
Virginia Power
Nuclear Operations Department Policy
Statement NODPS-QA-02 and NOD Standard on Corrective Action
(NODS-QA-01) adequately address adverse findings escalation.
During 1986, two CARs were issued to escalate audit findings.
CAR No. S86-0l was escalated to the Station Manager-QA Manager
level for resolution of unsatisfactory corrective action
proposed for issues identified in a scoping review that was
performed on IE Information Notice No. 80-21.
CAR NO. S86-02,
a 1 so handled and. reso 1 ved at that Station Manager-QA Manager
level, involved unsatisfactory corrective action concerning the
spacing and location requirements for plant smoke detectors.
Both of these issues i nvo 1 ved E&C 1 ong term so 1 ut ions that
appeared to be satisfactory and adequately handled.
Quality Control
The QC organization on site is distinctly separated into -four
different groups reporting to their own individual supervisors,
who in turn report to the Manager of QA.
These groups are O&M
E&C, NOE, and the Surveillance Inspection group.
The inspector
accompanied a *Qc inspector from the E&C QC group during his
inspection of a portion of the completed work identified in EWR
No.87-133.
This EWR was initiated to replace 3-inch water
treatment piping in Unit 2 whose wall thickness had degraded
(undersized).
The NRC inspector witnessed the QC hold point
verification of fit-up, preheat and interpass temperature checks
for weld no. 7 and the joint markings and final visual inspec-
tion of completed weld no. 6.
The* acceptance criteria
(Corporate Welding Manual PlOl, Visual Weld Inspection Guide-
lines QADIN 10.7, Weld Procedure -101, Weld Map No. EWR 87-133-
E200, R4) utilized for this piping replacement were satisfactory
for the inspection of the work activity.* Examination of the
latest listing of qualified welders ascertained. that the welder
observed working on the subject piping was qualified for the
specific weld procedure (101) used.
Likewise, examination of
the QC inspector certification and training records indicates he
was qualified to inspect the subject welds. A QA Tracking and
Trending System has been established and is primarily managed by
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the Supervisor, Quality Surveillance.
It is evident that
significant resources are being
used to generate trend
information.
This reflects positively on management's commit-
ment
to quality.
However,
discussion with knowledgeable
personnel and review of the site trending programs indicate they
are not fully developed to the point the licensee would lJke
them to be.
There are numerous programs in place to report adverse condi-
tions to management.
Some examples are, but are not limited to:
Station Deviation Reports
Work Requests
Engineering Work Requests
QC Activities Report
Nonconformance Reports
QA Audit Reports
Surveillance Audit Checklists
Construction Trouble Reports
A 1 though a 11
adverse findings are being trended in various
trending systems by various departments (QA/QC,
SES,
Site
Engineering, etc.), no one group appears to be monitoring the
various trending programs to establish overall plant-wide
trends.
The inspector also noted that station deviations are trended,
yet evaluation of the trending results apparently is not being
accomplished by SES for the SNSOC ,per Section 5.3.10 (e) of
Administration Procedure SUADM-0-12.
A *positive side to this
issue is that subsequent to this finding, the NRC inspector_
discovered Audit S86-09 (which has not been issued to date)
identified the same problem prior to NRC identification of this
issue.
Meaningful
FT&A of safety re 1 ated equipment is apparently
impossible due to an inadequate data base of information from
which to establish trends.
NRC inspector discussions with
personnel and documentation reviews revealed the Station Manager
has directed a task team to examine the existing FT&A program
and provide necessary recommendations 'lo establish a workable
program which will improve the material condition of the
station.
Examination of the QA Tracking and Trending System for open
inspection items, nonconformances, and risk releases did not
reveal
any
old outstanding
items.
It was
noted that
significant items were noted as such and corrective actions
appeared to be timely and appropriate in these areas.
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The inspector noted that in addition to routine audit/surveil-
lance/inspection programs, corporate and station management has
utilized the QA organization to assist in special station
studies, SSFis, and as task team members to improve construc-
tion, maintenance, operational, and security systems at the
station.
