ML20246P732
| ML20246P732 | |
| Person / Time | |
|---|---|
| Site: | Catawba  |
| Issue date: | 07/10/1989 |
| From: | Russell Gibbs, Lawyer L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20246P695 | List: |
| References | |
| 50-413-89-09, 50-413-89-9, 50-414-89-09, 50-414-89-9, NUDOCS 8907200297 | |
| Download: ML20246P732 (86) | |
See also: IR 05000413/1989009
Text
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4J yg Miho UNITED STATES
- J. J- 'o - NUCLEAR REGULATORY COMMISSION
_ g* J ' ' ' .- '* W : ggagou gg
101 MARtETTA STREET,N.W,'
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- e' ATLANTA, oEORGI A 30323
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L . Report Nos.: 50-413/89-09:and 50-414/89-09
' Licensee: Duke Power Company
422 South Church Street-
i. Charlotte, NC.28242
Docket No.: 50-413 and 50-414 License Nos.: NPF-35 and NPF-52
Facility Name: Catawb'a 1 and 2
Inspection Conducted: April 10-May 5,1989, Exit Conducted: May 16, 1989.
4
- Inspectors- [
p . Mbbs;. Team Leader
R
Yl, 7 i ti rd)
Datp'Sitned
, ifh -'
M . Lawyer, Team Leader (EOPs)
W)v tn Yi
Datp S t'gned
Team Members- R. Bernhard
G. Bryan, Jr.
M. Ernstes
G. Maxwel'
R. Musser
S. Ninh
C. Pau',k'
G. Cn yers.
R. Schin
A. Sutthoff
Accompanying Personnel: Arie de Joode, Ministry of Social Affairs
_ d7Em ment, Nuclear Department, The
eth nds.
/
Approved by: '
- dm/ /0,/9 W
W P."Kellogg, Chief .-
/ . /Date 'Signec
Operational Programs 4 tion
Operations Branch
Division of Reactor Safety
. SUMMARY
Scope: This was a special announced Operational Safety Team Inspection
(OSTI). The OSTI evaluated the licensee's current level of perform-
ance in the area of plant operations. The inspection included an
evaluation .of the effectiveness of various plant groups including
Operations, Maintenance, Quality Assurance, Engineering, and Training
in support of safe plant operations. Plant management's awareness
of, involvement in, and support of safe plant operation were also
evaluated.
8907200297 890710
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The inspection.was divided into three major areas including Opera-
tions, Support of Operations, ' and Emergency Operating Procedures.
The. team placed emphasis on interviews -of ' personnel at all levels,
observations of plant' activities and meetings, extensive . control room
observations, and system walkdowns. The team also reviewed plant
deviation' reports, LERs for the. current SAlp evaluation period, and'
evaluated the effectiveness of the licensee's root cause identifica-
tion; short term and programmatic corrective actions, and repttitive ~
failure. trending and related corrective actions.
Results: The 'overall assessment concluded that the site is well-managed. The
Emergency 0perating Procedures were determined to adequately cover the
broad range of- accidents and equipment failures necessary. for safe
shutdown of the plant. Only minor problems were found by the team. A
. summary of the weak areas and strong areas observed by the. team are as
follows:
Weaknesses:
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Management used verbal instructions to modify safety related proce-
dures for cold leg accumulators instead of . issuing a comprehensive
written procedure. (paragraph 2.a.) (IFI 413,414/89-09-02)
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Controis on-the thermal power computer and its inputs are weak. This
computer' is used for normal determination of plant power level and
for. adjusting the gain on the nuclear instruments. (paragraph 2.b.)
(IFI 413,414/89-09-03)
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0ne '10 CFR 50.59 evaluation was weak concerning a modification to
the nuclear service water pit strainer instrumentation. Annuncia-
tors' described in the FSAR were disabled for about 30 days with no
written . consideration of compensatory action. (paragraph 2.c.)
(IFI 413,414/89-09-04)
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.Many of the site's safety related pump rooms are contaminated, which'
l inhibits operator and management surveillance. (paragraph 2.e.)'
(IFI 413,414/89-09-05)
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Auxiliary operators on rounds failed to frisk immediately after
exiting contaminated areas. (paragraph 2.e.) (VIO 413,414/89-09-01)
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Control of doors was weak, as indicated by the three open fire or
security doors found by the team. (paragraph 2.g.)
(IFI 413,414/89-09-06)
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In the Independent Verification and Safety Tag procedures, three I
items for potential improvement are identified. (paragraph 2.1.)
(IFI 413,414/89-09-07)
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Valve 1-KC-9 (component cooling water pump 1A2 dischars e valve) which
is required to be locked by site procedures was found not locked
during system walkdown. (paragraph 2.k.) (VIO 413,414/89-09-01)
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Several deficiencies were noted during observation of a performance
test on one of the containment spray pumps. (paragraph 2.m.)-
(IFI 413,414/89-09-08)
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Scaffolding procedures do not address seismic considerations and
resultant inoperability of safety equipment. (paragraph 2.r.)
(IFI 413,414/89-09-09)
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I&E maintenance does not use portable equipment to facilitate timely
locating of de ground faults. (paragraph 2.s.) (IFI 413,414/89-09-10)
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There are many significant deviations between the E0Ps and the PSTGs
(Plant Specific Technical Guidelines) where there should be none.
This is primarily due to changes being made in the E0Ps before being
made in the guidance document (PSTG). (paragraph 3 and Appendix B)
(IFI 413,414,/89-09-11)
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There are many technical and human factors discrepancies that were
identif:ed in the E0Ps. Each one is listed. (paragraph 3.b. and
Appendix B) (IFI 413,414/89-09-12)
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Many labeling discrepancies between E0Ps and panel indication were
identified. Each one is listed. (paragraph 3.c. and Appendix D)
(IFI 413,414/89-09-13)
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There is a discrepancy between the E0Ps and the S/G pressure meter
in the control room. (paragraph 3.c.) (IFI 413,414/89-09-14)
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Many writer's guide discrepancies were identified in the E0Ps. Each
one is listed. (paragraph 3.c. and Appendix C) (IFI 413,414/89-09-15)
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Noise level in the control room during auto-start of both ventila-
tion trains during S/I response is excessive. (paragraph 3.c)
(IFI 413,414/89-09-16)
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Deficiencies were identified in simulator effectiveness in training
on E0Ps (paragraph 3.d) (IFI 413,414/89-09-17)
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There were weaknesses noted in the site's ETQS program. (paragraph
4.a.) (IFI 413,414/89-09-18)
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There are approximately 131 temporary modifications in effect on
site. Some date back as far as 3 or 4 years. (paragraph 4.c.)
(IFI 413,414/89-09-19)
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The separate reporting authority and duplication of support functions I
for the Transmission Group is considered a weakness. (paragraph 4.j.) l
(IFI 413,414/89-09-20) l
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, Strengths:
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Shift turnovers were efficient and effective.- (paragraph 2.d.)-
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Centrol' room decorum was good, with orderly appearance and proper
' beha vi o r.' (paragraph 2.d.)
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.0perators displayed a professional attitude toward their responsibi-
11 ties. (paragraph 2.d.)
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Operator control of access to the control room was good. (paragraph
2.d.)
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. Housekeeping in general was very good, but there were. some excep-
tions. (paragraphs 2.e. and 2.h.)
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Inside ' and outside auxiliary operator rounds were very thorough.
(paragraphs 2.e. and 2.h.)
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Labeling overall ' was very good, with the exceptions of ' auxiliary
building doors and instrument root valves. (paragraphs 2.e., 2.j.,
and 2,k.)
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On theiriown intitiative, the licensee is upgrading the seismic-
l safety margin of. the diesel generator batteries. (paragraph 2.f.)'
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There was good feedback from site personnel on management involvement
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in solving. problems. (paragraph 4.a 4.e and 4.k)
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Operations has a daily input into the MWR backlog for prioritizing
work items. (paragraph 4.g)-
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-The planners inspection of the worksite prior to initiation of the
MWR package is considered a strength. (paragraph 4 h). .
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Rotation of .,ork shifts together provides for a smoother flow of
work. (paragraph 4.h)
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The practice of. working items by train or division in a weekly
rotation helps limit problems of having 2 trains inoperable at the
same time. (paragraph 4.h)
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Plant meetings were brief, to the point, and provided adequate plant
status to involved management personnel. (paragraph 4.1)
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The new 10 CFR 50.59 training for site personnel is thorough and
meaningful. (paragraph 4.1)
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Changes to the Catawba Critical Safety Function integrity tree are
considered to be significant enhancements which are supported by
valid deviations from the ERG. Catawba treatment of the coolant
integrity tree ' was excellent, particularly with ' respect to cold
overpressure protection. (Appendix B)
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REPORT DETAILS ~
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1. Persons. Contacted
Licensee employees
K. Alcorn, Reactor Operator
J. Barbour, QA Director Operations
H. Barron, Superintendent Operations
W. Barron, Director of Operations Training
T. Beadle, Procedures Engineer-
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W. Bradly, QA Verification Manager
. R. Casler, Shift Operations Manager
- - J. Cox, Production Support
T. Crawford, Superintendent Intergrated Scheduling
M. Criminger, QA Verification Specialist II
R. Edmund, Reactor Operator
p J. Effinger, QA' Verification Specialist II- Audit
J. Frye, QA Verification Manager -Audit
R. Gill, Corporate Compliance Manager-
J. Glen, Production Engineer
M. Glover, Compliance Manager
C. Graves, Operations,~ General Office
T. Harrall, Sr. Project Engineer, Design Engineering
D. Jenkins,' Design Engineer
R. Kimray, Senior Instructor
V. King, Production Engineer
J. Knuti, Operations Support Manager
M. Lee, Nuclear Control Operator
P.. LeRoy, Compliance, General Office
W. McCollum, Superintendent Maintenance
K. Munk, Reactor Operator
C. ' O' Dell, Shift Supervisor
T. 0 wen, Station Manager ;
G. Rhyne, Nuclear Equipment Operator
M. Sanders, Nuclear Equipment Operator
L. Saunders, Reactor Operator
K. Seasely, Procedures Engineer
G. Swindlehurst, Engineering Supervisor
-D. Thompson, Senior Reactor Operator
G.'Winkel, Simulator Instructor
Other Licensee employees contacted included instructors, engineers,
mechanics, technicians, operators, and office personnel.
NRC Representatives
E. Merschoff, Deputy Director, DRS, Region II
W. Orders, Senior Resident Inspector
M. Lesser, Resident Inspector
B. Bonser, Project Engineer, Region II
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NRR Representative
- K. Jabbour, Project Manager
- Attended exit interview
Acronyms used throughout this report are listed in Appendix E.
' 2. Operations (41400, 41707, 61700, 71707, 93802)
Many of the positive attributes of operational safety can be directly
observed in the control room. These attributes include such things as
adequate shift manning, delegation of Shift Supervisor (SS) non safety
related duties, Reactor Operator (RO) and Senior Reactor Operator (SRO)
system knowledge, relief turnover procedures, etc. Adequate shift
manning assures: qualified plant personnel to man the operational
shifts are readily available and that excessive overtime need not be
utilized; delegation of nonsafety-related duties assures the SS attention
to the command function will not be diverted to nonsafety-related duties;
and accurate diagnosis and response to plant transients, minor and major,
require detailed operator systems knowledge, etc.
Other operational safety attributes can be better assessed through plant
tours and system walkdowns. These include material condition; conformance
to approved procedures; attentiveness to duties; and return to service of
. equipment important to safety, including correct system alignments.
Finally, interviews with personnel holding a variety of positions on the
plant staff together with some review of records is necessary to provide
indirect indicators of operational safety and to corroborate preliminary
assessments.
To assess the operational safety of the facility, the team performed
extended observations of control room activities, including back shifts,
with the units in modes 1, 5, and 6. Also, the team conducted system
walkdowns and plant tours. In addition, they interviewed operators during
these observations, walkdowns, and tours, observed shift turnovers, and
reviewed operator logs. The team also reviewed records used for indica-
tion or control of plant status for adequacy and verified operator aware-
ness of their contents. These included the LCO Log, configuration contisi
records, Danger Tag Log, and Increased Surveillance Log.
Tha team monitored operator performance, control room decorum, awareness
of plant status, response to alarms, and use of procedures. The team
conducted interviews or plant tours with the Operations Superintendent,
System Engineers, and operators. The team also reviewed engineering
evaluations, training, and maintenance as related to questions that arose
from observations in the plant.
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' a.. Cold Leg Accumulators
When the team first entered the control room at about- 9:00 a.m. ,
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on April 11, Unit I was at 100%, power and .was in two TS LCO action
statements for cold leg accumulator A:
(1) Boron concentration was below the required range, a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />
action statement, and
- (2) Level was below the required range, a one hour action statement.
The operators were in the process of partially draining the "A"
cold leg accumulator and then refilling it from the FWST to restore-
boron concentration to the required range. They were performing the
evolution for the second time that day. The first drain' and fill
evolution had been initiated in response to boron concentration
decreasing to 1918 ppm, just above the minimum TS requirement 'of
1900 ppm. After the first drain and. fill, sampling had. indicated
that boron concentration in the "A" accumulator had decreased to 1848
ppm. This reduction in boron had occurred in spite of the fact that
refilling was done from the FWST, which contained a boron concentra-
tion of 2026 ppm. The team asked the operators to explain why the.
. boron ' concentration went down after the first drain and fill. They
- had a theory based.on stratification in the accumulator, coupled with
inleakage from the RCS through or bypassing the check valves and
entering the bottom of the accumulator, then the draining from the
bottom followed by filling near the top, and finally sampling from
the bottom. The operators were able to use system piping diagrams
- to show this theory to the team and .to demonstrate a good level of
knowledge of the . systems. They were also able to explain why they
believed the 1918,1848, and 2026 ppm' ample results were reliable
numbers.
The licensee had entered the accumulator "A" level TS action state-
ment at 7:08 AM. This action statement required that level be
restored to the specified range within one hour or be in hot standby
within the next six hours and in hot shutdown within the following
six hours. The team asked the operators about their plans for
restoring level to within the TS specified range, and how they were
complying with the requirement to be in hot standby withii, the next
six hours. The operators stated that they planned to have level
restored by about 10:00 AM, which would leave them about four hours
in which to shut down the unit to hot standby in the unlikely event
that unforeseen problems prevented the restoration of level. They
stated that a normal shutdown to hot standby would take about three
to four hours. The operators understood that the intention of the
action statement was not to allow seven hours to restore level, but
instead to require a shutdown to be started in time to allow a
normal shutdown to hot standby to be conducted and completed prior
to the one hour plus six hour time limit.
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The team reviewed procedures that were in use for the drain and j
fill evolution to increase boron concentration. Operators -were
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using OP/1/A/6200/09, Cold leg- Accumulator Operation, Change 26. .
Draining was done per Enclosure .4.5, Decreasing Accumulator. Level, l
and filling was done per Enclosure 4.4, Increasing Accumulator
level. The operators stated that there was no overall procedure for
increasing boron concentration. The operators had given themselves
about three hours to restore level, and based or, that had decided
they could drain for about two and one- half hours. With the FWST
boron concentration at 2026 ppm and not greatly more than the boron
concentration in the accumulator, they would need to maximize the
amount of liquid exchanged to effectively increase boron concentra-
tion in the accumulator. A major consideration'was that a substan-
tial portion of the piping used for draining was also used for
filling. Thus some of the same liquid that was drained would be
added back during filling. After draining for about one hour and 20
minutes, the accumulator level dropped below the indicating range.
The operators then drained for an equal amount of-time, with no level
indication. By using a chart showing accumulator levels, gallons in
the accumulator, and level indicating range, the operators were able
to estimate the total quantity that they would be draining and the
quantity of liquid remaining in the accumulator. The accumulator
was on line during this evolution, with its isolation valve open and
power removed. The team noted that the written procedure in use did
not address being out of the level indicating range. It also did
not address time constraints of being in a TS action statement. The
procedure' simply stated: "Open the corresponding valve to decrease
level in the desired accumulator", then "When the accumulator is at
the desired level, close the corresponding valve."
The team questioned whether the evolution being conducted had
received appropriate management review and approval. The Operations
Superintendent stated that verbal review and approval had been done,
by the same management people who were authorized to give written-
approval for procedure changes or new procedures. Still, the team
considered that a written procedure covering the entire evolution of
increasing boron concentration in an accumulator would have been
more appropriate. The team considered management's use of verbal
instructions to modify written safety related procedures, including
draining below the level indicating range and related cautions, as
an area of weakness.
The team noted tha". the first step of the " Decreasing Accumulator
Level" enclosure states: " Review the Limits and Precautions." Under
limits and precautions, located in front of the procedure for cold
leg accumulator operation, step 2.7 states: "Do not use Enclosure
4.5 (Decreasing Accumulator Level) for draining an accumulator beyond
the limits of provided level instrumentation." However, this step
had been lined out by hand and deleted by Change 26 to the procedure,
which was dated April 10, 1989. The team reviewed Change 26 and its
10 CFR 50.59 safety evaluation. The forms were complete and the
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required preparation, review, and approval signatures were :all
present, and all were' dated April 10, 1989. The safety evaluation
. stated that the purpose of the precaution that was being deleted was
to prevent over pressurization of the FWST with nitrogen. It stated
that further evaluation has determined _this precaution to be unneces-
sary,' based on the small size of the drain line to'the FWST and the
much larger size of the vents on the FWST. The team then reviewed
the Justification Document for this procedure, which lists reasons,
restrictions, and commitments associated with each step of the
procedure. .The Justification Document stated that the reason for
step 2.7 was to prevent over pressurization of the FWST with nitrogen
if draining below the fill connection. It further stated that the level
instrument only covers the top 13 inches of the tank, and 'the fill
connection is midway up on the tank. Overall, the team identified
no deficiencies with the records for Change 26.
The operators restored the accumulator level to the TS required range
by about 10:30 AM, and by about 11:30 sampling results showed the
new boron concentration to be 1925 ppm. Overall on this day, the
licensee had operated the unit in a.one hour TS action statement
for a total of over six hours to gain a net increase-in boron con-
. centration of 7 ppm (from 1918 to 1925). The team judged that the
licensee would need to increase boron concentration again in the i
near -future,: and asked the licensee if there might not be a better l
way'to do it. The team suggested checking with a " sister plant", !
McGuire. lThe licensee found that McGuire had a written procedure
for increasing boron concentration in a cold leg accumulator that
did not require entering any TS action statements or going below the
level indicating range. The licensee then wrote their own similar
procedure, and used it successfully during the second week of this i
inspection.
The team subsequently reviewed the results of the licensee's previous
leak rate testing of the Unit I cold leg accumulator check valves,
and identified no deficiencies with them. The team also looked at
the current quantity of " unidentified leakage" from the reactor
coolant system, and identified no problems with it.
All concerns relating to accumulator boron concentration discussed
in the preceeding paragraphs were followed up under IFI 50-413,
414/89-09-02 during this inspection. This IFI is closed.
b. Thermal Power Computer
After the "A" co'd leg accumulator was restored to operable, the
team noted that the unit one computer screen indicated that total
power from each of the four nuclear instrument channels was about
100.5 percent. At the same time, each upper detector indicated
about 104 percent and each lower detector indicated about 103
! percent. Thermal power of the unit was indicated to be about 99.8
percent. The team asked the operators to explain what was the
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I maximum allowed power _ for.the unit and how'it was controlled. The
operators stated that maximum allowed power was 3411 megawatts .
thermal, as ' stated in the operating license. They were instructed
by management .to -implement this by maintaining eight hour average
power at 100 percent or less, as indicated by .the thermal power
computer.
The operators showed the team a station technical specification
interpretation, which stated the eight hour average thermal power
limit. It also gave short term limits on being above= 100 percent
thermal power, up to.a maximum of 102 percent for 15 minutes. The
operators stated . that the thermal power computer continuously
calculated average' power for the previous eight hours. .They used.
the thermal' power computer for normal steady state operation of the
unit, but they were also to keep each power range NI total power
reading within two percent of the current thermal power number. The
computer was programmed to give an alarm whenever there was a two
percent difference between the computed thermal power and a power
range NI. A daily check of power range NIs versus the_ thermal power.
was done, and~if this check or an alarm indicated more that a two
. percent difference, then the gain of the. NI would be adjusted in
accordance with' station procedures. One thermal power computer
generates one thermal power number, using inputs from many secondary
plant instruments. ,The . team asked the operators about the possi-
bility of all NIs being adjusted in a nonconservative. direction
based on a thermal power number 'that was erroneous because one of ;
its inputs had gone bad without being detected. -The operators
stated that this was possible and in fact had' happened just last
year. They saia the situation had been detected when an operator
realized that the unit was generating substantially more megawatts
than ever before. An LER had been written on this event.
