ML20141F203
| ML20141F203 | |
| Person / Time | |
|---|---|
| Site: | Arkansas Nuclear  |
| Issue date: | 03/14/1986 |
| From: | Dyer J, Falconer D, Horbuck C, Martin T, Mckee P, Morris G, Mullikin R, Murphy M, Overbeck G, Sharkey J, Danielle Sullivan, Walenga C, Larry Wheeler NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II), NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV), NRC OFFICE OF INSPECTION & ENFORCEMENT (IE), WESTEC SERVICES, INC. |
| To: | |
| Shared Package | |
| ML20141F141 | List: |
| References | |
| 50-313-86-01, 50-313-86-1, TAC-61519, TAC-61520, NUDOCS 8604220488 | |
| Download: ML20141F203 (38) | |
See also: IR 05000313/1986001
Text
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OFFICE OF INSPECTION AND ENFORCEMENT
DIVISION OF INSPECTION PROGRAMS
Report No.: 50-313/86-01
Licensee: Arkansas Power & Light Company
P. O. Box 551
Little Rock, Arkansas 72203
Docket No.: 50-313 License No.: DPR-51
Facility Name: Arkansas Nuclear One, Unit 1
Inspection Conducted: January 6 - 31, 1986
i
Inspectors: [OM
T. O. Mhrtin, Inspection Specialist
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Team Leader, IE
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J. E. Dyer', Inspection Specialist, IE
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Falconer, Reactor Inspector, Region II
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C. C. Hafb~u':R, ANO Resident Inspector
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G. W. Morri's, NRC Consultant, Westec
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R. P. Mullik
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M. E. Mufphy, Reactor Inspector, Region IV
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G. J. Oter
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J. M4 5 arkey, Ins on Specialist, I Dbte
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D. J. Sul iv'anf Jr., InspFction Spec /glfst, IE
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L. L. Wh'eeldr, Inspection Specialist, IE
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G. W&lenga, Inspection Specialist, IE
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Accompanying Personnel: *J. Auchland, Westec
- L. J. Callan IE
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- A. T. Howell, IE
- G. Vissing, NRR
!
Approved by:- -
3/W/Sla
! Phillip F. McNee, Chief Date
l Operating Reactor Programs Branch, IE
i *Present during the exit interview on January 31, 1986
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l
l SCOPE: This special, announced team inspection involved 756 inspection hours
to perform an in-depth assessment of the operational readiness of the
RESULTS: The licensee's operational readiness and management controls were
reviewed in six functional areas, primarily as they related to the
emergency feedwater system. The functional areas reviewed were:
Design Changes and Modifications
l Maintenance
l
Surveillance Testing
- Operations
! Quality-Assurance
j
Training
Training is not addressed separately in this report; rather, it
is incorporated within the other functional areas as appropriate.
1 Eleven potential enforcement findings, identified in this report as
l Unresolved Items, and five Open Items will be followed up by the
NRC Region IV.
l
,
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I. INSPECTION OBJECTIVE
The objective of the team inspection at Arkansas Nuclear One - Unit I
was to assess the operational readiness of the emergency feedwater
(EFW) system by determining whether:
o The system was capable of performing the safety functions required
by its design basis.
o Testing was adequate to demonstrate that the system would perform
all of the safety functions required.
O System maintenance (with emphasis on pumps and valves) was adequate
to ensure system operability under postulated accident conditions.
o Operator and maintenance technician training was adequate to ensure
proper operations and maintenance of the system.
o Human factors considerations relating to the EFW system (e.g., acces- '
sibility and labelling of valves) and the system's supporting proced-
ures were adequate to ensure proper system operation under normal and
accident conditions.
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l
.
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II. SUMMARY OF SIGNIFICANT INSPECTION FINDINGS
This section summarizes the safety effects of the more significant findings on
the operational readiness of Arkansas Nuclear One (AN0)-Unit 1 emergency
feedwater system.Section III provides the detailed findings pertaining to the
major functional areas evaluated.