(3)
Licensee Event Reports (LERs)
The station has submitted 62 LERs during 1986 and a total of 5
LERs to date for 1987.
The inspector selected a random sample
of LERs to review for corrective action and determination that
problems had been thoroughly investigated, appropriate correc-
tive actions had been assigned, and that corrective action was
either closed out or was scheduled and being properly tracked.
The inspector selected LER 86-07, Rl, Failure of Bolting
Material in Valve Flanges, for detailed review.
Regarding this
reportable event, the licensee was found to have taken appro-
priate action in both the immediate notification artd the LER.
The subject LER fully developed the details of the incident that
occurred. The safety imp 1 i cations and consequences, roo*t cause
analysis, and corrective action plan implementation appear
complete and appropriate for the particular incident. Review of
Surry Power Station Deviation Trending Report dated January 1,
1986 - December 31, 1986 did not disclose any similar repetitive
problems, which substantiates the supposition that the correc-
tive action taken to prevent recurrence was effective, and that
there was no generic implications as stated in the LER.
Based
on this limited review, the identification and reporting of LERs,
appears to be thorough and complete.
(4) Associated Overview Activities
10 CFR Part 21 Reporting
QA activities subject to the prov1s1ons of 10 CFR 21 appear to
be adequately described in Surry* s Administrative Procedure
SUADM-LR-09.
During inspection of the posting requirements
specified by 10 CFR 21._6, the inspector noted that the subject
postings located on both the QA and turbine building bulletin
boards still reference procedures from the Nuclear QA Manual,
which has been deleted. Discussion with the QA Audit Supervisor
disclosed that audit finding 86-03-03 (Audit No. QA 86-03 issued
March 19, 1987) for which a response is due by April 18 ~ 1987,
is similar to the NRC identified discrepancy.
Human Performance Evaluation Systems (HPES)
The program currently has one full time coordinator assigned to
investigate personnel error-type situations and to determine the
management actions that can be taken to prevent recurrence. The
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HPES program is a positive feature which allows concerned
employees to report suspect practices or defects while remaining
anonymous without fear of reprisal.
An excellent lecture was
recently given (part of general employee training) to all
station personnel describing the HPES program and its function.
However, the inspector could find only two HPES Reporting Form
boxes on site; one was located outside the Superintendent of
Operations' Office and the other at the training center.
Neither box is conveniently located for the station worker and
none exist in the Engineering-QA Building Complex.*
6.
Licensee Action on Previously Identified Inspector Findings (92701)
(Closed) Inspector Followup Item (280, 281/86-17-01):
Revise Upper-tier
and Lower-tier Program Documents to Assure* Compliance with Nucle~r
Operations Department Standard Manual
(NODSM)
and
Station
QA/QC
Organization.
The inspector reviewed the VEPCO Topical Report update to VEP-1~5A (Serial
No.87-076, dated March 23, 1987) and the licensee's proposed TS change
(Serial No.86-366, dated July 14, 1986). This update and change concerns
reorganization of the QA organization in that the QA organization will now
report to the Senior Vice President, E&C, rather than the Senior Vice
President - Power Operations.
The inspector verified that the reporting
requirements of the QA organization are now consistent between VEPCO' s
Topical Report; Section 6 of Surry' s TS, Nuclear Operations Department
Standard
NODS-ADM-06,
Organizations,
Responsibilities,
Interfaces,
Revision O;
and the Quality Assurance Department Instruction Nuclear
(QADIN) -
Section 1, QA Organization, Revision 2.
The licensee has
,
reviewed all of its station administrative procedures against the higher-
tiered applicable NOD standards, changing any inconsistencies to agree
with the way the station operates.
The licensee has fulfilled its
commitment in this area.
(Closed) In~pector Followup Item 280, 281/86-19-01: Emergency Vent Damper
EQ Documentation.
The Environmental Qualification Maintenance List (EMQL) was revised to
include the emergency vent dampers on September 9, 1986.