The team reviewed the licensee's controls on the thermal power
computer and its inputs with a system' engineer independent of the
previous LER. As a result of this review, the licensee stated that
two changes would be made to improve the controls on the thermal
power computer:
(1) Periodic calibration testing of the unit 1 thermal power
computer inputs will be added to the Computerized Periodic
Test Program, to provide formal scheduling control. This had
previously been done manually on an informal basis for Unit 1.
The Unit 2 thermal power computer inputs had been in the
Computerized Periodic Test Program.
(2) Out of calibration notification forms will be sent fr.om the
instrumentation technicians to the performance system expert, j
This is important, because the performance system expert trends l
historical readings on the inputs to the thermal power computer.
These trends are used for one of the most important controls on
the thermal power computer: prior to adjusting the gain on a
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nuclear instrument, the performance system engineer checks the
values in the computer for reasonableness. This is done by
comparisons with other values in the plant, and by reviewing
historic'al trends.
Overall, the licensee's control of tF Nrmal power computer was
considered to be an area of weakness. In. ' tem will be followed up
ur. der IFI 50-413,414/89-09-03.
c. Nuclear Service Water Annunciators.
.The team reviewed all lit or disabled annunciators in the control
room. of unit I with the operators, while the unit was operating at
100% power. Only eight of the annunciators were lit or disabled,
out of a total of about 450. The team hdged that this was a
relatively small number of lit or disabled annunciators, and that
the operators were adequately knowledgeable about the conditions
indicated by each.
Two of the lit annunciators were actually lit continuously (disabled)
due to plant modification work in progress. These two, RN Pit "A"
Screen Hi D/P and RN Pit "B" Screen Hi D/P, were designed to indicate
fouling of the trash screens on the suction side of the nuclear
service water pumps. The team asked the operators what compensatory
measures were being taken while these annunciators were disabled.
The operators showed the team an Increased Surveillance Log book,
that was used to record all increased surveillance in effect. The
team found this book to be well organized and an effective operator
aid. However, it indicated that no increased surveillance was in
effect for.the nuclear service water suction pit screens.
The team looked in the FSAR and found that these annunciators were
described therein. They then asked for the 10 CFR 50.59 safety
evaluation for disabling the annunciators. The licensee had a 50.59
evaluation, which identified three instruments that would be disabled
during modification installation: the two annunciators in question
and also tne control room indicator for Standby Nuclear Service
Water Pond Level. The evaluation stated that operators would have
to use compensatory measures to monitor the level of the SNSWP to
comply with TS 3/4.7.5. The team confirmed that SNSWP level was
being monitored daily by operators, as required by the TS. This i
was done by physical inspection of a level stick in the SNSWP by an ;
auxiliary operator, who then phoned the level information to the
control room.
The fact that operators would not have indication of differential
pressure across the screens in either pit for about 30 days was
stated in the safety evaluation. But the fact that tiie RN Pit Screen
Hi D/P annunciators were described in the FSAR was not specifically
stated, nor was there any mention of compensatory measures to be
taken while these annunciators were disabled. The licensee stated
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that unwritten consideration of compensatory measures had been done, )
and that they had decided that none were needed. The team identified j
the lack of written consideration of compensatory measures as a
weakness in the 10CFR50.59 evaluation. This -item will be followed
up under IFI 50-413,414/89-09-04. i
d. Shift Turnover and Control Room Decorum
The team observed two morning shif t turnovers. Operators conducted
both turnovers efficiently and effectively. Prior to turnover, the 1
off going shift assembled a thorough compilation of the scheduled
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surveillance sheets, technical memorandums, a special interest items
list, and an inoperable equipment list. They then informed the
on-coming shift about previous and planned plant activities. The
interface and exchange of information occurred between each of the
control room operators, the auxiliary operators, and the shift
supervisors. In. addition, the shift supervisor conducted a verbal
briefing of all auxiliary operators.
During the turnover, the oncoming shift completed and signed turnover
checklists, as required by Operations Procedure 2-22, Shift Turnover,
Revision 24. During and following turnovers, several annunciator
alarms occurred. The operators promptly acknowledged these alarms
and took the appropriate corrective actions.
Throughout the team evaluation the operators displayed a professional
attitude concerning the plant equipment and their responsibilities
as operators. The onshift operations personnel appeared to be
sufficiently rested, awake, and alert to safely perform plant
manipulations. Operator control of access to the control room was
good. Control room entry gates and 'at the controls area' markings
were in place, and operators were aware of who was in the control
room. Operators were attentive to their panels. Overall control
room decorum was good. Operators maintained an orderly appearance
and proper behavior in the room.
The team noted that a number of persons in the control room (pri-
marily maintenance or performance personnel) wore hardhats while
standing over main control boards. The team discussed this practice
with operators and management, who acknowledged that it is routinely
allowed. They reviewed the potential hazard of a hard hat falling
on a control parel and causing an uncontrolled equipment actuation, ,
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and the fact that many other plants do not allow hard hats to be
worn in the control room.
e. Plant Rounds
The team accompanied auxiliary plant operators on daily auxiliary
building rounds for units 1 and 2. The operators used Daily
Auxiliary Building Rounds sheets in the performance of the rounds.
They examined each area specified by the rounds sheet, ensuring that
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each parameter was within its required range. During the rounds,
the unit 1 operator had to enter four contaminated pump rooms and
the unit 2 operator had to enter six contaminated pump rooms for the
purpose of examining equipment as required. Each of these areas
required full dress in protective clothing. The process of multiple
suiting and unsuiting was time consuming, and may be a deterrent to
operator and management surveillance of the contaminated pump rooms.
Having the large number of contaminated rooms which require routine
access for proper surveillance is considered to be an area of weak-
ness. This item will be followed up under IFI 50-413,414/89-09-05.
The team observed that the operators did not frisk when exiting each
contaminated area. Portable friskers were not located at any of
the contaminated pump rooms. A few portable friskers were located
throughout the auxiliary buildino, and generally one was within about
50 to 200 feet of each contaminated pump room. However, operators
stated that they were not required to use these portable friskers,
but instead were to complete their rounds, walking throughout much
of the auxiliary building, and then use the whole body radiation
monitors. The team reviewed Station Directive 3.8.3 (T.S.), Contami-
nation Prevention, Control, and Decontamination Responsibilities,
' Revision 24. It states that exiting a contaminated area requires a
whole body frisk: "a whole body frisk shall be performed at the first
available frisker to prevent the spread of contamination." The team
reviewed this with health physics supervisors, who stated that they
had no problem with the observed practices of the operators, did not
have a problem of inadvertent spreading of contamination, and did not
intend to place more friskers in the auxiliary building. The team
also reviewed this matter with the operations superintendent, who
stated that the observed practices would be continued and the station
directive would be changed. Discussion of this item at the final exit
with plant management resulted in a commitment from the licensee to
re-review the resolution to this practice. The failure of operators
to frisk when exiting contaminated areas, as required by the station
directive, is identified as an example of violation 50-413/89-09-01.
Areas and equipment examined during the rounds were all levels of
the auxiliary building, including portions of the following systems:
containment spray, residual heat removal, high pressure injection,
safety injection, component cooling, auxiliary feedwater, ventilation
and air conditioning, eler u cal switchgear, spent fuel pool, diesel
generators, and various valve galleries. The team found labeling
to be overall very good, with the exception of doors and instrument
root valves. The operators exhibited a good " hands on" approach to
the rounds, and initiated corrective actions for a number of mino-
deficiencies that they observed. They demonstrated an adequate
knowledge of the equipment and existing conditions. Overall,
operator rounds were very thorough.
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The , team found that housekeeping in general was very good. The team . .
identified two areas in which an improvement could be made: the 522'
elevation in: the auxiliary building had various-items of protective
clothing on-the floor, and the 1A charging pump room contained trash.
f. Diesel Generator Batteries
During plant rounds, the team observed' that the batteries for
each of the- four emergency diesel generators did not appear to _ be
seismically mounted. ' Cell motion restraints were' lacking. ;There
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were no separators between the cells and not all end cells were
braced as required by current IEEE standards. In a seismic' event,
the cells could move and' impact with each other as well as with the
steel battery rack. When questioned about this, the licensee stated
>
that these battery installations were seismically qualified, and
that they had been seismically tested.
The team reviewed the battery seismic test results and identified no
deficiencies with them. The batteries had demonstrated operability
before and af ter being shaken at a minimum directional acceleration
of 0.2 g. The testing had been done in 1984 by Southwest Research
Institute in San Antonio, Texas. The FSAR states that the Safe-
Shutdown .Ea'rthquake maximum ground acceleration for this site is
0.15 g. The' team confirmed that the battery cells and rack that
were tested were the same as those installed in the plant. The team
also found that the licensee had not committed to current IEEE
standards that require cell separators and bracing.
The licensee stated that other people had questioned the seismic
design of these battery installations, and that a modification was
scheduled to be completed next year that would upgrade the diesel
batteries by adding cell separators and bracing. This upgrading
was being done in response to an EPRI initiative called Safe Margin
Earthquake. .The SME is calculated differently than the SSE, and the
licensee stated that for this site the SME had a maximum acceleration
of 0.3 g as compared to the SSE at 0.15 g. A licensee SME review of
the site had determined that, from a seismic standpoint, the diesel
batteries were the safety equipment that was most susceptible
to failure. The licensee stated that, for the site to meet SME
standards, basically only the diesel batteries and auxiliary feed
pumps needed to be upgraded.
On further investigation, the team found that this EPRI initiative
had begun after the NRC had found that SSE calculations for another
site were inadequate. A review of the design calculations that
determined the SSE for this site to be 0.15 g of ground acceleration
was beyond the scope of this inspection and was not done. Overall
on this issue, the team evaluated the licensee's initiative toward
upgrading the seismic safety margin of the units as commendable.
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g. - Fire 'and: Security Doors
- While touring the: plant, -the team observed that the door. to the 1A
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diesel generator room (fire door AX-302) did not close fully or
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latch by' itself. The team closed the door, and subsequently found
that procedure PT/0/A/4200/48, Periodic Inspection of Fire Barriers
- and Related Structures, change 0 requires that fire . doors "shall
h latch in the closed position. automatica11y' (no external force
l
. applied) when released from the open position." The team promptly
reported the fact. that . door AX-302' did not close automatically to ~l
the fire ' door coordinator, who checked the door and declared it-
inoperable that same day. The team verified that an hourly fire
watch had. been initiated on the door. The team also verified that
. the door had passed its last scheduled inspecti.on. The licensee
followed established procedures with respect to this fire door, and
when a problem with the door was identified to them, they did take
prompt' corrective action.
The team'also observed two other fire doors open because they. failed
to close automatically. One was the unit I control room door (fire
door 501), which the team found wide open and with no personnel in
sight. This door 'is not only a fire door, but also is a vital
security- door. The team promptly reported the open door to the
. shift supervisor, who assisted in closing it. ,This door, which is
very heavy, had rubbed on the floor and jammed open. The team
waited for a security guard, who arrived within two minutes. The
licensee. stated that a modification was planned to install a lighter
door. The control room security door problem has been referred to
NRC security personnel for followup.
.The team subsequently observed the fire door to the IAE engineers'
office area wedged open with its doorknob, which had apparently
fallen off. IAE. personnel were notified, and they closed the door.
As a result of finding three fire or . security doors open during
'the inspection, the team concluded that the licensee's control of
doors is an area of weakness. This item will be followed up under
IFI 50-413, 414/89-09-06.
h. Outside Rounds
The team accompanied an auxiliary operator on the daily outside
rounds, which covered both units. The operator examined each area
and component as specified by the Daily Outside Rounds Sheet. In.
the nuclear service water pump house, housekeeping needed improve- i
ment. Various loose items were in that area, including a seven foot
length of three inch pipe, a ladder, a fire extinguisher, a chair,
and some wood. In the intake and pump area for the conventional low
pressure service water pumps, the operator identified a deficiency
(water inside a pump flow gauge) which he properly documented via
the discrepancy reporting system. In addition, he initiated a work
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request and hung an orange tag as required by plant work request
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procedures. The cooling towers and their fan control rooms were
inspected, where the operator replaced a few burned out light bulbs.
The electrical switchyard was toured, with' no ' discrepancies noted.
Overall, the team considered' that the outside rounds were performed-
.iri a thorough and professional manner.
i. Configuration Control.and Independent Verification )
The team evaluated the methods utilized by.the licensee for control-
. ling the configuration of safety systems, particularly the alignment
1 of valves and breakers, to reduce the possibility of an. occurrence
which could. result in or contribute to an accident. .The evaluation
included a selective review of completed system alignment verifica-
tion checklists; system walkdowns; a review of Station Directive
4.2.2, Independent ' Verification Requirements, revision 1 and
Operations Management Procedure 1-5, Independent Verification,
revision 11; and interviews of several plant operations personnel.
The ' team also reviewed Station Directive 3.1.1, Safety Tags and
Delineation Tags, revision 21. The team identified no deficiencies
with.the operators' knowledge of independent verification. procedures
or with the completed system alignment verification checklists.
The team did identify three items for potential improvement in the ;
1
licensee's procedures: These items will be followed up under IFI
50-413,414/89-09-07.
(-1) The procedures allow both operators who are checking and
verifying the position of a valve or breaker to go together,
and the team observed this to be the practice of the operators.
Past experiences at other sites have shown that two operators - I
together are not totally independent, as there is a tendency ;
for' both to make the same mistake. A more effective' practice I
is for both to go separately.
(2) The procedures allow both operators to use the same remote
indicator to verify the position of a valve. This allows
iinporUnt valves, which are remotely operated from the control '
room, to be aligned for plant startup without being physically l
inspected for deficiencies. The inspection of equipment for j
significant material conditions should be included in a good 1
system alignment verification process. l
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(3) The procedures for restoration of a system during removal of a
tagout do not address alignment or independent verification of
valves inside the tagout boundary, such as a valve on which l
maintenance was performed. Operators that were interviewed !
stated that they were trained to list such valves on the tagout l
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restoration checklist, even though this was not specified in
the plant procedures.
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j. System Walkdowns: AC Power and Nitrogen
The team conducted a partial walkdown for two safety related systems;
one electrical and the other mechanical / piping. The electrical
walkdown verification checked the condition and position of the
power supply breakers for portions of the unit 2 4160 and 600VAC
switchgear. The other walkdown checked the valves and piping
which supply the nitrogen to the unit 1 passive safety injection
The team accompanied an auxiliary operator while conducting the
electrical walkdown verification for the unit 2 4160 and 600VAC
switchgear. During the walkdown PT-2A-4350-03, Electrical Power
Source Verification Checklist, change 14 was utilized for assuring
proper breaker positions. The team compared the as found positions
of the electreal circuit breaker with the positions shown on the
checkli st. No deficiencies were identified.
While conducting the walkdown for portions of the nitrogen system
for unit 1 passive safety injection accumulators, the team refer-
enced site drawings CN-1562-1.1, Safety Injection NI, revision 6;
CN-1602-1.0, nitrogen system, revision 13; the control room completed
copy of OP-1A-6200-09, Accumulator Valve Checklist Enclosure 4.2,
retype 6; and the applicable Independent Verification Checklist
Enclosure 4.2. , retype 6. The walkdown verified valve positions
as compared to the above referenced valve checklists. Each valve
was found to have attached valve identification tags which clearly
identified the appropriate valve number. All pipe caps were
installed as shown on site drawings. The team did not identify any
unsatisfactory conditions while conducting these walkdowns.
k. System Walkdown: Component Cooling Water
The team also performed a partial walkdown of the unit 1 component
cooling water system with the assistance of the system engineer.
The system operating procedure OP/1/A/6400/05, Component Cooling
Water, change 45, and system flow diagrams CN-1573-1.0, Rev. 16
and CN-1573-1,1, rev. 11, were utilized by the team during the
walkdown. The majority of the walkdown was conducted in the
Auxiliary Building on levels 560' and 577' . The team traced out
various portions of the system checking for proper labeling of
components, material condition of the system, proper labeling of
components compared to procedural requirements, and the status of
locked valves.
The team observed system valve and component labeling to be good.
All valves and components examined were labeled with large black
tags with white letters that were readily readable from a distance
and allowed for easy identification of equipment. The team con-
sidered the overall material condition to be adequate. The only
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discrepancies noted were a few slightly leaking valves which had
been previously identified by the licensee. These valves were
tagged with the licensee's orange deficiency ID tags' and had cable
funnels installed beneath them.
The team verified that all valves observed during the walkdown were j
in the correct position as required by the operating procedure, t
However, valve 1KC-9, the component cooling pump 1A2 discharge
valve, was found open in lieu of locked open as required by the
system operating procedure and system flow diagram. The valve was
.not locked open due to the chained handwheel being separated from
the valve stem. The licensee has been previously issued notices of
violation for failure to lock other valves: Violation 414/86-18-01
dated June 3, 1986 and Violation 413/87-30-03 dated October 14, 1987. I.
This valve not being locked as required is identified as an example g
of Violation 50-413/89-09-01.
After the licensee had re-attached the 1KC-9 handwheel, the team
checked all of the unit 1 and 2 component cooling pump suction and
discharge valves. During this walkdown, the team noted that the
handwheels on unit I valves IKC-4,1KC-9, IKC-7 and 1KC-10 were not
fully seated on the valve stems. The team also found that all of
the unit 2 pump suction and discharge valve handwheels were more
positively attached with a stem bolt and washer, while none of the
unit I valve handwheels were attached in this manner. This may have
contributed to the valve problem noted. (These valves are IKC-4,
IKC-6, 1KC-7, 1KC-9, 1KC-10, 1KC-12, 1KC-13, AND 1KC-15). The final
item identified by the team during the walkdown was that the valve
positions of valves IKC-16 and 1KC-17 could not be determined without
the use of an extension mirror due to the close proximity of the
valves to a wall . The team did not note any such implement in the
area of the valves. - -
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1. Auxiliary Feedwater Surveillance
On April 12, the team observed the performance of portions of the 1B
Auxiliary Feed (CA) Pump Surveillance in accordance with procedure
PT/1/A/4250/06, Enclosure 13.4, CA Pump Head and Valve Verification,
change 28. The team accompanied a licensed operator and auxiliary
plant operator for the local performance of the surveillance. The
purpose of the surveillance was to ensure that the auxiliary feed-
l water pump head and flow were within the technical specification
'
allowable limits. During the accomplishment of the test, the opera-
l tors followed the written instructions specified in the procedure.
At the completion of each step requiring a sign-off, work was stopped
and the operators made the required signatures. The operators kept -
control room personnel well aware of the status of the test and
informed them of any problems as they were encountered.
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1 The- results of7 the surveillance (as observed by the. team)' were
unsatisfactory. The requirement that the . pump achieve - an dynamic
head ~ pressure -(DHP) (DHP = pump discharge . pressureminus pump
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- suction. pressure) of.1521 psig was not' satisfied. . Calculations
revealed.the result'to be approximately 1507 psig. At this time, the
licensee had already entered a 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> T.S. - Action . Statement due to
removal of, the pump from service for t? sting.
The following day, the team inquired about the operability status of
the' 18 auxiliary feedwater pump. The team was informed that the pump-
had passed its operability run and had subsequently been declared ~
. operable by-the licensee. The team reviewed the surveillance records'.
This data was accompanied by a Duke Power Company, Procedure Discrepancies-
Process Record (DPCPDPR) which recognized the discrepancy'. The problem
resolution as'specified on the DPCPDPR and an accompanying calculation
on enclosure 13.4' of procedure PT/1/A/4250/13B was to ' compensate for'-
-the temperature difference in the suction source for the pump (the UST).
The UST temperature had been found to be approximately 140 degrees F,
which was higher.than the tank's normal temperature of 90 degrees F.
Additionally,. .the licensee had determined . that the temperature
difference in the UST had been caused by failure of a steam regulator
in' the steam supply for the tank. This regulator was subsequently
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repaired /r9placed by the licensee.