A. Safety Effects on the Emergency Feedwater (EFW) System
1. The inspection team identified design concerns regarding the ability of
the EFW system to perform its safety function during abnomal events,
a. For steam line break accident scenirios, given a single active
failure within the electrical power system (i.e., vital power), the
emergency feedwater initiation and control (EFIC) subsystem did not
have the capability to isolate the affected steam generator (SG) from
the unaffected SG. It appeared that this could result in the loss of
all EFW flow to both SGs. For a nonisolable steam line break in SG A
with a concurrent loss of offsite power, the EFW system and EFIC sub-
system rely on onsite power sources. If the loss of " red" ac power is
assumed as the single active failure (i.e., failure of " red" diesel to
start, fault on bus, etc.), the EFW motor-driven pump is unavailable
and motive power is lost to operate CV-2667 (the isolation valve
between SG A and the EFW turbine-driven pump). As a consequence,
CV-2667 could not be closed and EFIC would have unsuccessfully attempt-
ed to isolate SG A from SG B. Instead, the unaffected SG B would have
been cross-connected to the affected SG A through CV-2667 and CV-2617.
As a consequence, both SGs could have depressurized through the nonisol-
able break, and the steam supply to the turbine-driven EFW pump may
have been insufficient, causing a complete loss of EFW. In addition,
the blowdown of two SGs through a nonisolable break inside the contain-
ment building was outside the design basis for the containment build-
ing (See figure 1, page 6).
Subse.quent to the inspection, the licensee provided information indi-
cating that, for the main steam line break accident postulated above,
sufficient steam would have been available to the EFW turbine until
SG pressure dropped to approximately 80 psia.
b. No design analysis was found evalcating the consequences of
high-energy line breaks (such as a main steam line break within the
penthouse area) on the EFW system concurrent with a single active
failure even though the steam supply piping and valve arrangement was
modified. Likewise, the team found no design analysis performed to
assess the impact of high-energy breaks within the EFW steam supply
piping on other safety-related equipment.
The team found that the EFW system will function properly in response to
anticipated transients such as loss of offsite power concurrent with a
turbine trip and loss of main feedwater events. However, as evidenced by
the deficiencies identified above, the team found that the system may not
have been adequately protected from abnormal events such as high-energy
line breaks and earthquakes (see observation II.B.2).
2
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.
--
2. The team identified the following safety concerns with the licensee's
program for maintenance and testing of EFW system motor-operated valves
(MOVs),
a. Licensee personnel were generally unaware that EFW M0V torque
switches for ANO-Unit I were only bypassed during initial valve
movement and that, as a consequence, improper torque switch operation
could prevent the EFW system from completing its safety function.
This lack of understanding was apparently due to a design difference
in MOVs between Unit I and Unit 2. In ANO-Unit 2, M0V torque switches
are typically bypassed for full valve travel,
b. Torque switch settings were made without reference to the minimum
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recomended values provided by the vendor. The team reviewed
selected M0V. torque switch settings and found them to be set low; in
one case, the setting was below the minimum value used for
manufacturer testing.
c. MOV limit switches appeared to be set to bypass torque switches for
an insufficient amount of initial valve travel. The purpose of these <
limit switches was to bypass the torque switch until the valve was
fully off its shut seat, thereby providing some assurance that the
torque switch would not prematurely stop valve motion.
d. EFW system M0Vs located in the pump discharge piping were not teste!
under flow conditions to ensure that they would operate as expected
in emergency situations.
I
e. Several discrepancies in the MOV maintenance procedures were
l identified. These discrepancies could cause confusion among
! . personnel performing maintenance.
! In summary, the licensee could not verify, by test results, engineering
evaluation or venir input that current torque switch and limit switch
settings were adequate to permit proper MOV operation under expected flow
!
conditions for all operating scenarios. Most EFW system M0Vs are not
required to reposition under nonnal circumstances for EFW initiation.
However, EFW system MOVs would be expected to operate against design
differential pressure if a steam generator isolation signal was received
during EFW operation, if EFW water supply sources were required to be
shifted from the condensate storage tank to service water, or if EFW
initiation occured during system flow testing.
- 3. In addition to tne concerns described above relating to the testing of
! motor-operated valves, the inspection team identified other electrical and
l mechanical equipment in the EFW system that had not been tested.
!
I a. The condensate storage tank (CST) level indication transmitter,
'
LIT-4203, had apparently not been calibrated after installation
during the 1984 refueling outage. The licensee also had no routine
surveillance procedure to ensure that this instrument is periodically
< 3 i
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calibrated. This instrument is used by operators to make the
determination to manually shift EFW pump suction from the
non-safety-related CST to the safety-related service water backup,
b. Eight valves in the EFW system that required routine in-service
testing were not periodically tested. These valves included four
check valves in the EFW pump suction line from the CST, one check
valve in each EFW pump minimum recirculation line, and one 3-way
valve downstream of each EFW pump that allows recirculation flow when
the EFW pump is discharging at high pressure. The proper operation
of these valves apparently cannot be verified without the
installation of additional instrumentation.
B. Effects on Other Safety Systems
In addition to the specific concerns discussed above that relate directly to
the operational readiness of the EFW system, the team also identified several
general concerr.s that have the potential to affect the proper operation of
other safety systems. ,
1. Problems were noted in the ANO-1 mechanical design-change process. The
team identified instances where modifications were done without significant
mechanical design activities being performed, completed, or documented.
The team believes that these oversights should have been corrected during
the design verification and supervisory reviews. The fact that these omis-
sions were not detected indicated an apparent lack of design experience
and/or a lack of supervisory attention.
2. ANO-Unit I did not routinely consider the effect of equipment that is not
designed to meet maximum design basis earthquake requirements (seismic
Class 2) on equipment that is designed to meet maximum design basis earth-
quake requirements (seismic Class 1). The team detemined that evaluations
of potential seismic interaction, seismic Class 2 over Class I situations,
were not being routinely considered when preparing the civil portions of
design-change packages. The lack of consideration for seismic interaction
could have a significant effect on the operability of all safety systems
at AN0-Unit 1 during a seismic event. Seismic Class 1/ Class 2 interaction
is apparently fully considered at AN0-Unit 2.
3. The team found several samples of controlled design documents with incor-
rect or misleading information. Based on the number and types of discrep-
ancies, the team believes that the implementation of configuration control
activities was weak.
III. DETAILED INSPECTION FINDINGS
A. Design Changes and Modifications
The inspection team examined design aspects of design-change package (DCP)
82-D-1050. This design change was to replace the EFW pump 7A turbine driver,
4
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to add new steam admissicn valves, to reroute the turbine steam supply piping,
and to modify the turbine pump suction and discharge piping. In addition, DCP
80-10838 was examined. This modification was to replace the discharge piping
of the EFW pumps, and to add modulating control valves, automatic recirculation
control features, and a full flow test leop, and to change selected valve
actuators from ac to dc power. The following observations were made:
1. The team determined that the implementation of DCP 82-D-1050 failed
to ensure that it met the single-failure criterion. Specifically, for
stean line break scenarios, given a single failure within the electrical
power system (vital power), the emergency feedwater initiation and control
system (EFIC) would not have the capability to isolate the affected steam
generator (SG) from the unaffected SG. It appeared that this could result
in the loss of all EFW flow to both SGs.