On May 1, the team observed the performance of the 1A auxiliary feed-
water pump surveillance in accordance with procedure PT/1/A/4250/06,
Enclosure'13.3, CA Pump Head and Valve Verification, change 29. The
team observed the local performance of the test by .two auxiliary-
operators. -The test was performed as specified by the procedure,- i
and'the results were satisfactory.
m.' Test Observation
The team observed performance of the INS-1B pump performance test,
PT/1/A/4200/04C, Change 0 to 27 incorporated, dated 4/30/86. Review
of the procedure and observation of the PT resulted in the following.
comments (Note: The pump satisfactorily past the performance PT): {
1. Section 2.0, References, should include the KF drawing showing
the location of 1KF101B, which is listed on Enclosure 13.5,
Valve Checklist.
2. Step 6.8 refers to minimum and maximum flows for pump operation. !
Step 12.8 and step 12.10 start the pump and throttle flow. No j
cautions or warnings are included immediately prior to these
steps to reinforce the limits of pump operation. During the
performance of the PT, the pump was run below the minimum flow
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value until the throttle valve could be properly adjusted.
I Starting the pump with the throttie valve set to allow minimum
- flow could possibly eliminate this problem.
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3. The required values in the procedure have many times the
accuracy indicated in their significant figures than can be
obtained through the measurement instrumentation used. For
example, step 12.10 states, ".. . obtain a flow of 620.3 gpm
(613.8 to 626.7 gpm) by observing INSPG5120. . ." . The flow
instrument is a 0 to 700 gpm Barton with 10 gpm divisions.
Readings are possible to the nearest 5 gpm, if the needle is
stable. The instrumentation used in the test were subject tc
considerable bounce.
4. Communications between the remote location of the throttle
valve and the meter that reads the flow was difficult during
performance of the PT. One person reading the flow gauge
walked about 40 feet to a location that could be seen by
another technician in a doorway. This person then walked to a
position that could be seen by the operator manipulating the
throttle valve. The operator changed the valve position, and
the process started again, until the proper flow was indicated.
Improved communications should be worked out.
5. In the pump room, instrument number 1NSTH5010 was broken,
and its laminate tag was wrong. In addition, the motor covers
on NS pump 1B were loose or missing.
These deficiencies will be followed up under IFI 50-413,414/89-09-08.
n. Safety Tags
The site has two procedures which focus on the control and issuance
of safety and delineation tags. These procedures are Station
Directive 3.1.1 (0P), Safety Tags and Delineation Tags, revision 21;
and Operations Management Procedures 2-1, Audit Of Safety Tags and
Tagout (R&R)'s, revision 11. The first of these two provides for
the issue, placement, recall, transfer, and removal of red personnel
safety tags, white equipment safety tags, and yellow " HOLD" safety
tags. The audit procedure is implemented vigorously by operations
management personnel to make sure that none of the listed tags are
missing or inappropriately applied. 3
1
The team selected several safety tags which were fastened to the
unit 2 4160 VAC switchgear. The tags were checked against the
l appropriate tagout (R&R) record sheets and were found to be active
and properly indexed. The tags and the tagout records were com-
pleted, signed, dated, and applied as required by the controlling
station directive. The tagout (R&R) records sheets which have been
outstanding for an extended period were evaluated. Two of the
sheets, one for each plant, indicate that in 1987 the diesel
generator engine fuel oil booster pumps had tags applied to their
power supply switches. The plant operations supervisor stated that 3
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these tags are necessary due to the incomplete status of the instal-
lation of these booster pumps. He further revealed that prior to
installing these pumps more guidance must be provided . by design
engineering.
A Unit I tagout sheet indicated that several condensate flow orifice
bypass valves have had tags applied to them since 1986. The opera- ,
tors stated that this is an acceptable site practice authori.ed i
by the condensate system controlling procedure. The procedure
allows the tags to be temporarily lifted as required to manipulate
the valves. Upon completion of the valve operation the valves are
returned to the properly tagged position and then the tags are
reapplied.
A similar tagout sheet has remained outstanding since 1984 for two
alternate power supply breakers in unit 1. These two breaker 3 are
normally " RED" tagged in the off position. But when the need arises
the breakers could be put into service and operated, as allowed by i
procedure. Upon completion of use, the breakers would be returned
to the tagged positions and the " RED" tags would be reapplied.
The team found that there are a limited number of other instances
similar to the above. Allowing certain tagouts to remain active for
extended periods and allowing the tags to be temporarily lifted has
been authorized by site procedures. The team considered that
leaving red tags in place for years and routine temporary lifting of
red tags potentially dilute the importance of the red tag system.
o. Operator Access
The auxiliary operators are issued key rings which contain all of
the required keys for routine access to areas which are administra-
tively controlled. In the event that the normal security door locks
improperly function, provisions have been made which will allow
these doors to be opened by the operators. Keys for other personnel
who may need them for access to administrative 1y controlled areas
may be obtained from the shift foreman. The team observed operations
personnel using the system and when questioned each of those
interviewed were familiar with the key control process and its
importance. The system utilized for key controls seems to be working
satisfactorily,
p. Required Reading
The shift foreman's administrative staff is responsible for assuring
that the various plant operators complete their required reading.
The required reading material may consist of procedures which have
been recently revised and other material which management feels that
the operators should be familiar with. The tehm verified that the
operators have been reading the required material and that they are '
familiar with what they read. The administrative staff requires
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that each of the operators complete reading the material within the
established time period. Upon completion, the operators sign or
initial the required reading notebook as proof that they reviewed
the material,
q. Overtime
The team verified that the licansee has in place controls and .
procedures for use of overtime. Station Directive 3.3.0 (SS),
Control of Overtime Hours, revision 2 provides guidance to help
assure that the licensee maintains the staff overtime and work hours
within the limits of T.S. Section 6.2.2,f. The team evaluated the
overtime hours which were worked by the plant operators for the
months of January, Februa ry , and March 1989. The team concluded
that the operations staff does frequently work overtime hours.
However, after evaluating the records and interviewing several
operations personnel, the team concluded that overtime hours are
being worked within limits of the TS.
The team also observed operators dividing up available overtime days i
among themselves. They were adhering to a plant administrative
limit of 60 work hours in any 7 consecutive days. This 60 hour6.944444e-4 days <br />0.0167 hours <br />9.920635e-5 weeks <br />2.283e-5 months <br />
limit is substantially below the TS limit of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> in 7 days. i
The operators stated that these administrative overtime limits are
in force during outages as well as when a unit is operating.
r. Scaffolding Controls
While walking through the plant, the team observed scaffolding that
was not tied down and had no kickboards. For example, scaffolding
in the 1A diesel generator room had a work platform that was
approximately six feet above the floor and had no kickboards. In
addition, this scaffolding was not tied down to prevent movement.
The team subsequently reviewed scaffolding controls with the
licensee. The licensee statad that the scaffolding control program
was recognized to be weak, and that an improvement effort was under- ;
way. Personnel safety items such as tiedowns and kickboards were to
'
be addressed in a forthcoming rewrite of scaffolding procedures. i
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The team inquired about scaffolding controls as related to potential
impact on operability of safety equipment. Three specific concerns
were discussed: additional loads placed on safety equipment,
physical interference with safety equipment, and seismic considera- 4
tions. The licensee has a program in place for evaluation of placing
additional loads (such as scaffolding) onto safety piping. This
program is implemented by Station Directive 3.8.17, Installation of
Temporary Loads, revision 4. The licensee also tas procedures that
address physical interference with safety equipment (ie. by obstruct-
ing a travelling valve stem): Station Directive 3.8.12 and also
Station Directive 2.11.6, General Scaffold Guidelines, revision 3.
In addition, the licensee stated that the crews of scaffolding
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l builders are aware of equipment operability concerns and have demon-
strated the knowledge needed to be able to build scaffolds without
affecting the operation of equipment.
The potential seismic impact of scaffolding on the operability of
safety ' equipment was not addressed in the licensee's procedures.
l Since the scaffolding is not seismically qualified, the concern here
is that scaffolding erected over or near safety equipment could, in
a seismic event, reduce the functioning of the safety equipment.
This concern is addressed in NRC Regulatory Guide 1.29, to which the
licensee has committed. The failure of the licensee's procedures to
address seismic impact of scaffolding on operability of safety
equipment is considered to be a weakness. This item will be followed
up under IFI 50-413,414/89-09-09.
s. DC Electrical Ground Faults
In the control room, the team observed a unit 2 lit annunciator,
"125 V ESS PWR Channel A Trouble", that indicated an existing vital
de system electrical ground fault. The licensee was aware of the
ground fault and had recently initiated an MWR to locate and repair
it. The team then discussed vital de ground faults in general with
licensed operators, cognizant I&E engineers, and the cognizant I&E
foreman, Discussions covered safety significance, IEN 88-86,
frequency and duration of ground fault occurrences, policy and
procedures, methods of detecting and locating, annunciator setpoint
and calibration, types and sensitivity of ground locating equipment,
and IEN 88-86 Supplement 1. The licensee had procedures in place to
identify and correct ground faults. However the procedures and
practices did not include the use of any portable ground locating
equipment, such as is used by other plants, including the licensee's
sister plant, McGuire. The use of this equipment would enable ground
faults to be located and isolated much more expeditiously. The
licensee stated that vital dc ground faults are likely to take a
week or more to locate, due to waiting for operations to open
breakers. Use of portable equipment would not require opening
breakers and would enable ground faults to be located and repaired
within one or two days. The team considered the use of portable de
ground fault locating equipment as a much needed improvement, with
direct safety importance. This item will be followed up under IFI
50-413,414/89-09-10.
t. Safety Rtview Group
The team observed a meeting of the Safety Review Group. The subject
of the meeting was a review of draft LER 413/89-011, titled "Techni-
cal Specification Viciation for Lower Containment Compensatory Action
Not Being Performed due to Failure to Notify Appropriate Personnel".
This event centers around a large number of :ontainment fire detector
failing. In two samples, 37% and 50% were found to be out of cali-
bration. Design Engineering had sent a letter to Compliance stating
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th'at both- unit 1 and unit 2 lower containment fire detectors should ,
be considered inoperable; _ Compliance-then sent a Technical Specifi-
cation Operability Notification Sheet to unit. 2 operators. but not
unit 1. As a result, unit 2 operators conducted the 'TS required
hourly temperature monitoring in lower -' containment but: unit 1
operators did not. ' The failure of . Compliance to notify unit l'
operators 'was identified and discussed' as the only root. cause of
this event.
.The failed : detectors were Hochiki model SIF-24F. Ionization Smoke
Detectors, which .had been installed throughout the Containment
Buildings. Turbine Building, Auxiliary Building, and. Service-
F
Building in 1987.
'l
In' January 1989, a high failure rate of the detectors located _in the
Containment Buildings was recognized. In February 1989, Hochiki
Electroni.cs determined the.cause of the failures to be a high level
of radiation. The licensee plans to replace the Hochiki ionization.
detectors in the containments with more reliable photoe'lectric type
~ detectors, as recommended by the manufacturer.
The team observed the discussion- among the Safety Review Group
members to. be lively, open, and focused on the details and wording
of. the LER. However, the team noted that a significant root cause
of this event had been overlooked - the purchase of the. Hochiki
detectors for use in containment. Had the purchase order correctly
specified the environmental conditions ' (including radiation) in
-
which these detectors were to be operated? Are incorrect purchase
order: specifications for safety. equipment a recurring problem?. The.
team considered that the identification of all contributory causes
i of. a event and accomplishment _ of complete corrective actions to
prevent recurrence are the most safety significant parts of an LER.
The Safety Review Group stated that they would investigate the
purchasing of these detectors.
The team reviewed approximately- two hundred licensee LERs, and found .
them generally to be well written and complete. Only one other
case of overlooking a major root cause and corrective action was
identified. The team judged that this instance of incomplete identi-
fication of root cause and needed corrective action was an isolated
case.
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In the area of Operations, . one violation (paragraph. 2.k) and no devia-
tions were identified.
3. Emergency Operating Procedures (42700, 2515/92)
a. E0P/GTG Comparison
The team reviewed the relationship between the Catawba E0Ps and the
plant specific technical guidelines (PSTG). The Catawba PSTG was
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developed from Revision 1 of'the ERG by the safety analysis group at
the Duke' Power general office. The PSTG incorporates a number of
additions to, deletions from, and restructuring of the ERG resulting
from:
- plant-specific design differences
preference for some elements of ERG Revision 0
engineering evaluations
operating philosophy
operating experience
experience with other vendor guidelines
verification and validation activities
Those changes determined by the safety analysis group to be safety
significant were justified in two deviation documents, dated June
and July 1984 In addition, plant specific setpoints were developed
by the safety analysis group for use in converting the ERG into the
Catawba PSTG. However, the document, " Emergency Procedure Guideline
Setpoints," was not approved until May 1986. Duke Power identified
one incorrect setpoint, pressurizer level, in the original revision
of the Catawba E0Ps, and the E0Ps were subsequently corrected.
Production of the upgraded Catawba E0Ps from the PSTG was conducted
by the document development group of the Catawba operations section
in parallel with PS1G development. E0Ps were produced by application
of the principles in the Catawba writer's guide to the technical
information in the PSTG. Following completion of the E0Ps in January
1984, verification and validation of the procedures began, with
implementation of the procedures on Unit 1 in May 1984.
A description of the PSTG was submitted for NRC approval as part
of the PGP in February 1983. Upon the request of the NRC, the
deviations document was provided for review. Subsequently, the NRC
required that the deviations document be revised to be based upon
Revision 0 of the ERG. In this version, some deviations were
included by Duke Power due to preference for the Revision 1 ERG
approach. Several requests for additional information were made by
the NRC. In SER Supplement 6, dated May 1986, the NRC concluded
that all information received on the PSTG was complete and adequate
at that time.
The team con. pared the Catawba E0Ps to the ERG to verify that the
L accident mitigation sequence of the ERG was represented in the E0Ps.
The E0Ps were determined to adequately cover the broad range of
accidents and equipment failures addressed in the ERG.
The role of Duke QA in the development of the PSTG and upgraded
E0Ps was reviewed. There was no documented QA involvement in the
development of the Catawba PSTG. The QA departacnt at Duke General
Office reports performing an overview of the McGuire PSTG, which was
reported to be a similar process, but has no record of any direct
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involvement in the? Catawba PSTG - development. ' However,. the team
found that adequate management controls ~ (general office safety
analysis group oversight, Catawba- document development group) had
been applied in' lieu of QA involvement.
The ' team compared ' the E0Ps to the Catawba PSTG .and found many,
p differences, where there should be none. These differences are
L 11dentified by the designation "PSTG DEV" in apper. dix B. The. team
i. did not - consider the numerous instances of a single PSTG step which -
had been broken out to multiple steps ir the E0P. as constituting - ,
' di f ferc.nce s . An assessment of this comparison will be performed
during a future inspection under IFI- 50-413,414/89-09-11.
The' current: Catawba writer's guide applies to both E0Ps and A0Ps.
- Review = of the E0Ps. against- the requirements of the writer's guide
identified a variety of deviations. The_. most significant and
. consistent .of these ' is the . improper structure. and applic3.an of
cautions and notes (paragraph 3.b). This weakness 1 suggests a lack
of verification against the writer's. guide.
'.The relationship . of procedure nomenclature to the control room.
. labeling was found'to be clear-and consistent.
The.AOPs contained many.more deviations from the writer's guide than-
did the E0Ps.- Every aspect of the A0Ps contained examples of lack
of conformance to guidance, as well as, inconsistencies within and
between the AUPs.. The Catawba staff stated that the- A0Ps had neither
been rewritten nor verified to correspond to' the writer's guide and
-
-that the schedule for upgrading the AOPs has been receatedly~ delayed
due'to reprioritization. The team finds this delay undesirable.
b. -Independent technical adequacy review of the E0Ps
The team. reviewed the procedures listed in Appendix A and found that
generally the vendor recommended accident mitigation strategy was
followed. However, the team identified many instances where the
vendor recommended action sequence was not followed. Although some
of these action sequence variations were cited in the deviation
document, many of these variations were not - documented. Another
variation from the vendor guidance was the lack of entry conditions
contained in the E0Ps. The two entry pointy were E-0 and ECA 0.0.
These procedures listed symptoms which would require implementation
of the procedures but did not have definitive entry conditions as in
the ERG and the PSTG. Some of these variations are identified in
appendix B and will be resolved under IFI 50-413,414/89-09-12.
Cautions and notes were consistently incorrect in application of the
writers guide. In'some cases cautions were actually notes or action '
steps required in the step sequence. Notes were at times actually
cautions or procedure steps. Some notes and cautions that were !
appropriately . labeled as such lacked conformance to the writer's J
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guide. For example, cautions were generally found lacking identifi-
cation of the potential hazard to equipment or personnel as required
by t'e writer's _ guide, and both notes and cautions were written
containing action steps -or conditional steps also contrary to the
writer's guide. Specific examples are delineated in Appendix B.
Peacekeeping deficiencies were identified during the simulator
inspection. of the E0Ps and are discussed in paragraph 3.d. No
deficiencies in the control room usage of peacekeeping aids were
identified.
The degree of adherence to the guidance in the ERG was found to be
generally acceptable although, as documented in Appendix B, many
undocumented deviations existed.
Operator action setpoint values were contained in the Catawba set-
point document and associated engineering calculation sheets. These
values were used in the E0Ps except for the few instances noted in
the appendices.
Control room drawings were inspected to verify that E0P specified
components were accurately typified.
The team found that the safety significant deviations identified by
the licensee had been reported to the NRC. Safety Evaluations for
these deviations were not inspected.
c. Review of the E0Ps by inplant and Control Room walkthroughs
Inplant and Control Room walkthroughs of the emergency and abnormal
procedures listed in appendix A were conducted. Generally, the
nomenclature appeared to be consistent between the procedures and
the instrumentation and labeling on the control board. The discrep-
ancies noted were enumerated in appendix D. The licensee committed
to review these and make changes as appropriate. Resolution of this
issue is identified as IFI 50-413,414/89-09-13.
Indications, annunciators and controls referenced in the E0Ps were
found to be available to the operators. One set of emergency and
abnormal procedures was maintained in the Control Room at all times
for each unit. These procedures were verified to be the latest
revision. A discrepancy between step C.4, RNO, of procedure
EP/1/A/5000/01, Reactor Trip of Safety Injection and the S/G pressure
meter in the Control Room was found during the walkthrough. This
1 item had previously been identified co the licensee in August 1987 :
l but had not been resolved. Resolution of this issue wil' be identi-
L fied as IFI 50-413,414/89-09-14.
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While the: results of the walkthroughs were generally' positive, some
discrepancies ; in the' areas of technical adequacy, writer's guide,-
adherence and human factors were noted. Technical and human factors
discrepancies are noted in appendix B while. writer's guide discrep-
ancies 'are noted in appendix C. .The licensee has committed' to
consider 'the. discrepanc-les identified in the -aforementioned
,: appendices. Appendix C discrepancies will' be' identified as' IFI-
50-413,414/89-09-15. <
Operators' stated that the level of noise in the Control Room caused -
by auto-start .'of both.. ventilation trains during S/I response ~ is
.
cxcessive and requires shouting _ for audible communications between
personnel. Problem Investigation Report serial number;0-C-89-0145
dated April 12,. 1989, had been' submitted to Duke Power design-
engineering L for evaluation and correction. The design engineering
staff reported that a sound survey during use of both trains of
' control room ventilation _ is currently being scheduled and that
necessary action:will be based on analysis of sound survey findings.
This item will be' identified as IFI' 50-413,414/89-09-16.
Due to time constraints, many of the aspects of thE validation and
verification program that were applied to the development of the
E0Ps were not inspected in' depth. Deficiencies in ' connection with
the licensee's ongoing evaluation of the E0Ps are identified in
paragraph 3.e.
d. Simulator Observations
The -team observed a crew performing the following five scenarios on-
~
the Catawba simulator:
(1) Steamline break outside containment
(2) Loss of all ac power
(3) S/G tube leak
(4) S/G tube rupture with a steam line break.
(5) Natural circulation cooldown with a void in the reactor head
The procedures provided operators with sufficient guidance to fulfill
their responsibilities and . required actions during the emergencies,
both individually and as a team.
The procedt.res did not cause the operators to physically interfere
with each other while performing the E0Ps and AOPs. However, the
concurrent use of several AOPs resulted in operators responding to
'
, the directions of more than one person at a time.
The procedures did not duplicate operator actions unless required
(e.g. , for independent verification).