Figure 1 on page 6 illustrates the main steam system supply configuration
to the EFW turbine pump at the time of the inspection. The steam supply
to EFW pump 7A is supplied from both SGs through normally open ac motor-
operated control valves CV-2617 (SG B) and CV-2667 (SG A). Like the motor-
driven pump, the EFW turbine pump supplies feedwater to either or both SGs
depending on the EFIC vector signals. For a steam line break, the EFIC
system will isolate the depressurized SG in order to isolate that affected
SG from its associated main steam and main feedwater lines. If isolation
of the affected SG does not isolate the break, the EFIC system will provide
EFW only to the intact SG. For a nonisolable steam line break in SG A with
a concurrent loss of offsite power, the EFW system relies on onsite power
sources. If the loss of " red" ac power is assumed as the single active
failure (i.e. , failure of " red" emergency diesel to start, fault on bus,
etc.), the EFW motor-driven pump is unavailable and motive power is lost
to CV-2667. As a consequence, EFIC would have unsuccessfully attempted to
close CV-2667, and therefore the unaffected SG B would have been cross-
connected to the affected SG through CV-2G67 and CV-2617. Both SGs would
have then depressurized through the nonisolable break and the steam supply
to the turbine-driven EFW pump could have been insufficient, causing a
complete loss of EFW.
Subsequent to the inspection, the licensee provided infonnation indicating
that, for the main steam line break accident postulated above, sufficient
steam would have been available to the EFW turbine until SG pressure dropped
to approximately 80 psia.
Review of DCP 82-1050 (the design change to install the new EFW turbine,
new dc steam admission valves, and to modify EFW suction and discharge
piping) indicated that a single-failure analysis was not performed.
Specifically, question 15 of the DCP asked, "How was the impact of failure
of the systems, components, and structures considered in the design?" In
response, the Project Engineer indicated that the question was not
applicable by answering "NA." This response was checked and approved
without comment. Procedure 1032.01, " Design Control," Pevision 7,
required an independent reviewer to verify that responses to the Design
Evaluation Questions had been properly addressed and that the discipline
portion of the design change was complete and technically accurate.
5
(LOW VACUUM) TRAIN A TRAIN B (Low VACUUM)
TRAIN A MSLI CONTROL CONTROL TRAIN 8 NSLI
CV 2676 CV 2668 CV 2618 CV 2619
- TRAIN A MSLI
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OR ;;
74 = A THOS = v, 8 TRAIN A HSLI
1 RAIN 8MSLh 8
CV 2691 SAFETY OR
SAFETY
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VALVES TRAIN 8 HSLI
Cv 2692
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STEAM '
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fCv2667 CV 2617
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CV 26C6
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1 g TRAIN B EFW- - --
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TRIP THROTTLE VALVE
GOVERNOR VALVE
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) EFW TURBINE PUMP
, FIGURE 1
ANO-1 MAIN STEAM SUPPLY -
TO EMERGENCY FEEDWATER TURBINE PUMP
4
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-
The team noted that the final design of the EFW system upgrade was submit-
ted to the NRC for approval by an AP&L letter dated December 1,1981. The
design described in that letter and subsequently approved by the NRC
contained check valves to prevent blowdown of the unaffected SG through
the affected SG. However, because a similar application of steam check
valves had not proven reliable, the licensee subsequently decided to
eliminate the check valves from the design and did not perform an adequate
10 CFR 50.59 review to determine if an unreviewed safety question existed.
At the completion of the onsite inspection activities, the licensee was in
the process of installing check valves in the steam supply lines to the
EFW turbine to correct this deficiency.
Contrary to the requirements of 10 CFR 50, Appendix A, General Design
Criterion 34, the EFW system did not have suitable redundancy in
components and features and isolation capabilities. Assuming a single
failure, no assurance was provided for proper safety system function for
onsite electric power system operation (assuming offsite power is not
available) and for offsite power system operation (assuming onsite power
is not available). In addition, contrary to the requirements of 10 CFR
50.59, the licensee failed to perfom an adequate analysis to determine
the existence of an unreviewed safety question.
This item was discussed with the licensee and will remain unresolved
pending followup by NRC Region IV (50-313/86-01-01).
2. The licensee had not routinely considered the effect of equipment that is
not designed to meet maximum design basis earthquake requirements (seismic
Class 2) on equipment that is designed to meet maximum design basis earth-
quake requirements (seismic Class 1) at ANO-Unit I whe. preparing the
civil portions of design change packages. The team was inforrud by the
licensee's engineering personnel that no requirements existed to perform
seismic Class 2-over-1 evaluations, either as part of the ANO-Unit I
design change process or original design. In scope, ifcensee Procedure
CEQN-00002-0 indicated that all ANO-Unit 2 OCPs are evaluated f or poten-
tially hazardous seismic Class 2-over-1 interactions but that Unit I
design changes are evaluated only at the direction of the lead engineer.
This approach appears to be contrary to FSAR commitments. The FSAR states
in a description concerning the design of seismic Class 1 piping systems
that:
"Where Class I seismic structures are directly connected to or in
close proximity to Class 2 seismic equipment and piping systems, the
failure or excessive movement of the Class 2 seismic systss are
restrained in such a way as not to cause a failure of Class I
structures."
I
i The licensee had interpreted this statement to mean that seismic Class 2
equipment and piping systems will not interfere with seismic Class 1
structures. The licensee did not consider safety-related seismic Class 1
( systems and components to fall under the domain of seismic Class I
structures; therefore the licensee did not routinely consider seismic
Class 2-over-1 interaction.
7
.
The team observed no documentation of instances where seismic Class 1/
Class 2 interactions were evaluated, with the exception of minor statements
in response to DCP Design Evaluation Questions and redesign of the support
system for the EFW pump room chiller (DCP 80-10838). The inspection t en
considered a seismic Class 1/ Class 2 evaluation of service water piping '
located in the EFW r. ump room to be inadequate because it appeared to assume
that the initiating event was a pipe break and not a seismic event. The
potential for pipe movement (i.e., seismic shake space) or hanger pullout
considering dead weight and seismic accelerations was not addressed. The
analysis concluded, without documented justification, that two hangers
provided at both ends were adequate to support the weight of the pipe.
The lack of consideration for seismic interaction will remain unresolved
pending clarification of the requirements for ANO-Unit 1 (50-313/86-01-02).
3. Civil design calculations of structures with multiple degrees of freedom
did not always consider the effects of seismic forces acting simultaneously.
Specifically, the team found that the seismic support design of the EFW
pump room chiller was a structure with two degrees of freedom in the horiz-
ontal direction but, in the analysis (Calculation 80-D-1083B-01), it was
assumed that seismic movement can only occur in one direction at a time.
The following discrepancies and errors also were noted:
a. The calculation did not combine the maximum values of responses for
each of the two applicable orthogonal spatial components of an earth-
quake to obtain a combined representative maximum value. In addition,
a nonconservative section modulus was used because of an assumption
to consider seismic movement in only one degree at a time. The
analysis used a section modulus of 1.07 from the AISC Steel Construc-
tion Manual for the angle f ron used the support design; however, trans-
formation about the principal axis was apparently not considered to
evaluate bending stress. The team determined that the correct section
modulus would be approximately 0.714, indicating a less conservative
design.
b. The analysis did not include a design evi.luation of the connection
between the angle f ron and the frame of the chiller. The team was
informed that the connection was welded and that the design adequacy
of the connection was performed by inspection without documentation.
c. In conducting the design verification of the calculation, the checker
performed an alternate calculation which applied inappropriate design
equations. The checker used AISC Steel Construction Manual equation
1.5.1.4.5.2 which dealt with struts in compression and not angles in
compression and/or tension.
d. Design input was incorrectly stated and, in one instance, an incorrect
reference was identified. A critical damping value of 2 percent was
used in the calculation instead of 0.5 percent as indicated. Addition-
ally, the reference identified as the source of the maximum peak vert-
ical acceleration was incorrect because it referred to a seis..;ic
response spectrum for horizontal accelerations.