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When a transition from one E0P to another E0P or other procedure was
required, precautions were taken to ensure that all necessary steps,
prerequisites, initial conditions, etc. were met. However, the
method of filing procedures made it possible for an operator to
select the wrong procedure from the filing cabinet in the simulator
'
Control Room. Operators were found to be knowledgeable about where
to enter and exit the procedures.
1
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It was observed that the entry symptoms contained in the E0Ps were
not sufficiently clear to preclude an operator from inadvertent
implementation of certain procedures. An inconsistency between the
plant and simulator existed in that peacekeeping used in the plant
for E0Ps and required by the PSTG was not used in the simulator.
Deficiencies in 1) concurrent use of several AOPs, 2) procedure
filing and 3) clarity of entry conditions will be identified as IFI
50-413,414/89-09-17.
Activities that should occur outside the control room were initiated
by the operators and proper confirmation of their completion was
given. These actions were inspected during in plant walkthroughs of
the procedures. However, one deficiency was noted in that the
simulator was unable to simulate the local closing of NV-295 on
malfunction of NV-294. This deficiency prevented the proper
completion of the planned scenario.
e. The team reviewed audit cccumentation and conducted interviews to
determine the quality assurance measures taken to assure that the
emergency procedures were adequate and that they met the require-
ments of the Procedure Generation Package (PGP). The team found
that the QA organization conducts audits at periodic intervals. The
adequacy of these audits was not examined in detail.
The team verified that the PSTG and the set point document are
controlled documents. Station master files, retain E0P retypes and
V & V associated with the E0Ps.
f. E0P user interviews
The team conducted interviews with six licensed operators. The
operators felt that the E0Ps had been improved with the recent revi-
sion. Those interviewed expressed their belief that the level of
detail.in the E0Ps was adequate for and compatible with the level of
knowledge of the typical operator. Overall, the operators had confi-
dence in the ability of the E0Ps to perform their intended function.
The operators noted that the A0Ps are not at the same useability
level as the E0Ps. Those interviewed felt that an upgrade to the
AOPs similar to that which the E0Ps received would be beneficial.
In the area of Emergency Operating Procedures there were no violations or
deviations noted.
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-4. Support of Plant Operations (62700,42700,37700)
a. Maintenance interviews
Interviews were conducted with mechanics, IAE technicians, . and
maintenance supervisors and managers. The interviews concentrated
on maintenance training and retraining, overtime, supervision,
operations / maintenance interface, and staffing. Some strengths and
weaknesses were identified during these interviews and are discussed
below.
Interviews with four mechanics and four IAE ' technicians indicated
that there is a good working relationship between the various plant
work groups (i.e. operations, maintenance, health physics, and
engineering). All who were interviewed conveyed a " team effort"
attitude. All felt that they worked together well to operate and-
maintain the plant. This attitude was determined by the team to be
a strength and overall performance should improve as the groups
continue to work together.
The mechanics and technicians stated that they feel that plant
management has taken measures to emphasize procedural compliance and
independent verification. Maintenance personnel were provided
training sessions on these topics, and discussions are periodically
conducted at the daily crew meetings.
During an interview with an IAE supervisor, an incident was used to
demonstrate management's commitment to ensure compliance with the
independent verification program. In this incident, two technicians
were found to have violated the independent verification program and
were given written reprimands that were placed in their personnel
files. This action by management impressed upon plant personne) ,
that management was serious about compliance with the independent '
verification program, as well as, procedural compliance. This was
seen by the team as a strength. '
Discussions with the mechanics and technicians revealed differing
attitudes with regard to overtime. Management has taken steps to
reduce the amount of overtime for plant personnel as a result' of
discussions with the NRC Resident Inspector. Prior to taking action
to reduce the emount of overtime, there were instances of personnel
exceeding the T.S. limits on overtime. As a result of management's
actions, some of the mechanics and technicians enjoy the reduction
in overtime, while others feel there is not enough. The first line ,
i
supervisors expressed the feeling that they had sufficient staffing
to handle the day to day maintenance requirements, but that increased
staffing would be needed for outages in order to comply with the
requirements on overtime and to perform the outage work on schedule. 1
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The mechanics and technicians expressed. dissatisfaction with the
manner in which the training and . qualification program (ETQS) was
being implemented. They did state that they felt that the objective j
of the program was good and that once the bugs get worked out, it
will be beneficial. They stated that they . did, not ' feel- that the
.
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time requirements for completing. the program were fair This was
because .they felt that certain requirements could not be - met in a
- . two year period. Additionally, they expressed. concern that they may
lose positional status or promotional opportunity if they did not ,
meet the time restraints.
Discussions with the supervisors of these men indicated that the
mechanics and technicians did not fully understand the program '4
and its requirements. Some of the concern expressed by them was-
unjustified, according to the supervisors. The supervisors stated -
that some of concerns were due to the program changing several-
, times in order to improve it. Other concerns were due to the plant
personnel. responding to the personnel that were brought in from'CMD.
When the CMD personnel were informed of the program they apparently-
misunderstood how the program was to work. The CMD personnel then
discussed. their understanding of the program with the. permanent
pl. ant personnel and the problem grew. The. supervisors stated that
had management communicated the intents and requirements of the
program better, there would not have been- as much adversity. The
supervisors also stated that no one would lose positional status or
promotional opportunity by not . completing the program within the
requirnd time frame. They said that this was another case of
misunderstanding what was promulgated by management.
Discussions with the Maintenance Manager indicated that the licensee
was already aware of the problem and was taking steps to correct it.
The-weakness was in the Employee Training and Qualification System
(ETQS) and was due, according to the Maintenance . Manager, to the
program being in a state of flux as a result of reevaluation of the
system. Management is attempting to improve the system by making
the requirements for completing the tasks more consistent and
relative to job performance. Additionally, management is evaluating
'the time requirements for completing the qualification program and
how to deal with those that are delinquent in their qualifications.
The ETQS for IAE is scheduled to be implemented by June, 1989, while
that for mechanical W ntenance is scheduled for January, 1990.
There is a possibility that the implementation of the IAE system
wi? ' be delayed to January,1990, but no decision had been reached
at the time of the inspection.
Every mechanic and technician expressed a feeling that their first
line supervisor was the best possible. All were supportive of the
first line supervisors, but expressed some dissatisfaction with
upper management. This dissatisfaction was concentrated in two main
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areas. One was the ETQS discussed above, and the other was the
change of ' shift assignments and shift schedule for: the current
outage.
The IAE ' technicians stated that they were dissatisfied with manage-
ment's- decision to alter the shift schedule and assignments. The
supervisors of these technicians stated that it'was only a perception
that the technicians would lose some overtime. _ The supervisors also
stated that- the problem could have been avoided if there had been
better communications among those involved in making the decisions
and those that the decisions affected.
The first 'lin'e supervisors, in general, felt that their supervision
was supportive, but felt that first line supervisors were not .
included enough in some decision making processes. They felt .that
if they were included more, they could help correct problems .that
arose due to misunderstanding the intent of what was to be _imple-
mented. This feeling apparently was also due to poor communications
. because their supervisor, when interviewed, stated that 'the first.
line supervisors were included in the process but may rot be aware-
of it.
The interviews 1 indicated that upper management may not have a working
l' . feedback loop .in the communication path to ensure that the: communi-
- cated ' idea was received and understood properly. Discussions with
'
the Mechanical and IAE Supervisors and the Maintenance Manager
identified this as a ' potential problem. They agreed that the
communication path may have a missing link and that.it was a weakness
that would be investigated and resolved.
Following are the strengths identified during. the interviews and
observations. There is an attitude of being on the same team and
everyone working together to achieve a common . goal . Management
. tries to take an active role in the daily operation of the plant.
Management .is serious' about enforcing procedural compliance and
independent verification. And, lastly, management is trying to
improve the qualification program for mechanics and technicians.
Only two weaknesses were identified during the interviews and
observations. These were the present state of the qualification
program, and the problems with communications. These issues will be
'
followed up under IFI 50-413,414/89-09-18.
b. Nuclear Station Modifications
As of April 11, 1989, there were 141 active NSMs for the Catawba
project. Of these,17 safety related . isms were " Design Complete -
Not Ready to Work", and 34 safety related NSMs were " Design Complete
- Not Installed", for a total of 51. active safety related NSMs. The
team reviewed two NSMs for compliance with the requirements of the
Nuclear Station Modification Manual (NSMM) and Catawba Nuclear
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Station Directive (CNSD). The NSMs were: NSM #CN-11042, Rev. O,
Replace Valves IKC50A and 1KC53B with 20" Possiseal Valves; and, NSM
- CN-11159, Rev. O, Replace Reactor Vessel Nonle Inspection Hatch
' Covers.
Engi.neering Safety Evaluations for the NSM were thorough, addressing
the potential affect on the FSAR and Technical Specifications
as well as unreviewed safety questions. . The NSMs contained the -
neces sary . documentation and were normally completed . as required
by the procedures. There was one example, NSM #CN-11159, which
was completed on November 29, 1988, and the -affected procedure,
MP/1/A/750/42 had not been revised as of April 28, 1989. This is
considered to be an isolated case and the team concluded -that the
NSM program was satisfactory.
c. Temporary Station Modifications (TSMs)
As of April 11, 1989, there were 131 active TSMs, of which 33 were
. safety related. Of the 131 active TSMs, 68 were older than 16
months, with 7 being safety related. CNSD 4.4.5, Rev. O, Temporary
Station Modifications, dated July 5, 1988, states that temporary
modifications should not be installed for more than 12 months for
those not requiring -an outage, or. the next refueling outage for
those that do require an outage for removal. The licensee stated
that the intent was to apply the directive to all new TSMsj and-
to work at reducing the number of existing TSMs. A meeting was
scheduled for May 24, 1989, to discuss reducing the number of active
NSMs and TSMs. The high number of TSMs and the duration of time
some are open is considered a weakness. This issue will be followed
up under IFI 50-413,414/89-09-19.
Two TSMs were randcmly selected to determine the effectiveness of
the control and documentation of TSMs. The modifications selected
were WR# 007121, Replace SSF Diesel Water Jacket Heater Model
- 3P5-0600 with Model #C5033-050; and, WR# 009389, Replace VI Pressure
Regulator (PR-2) with Fairchild Model 80P. Both were found to be
adequate and documentation was completea as per CNSD 4.4.5 and NSMM
j Section 9.
Fifteen safety related TSMs were selected to review the affected
control room drawings. The drawings were reviewed to verify proper
reference to or red lining of the applicable TSM on the affected
,
drawing. No discrepancies were noted during this check. A complete
! review of control room drawings for the effects of all types of
f
'
plant modifications was not conducted by the team due to issues
in this area which had already ' oeen addressed by the resident
inspectors. The results of their review of the area is documented by
a violation in their April,1989 monthly inspection report.
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d. Licensee Event Reports and Potentially Reportable Events
The team examined the licensee's administrative control programs for
review, investigation, and reporting of non-routine events to assure
conformance with regulatory requirements and to assess its efficiency
in increasing equipment reliability through correct identification
of root causes and by initiating appropriate corrective actions. The
program was'being applied to a number of events which were the scope
of the team's evaluation. These events occurred between August 1,
1988, and April 24, 1989.
The number of events reported during the previous SALP period was
68. The number reported during the 9 month sample performed for
this inspection was 23. The percentage of personnel errors remained
constant at approximately 33%, however, the percentage of procedural
deficiencies increased from approximately 3% to approximately 17%.
The reduction of total LERs indicates that the licensee is making an
effort to reduce reportable events. However, the increase in
procedural deficiencies indicates that a review of procedures !s
warranted. The licensee had realized this also and was in the
process of performing the necessary reviews and procedural upgrades.
The area of potentially reportable events is covered by the Problem
Identification Report (PIR) program. This program is governed by
CNSD 2.8.1 which describes the problem identification ard assignment
of the responsible group to investigate the problem. The FIR program
serves as the basis for the processing, evaluating, and resolving of
any identified problem. The PIR program also includes provisions for
recognizing and reporting events covered by 10 CFR 50.73, as well as,
10 CFR 21 and other reporting requirements.
e. Preventive / Predictive Maintenance Programs
The team reviewed the licensee's preventive / predictive maintenance
programs in an effort to assess management initiatives to improve
the availability and reliability of equipment service. The team
determined that the licensee has well established maintenance
programs.
The Standing Work Request (SWR) program is used to schedule, track,
and document routinely performed preventive maintenance tasks.
Daily, an SWR report is generated that contains a complete listing
of all maintenance, pe.riodic testing, and scheduling records, as
well as, the associated schedule dates. The weekly periodic test
report contains the completion dates for all surveillance from
the previous week and/or surveillance requirements not previously
reported. An overdue report is run daily to identify any required
SWR item that has reached or exceeded the earliest date. As of
April 24, 1989, the team verified that there were no T.S. items
overdue, and only a few backlogged PM items.
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The licensee has. a ' computerized ' program to assist .in . scheduling PM
items.. The' program calculates the earliest. start date and the late
date, to ensure that the requirement does not exceed any T.S. limit.
This' includes the 3.25 times the periodicity for three consecutive
.. times. - Any requirements that have' been missed to date' have not been
the result of lack of scheduling, but due to other factors. (i.e.
personnel error, plant conditions, lack of parts).
The team discussed the predictive maintenance program with plant .
. personnel. .The goal of the program is to provide a structure for
monitoring and evaluating rotating' and. reciprocating equipment' in -
order to aid.in predicting equipment failure. ~
- The predictive ' maintenance program consists- of oil analysis' and
vibration . analysi s . and trending. During 1988, ' performance trending
was conducted on. approximately 300.. components. The licensee has a'
plan' that will expand the program wo include more high maintenance
components in the vibration analysis database and to also purchate
additional diagnostic . equipment. Management has provided excellent
support:to this effort in order to insure its success.
f. Information Notices (ins)
Information Notices are useful in avoiding fmaking the same mistakes.
that others have made, as well as, providing for increased equipment-
availability. The team examWed the licensee's program for review,
response, and resolution of ins. A random selection of six notices
issued during the previous.18 months was performed and the applicable
notices were reviewed.
The following lists the ins selected.
IN 89-08 Pump Damage Caused by Low Flow Operation, January 26,
1989.
IN 88-86 Operating With Multiple Grounds in Direct Current
Distribution Systems, October 21, 1988.
IN 88-74 Potential Inadequate Performance of ECCS in PWRs
During Recirculation Operation Following a LOCA,
September 14, 1988.
IN 88-34 Nuclear Material Control and Accountability 'of
l Non-fuel Special Nuclear Material at Power Reactors,
May 31, 1988.
l
IN 87-60 Depressurization of Reactor Coolant System in PWRs,
e December 4, 1987.
IN 87-53 Auxiliary Feedwater Pump Trips Resulting from Low ,
Suction Pressure, October 20, 1987. l
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The team verified that the Nuclear Safety Section of the Nuclear
Safety Assurance Group at 'the General Office coordinates the
processing of ins. 'This requires inputs from various plant sections,
including Design / Technical Services Engineering Support, Production
Training Services, and . Regulatory C )mpliance. Applicable ins are
distributed to the appropriate station work group for information,
for additional input, or for corrective action if necessary.
The team determined that the licensee reviewed the subject ins in a
timely manner and any actions that were required were also performed
in a timely manner.
- g. Backlog Status of Maintenance Work Requests (MWRs)
The team reviewed the status of d- MWR backlog and the adequacy of
the assignment of priorities to MWRs. The status of outstanding MWRs
is published biweekly by the Integrated Scheduling Group. The MWRs
are categorized based on whether the work '+ Corrective Maintenance -
Non-outage, Corrective Maintenance - Outage, Preventive Maintenance,
or Modification. Although the number of MWRs outstanding appeared
large, Catawba is average compared to the INPO guidelines.
As of April 24, 1989, there were 5,332 outstanding MWRs. These can
be divided-into: 1,953 Corrective Non-outage; 1,994 Outage; 504 PM;
and 881 Modification. As of May 4, 1989, the Outage MWRs outstanding
had been reduced to 1,646, with many of those (approximately 600)
waiting for functional testing. The ratio of Non-outage MWRs greater
than 90 days to the total number of Non-outage MWRs has remained
approximately constant at approximately 45%, which is better than the !
INP0 guideline of 52%. Although the raw data is not encouraging '
(proper management of over 5000 items is very difficult), team review
of the details of this backlog determined that the licensee does have
control ever the backlog and is actively pursuing means to reduce it.
The I,tegrated Scheduling Group conducts a daily review df out-
standing MWRs by priority code and works with Operations and other
departments to determine which MWRs could be worked in conjunction
with plant availability. This was considered to be a strong point ;
by the team. I
Priorities are established based on the classification of the
component and the nature of the work. Priority 1, 2 and 2X are
assigned to work requests of a critical nature and to safety related
equipment. Priority 3 is assigned to work that will improve plant ,
performance or is for preventive maintenance. Priority 4 or 5 are '
for non-critical work with Priority 5 being used to designate outage
related work. The team concluded that the licensee adequately
prioritized MWRs.
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h. Work Requests
The work request system was reviewed to determine work flow from
origination of a work request at the time _of discovery of a problem
with plant equipment, through the actual repair. Maintenance
Management Procedure 1.0, Revision 25, dated January 13, 1989, " Work
Request Preparation", and Operations Management Procedure 2-3,
Revision 2, dated March 22, 1988, " Operations Work Req. ;ts", were
reviewed. Interviews were conducted with personnel from cperations,
the Shift Manager, the Unit Operations Manager, the Mechanical
Planners, Integrated Scheduling, and a maintenance crew was observed
working WRs. '
The WRs observed were 10274 SWR for cleaning and inspection of the
IVGHXB002 aftercooler tubes, and 503490PS for replacement of a
diaphragm on IVGCPB002 Diesel Air Start Compressors. The mechanics i
were knowledgeable of the equipment and the tasks. The mechanics l
familic.rity with the task led to performance of maintenance without i
removing the procedure from its bag or opening it. The team reviewed ;
the procedure and determined all appropriate sign-offs had been made,
and no procedural errors had been committed.
Several strengths were noted in the WR process. The' hanging of
orange Work Request ID Tags on affected equipment helps alert others
using the equipment of its status and helps avoid duplication of
WRs. The planner's inspection of the defective equipment during the
job planning phase is a strength. The concept of working items by
train or division in a weekly rotation should help to limit problems
with two trains being inoperable at the same time. The trip list
concept is good, but could potentially be expanded to include system
inoperable work lists to take advantage of system outages, as well
as unit outages. The working groups rotating shifts together is a
strength, in that interpersonal relationships and a feelin; of
teamwork can be deve'noad.
The veakness noted in this area was the mechanical maintenance
meckonics use of procedures. Although no procedural errors were
discovered, the crews did not have the procedures open while the work
was being perfornied. Management needs to work harder to encourage
full utilization of procedures, and encourage the mechanics to pro-
vide feedback in case of inadequacies in the detail of procedures
for covering the assigned task.
1. Planning Meetings
The team observed several planning meetings. Among the meetings
observed were the daily planning meeting, the morning outage
meeting, and the operating units morning meeting. The meetings were
short, to the point, and effective. Participants were well prepared
for discussion of items, and kept comments focused.
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.j. Transmission Group
.The . team inter. viewed the Transmission Group supervisor. ' Transmission
'does not have ' direct reporting to management. on the plant ' site, ;
but is a separate corporate group'. The group provides maintenance
services for. components of greater than 600VAC!and the 1250C breaker.
control power co'aponents and relaying. The technicians work , both '
nuclear and non-nuclear facilities in the Duke . system. -Transmission-
has its own procedures, training program, -and equipment calibration
program. Changes to' the station Mechanical or IAE groups programs
may not be reflected in Transmission, due to 'its separate nature and ,
. reporting- authority. Transmission has a fraction of the resources 1
available for. procedure upgrades, training, or maintenance of test ,I
equipment- that is available to other onsite maintenance groups. 'I
j
The limited resources available to support these activit4s, which
are considered normal overhead for a nuclear - plants maintenance
group, will increase the need for monitoring 'to insure co.:pliance in
safety related activities the group performs. The separate reporting
authority. and duplication of support functions of Transmission !
>
is considered a : weakness. This item will be ' followed - up under
IFI 50-413, 414/89-09-20.
.k. Management support of Engineering
Interviews conducted with Design Engineering, Performance Engineer-
ing, and Maintenance Engineering, showed plant management-to be very
supportive of these groups. Maintenance Engineering was encouraged
to develop a Predictive Maintenance program. Funding for equipment '
was provided, and the group .was allowed to dedicate engineering
staffing full time to the program. Maintenance Engineering was
reorganized by component type to allow component expertise to
develop..
Performance Engineering was provided support to fully implement a
system engineer or system expert program. These experts use system
requirements to evaluate equipment. In conjunction with the ]
component engineers from maintenance, this provides for a matrix for. <
the evaluation. of plant equipment. This will allow both component ;
and system limitations to be considered in evaluations. )
l
Interviews with Design Engineering stowed plant management is
encouraging all groups onsite to work as a team in problem i
resolution.
/ !
After interviewing the engineering groups, the plant manager was
interviewed. He stressed a continuing concept of all the groups _ i
wor king together to support plant operations. Congruence of goals
in the different plant engineering groups with support of plant
management is a strength.
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1. 10 CFR 50.59 training
The plant is currently developing a program for certification of
individuals to perform 10 CFR 50.59 evaluations. Knowledge of
requirements and methods of performing the evaluations are being
taught to individuals who, upon completion of training, will be
certified ' level III' evaluators. This program is seen as a
strength, as it will allow for more consistent evaluations.
In the area of Plant Support there were no violations or deviations
noted.
5. Action on Previous Inspection Findings (92701, 92702)
(Closed) DEV. 413,414/87-13-01, Failure to meet commitments of the
approved PGP. The licensee provided documentation which indicatad that
appropriate corrective actions had been taken.
(Closed) VIO. 413,414/87-13-02, Failure to provide adequate training on
calculation of subcooling margin. The licensee provided documentation
which indicated that appropriate corrective actions had been taken.
(Closed) IFI 413,414/87-21-01, Design and implementation of corrections
to identified human engineering deficiencies. The licensee provided
' documentation which indicated that appropril 3 corrective actions had
been taken.
6. Exit Interview (30703)
The inspection scope and findings for both the E0P and Operations / Support
portions of this inspection were summarized in separate pre-exit inter-
views during the inspection. The findings were again summarized with
those persons indicated in paragraph 1 at the formal exit on May 16,
1989. The NRC described the areas inspected and discussed in detail the
inspection . findings. Although proprietary material was reviewed during )
this inspection, no proprietary material is contained in this report. j
i
Item Number Status Description / Reference Paragraph
VIO 413/89-09-01 Open Valve 1-KC-9 found unlocked
(paragraph 2.k) and operators
not frisking immediately after
exiting contaminated areas l
(paragraph 2.e) l
IFI 413,414/89-09-02 Closed Cold Leg Accumulator Boron
concentration adjustment made
- with a weak written procedure
(paragraph 2.a)
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Item Number Status Description / Reference paragraph
IFI 413,414/89-09-03 Open Thermal power computer calibration
inputs not tracked on computerized
tracking system (paragraph 2.b)
IFI 413,414/89-09-04 Open Weak 10 CFR 50.59 evaluation on
Nuclear Service Water Modification
(paragraph 2.c)
IFI 413,414/89-09-05 Oper. Many of the sites safety related
pump rooms are contaminated
(paragraph 2.e)
IFI 413,414/89-09-06 Open Weak control of fire doors
(paragraph 2.g)
IFI 413,414/89-09-07 Open Procedures for independent
verification need improvement
(paragraph 2.1)
IFI 413,414/89-09-08 Open Deficiencies noted during NS
PT (paragraph 2.m)
IFI 413,414/89-09-09 Open Control of scaffolding needs to
be improved (paragraph 2.r) ;
IFI 413,414/89-09-10 Open Site does not have DC ground fault
locating equipment (paragraph 2.s)
IFI 413,414/89-09-11 Open There are many differences between
the E0Ps and the PSTG (paragraph
3.a)
IFI 413,414/89-09-12 Open Correction of technical discrep-
ancies contained in the E0Ps as
outlined Appendix B (paragraph
3.b)
IFI 413,414/89-09-13 Open Correction of labeling discrep-
ancies betwcen E0Ps and panel
indication as outlined in
Appendix D (paragraph 3.c)
IFI 413,414/89-09-14 Open Correction of S/G pressure meter
'
indications (paragraph 3.c)
IFI 413,414/89-09-15 Open Correction of writer's guide
discrepancies contained in E0Ps
as outlined in Appendix C
(paragraph 3.c)
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Item Number Status Description / Reference-Paragraph
IFI 413,414/89-09-16 Open Resolve control room noise level
(paragraph 3.c)
1
I FI . 413,414/89-09-17 Open Review simulator. effectiveness in
training on E0Ps (paragraph 3.d)
IFI 413,414/89-09-18 Open Weaknesses noted in the site's
ETQS program (paragraph 4.a)
IFI 413,414/89-09-19 ' Open There are a significant number of
TSMs on site, some ranging in , age
of from 3 to 4 years. (paragraph
4.c)
- IFI-413,414/89-09-20 Cpen The seperate_ reporting authority
and duplication. of ' support
functions for the transmission
group is considered a weakness
(paragraph 4.j)
The following is a list' of the commitments. made by licensee _-personnel
during this inspection:
-
Licensee personnel committed to add calibration of themal power.
computer inputs'to the computerized periodic Test Program for Unit 1
(see paragraph 2.b).
-
Licensee personnel committed to sending Out of Calibration Notifica-
tion Forms for the _ Unit 1 thermal power computer inputs to the
systems Engineer ,(see paragraph 2.b).
-
Plant management committed to review the procedures for and practices
of plant operators concerning frisking when exiting contaminated -
areas (see paragraph 2.e).
-
The SRG committed to investigate the purchase of Hochiki Detectors as
a part of LER 413/89-011 (see paragraph 2.t).
The lice ;<e cumm, Lo&d t: r.<;ew and correct (as appropriate) the
'
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momemclature difficiencies in Appendix 0 (see paragraph 3.c and
Appendix D).
' -
The license committed to evaluate the discrepancies in Appendices B
and C (see paragraph 3.c and appendices B and C).
-
The licensee committed to resolve the conflict between EP/1/A/5000/01
and the markings on the S/G pressure meters (see Appendix B, para-
graph 1.g).
5
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APPENDIX A
PROCEDURES REVIEWED
AP/0/A/5500/20 LOSS OF NUCLEAR SERVICE WATER 10/29/87
AP/0/A/5500/22 LOSS OF INSTRUMENT AIR 06/02/88
AP/0/A/5500/31 ESTIMATE OF FAILED FUEL BASED ON I-131 02/19/88
CONCENTRATION
AP/0/A/5500/34 SECONDARY CHEMISTRY OUT OF SPECIFICATION 11/04/88
AP/1/A/5500/02 TURBINE GENERATOR TRIP 03/13/89
AP/1/A/5500/03 LOAD REJECTION 03/31/87
AP/1/A/5500/04 LOSS OF REACTOR COOLANT PUMP 10/20/86
AP/1/A/5500/05 ECCS ACTUATION DURING PLANT SHUTDOWN 06/18/87
AP/1/A/5500/06 LOSS OF S/G FEEDWATER 03/05/87 i
AP/1/A/5500/07 LOSS OF NORMAL POWER 06/06/88
AP/1/A/5500/08 MALFUNCTION OF REACTOR COOLANT PUMPS 08/18/86
AP/1/A/5500/10 REACTOR COOLANT LEAK 01/16/89
AP/1/A/5500/11 INADVERTENT NC SYSTEM DEPRESSURIZATION 03/13/89
AP/1/A/5500/12 LOSS OF CHARGING OR LETDOWN 04/02/86
AP/1/A/5500/13 BORON DILUTION 01/07/87
AP/1/A/5500/14 CONTROL ROD MISALIGNED 06/06/84
AP/1/A/5500/15 R00 CONTROL MALFUN TION 03/24/87
AP/1/A/5500/16 MALFUNCTION OF NUCL TR INSTRUMENTATION SYSTEM 11/07/87
AP/1/A/5500/17 LOSS OF CONTROL ROOM 01/31/89
AP/1/A/5500/18 HIGH ACTIVITY IN REACTOR COOLANT 03/15/88
AP/1/A/5500/19 LOSS OF RESIDUAL HEAT REMOVAL SYSTEM 11/30/88
AP/1/A/5500/21- LOSS OF COMPONENT COOLING 12/22/87
AP/1/A/5500/23 LOSS OF CONDENSER VACUUM 11/13/86
AP/1/A/5500/24 LOSS OF CONTAINMENT INTEGRITY 01/08/87
AP/1/A/5500/25 DAMAGE 0 SPENT FUEL 09/10/87
AP/1/A/5500/26 LOSS OF REFUELING CANAL OR SPENT FUEL POOL LEVEL 05/29/86
EP/1/A/5000/1 REACTOR TRIP OR SAFETY INJECTION 03/13/89
EP/1/A/5000/1A REACTOR TRIP RESPONSES 03/13/89
EP/1/A/5000/1A1 NATURAL CIRCULATION C00LDOWN 03/13/89
EP/1/A/5000/1B S/I TERMINATION FOLLOWING SPURIOUS S/I 03/13/89
EP/1/A/5000/1C HIGH-ENERGY LINE BREAK INSIDE CONTAINMENT 08/01/88
EP/1/A/5000/1C1 S/I TERMINATION FOLLOWING HIGH-ENERGY LINE BREAK 08/01/88
IN CONTAINMENT
EP/1/A/5000/1C2 POST LOCA C00LDOWN AND DEPRESSURIZATION 03/01/89
EP/1/A/5000/1C3 TRANSFER TO COLD LEG RECIRCULATION 08/01/88
EP/1/A/5000/1C4 TRANSFER TO HOT LEG RECIRCULATION 08/01/88
EP/1/A/5000/1C5 LOSS OF EMERGENCY COOLANT RECIRCULATION 08/01/88 !
EP/1/A/5000/1C6 LOCA OUTSIDE CONTAINMENT 08/01/88 l
EP/1/A/5000/10 STEAM LINE BREAK OUTSIDE CONTAINMENT 03/13/89
EP/1/A/5000/1D1 S/I TERMINATION FOLLOWING STEAM LINE BREAK 08/01/88
EP/1/A/5000/1E STEAM GENERATOR TUBE RUPTURE 03/01/89 '
EP/1/A/5000/1El POST-S/G TR ALTERNATE C00LDOWN AND 03/13/89 ;
REPRESSURIZATION l
EP/1/A/5000/IE2 S/G TR ALTERNATE C00LDOWN USING BACKFILLING 03/13/89
EP/1/A/5000/1E3 S/G TR WITH CONTINUOUS NC SYSTEM LEAKAGE- 03/01/89 ,
SUBC00 LED REC 0VERY j
EP/1/A/5000/1E4 S/G TR WITH CONTINUOUS NC SYSTEM LEAKAGE- 03/01/89 i
SATURATED RECOVERY
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EP/1/A/5000/IE6 S/G TR C00LDOWN USING ND 08/01/88
EP/1/A/5000/2 CRITICAL SAFETY FUNCTION STATUS TREES 08/01/88
EP/1/A/5000/2A1 NUCLEAR POWER GENERATION /ATWS 03/01/89
.EP/1/A/5000/2A2 LOSS OF CORE SHUTDOWN 08/01/88
EP/1/A/5000/2B1 INADEQUATE CORE COOLING 08/01/88
EP/1/A/5000/2B2 DEGRADED CORE COOLING 08/01/88
EP/1/A/5000/2B3 SATURATED CORE' COOLING CONDITIONS 08/01/88
EP/1/A/5000/2C1 LOSS OF SECONDARY HEAT SINK 08/01/88
EP/1/A/5000/2C2 S/G OVERPRESSURE 03/01/89
EP/1/A/5000/2C3 S/G HIGH LEVEL 03/01/89
EP/1/A/5000/2C4 LOSS OF NORMAL STEAM RELEASE CAPABILITIES 08/01/88
EP/1/A/5000/2C5 S/G LOW LEVEL 03/01/89
EP/1/A/5000/201 IMMINENT PRESSURIZED THERMAL SHOCK CONDITIONS 03/01/89
EP/1/A/5000/2D2 ANTICIPATED PRESSURIZED THERMAL SH0CK CONDITIONS 03/01/89
EP/1/A/5000/2D3 HIGH PRESSURIZER PRESSURE 03/01/89
EP/1/A/5000/2E1 HIGH CONTAINMENT PRESSURE 03/01/89
EP/1/A/5000/2E2 HIGH CONTAINMENT SUMP LEVEL 08/01/88
EP/1/A/5000/2E3 HIGH CONTAINMENT RADIATION LEVEL 08/01/88
EP/1/A/5000/2F1 PRESSURIZER FLOODING 08/01/88
EP/1/A/5000/2F2 LOW NC SYSTEM INVENTORY 08/01/88
EP/1/A/5000/2F3 VOIDS IN REACTOR VESSEL 08/01/88
EP/1/A/5000/3 LOSS OF ALL AC POWER 08/01/88
EP/1/A/5000/3A LOSS OF ALL AC POWER RECOVERY w/o S/I REQUIRED 08/01/88
EP/1/A/5000/3B LOSS OF ALL AC POWER RECOVERY WITH S/I REQUIRED 08/01/88
PROCEDURES REFERRED TO BY E0P OR AOP THAT WERE REVIEWED (IN FULL OR IN PART)
OP/0/A/6200/08 ICE CONDENSER REFRIGERATION SYSTEM
OP/0/8/6100/13 STANDBY SHUTDOWN FACILITY OPERATIONS
OP/1/A/6150/02A REACTOR COOLANT PUMP OPERATION
OP/1/A/6450/10 CONTAINMENT HYDROGEN CONTROL SYSTEM 02/12/86
OP/1/A/6700/01 UNIT ONE DATA BOOK
OP/1/B/6250/078 AUXILIARY ELECTRIC BOILER 09/09/86
OP/2/B/6250/07A AUXILIARY STEAM SYSTEM ALIGNMENT 01/04/89
DOCUMENTS UTILIZED DURING E0P REVIEW
EMERGENCY PROCEDURE GUIDELINE SETPOINTS 05/14/86
CATAWBA NUCLEAR STATION EMERGENCY PROCEDURE GUIDELINES (PSTG) SEP 1988
WESTINGHOUSE OWNERS GROUP EMERGENCY RESPONSE GUIDELINES: HP VERSION 09/0l/83
REVISION 1A
CATAWBA NUCLEAR STATION WRITER'S GUIDE FOR EMERGENCY AND ABNORMAL 03/09/88
PROCEDURES
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APPENDIX B
TECHNICAL AND HUMAN FACTORS COMMENTS
This appendix contains technical and human factors comments, observations and
suggestions for E0P improvements made by the team. Unless specifically stated,
these comments are not regulatory requirements. However, the licensee agreed
in each case to evaluate the comment and take appropriate action. These items
will be reviewed during a future NRC inspection as noted in paragraph 3.b.
I. General comments:
1. The SPD provides operator action setpoints which are required b/ the
CNS E0Ps. There is no SPD to serve A0P unique requirements.
2. Operation of the SSF is conducted under an OP. Since the use of
the SSF presumes the control room and the alternate shutdown panel
have been abandoned, SSF operation is an abnormal condition. SSF
operation should be governed by. a procedure which has the added
control and review provided by E0Ps and AOPs.
3. AP/0/A/5500/34,- secondary chemistry out of specification, treats
out-of-specification actions by a three case analysis and corrective
response process, by operating mode. The process is an excellent
method of treating this type problem.
4. In the opinion of the team, EP/1/A/5500/203, high pressurizer
pressure, and the companion modification which added the pressurizer
pressure (2400 psig logic to the integrity critical safety function
tree in procedure EP/1/A/5000/2 were a significant improvement over
the ERG integrity treatment.
5. Many differences exist between the ERG and the PSTG. The majority
are ERG mitigation sequence differences. The licensee stated that
all differences were evaluated and that deviations were documented
for those differences found to be safety significant. Those which
were not safety significant were not documented. The team considers
all mitigation sequence differences as safety significant.
6. E0P changes can be originated by CNS or the general office. Since
the CNS staff does not use the PSTG during the E0P change development
process, the burden of ensuring that the E0Ps conform to the PSTG
falls entirely upon the general office staff. In view of. the
importance of maintaining conformance, the PSTG must be utilized
during the development of E0P changes.
7. PSTG DEV Only EP 01 and 03 contain entry conditions; the remaining
E0Ps do not. The licensee stated that entry conditions were not
required because entry is by transfer from either EP 01 or EP 03.
The team noted that the PSTG lists entry conditions for all E0Ps.
The team considers the absence of entry conditions in E0Ps as a
deviation from the PSTG and ERG.
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II. EP portion of the E0P comments:
1. EP/1/A/5000/01 Reactor Trip Or Safety Injection i
a. Step 18: The E0P and the PSTG deviate from the sequence in the
ERG and no deviation has been provided. In the ERG, " Check If
RCS Is Intact" occurs before " Check If SGs Are Not Faulted."
b. Step 5-14: These E0P steps and PSTG steps are listed as subse-
quent actions, unlike the ERG which list them as immediate
actions and no deviation is documented.
c. PSTG DEV Step 6: Steps 6 and 7 in EP01 are in the reverse order
of the PSTG.
d. Steps 7 and 10: These steps require the operator to check the
monitor light panel for proper S/I alignment. The monitor
lights are arranged in group.s. Not all lights in a given group
are lit on receipt of an S/I signal. This makes it much more
difficult for the operator to verify proper S/I equipment
alignment. The licensee had previously i'lentified these
discrepancies. Examples of these discrepancies are:
(1) On the Ss panel, the actuation signal for windows D6, 07,
E6, and E7 has been changed and they are no longer actuated
by an Ss signal.
(2) On the St panel, windows A6, A7, B6, and B7 light on an Ss
signal. The rest of the St panel is off on an Ss signal.
(3) On the St panel, the actuation signal for windows L11 and
L12 has been' changed to an Sp signal, but they are still
located on the St panel. l
(4) On the St panel, windows F4, F5, and F12 remain da) K for
approximately 15 to 20 minutes after an St signal. The rest
of the panel is lit during this time.
e. PSTG DEV Step 1: This step contains a kick-out to an A0P
unlike the corresponding step in the PSTG.
f. Step 4: None of the status light panels in the Control Room
have alpha numeric demarcation necessary for ease of location.
g. Step I.4, RNO: This step requires the operator to check
whether S/I is required based on a S/G pressure of 725 psig.
The "S/G PRESS" meters in the control room have indicated in red
"SI" at 710 psig. This Item was previously identified in NRC
INSPECTION REPORT NOS. 50-413/87-13 AND 50-414/87-13, 7.0.2 page
20, dated August 6, 1987. This is a safety significant item
which the licensee has committed to resolve. Resolution of this
.
.
issue will be identified as IFI 50-413,414/69-09-17.
_ - - _ _ _
- _ - - _ - -
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B-3
h. Step 6c.: This step specifies operator action based on a meter
reading of 195 psig; a value which can not be read. The meter
has a range of 0 to 3000 psig and is graduated in 50 psig
increments.
1. Step 6d.: This step requires operator action at 500 gpm ND
flow; a value which cannot be read.
j. Enclosure 3: In the first and second bullet, the pot setting
corresponding to a pressure of 1090 psig is not included.
k. Step 18: This step requires operator action at a containment
sump level of 0.5 ft or greater. The operator can not dependably
read this value on the meter. 0.5 ft is-the bottom of the' meter
scale. In addition, the meter erroneously read 0.75 ft with a
dry. sump at the time of the inspection.
1. Step 29: The values given for PRT pressure, level, and tempera-
ture in each of the three bullets do not agree with either the
alarm manual or the setpoint document.
2. EP/1/A/5000/1A Reactor Trip Response
a. PSTG DEV Step 1 thru 3: Steps 1 thru 3 are not contained in the-
PSTG or the ERG.
b. PSTG DEV Step 4: This step is conducted prior to the corre-
sponding steps 1-9 of the PSTG vice after it.
c. Step 17 fourth bullet: The' step states "Stop one CF pump." If
only one CF pump is running, all CF would be lost.
3. EP/1/A/5000/1A1 Natural circulation cooldown
a. PSTG DEV Step 9: There is no caution prior to this step
indicating that S/I will unblock if reactor coolant system
pressure increases above 1955 psig as there is in the PSTG.
b. Step 11: The E0P and the PSTG do not indicate that subcooling
should be based on core exit thermocouple as does the ERG and
no deviation is documented,
'~
c. PSTG DEV Step 13: This step does not contain a substep which
ensures letdown is in service, nor its associated RNO, as does
step 12c of the PSTG.
d. PSTG DEV Step 17: This step does not contain a substep which
ensures letdown is in service, nor its associated RNO, as does
step 17c of the PSTG.
_ _ _ - _
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B-4
e. PSTG DEV Step 31: The caution concerning depressurizing the
reactor coolant system is contained after this step vice before
as in the PSTG. Additionally, this caution does not include a
statement directing the maintaining of .the subcooling require-
ments of step 17 as in the PSTG.
f. The training department does not have an established scenario
for training operstors in how to control the reactor.with a void
in the head. .
I
4. EP/1/A/5000/1B S/I Termination Following Spurious S/I
.a. Step 13c1 RNO: The labeling on the reference instrument is
misleading and makes location difficult. The meter actually
indicates the RN to the KC HX outlet flow,
b. Step 13c2 RNO: The step does not reference the procedure number
for aligning RN.
c. Step 29 page 25 first bullet: Valve 1-NM3A is not included. i
5. EP/1/A/5000/1C High energy line break inside containment
'a. Step 1, note: This note is actually a conditional step. It is
required within step 1 prior to the actions called for in
substep b.
b. Step 8, caution: This caution is actually an action step. It
is required within step 8b RNO, which also requires a condition
step beginning "IF PZR pressure is greater than 2315 PSIG."
c. Step 15, caution: This caution is an action step related to the
completion of step 15.
d. Step 18c: This step is not a substep required to accomplish
high level step 18. It constitutes an additional high level
step in this procedure.
e. Step 23c: The "CLOSE/ RESET" pushbutton on ISM-1 is a dual
purpose pushbutton used both to close the MSIVs as well as reset
the MSIV bypass valves. If the pushbutton is used while the
MSIVs are open, the MSIVs will close. This system holds consid-
erable risk of inadvertent closure of an MSIV, and this accident
has occurred in the past. Single purpose controls are required
to eliminate this problem.
f. Step 23d, note: This note is a caution identifying a potential
hazard for increased of fsite radiation release when dumping
steam from the S/Gs.
- - _ - - _ _ - _ _. _ - __. __ ._ _ _ _ _ _ - _ . _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ - -
._. . ._ - .
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t
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g. Step 23d, RNO c: .The' desired NC pressure referenced .in this
step is indicatedLin Step i23e on the fol1owing page. The
~
. - definition of desired NC pressure is required prior to' Step 23d,-
..
RNO.c.
L'
L
h. Step 26a, RNO 1: This step requires an additional caution to
identify the potential hazard related to de-energizing the.EHM
'
system within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> tfter actuation.
l 1.. Enclosure 1, section B: The information following the section
title "S/I Termination Criteria" is actually a note related to
,
execution of the entire section.
6. EP/1/A/5000/1C1 S/I Termination Following High Energy Line Break
. Inside Containment
a. PSTG DEV Step 5: Phase A containment is reset in step 5'of the
E0P.' The equivalent step is not performed until . step 13 of the
PSTG.
b. PSTG DEV Step 3a RNO: This step does not direct the operator
to the step " aligning charging. flow path" as does step 2 RNO of.
the PSTG.
c.
~
Step 4: There is no guidance on which indication toluse for
subcooling. There are three different -indications given on the
plasma. display,
d. Step 9a: There is no guidance defining " desired charging flow".
Transferring to auto with a large error signal' could cause- the
valve to fail,
e. Step 27: The usage of the 50 deg. F subcooling limit'is incon-
sistent with the ERG and the setpoint document.
7. . EP/1/A/5000/1C2 Post-loca cooldown and depressurization
a. Step.1, caution: This caution statement is actually two notes
providing -supplemental information for the performance:of step
1.
b. Step 4, caution: This caution includes a conditional statement
that is actually the first substep of step 4. It is required
prior to the action described in step 4a. l8
c. Step 9b, RNO: This conditional step is out of sequence. It is
required just prior to step 9d.
d. Step 9d, note: This note is actually a caution related to the
performance of step 9d. It also contains a conditional sequence
required just prior to step 9dl.
.1
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B-6
i.
e. . Step 12 b, RNO: This conditional step is out of sequence. It
is required just prior to step 12f.
f. Step 12d, caution: This caution statement is actually a note
that provides supplemental information for the performance of
the remainder of step 12.
g. Step 12f, note: This note is actually a caution related to
the performance of step 12f. .It also contains a conditional.
sequer.ce required just prior to step 12fl.
h. Step 12f4: The desired cooldown rate mentioned in this step
is defined quantitatively in step 12d on the previous page.
Quantitative definition of the cooldown rate is required in this
step to reduce operator memory burden and eliminate a transition-
backwards within the procedure.
1. Step 17, note: Both note statements are actually cautions
related to the performance of step 17. Identification of the
potential hazards are required within these cautions.
J. Step 20, caution: This caution contains an action step that is
required prior to the performance of step 20c. Identification
<
of the potential hazard is required within this caution,
k. Step 32, caution: This caution is actually a step related to
the performance of step 32.
1. Step 33, caution: This caution contains an action step related
to the performance of step 33. Identification of the potential
hazard is required within this caution.
8. EP/1/A/5000/1C3 Transfer to cold leg recirculation
a. Step 1: The E0P and the PSTG, prior to this step, do not have a
caution concerning taking manual actlon to restart safeguards
equipment if offsite power is lost as does the ERG and no
deviation is documented.
b. Step 2: The E0P and the PSTG perform this step before S/I is
reset vice after as does the ERG and no deviation is documented.
c. PSTG DEV Step 6: The E0P does not contain the caution that if
pressure increases above the NI pump shutoff head the NI pumps
should be stopped.as does the PSTG.
d. PSTG DEV Step 13b, RNO: This step does not refer to FR-Z.1
" Response to high containment pressure", as does step 9c, RNO of
the PSTG.
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9. EP/1/A/5000/1C4 Transfer to hot leg recirculation
a. Step 1, caution: This caution is actually an action step 1
required at the beginning of the substeps to step 1.
10. EP/1/A/5000/1C5 Loss of Emergency Coolant Recirculation
a. Step 3c: This step does rot specify which subcooling indication
to use.
l
b. Steps 3c and d: These steps instruct the. operator to start and
stop the NV and NI pumps, but do not provide pump duty cycle
restrictions.
c. Step 5: This step and step 4 of 'the PSTG secure all NC pumps
unlike the ERG which leaves one running. No deviation is
documented. j
d. Enclosure 3 and other comparable enclosures: These enclosures
do not provide the number of the key necessary to unlock the CLA
isolation valve electrical breakers. During the inspection, the
wrong key for operating the breaker was issued to the operator.
e. Step 3d first bullet: This step does not use maintenance of -
subcooling greater than or equal to zero as a criteria.
i
f. Step 18 and 22: There is no direction after these steps to
return to the procedure in effect.
g. Step 19: There is no note warning the operator to monitor
containment sump level nor ND pump current.
11. EP/1/A/5000/1C6 Loca outside containment 1
a. No comments.
12. EP/1/A/5000/10 Steamline break outside containment
a. Step 3: This step and step 3 of the PSTG do not verify S/G l
blowdewn isolation of the faulted S/G(s) as does the ERG and no 1
deviation is documented. 3.
b. PSTG DEV Step 8: This step does not check intermediate range
flux prior to S/I termination as does step 7c of the PSTG.
c. PSTG DEV Step 8b: This step checks " total feed flow" where as
step 7b of the PSTG checks "CA flow". i
i
1
_ _ _ _ _ _ _ _ _ _ _ - _ - _ - _ - - - _ )
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13. EP/1/A/5000/1D1 S/I . Termination Following Steam Line Break
a. Step 3: The preferential order of depressurization differs from
the similar. step in other EPs.
b. Step 27b: The placement of the note obscures the step.
14. EP/1/A/5000/IE Steam generator tube rupture
a. Step 3b RNO 2d: Since the PORV is known to be.open, " ensure" is
incorrect. The appropriate action verb is close,
b. Step 3d RNO: As implied by the preceding caution, this step
works well unless the CA turbine pump is running as the only
pump; in that case it will shut the pump down. The RNO step
should be expanded to provide an action sequence in the event
the turbine pump is the only running pump.
c. Step 20b RNO la: The step directs that S/I pumps be started "to
restore subcooling and PZR level". The step should be revised
to ensure that' PZR level and subcooling are restored prior to
continuing to the sub step which transfers back to step 1..
d. Step 30a and elsewhere in other S/G TR procedures: The table
compares trends in pressurizer level and S/G level in an attempt
to determine subsequent mitigation strategy. Since pressurizer
level control is in automatic pressurizer level will remain
constant, within broad limits, in spite of water transfer
through the breat. For this reason, the team concluded .that
the table was not a suitable method of determining mitigation
strategy.
e. Step 34: The step does not direct periodic sampling of the
turbine buildina sump.
f. Enclosure 1, step F: The step does not place OAC point ID P0828
on a trend recorder.
g. Enclosure 1, step B: The S/I termination criteria parmits S/I
to be terminated prior to sufficient primary depressurization
following a S/G tube rupture.
15. EP/1/A/5000/IE1 Post-S/G TR cooldown and depressurization
l- a. Step 10, table: As discussed under E0P EP IE comments in this
l report, the table relating PZR and S/G level trends is not valid
if PZR level control is in automatic.
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16. EP/1/A/5000/IE2 S/G TR alternate cooldown using backfill
a. The SPD value is 150 ppm for backfill margin, not 170 as shown
in the E0P. The latter is correct. This value is recalculated
for each fuel cycle. Rather than change the SPD each time, a
controlled document calculation. Sheet is issued to provide
updated backfill margin. The team considered this practice
acceptable-
b. Step 1, caution: The second bulleted caution is actually an
action step that is required for performance' of this procedure.
The third bulleted caution is actually a note along with an
action step that is required for the performance of this
procedure.
c. Step _5, caution: This caution is structured as an action and
fails to identify the related potential hazard.
d. Step 12, caution: This caution is actually a note. However it
has no relation to the remaining steps in this procedure. The
actions it addresses are included in the procedure referenced in
step 13, and that procedure contains the necessary information.
17. EP/1/A/5000/IE3- S/G TR with continuous NC leakage: subcooled recovery
a. Step 28b RNO: Typo; the reader should be referred to steps
33-35, not 32-35.
b. Caution before step 34: This discusses rack out of NI or NV
pumps; it should discuss rack out of pump breakers.
c. Step 37. There is no requirement listed for periodic HP
sampling of the Turbine Building sump.
18. EP1/A/5000/IE4 S/G TR with continuous NC system leakage: saturated
recovery
a. Step IES: Typo; change NV to NC.
b. Step 38: The Turbine Building sump should be sampled periodi-
cally.
19. EP/1/A/5000/IE6 S/G TR cooldown using ND
a. When the ERGS place decay heat removal in service with S/G TR,
the process is listed within each ERG. The licensee chose to j
create IE6 as a single procedure which covers all decay heat
removal with S/G TR via a transition to IE6. The team evaluated !
this as a positive addition to the CNS E0PS. !
i
i
1
_ _ _ _ _
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q
1: 43% which the
setpoint document describes as fuel mid plane level with zero
void fraction. The ERG requires this value to be 3.5 ft above
the bottom of active fuel with zero void fraction. The conflict
between the ERG 3.5 ft requirement and the CNS use of mid plane
is not a documented deviation. However, this difference from
the ERG was documented in a Duke letter of August 29, 1984 to
the NRC (Tucker /Denton).
e. CSF 2C: The CNS provides feed flow only to intact generators;
the ERG does not limit flow to only intact generators. No
deviation exists.
f. CSF 2D: When compared to the ERG, the changes made to the CNS
CSF integrity tree were significant enhancements which were
supported by valid deviations. In the opinion of the team, the
CNS treatment of the coolant integrity tree was excellent,
particularly with reference to cold overpressure protection.
g. PSTG DEV CSF 2E: The PSTG and the E0P logic use a containment
sump design flood level of 13 ft. The number in the SPD is
17 ft.
- _ _ - - - - _ _ _ _ - _ _ _ . -
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B-11
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21. EP/1A/5000/2A?. Nuclear Power Generation /ATWS
a. Step 4f RNO: The step directs opening of all PORVs and does not
allow for use of just one PORV.
22. EP/1/A/5000/2A2 Loss of Core Shutdown
a. Nc comment
23. ED/1/ /5000/2B1 Inadequate Core Cooling-
a. Step 24: This . step does not specify the minimum procedural
criteria for sta ting and running an NC pump.
b. Step 27: This step specifies' operator action based on a meter
reading of 195 psig; a value which can not be read. The meter
.has a range of 0 to 3000 psig and is graduated in 50 psig
increments.
c, Step 31: This step ' cannot be reached from any point in the
procedure.
24. EP/1/A/5000/2B2 Degraded Core Cooling
a. Step 17b: Step 17b list the D/P for two conditions (Train A
and Train _B) Steps 17c and 17d only ask for D/P. There is no
guidarre to the operator if, due to operating conditions, the
D/Ps were.different between train A and train B.
b. Step 24: There is no way to enter step 24. Step 23 is a GO T0
statement.
25. EP/1/A/5000/283 Saturated Core Cooling Conditions
a. No comment
l
26. EP/1/A/5000/2C1 Loss of secondary heat sink
a. Step 7: This step establishes CA flow to "at least one" S/G
which means ficw could be restored to all four S/Gs. Since the
S/Gs are " dry", CA flow should be established to the minimum
number of S/Gs required ta restore the heat sink to avoid
unnecessary thermal shock.
b. Step 8 and elsewhere in this and other procedures: The logic is
based upon total CA flow. No total CA flow meter exists. The
operator is required to sum flows from individual S/G sensors.
- _ _ - _ - _ _ _ _ _ _ - - _ _ _ _ _ - _ . _ _ - _ - _ - _ _ _ _ _ _ - _ - _ _ _ . _ _ _ - _ _ . _ _ _ . _ _ _ - _ _ _ _ _ . . _ _ _ _ _ _ _ _ _ _ - _ _ _ _ - _ _ _ -
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e 4
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B-12
c. Step 12 and elsewhere: The feed regulator bypass valves are
about 37 ft above the floor level. Since the valves have
vertical rising stems, it would be difficult to install chain
operators. Interference limits the potential for use of a
. ladder; no ladder long enough to reach the valves could be
found. No emergency lighting was available in the vicinity.
d. Str7 17 RNO 2: Typo; change "ro" to "no",
e. Steps 23bic & 23b2b: One step uses "C/L", the other "C-Leg" to
designate cold leg.
f. The spare annunciators on the MD panels are either black faced
or blank. A standi i convention has not been followed.
g. Step 37 RNO a, second alternative: The operator should be
required to ensure the head vents are closed prior to the
h. Encl 2: The procedure does not include a requirement to report
action complete to the Control hoom.
'27. EP/1/A/5000/2C2 S/G overpressure
a. Step 10, caution: This caution fails to identify the potential
nazard as required by the writers guide.
28. EP/1/A/5000/2C3 S/G high level
a. Step 10: The RNO directs action to be taken if the verifica-
tions in either step 10a or step 10b are not met. However, with
the existing step format the RNO only applies to step 10a.
29. EP/1/A/5000/2C4 Loss of normal steam release capabilities
a. Step 1, caution: This caution fails to identify the potential
hazard.
30. EP/1/A/5000/2C5 S/G low level
a. No comments
31. EP/1/A/5000/2D1 Imminent pressurized thermal shock condition
a. Step Id1 RNO: Typo, the step is supposed to read "NC" tempera-
ture, not "NV" temperature.
b. Enclosure 4: The enclosure is illegible.
_ _
_ _ _ _ _
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B-13
32. EP/1/A/5000/2D2 Anticipated pressurized thermal shock,
a. Enclosure 3: The enclosure is illegible.
33. EP/1/A/5000/2D3 High pressurizer pressure
a. Step 3: The if/then step may require initiation of NV aux
spray. The method is not specified. Use of NV aux spray is
infrequent. In the AOPs, when NV aux spray is required, the
method is specified.
b. Step 21: Use of the word maintain is incorrect. Boron addition
establishes a new concentration.
c. PSTG DEV Caution: The PSTG FR-P.3 initial caution concerning
restoration of pressurizer pressure control was not included in
the E0P. Procedore step 5 addresses the same subject but an
action step cannot fully accomplish the intent of a caution.
d. PSTG DEV E0P step 23 requirement to ensure adequate shutdown
margin before returning to the procedure in effect does not
appear in the PSTG. This is a valid addition to the E0Ps which
is not currently in the PSTG.
34. EP/1/A/5000/2E1 High con,ainment pressure
a. Step 2, note: This note is actually a caution. It requires
identification of the related potential hazard. In addition, an
action step is included in the note that is required prior to
performance of step 2a.
b. Step 3, caution: This caution statement is actually a condi-
tional step that applies throughout the procedure. It is
appropriately placed on a foldout page for this procedure,
c. Step 3, note: This note is actually a conditional step that is
required within the procedure prior to the actions included in
step 3.
d. Step 5, caution: This caution fails to identify the related
hazard. In addition, it is incorrectly structured as an action,
rather than as an alert to personnel about potential damage or
injury.
e. Step 7b, RNO: This step is overly complex, with multiple
possible meanings due to the combined use of the logic terms AND
and OR.
i
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E f. Step 11, note: The first bulleted item in this note is unneces-
sary. This concern is a basic training issue, and need not
be included as a note here. The second bulleted item is a
conditional step. It is required within the procedure prior to
the actions included in step 11.
g. Enclosure 4, step 2c: The bulleted items within this step are
actually conditional sequences and are not in accordance with
the format for logic statements found in the writer's guide.
35. EP/1/A/5000/2E2 High containment sump level
a. Step 2a: The sequencing of containment isolation valves within
this step is awkward ' and inconsistent with the placement of
valve switches on the control boards.
36. EP/1/A/5000/2E3 High containment radiation level
a. No comment
37. EP/1/5000/2F1 Pressurizer flooding
a. Step 2: From the definitions in the writer's guide, the use of
-verify followed by ensure is incorrect. Verify does not permit
a status change; ensure requires a status change if not as
listed.
38. EP/1/A/5000/2F2 Low NC system inventory
a. No comments.
39. EP/1/A/5000/2F3 Voids in reactor vessel
a. Step 1: There is no caution prior to this step nor step 1 of
the PSTG warning against use of this procedure if a controlled
cooldown is in progress and a void in the head is expected, a:
does the ERG and no deviation is dacumented.
b. Step 4, RNO b(2): This step does not give guidance defining
" minimum charging".
c. Step 14: This step and step 9 of the PSTG are not preceded by
a caution alerting the operator to evaluate the status of any
reactor coolant pump prior to starting it if seal cooling
had previously been lost as does the ERG and no deviation is
documented.
d. Step 14: This step and step 9 of the PSTG are not preceded by a
note informing the operator of the priority for starting reactor
coolant pumps as does the ERG and no deviation is documented.
.
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B-15
e. PSTG DEV Step 17: This step does not direct the closing of
both valves in a vent line with a failed valve as does step 12
of the PSTG.
f. Step 20d: This step sends an operator inside containment with
up to 6% hydrogen concentration present,
g. PSTG DEV Step 26: This step does not direct the closing of
both valves in a vent line with a failed valve as does step 20
of the PSTG.
40. EP/1/A/5000/03 Loss of all ac power
a. PSTG DEV This procedure does not list entry conditions at the
beginnini of the procedure as does the PSTG. The E0P as written
contains symptoms at the beginning of the procedure. However,
these are not clear enough to prevent inadvertent entry into the
procedure.
b. Step 3, RNO: The valves in this step which are ensured to be
open will not have power available to their control board
indications during a loss of all ac power.
c. Step'3: The E0P and the PSTG, in this and subsequent steps do
not list " Verify NC System isolation" and " Ensure CA flow to
S/G(s)" as immediate actions as required in the ERG. The PSTG
does not specify any immediate actions for any procedures
contrary to the ERG and no deviation is documented.
d. Step 7: The E0P and the PSTG do not contain a caution prior to
this step alerting the operator to reset an S/I signal to permit
manual loading of equipment as does the ERG and no deviation is
documented.
e. Step 7: The E0P and the PSTG do not contain a step prior to
this step to ensure that CST inventory is conserved for makeup
to the steam generators as does the ERG and no deviation is
documented.
f. Step 7: This step and step 12 of the PSTG check steam generator
isolation but do not address feedwater isolation as does the ERG
and no deviation is documented.
g. Step 10: This step and step 15 of the PSTG direct maintaining
steam generator levels at no-load level instead of maintaining
them within the band established in the ERG and no deviation is
documented.
h. Step 11a: This step and step 16a of the PSTG do not contain
adverse containment values for steam generator narrow range
level a* Joes the ERG and no deviation is documented.
- - _ - _ _ _ _ _ _ - _ _ _ _ _ _ - _ _ _ _ _ _ _ . _ _ _ _ _ _ _ ___ _ ._. _ _ . _ . . _ - _ _ _ _ _ _
_ . _ _ . - - _ . __
k -
p ..
? .. ~
.
- . .
f
'
I
( B-16
i
L
i . Step 11b: This step directs an operator to unlock valves.
These valves do not have locks on them and are not designated as
l.- locked valves on the print.
J. Step 12b: This step directs an operator to ensure that ICA-6 is
closed. This valve can not be operated locally with ladders
provided.
k. Step 12d: This step checks hotwell level < 6 inches. The
required meter is graduated in feet.
1. PSTG DEV Step 12e: This step does not isolate the CA pump
suction from condensate grac'e sources as does step 17e of the
PSTG.
m. Step 16e: This step references figure 6.10 of the curve book.
The correct figure is 6.9.
n. PSTG DEV Step 16e: This step maintains S/G pressure at a value
based on NC criticality temperature limic. The PSTG directs
maintaining S/G pressure at 10f psig.
o. Step 18: This step and step 23 of the PSTG do not address
checking source range instrumentation to verify reactor shutdown
as does the ERG and no deviation is documented.
p. Step 27: This step and step 32 of the PSTG are not preceded by
a caution against exceeding the capacity of the power source as
does the ERG and no deviation is documented.
41. EP/1/A/5000/3A Loss of all ac power recovery without S/I required
a. PSTG DEV Step Sh: This step ensures only %e 4V pump is
running whereas step 4e of the PSTG directs star + mg all avail-
able NV pumps.
b. Step 7e: This step directs establishing " desired charging flow"
and does not define it as a value comparable to normal NI pump
miniflow as does the ERG and no deviation is documented.
c. Step 10: The E0P and PSTG do not contain a note prior to this
step to prevent inadvertent start of the motor drlven auxiliary'
feedwater pumps as does the ERG and no deviatien is dccumented.
d. PSTG DEV Step 15: This step does not start an additional NV
pumn as does step 14a of the PSTG.
e. Step 16: This step and step 15b of the PSTG do not check let-
down in service n,or direct use of auxiliary spray to control NC
system pressure as does the ERG and no deviation is documented.
-_ . _ - _ . - _ _ _ _ - _ _ - _ _ _ _ _ _ _ _ - _ - - - - _ - _ - - _ - - - - - _ _ - -
-____ _ ___ - - - -
.
.
t- .
'
B-17
42. EP/1/A/5000/3B Loss of all ac power recovery with S/I required
a. Step 8: The E0P and the PSTG do not contain a step prior to
this step which places the containment spray pump switches in
standby as does the ERG and no deviation is documented.
b. Step 8: The E0P and PSTG do not contain a note prior to this
step to prevent inadvertent start of the motor driven auxiliary
feedwater pumps as does the ERG and no deviation is documented.
c. Step 11: This step and step 10 of the PSTG direct transition to
E-0, " Reactor trip or safety injection" instead of E-1, " Loss of
reactor or secondary coolant" as does the ERG and no deviation '
is documented.
III. AP portion of the E0P comments:
1. AP/0/A/5500/20 Loss of nuclear service water
a. Paragraph A, purpose: On line two, after " loss of RN train or"
some wording has been omitted. The remainder of the sentence
does not make sense.
2. AP/0/A/5500/22 Loss of instrument air
a. Page 1: The enclosure listing and the actual enclosures are
untitled. This makes selection of the proper enclosure diffi-
cult.
b. Pg. 1, step B: Use of "and/or" is prohibited by the writer's
guide,
c. Pg.5, step 6: Neither the procedure nor enclosure 3 note that
realignment of the turbine aux feed pump to S/G A or C requires
operation of CA38A or CA668,
d. Encl. 1, pg. 15: Contrary to most CNS drawings, drawings j
CN1594-1.2, CN1594-1.3, CN2594-1.2 and CN 2594-1.3 do not the
'
list fail position for air operated valves.
e. Encl. 1, pgs. 20 & 21: The fail positions for IKC-122 and
2KC-122 are open, not closed as shown.
f. Encl. 1, pgs. 24 & 26: Valves 1NV-309 and 2NV-309 are missing
from the list.
g. Encl. 2, step 3: This step requires the IAEs to install port-
able air bottles and open some letdown valves. IAE personnel
are not trained on the A0Ps. No IAE procedure reference is
provided.
-
_- ._ . _ _ .
.
e.- s,
. .
B-18 I
t
i
h. Encl. 2, step 4: The order of the two "or" gated substeps
appears to be reversed since opening the 45 gpm letdown orifice
would allow the control room to control inventory with NV-11A.
i
1. Encl. 3, step 2: It is not clear in this step whether the
" check and "IF" statements apply to at least one, more than
one, all, etc. S/Gs?
3. AP/0/A/5500/34 Secondary chemistry out of specification
a. No comments.
4. AP/1/A/5500/02 Turbine generator trip
a. Step Cla: The step does not give the expected P-9 light status
or panel location.
b. Step Did: Typo, Should be "D.3" not "d.3".
c. Step D1 RNO: Typo, Should be "D.2" not "d.2".
d. Step 05 Note: The note is unclear in that it- does not specify
" Transformer" cooling banks.
e. Step D7 RNO first bullet: There are two switches with the same
name. Currently the operator cannot distinguish the difference
in switches.
f. Step D7 RNO second bullet: There are two switches with the
same name. The operator neads to be able to distinguish the
difference in switches.
g. Step D13: The step does not provide an RNO if the steam dumps
are not available.
h. Step D2e: The procedure does not address the method of rod
control below 15% power.
5. AP/1/A/5500/03 Load Rejection
a. Step D4 note: There is no operator guidance given as to where to
read the 3 deg. delta Tave-Tref,
b. Step D10 Note: See 4.d above,
c. Step D14c RNO third bullet: There are two switches with the
same name. The operator needs to be able to distinguish the
difference in switches.
_ _ _ - - _ __. _
- _. _ _ _
.
4 e
'
' ?. : .
}
d-19
1
d. . Step D14c- RNO second bullet: There are two switches with the
same name. The operator needs to be able to distinguish the
difference in switches.
e. Step D15 the second bullet: The graduation of the meter is such
that an. operator can not determine + or .1 KV .
.f. Steps D16c rnd d: The steps contain six separate actions and
they are written in two steps.
g. Steps D16f and g: The steps contain six separate actions and
they are written in two steps.
h. Step D18: The temperature given for the PRT action point is
inconsistent'with the temperature given in the E0P.
6. AP/1/A/5500/04 Loss of reactor coolant pump
a. No comments
7. AP/1/A/5500/05 ECCS actuation during plant shutdown
a. Step 15c: The list of OAC point identifiers is inconsistent and
not in accordance with the placement of these points on the
computer screens. However, all of the information provided on
these computer points is available on the graphics 25 computer
screen.
b. Step 15d: The information provided by' all of the listed 0AC
computer points is available .on the graphics 25 screen, along
with the information required in step 15c.
c. Step 16, note: This note is actually a caution related to the
performance of step 16. It lacks identification of the poten-
tial hazard of seal failure. !
d. Step 17: This step fails to identify the operating procedure
required to accomplish the actions listed. An alternative to
referencing the operating procedure is to specify the required i
number of chillers to pumps for these actions.
e. Step 19: This step includes reference to the NR system. This
system is not in service at CNS and is not intended for any
future use.
f. Step 25a, RNO: This step includes an overly complex layering of
logic sequences.
g. Step 32, caution: This caution is actually an action step
required within the procedure prior to performance of step 32.
- _ - _ _ _ _ _ -__ _ . _ - - _ -
_ __- _ _
.
. .
'
. ..
B-20
h. Step 32u: The list of valves included in this step is awkward
and inconsistent with the placement of the ' valve switches on the
. control boards.
1. Step 33, caution: This caution is actually an action step
required within the procedure prior to performance of step 33.
8. AP/1/A/5500/06 Loss of S/G feedwater
a. No comments
9. AP/1/A/5500/07 Loss of normal power
a. No comments
10. AP/1/A/5500/08 Malfunction of reactor coolant pumps
a. Case II, step 6e: This step does not give guidance defining
" normal" for " lwr brg temp".
11. AP/1/A/5500/10 Reactor coolant leak-
a. Step 1, caution: This caution lacks identification of the
potential hazard and incorrectly includes use of the logic term
WHEN.
b. Step 5, note: This note is actually a conditional step required
within the procedure prior to performance of step 5.
c. Step 8: The first bulleted item in the step incorrectly refer-
ences OP/1/A/6200/02 with the title to OP/1/A/6100/02. The
title is correct, however, the correct procedure number is the
latter.
d. Enclosure 2, note 1: This note is actually an- action step
required prior to performance of this enclosure,
e. Enclosure 2, page 13, caution: This caution incorrectly
contains a directive to the operator.
f. Enclosure 2, page 16, step 6a: This step references
OP/2/6250/07A, Enclosure 4.3. A 35 foot extension ladder
necessary to perform the procedural actions is dedicated for NE0
use at E33, TB-568. This ladder may be required for performance
of the procedure enclosure. During the inspection walkthrough,
the wrong type of ladder (12 foot step ladder) was found at the
dedicated ladder location.
g. Enclosure 2, page 16, step 6al: This step fails to identify the
required operating procedure enclosure number.
L__----_-----------_- - - - - -
-
y
..
t' 4,
.
f .
I
1' l
, 8-21 -
l
l
I
h. Enclosure 2, page 16, step 6a2 This step fails to identify the l
required operating procedure enclosure number.
1. Enclosure 2, page 19, step 1: "NC Pmp A (B,C,D) #2 Seal S-Pipe
Hi/Lo Lvl" annunciator lights are removed as temporary modifi-
cations during outages. However, these lights are referenced
in this enclosure with no indication that they may not be
available.
12. AP/1/A/5500/11 Inadvertent NC system depressurization
a. Case I, step C1, caution: This caution is actually a condi-
tional step that applies during the performance of the entire
procedure. Correct placement would be on a foldout page to the I
procedure.
b. Case I, step 4, caution: This caution is actually a step that
is required within the procedure prior to the performance of
step 4.
c. Case I, step 5, caution: This caution is actually a step that
is required within the procedure prior to the performance of
step 5.
d. Case II, step C1, caution: This caution is actually a condi-
tional step that applies during the performance of the entire
procedure. Correct placement would be on a foldout page to the
procedure.
e. Case III, step C1, caution: This caution is actually a condi-
tional step that applies during the performance of the entire
procedure. Correct placement would 'Je on a foldout page to the
procedure.
13. AP/1/A/5500/12 Loss of charging or letdown
a. Case I, step C1, caution: See 11b above.
b. Case I, step C3, caution: This caution fails to identify the
potential hazard. In addition, it.contains a conditional stop
that is required within the procedure prior to step 3.
c. Case I, step 01: See 7e above.
d. Case I, step D2e, RNO: This step also requires a caution to
address the consequences of exceeding 1 degree F per minute
cooldown on any NV pump.
____ __
-_ -- -____ _ - - -
.
. .
j
u..
.
1
B-22
l
e; Case I, step 6, caution: The first bulleted item in this
caution is actually a step that is required within the procedure
prior to performance of step 6. The second bulleted item is a
caution, however, it fails to identify the potential hazard.
f. Case II, step C1, caution: See 11b above.
g. Case II, step D1: See 7e above.
14. AP/1/A/5500/13 Boron dilution
a. No comment
15. AP/1/A/5500/14 Control rod misaligned
a. No comment
16. AP/1/A/5500/15 Rod control malfunction
a. No comment
17. AP/1/A/5500/16 Malfunction of nuclear instrumentation system
a. Case I, step 3c: This step directs , ensuring adequate shutdown
margin but does not reference the procedure which is Lsed to
accomplish this.
b. Case III, step C.1: This step does not provide the setpoints
associated with the parameters to determine if a reactor trip is
required.
c. Case IV, step 2: This step directs monitoring nuclear instru-
mentation but does not provide any actions to be taken if the
listed conditions are not met.
18. AP/1/A/5500/17 Loss of control room
a. Communications between unit ASPS will be lost if PBX battery
depletion renders the station dial phone system inoperative.
Since the string phone circuits are unit unique and no radios
are repositioned at or carried to the ASPS, there are no
alternative communications options.
b. The procedure does not specify which of the two separate string
phone circuit; -tauld be used for communications within a unit
when the ASP or the SSF is activated. The walkthrough operator
was not certain which was correct.
i
_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
__-__ ____-____ - _ __ -
s
. .
.* , .
B-23
c. Enclosure 1, step 1: During the walkthrough, the ASP operator
was unable to simulate completion of this step because he lacked
tools: to loosen the front panel bolts. Tools were available in
a locked tool box in the AFWPTCP room but the ASP operator did
not have the combination.
d. Contrary to instructions posted on the unit one ASP A panel
access cover plate, the panel plate was unlocked, the cicsure
bolts were removed and the access was open.
e. Enclosure 1, step 6 RN0: This step neglects the case where one
pump fails to start but the other is available. The problem
probably stems from the prohibited use of "and/or".
f. Enclosure 1, step 10 RNO a5: This double action statement
should be split into two elements.
g. Enclosure 1, step 10 b2c: The intent of this step is to reach
and maintain ~25% PZR level . The RNO side accomplishes this.
Due to the lack of an AER action verb, if level is already ~25%
the operator will continue without instruction to maintain level
~25%
h. Enclosure 1, step 11a: The results of the AER and RNO sides are
different. The RNO side adjusts pressure to ~2235 psig and
maintains it there. The AER side checks for pressure ~2235 psig
and if satisfied continues without instruction to maintain that
pressure.
1. Enclosure 1, step 12: The use of " adequate normal" instead of
just " normal" is confusing and unnecessary.
j. Enclosure 1, step 13 RNO 2: Delete typo ":" on line 5.
k. Enclosure 1, step 14: The team noted that the file of data book
excerpts maintained at the ASP did not include the cooldown
limits curve.
1. Enclosure 1, ste, 29 and elsewhere within the E0Ps: Grammar;
the two EPIP prccedures listed concern classification and
notification, not just notification.
l m. Enclosure 1, step 23 and the preceding caution: The cooling
l tower fans are no longer required beyond this step in the
! procedure. This step and the caution may be replaced by an
action statement shutting down the fans.
l
l
t
I
.. . _ _ _ _ . _ _ _ _ - _ _ _ _ _ _ - _ _ - _ - _ _ _ _ -
.-
. .
4 .
B-24-
n. Enclosure 3, step 3: Operation of the MODS under normal current
load would blow. up the breaker cabinet. Although there are
interlochs to prc<ent this and operators are trained on breaker /
MOD sequence of operation, the.EOP step is written with bullets
indicating that sequence is not important. The step should
provide a mandatory sequence and should be accompanied by an
appropriate caution,
o. Enclosure 3, step 5: The reciprocating charging pump for unit I
has been tagged out of service awaiting repair since July 1988.
Two operators indicated that the positive displacement NV pumps
on both units have.been difficult to maintain. If this service
were typical for these pumps, their unavailability would ad-
veesely impact the E0Ps. Licensee management assured the team
at the exit that the availability of these pumps is improving.
p. Enclosure 7, step 4 RNO 1: Use of "out-of-specification" is
confusing since the specification is not directly identified nor
is it conventional to describe a containment 3 psig ESF signal
as containment "out-of-specification"
19. AP/1/A/5500/18 High activity in reactor coolant
a. No comments
20. AP/1/A/5500/19 Loss of residual heat removal
a. Case I, step C1, note 1: This note is overly detailed. It is
actually an action step that is required prior to step 01.
b. Case I, step D8e, caution: This caution is actually a note, as
well as an action step that is required prior to performance of
step 08e.
c. Case I, step D9, caution: See 20b above.
d. Case I, step D11f: This step fails to identify the necessary
enclosure to the operating procedure referenced. In addition,
only a limited number of the valves listed in the operating
procedure enclosure are applicable in this case,
e. Case II, step C1, note 1: See 20a above.
f. Case II, step D3, caution: This caution is actually a note,
however, it does not apply to performance of step D3.
g. Case III, step C1, note 1: See 20a above,
h. Faclosure 2, step A, caution: This caution contains an action
step that is required within the procedure prior to performance
of step C.
- - _ _ _ _ _ _ _ - - - _ _ - _ _ __. ._ _ _ _ _ _ _ _ _ ._ _ - _ - _ _
-- _ _ _ _- = _ _ _ - _ _ _ -
l4 '
<
x x
- + ac
.B-25
'
i '. Enclosure 5,fstep A, note: This note is actually an action step
that.is~ required prior to performance of step A.
' j. Enclosure 5, step A3, caution: .This caution fails to identify
'the potential. hazard. In addition, it contains an action step
~
required within the procedure prior to performance ~ of step. A3.
21. AP/1/A/5500/21 Loss of component cooling
a. Step 3, RNO a.2: The valves required to be shut by this step do
not have locations listed. Due to the fact that these valves
are not located in proximity to the equipment being isolated an
operator would have difficulty closing these -valves' in a timely
manner.
22. AP/1/A/5500/23 Loss of condenser vacuum
a. No comment
. 23. AP/1/A/5500/24 Loss of containment integrity
- a. -Section B,' case II: This section has multiple possible meanings
between the second and third bulleted items due to the combined
use of logic terms AND and OR.
b. Case I,. step D2a: The four hour time frame indicated in .this -
step is in conflict with Tech. Spec. 3.6.1.1 LCO which indicates-
that containment integrity must be restored within one hour. A
justification for the basis of this conflict is required.
24. - AP/1/A/5500/25 Damaged spent fuel
a. Case 1, step'c2-4: This equipment is infrequently operated
and the walkthrough NE0 had difficulty locating it. It's
location is not specified.
b. Case 1, step d3 and elsewhere'in other procedures: This step
requires ensuring containment integrity; the technical specifi-
cation reference applies to all penetrations. The walkthrough
operators were uncertain of which of several alternative methods
of ensuring integrity applied.
25. AP/1/A/5500/26 Loss of refueling canal or spent fuel pool level
a. Incident to the walkthrough, the team inspected alarm response
procedure IAD-13 E2 which listed minimum fuel pool level as 36.6
ft., the alarm setpoint, and referenced technical specification 3.9.10. The tech spet requires a minimum of 23 ft. of water
above the top of the fuel. This equates to a level of 36.923 ft.
.
u-mmm_-_u_m_u.__m-_m _m_._m _ __m__m
- - . .. _ _ - - _ -
,
e
- .
. . .
. . ...
B-26
T;,e licensee indicated that tha cror had been identified
previously and that procedure and alarm setpoint changes were
being held in abeyance pending results of a study concerning
tech spec applicability and compliance in the event of a
damaged, jammed or cocked assembly in the pool. The daily
surveillance procedure minimum level was 37.6 ft.
-
,
m.,---___--.-__.--- - - . . - - - - - - . - - - - ---
- _ _ _ _ _ _ _ _ _ _ _ -
..
. .
- -
. ..
APPENDIX C
WRITER'S GUIDE COMMENTS
This appendix contains writer's guide and human factors comments, observations
and suggestions for E0P improvements made by the team. Unless specifically
stated, these comments are not regulatory requirements. However, the licensee
agreed in each case to evaluate the comment and take appropriate ection.
These items will be reviewed during a future ' NRC inspection as notea ir.
paragraph 3.c.
I. Deviations from the Writer's Guide
A sample of the E0Ps and AOPs were evaluated for deviations from the
Catawba writer's guide. Types of deviations noted are characterized in
this section and accompanied by a list of examples of the specific devia-
tions. Note that some steps contain more than one example.
1. The following steps violate writer's guide directions for the
structure of logic statements:
EP/1/A/5000/1C 5 RNO
8 RNO
EP/1/A/5000/1C2 33
EP/1/A/5000/1E2 2
6
6 RNO
EP/1/A/5000/2C2 10
EP/1/A/5000/2E1 5
EP/1/A/5000/2E2 3
AP/1/A/5500/05 D4
07
D7 RNO
D12
013
D22 RNO
D25 RNO
D34
D30
D35 RNO
AP/1/A/5500/10 D4
l D8
l
AP/1/A/5500/12 Case I C3 RNO
02 RNO
D6
Case II D2 RNO
D4 RNO
\
r
- :
1
. .
.-
.. <
C-2
AP/1/A/5500/19 Case I D7
D10
D]1 RNO
D14
D14 RNO
Case II D2
D2 RNO 1
l
D6
D8
Case III D15 RNO
AP/1/A/5500/24 Section B Case I
Case II
Case I D1
D2
D3
Case II C1
The team reviewed 10 A0Ps for compliance to the writer's guide.
Generally, in the AOPs reviewed where the conjunctions "and" and
"or" were used, they were f.ormatted as if they were being used as
logic terms.
2. The - following steps violate writer's guide directions for the
structure of transition steps:
EP/1/A/5000/1C 14
26
EP/1/A/5000/1C2 18 RNO
25 RNO
33 RNO
EP/1/A/5000/2E1 13
AP/1/A/5500/05 C1 RNO
D1 i
D2 RNO
D5 RNO
D7 RNO
D13
D20 RNO
D23 RNO I
D25 RNO >
D27
D27 RNO
D28 RNO
DhD
D31
D32
D34
D35
D35 RNO
. _ - _ _ _ _ _ _-
, - - _ - _ - _ . - .. _ _ __ _ _ . . _ _
.
. .
1
4. .
C-3
- AP/1/A/5500/10 01 RNO
D3 RNO
D4
D5 RNO
D6
D6 RNO
D7
D8
AP/1/A/5500/1.1 Case ' D6
Case III D5
.AP/1/A/5500/12 Case I C3 RNO
D5 RNO
07
D8
D9
Case II D2 RNO
D4 RNO
D5 RNO
D7
D9
DIO
D11
AP/1/A/5500/19 Case I D1
D4 RNO
D5
D7
D8
D8 RNO
09
D11
D11 RNO
D12
013
D14 RNO
Case II D2 RNO
D3 RNO
D4
05
Case III D1 RNO -
D2 RNO
D4
D5
D7
D11 RNO
D12
D13
D14
D15
- - _ _ _ . - _ _ _ _. _ _ _
- _ _ _ _ - _ _ _ . _ _ - _-__ _ _ _ ._ ._ __ ___ - _ - -
.
, .
.
C-4
i
AP/1/A/5500/24 Section B Case I-
Case I D1
D2
D4 RNO
Case II D1
02
3. The many deviations from the writer's guide in the structure of and
use of cautions and notes is described in appendix B of this report.
4. The writer's guide defines a format for presenting plant expected
responses. The following steps do not use the defined format for
expected responses:
EP/1/A/5000/1C 3
4
8
10
20
20 RNO
21
EP/1/A/5000/1C2 11
12
20
31
EP/1/A/5000/2E1 10
EP/1/A/5000/2F2 1
The team reviewed 10 AOPs for compliance to the writer's guide.
Almost every expected response listed in the .AOPs reviewed was
formatted incorrectly.
5. The writer's guide states that common English grammar should be
applied within the procedures and that the verb is the most important
word in an action step. The following steps lack a verb:
EP/1/A/5000/1C 1
2
4 RNO
5 RNO
7
9
9 RNO
12
15 RNO
23
23 RNO
24
27 RNO
- .. - - - _ _ -
_ _ _ - .. - . _ -
.,
-
3.:
.'e e-
.'., . . .
C-5
EP/1/A/5000/102 4
5
5 RNO
8
9 RNO
12
12.RNO
19
30-
EP/1/A/5000/IE2 5 RNO
9 RNO
10
EP/1/A/5000/2C2 9
EP/1/A/5000/2C4 3
EP/1/A/5000/2E1 1
8 RNO
AP/1/A/5500/05 C2 RNO
D2
03
D5
D6
'D7
DIO
D15
D23 RNO
D24
D25
D28
D34
D35
D35 RNO
AP/1/A/5500/10 D1 RNO
D2 RNO i
D5 RNO
D8'
I
AP/1/A/5500/11 Case I D1 RNO
D3
D6
Case II C1 RNO
D1 RNO
Case III C1 RNO l
D1 RNO l
D3 RNO
__ _ _ _ _ - _ _ _ _ _ - _ _ _ .
_ _ _ _ _ _ . _ _ _ _ _ - _ _ -
_ _ _ _ _ _ _ _ _ _ _ _ _ -
.
" ,,- .
. ,
C-6
l' AP/1/A/5500/12 Case I D2
D2 RNO
D3 RNO
Case II C2
D1
D4
l
AP/1/A/5500/19 Case I D6
D8
08 RNO
,
'
Case III D8
D11
D12
AP/1/5500/24 Case I D1
Case II C1
6. The following steps lack a subject:
EP/1/A/5000/1C 2 RNO
EP/1/A/5000/102 34
AP/1/A/5500/05 D15 RNO
D22 RNO
AP/1/A/5500/12 Case II D2 RNO
7. Location information for annunciator lights was missing or incomplete
in a number of procedures. The following examples lack either panel
number or grid location number:
EP/1/A/5000/1C 22
EP/1/A/5000/2C4 3
3 RNO
AP/1/A/5500/02 D1
AP/1/A/5500/02 C1
DS
AP/1/A/5500/11 A
l
]
1
_ _ _ _ _ _ _ _ _ _ _ _ _ _ _
. _ _ _ . __ ._ -. __ _ _ _ _ _ _ _ _ _ _ _
_- _ _ . _
- _ _
.
- ~' a
6 . - .$ '
C-7
8. The writer's guide. indicates that procedure nomenclature that exactly.
replicate; plant labels'should be set off by quotation marks. The.
following steps use quotation marks for nomenclature that does not
exactly match that in the control room and plant:
EP/1/A/5000/1C 2
4
-
6
7
10
17
20
22 ,
23
23 RNO
EP/1/A/5000/IC2 1
6
7
30
33
EP/1/A/5000/IC4 2
EP/1/A/5000/2C4 2
3
EP/1/A/5000/2E1 8
9. The following steps contain lists of valves that'are not arranged in
an order consistent with their placement on the control board:
EP/1/A/5000/2E2 2
AP/1/A/5500/05 3
10. Appendix 5 to .the writer's guide states that a colon should be used
to indicate substeps or that a list follows. The following
procedure steps lacked use of a colon in this manner:
EP/1/A/5000/1C 1
4
5 RNO
7'
8
9
14 1
15
l 17
'
20 RNO ;
l
22
_ - _ - _ _
. . _ _ . - _ _ . - - _ _
.
-
- ,; .
.
. .
$- ....
', C-8
' '
.
s 24
26
1 27
EP/1/A/5000/ ICE 1-
2
4
'
5
6 RNO
7
9
10
11
12
14
15
17
18
20
21
22
23
2A
25
26
27
28
29
31
33
'
EP/1/A/5000/104 1
2
EP/1/A/5000/1C6 1
'
2
3
4
EP/1/A/5000/IE2 3
4
5
6
9
10
EP/1/A/5000/2C2 3
6
7
8
9
l
l
l
_ - _ _ - _ .
_ _ _ _ _ _ _. ._. . _ _ . . _
_ _ _ _
.
. .
.. ..
C-9
EP/1/A/5000/2C4 2
3
EP/1/A/5000/2E1 3
7
10
11
EP/1/A/5000/2E2 2
EP/1/A/5000/2F2 2
3
4
5
AP/1/A/5500/05 D7
D8
D24
D29
AP/1/A/5500/19 Case I D4
Case II D2
D3
D4
Case III D3
D6
D10
D11
D12
11. The writer's guide states that all steps should be written in active
voice. The following steps are written in passive voice:
EP/1/A/5000/1C 4c RNO
28
II.-Inadequacies in the Writer's Guide
In order to assure consistency within and between procedures and to retain
that consistency over time and through personnel changes, the writer's
guide must thoroughly address each aspect of the procedures and must
define restrictively the methods designated for use.
1
The Catawba writer's guide contains a number of areas where lack of
restrictive or thorough guidance has led to problems and inconsistencies
in the E0Ps and AOPs. These weaknesses are as follows:
1: 1. The writer's guide describes a structure for consequential steps
l that combines a transition forward and a "WHEN condition X, THEN
l
transition backward in the procedure." This system is overly com-
plex. It is difficult to perform and provides no method of reminding
the operator to transition backward to the original step.
- _ - _ _ _ _ - _ _ _ _ _ _ _ _ _ _ - _ . -_ __ _
__ . _ _ _ _ _ . - - - - - - . _ _ _ - _ . - - _ --_
6
4'
. ..
M :.
A '
C-10
- s" .
'
'2, The guidance on preparation of notes and cautions improperly allows-
.the use,of logic-sequences in these statements.
3. The instructions for use of "and" and "or" asi conjunctions directs -
a use of these terms when unnecessary, thereby contributing to confus- -
ing and overly complex action steps.
.4. The writer's guide allows. the use of the logic term "if" as part of
other sentences (for example, " check if"Jand " determine . if"). These
forms dilute the usefulness of logic' statement structure and could .
lead to confusion.
5.' The~ description of procedure substep numbering, bulleting and inden--
tation described in the writer's guide does not provide adequate
guidance. As -a result, the procedures contain numerous examples of
duplicate step numbering and steps where the relationship between a
step and.its RNO step is not clear.
6. 'The guidance on structure of subs'teps does not adequately define the
difference between substeps as action steps and substeps. as lists.
~ It allows inconsistent use of complete sentences and incomplete
sentences.
7. The peacekeeping space system defined by the writer's guide provides
checkoff' spaces at high level steps and in sequences of'four or more
-
. bulleted substeps. When a step includes several pages of substeps,
this method does not provide ahquate peacekeeping and it requires
operators to turn- backwards in the procedure to find the checkoff
-mark. The ' system also also. lacks sufficient peacekeeping for lists
of controls.
8. The writer's guide states that procedure steps should have one ' main
action and that multiple actions with a step are to be avoided.
However, numerous examples of multiple actions with steps were found.
9. .The writer's guide does not adequately address nor require some
method 'of reminder to operators of steps that may be performed
at some time in the future (e.g. , "WHEN condition, THEN action"
sequences).
10. The writer's guide allows the listing of partial valve numbers in a
horizontal list following one complete valve number. This method is
s unsatisfactory. It circumvents the writer's guide method for place-
keeping and increases the possibility of error or confusion.
11. The writer's guide defines the transition tern REFER T0" as indi-
cating that an operator will leave his place in the procedure to
go elsewhere, and then later return. This is in contrast to the PSTG
definition and the common definition of " REFER T0" as indicating
concurrent execution of steps.
_ _ - _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ - - _ _ _ _ _ _ _ _ - _ _ _ - - _ _ _ _ _ _ - _ _ _ _ _ _ - - - _ - _ _ - _ _ _ _ -
-- _
- -_ - -- _. - _ - _ _ _ _ _ _ . _ _ - . _ _ _ _ _ - _ .
,.
. '.* .
C-11
12. The ' dictionary of acronyms and abbreviations in the writer's ' guide
lists a number of abbreviations for which there are two definitions
and a number of definitions for which there are two acronyms or
abbreviations. Elimination of all dual use or dual definition
entries is necessary.
13. The constrained language list in the writer's guide contains a number
of words that have the same meaning and others that ciffer only
-slightly in meaning. Elimination of multiple approved vocabulary
having the same meaning will increase ease of procedure comprehension
and clarify distinctions between those words that are similar but
different.
14. The writer's guide fails to describe a method for indicating possible
plural status. For example, as in the step " check faulted S/Gs."
15. Enclosures to procedures must be subject to defined structure in the
writer's guide. The Catawba writer's guide dismisses enclosures from
the restrictions used'in procedures.
16. The use of the symbol for "approximately" is allowed by the writer's
guide. Directions that prohibit use of this symbol and require the
use of bounded tnierances whenever possible are not included in the
writer's guide.
1
! !
l' ___ ______________j
,_. - _ - _ . -
'
.
.- ..
- s ,
APPENDIX D-
NOMENCLATURE
- This appendix contains team observations of cases where E0P and panel
nomenclature differ The licensee agreed in each case to evaluate the
difference and make the appropriate change. These items will be reviewed during
a future.NRC inspection as noted in paragraph 3.c.
Procedure Step /pg. E0P Nomenclature Component Nomenclature
EP/1/A/5000/1A 5.a.7 "S/V BEFORE SEAT "S/V BEFORE SEAT DR"
DRN CLOSE" "C LOS E
EP/1/A/5000/1A 11.2 VCT FWST
EP/1/A/5000/1B 29/25 1-RF457 1-RF457B
EP/1/A/5000/1C 24/15 -1NI-178B (ND Hdr IB To ND HEADER 18 TO NC
Cold Legs A & B) COLD LEG LOOPS C&D
VALVE INI-178B
INI-173 (ND Hdr IA To ND HEADER 1A TO NC
Cold Legs C & D) COLD LEG LOOPS A&B
VALVE INI-173A
4/4 INI-334B (NI Pump Suct SAFETY ING. PUMP
X-0VER From ND) SUCT X0VER FROM
EP/1/A/5000/103 4 1EDE-F01F No label
EP/1/A/5000/2A
Enclosure 1 1 1CA-185 LETTER SIZE IS SMALLER
THAN THE REST OF THE
LABELS
-EP/1/A/5000/2C4 3/3 1CDB-F0IC ICDB (nc breaker
cubicle label)
ICDA-F08H ICDA (no breaker
cubicle label)
EP/1/A/5000/2C5 2 IBB69 No label
EP/1/A/5000/2d3 14/7 multiple "... T/V SS ... T/V Ss RESET ... ,
RESET"
AP/1/A/5500/02 C4a2 RNO STM PRESS PRESS
D2 CF HDR PRESS S/G INLT HDR PRESS
- )
- - _ _ _ - _ .. - -
. _ - _ _ _ ____- __ -
.r. ,
yg. .
=
1
D-2
Procedure ' Step /pg. E0P Nomenclature Component Nomenclature
AP/1/A/5500/03 C1,2 RNO CF HDR PRESS S/G INLT HDR PRESS
D17 R-L RAISE-LCYER I
I
D19d SWITCH NOT ON THE CONTROL j
BOARD {
AP/1/A/5500/04 2a Temp defeat Delta temp defeat
AP/1/A/5500/08 II,D.1 1AD-17 1AD-7
II,0.4b Chg Hdr Flow Chg Ln Flow
AP/1/A/5500/13 C2 & RNO CONTROL R00 BANK IS THE WRONG NAME FOR
LO-LO LIMIT FOR COMPUTER POINT
D4409
C2c. BORIC ACID XFR PMP B/A XFER PMP
AP/1/A/5500/17
Encl. 1- b2/11 Chemical letdown ... xNVP5531 LETDN ...
l
'
13/14. Blackout accident B/0 SEQ activated
sequencer activated
Encl. 6 4/2 ISGR-D-1, -3 Does not exist
1
4RN0/2 ISGR-D-2, -4 Does not exist
Encl. 7 4/3 Containment pressure Applicable meters have
inst. ids and noun;
latter do not include
any ref. to containment
pressure.
i AP/1/A/5500/25 3e/1 Refueling bridge Reactor b1dg refueling
3b/1 reactor bldg ... bridge
&
cl/2
d1/3 vp trn a upr cent vlvs ... pushbutton ...
enable switch ...
l 'vp trn b upr cont vlvs ... pushbutton ...
! enable switch
l
l
1
!
L__ _ ___ = - _ - - - - _
.. _. _ _ . . _ _ - - __
_ _ _ - _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ - _ _ - _ - _ _ _ _ - _ _ _ _ _ _ _ _ -
..
.. .. ,
- u ..
D-3
Procedure. Step /pg. E0P Nomenclature Component Nomenclature
AP/1/A/5500/26 b/1 IEMF-15 refueling spent fuel bldg
bridge spent fuel bldg refueling bridge ...
AP/1/A/5500/26 d1/3 vp trn a upr ... cont ... P/B ...
vivs enable switch ... block ...
"close"
... lwr cont vivs switch ... key switch ...
"close" . . . b1 k cl sd . . .
.. vp tr a enable ... keyswitch ...
pushbutton "close" ... block ...
vp tr b upr cont vivs ... P/B ...
enable switch "close" ... block ...
vp tr b lwr cont enable ... key switch ...
switch "close" ... bik cisd ...
OP/1/A/6450/10 2/3 -1ELCP0025 IELCP0251
e__________-____--
_ __ .
-
1
a
. . . ,
sl 9
h APPENDIX E
l LIST OF ABBREVIATIONS
1
AC Alternating current
AER Actions / expected response
A0 Auxiliary operator
A0P Abnormal operating procedure
AP Administrative procedure
ASP Auxiliary Shutdown Panel
CA Auxiliary Feedwater System
CFR Code of Federal Regulations.
CLA Cold leg accumulator
CMD' Construction and modifications division
CN Catawba Nuclear
CNS Catawba Nuclear Station
CNSD Catawba Nuclear Station Directive
CSF Critical Safety Function
CST Condensate Storage Tank
DPCPDPR Duke Power Company Procedure Discrepancy Process Record
D/G Uiesel generator
DHP Dynamic head pressure
D/P. Differential pressure
DRS Division of Reactor Safety
ECA Emergency contingency action
ECCS Emergency Core Cooling System
E0P Emergency operating procedure
l EPIP Emergency plan implementing procedures
EPRI Electric Power Research Institute
ERG Westinghouse emergency response guidelines
ESF Engineering Safety Features
ETQS Employee training and qualification system
FSAR Final Safety Analysis Report
FWST Fueling Water Storage Tank
GPM Gallons per minute
GTG Generic technical guidelines
HP Health physics
IAE Instrument and electrical
IEEE Institute of Electrical and Electronic Engineers
IEN Inspection and Enforcement Notice
IFI Inspector Follow-up Item
IN Information Notice
INPO Institute for Nuclear Power Operations
KC Component Cooling Water System
KF Spent Fuel Coeling System
LCO Limiting Condition for Operation
LER Licensee Event Aeport
LOCA Loss of Coolant Accident
MOD Motor operated disconnects
MSIV Main steam isolation valve
MWR Maintenance Work Request
!
.
. _ . - . _ _ _ _ _. . _ - _ =- . _ - _ _ - _____ -___--_-_-_._____ _ ___ ___- - - - _
- _ , -
'
.,
a[s A'
'
'e
.
E-2:
,
NE0 Nuclear equipment operator
NI Nuclear Instruments
NRC Nuclear Regulatory Commission
NS . Containment Spray System
NSM_ Nuclear Station Modification
NSMM' Nuclear Station Modification Manual
NUREG Nuclear Regulatory Commission
NV Chemical Volume and Control System
OAC Operator aid computer
OP Operating procedure
< 0STI Operational Safety Team Inspection
PGP Procedure generation package
PIR Problem Identification Report
PM Preventative maintenance
PORV. Power operated relief valve
PPM Parts per millfon
PRT Pressurizer relief tank
PSIG Pounds per square itich gage
PSTG Plant specific technical guidelines
PT Performance test
PWR Pressurized Water Reactor
PZR Pressurizer
QA Quality assurance
RN Nuclear Service Water System
RNO Response not obtained
R0 Reactor operator
R&R Removal and restoration
SALP Systematic Assessment of Licensee Performance
SER Safety evaluation report
S/G Steam generator
S/G TR Steam generator tube rupture
S/I Safety injection
SME Safe Margin Earthquake
SNSWP Station Nuclear Service Water Pond
SPD .Setpoint document
SRO Senior reactor operator
SS Shift supervisor
SSF Safe shutdown facility
SWR Standing work request
TS Technical Specifications
TSM Temporary Station Modification
UST Upper Storage Tank
VAC Volts alternating current
VCT Volume Control Tank
V&V Validation and verification
WR Work request
- _ _ - - _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ - _ _ _ _ - - _ _ _ - _ - _ - _ _ - - _ _ _ _ - - ___-_ ___-- _____ ________ _-__ _ _ - _ _ - _ _ - _ _ _ _ _ - _ .