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Although the team found the design of the EFW pump room chiller
seismic supports to be adequate when the two horizontal degrees of
freedom were considered, the team was concerned that similar seismic
-
calculation errors may exist for the design of other seismic
supports. This item will remain open pending further NRC review of
the licensee's method for performing seismic calculations
(50-313/86-01-01).
4. Post-modification testing in the form of an adequate service test was not
performed on the recently replaced station batteries to conclude that these
batteries had sufficient capacity under design conditions to perform their
safety function. The following observations pertain:
a. DCP 83-1032 was issued to replace the Class IE station batteries.
As part of this replacement, the design change included the require-
ment to perform a 2-hour service test using the duty cycle from
calculation GE-830-1032-01. In response to this requirement, a
service test was performed for battery 007 under ANO Job Order 058396
on March 24, 1984. The team reviewed the test data and determined
that this initial service test did not include all the necessary
design requirements, such as corrections for minimum design tempera-
ture. In addition, it did not appear that the test discharge current
was corrected for the average cell electrolyte temperature at the
start of the test. Temperature affects the response of the battery
so that test temperature must be accounted for in order to have a
common reference point. Additionally, the team could not confirm
what the actual test current was because the test data sheet did not
record the actual test current but instead referred to a specific
sheet of the battery sizing calculation for the test profile. The
calculation sheet that was referenced for both the 007 and 006 bat-
teries did not contain any test profile.
Another problem with the test currents was that the licensee measured
battery voltage at half-hour increments, completely missing the
critical discharge period at I minute into the test where the battery
sizing calculation indicated the voltage would be most limiting. The
test results indicated less than one-half volt difference in battery
, voltage during the test. A discharge voltage profile calculation
i
for the latest duty cycle (which was similar to the original duty
cycle for the first 30 minutes) indicated voltages should be 5 to 12
volts below what the test results showed.
b. DCP-83-119 was issued to modify the dc system components, including
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removal of two cells from each of the station batteries to reduce
the de system voltage. The newly configured battery was then tested
per Special Work Plan 1409.29 using a performance discharge test to
i
meet the Technical Specifications requirements for battery testing.
l
During the performance of this test, the average battery temperature
was determined to be 82 F. To determine the actual test discharge
current, the battery current for an 8-hour discharge was corrected
for temperature. However, the team had the following concerns:
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(1) The temperature correction factor used was not for 82*F.
The procedure permits the use of battery room temperature
if many hours have passed since the average electrolyte
temperature was determined. The data sheet did not record
if room temperature was used or what that value was.
(2) The temperature correction factor that was used was incor-
rectly applied by multiplying the rated discharge current
by this factor to give, in this case, a lower test current.
This method was in disagreement with industry standard IEEE 450-1980, which was included as a referenced document.
IEEE 450-1980, Section 5.3, states that the rated discharge
current should be divided by the temperature correction
factor. This would have increased the required discharge
current instead of decreasing the current, resulting in a
lower capacity in the battery than what was determined in
the perfomance test.
ANSI N18.7-1976, " Administrative Control and Quality Assurance for the
Operational Phase of Nuclear Power Plants," Section 5.2.19.3, requires l
that modifications that affect functioning of safety-related systems or
components be inspected and tested to confirm that the modifications or
changes reasonably produced expected results and that the change does not
reduce safety of operations. Contrary to the above, the modification
acceptance tests for the station batteries did not confim the expected
results because the tests included incorrect discharge currents and the )
service test did not have an appropriate acceptance criteria (i.e., it j
failed to measure the voltage at the critical period). This issue was
discussed with the licensee and will remain unresolved pending followup
by NRC Region IV (50-313/86-01-03).
5. In some cases, mechanical design change packages were found to be reviewed
and approved without completion of all design calculations or design
evaluations for critical design attributes. The following examples pertain:
a. No design analysis was performed to evaluate the consequences of
high-energy line breaks when DCP 82-D-1050 was reviewed and
approved. Although this design package modified and extended ,
the boundary between high- and low-energy conditions, the
consequences of high-energy line breaks (such as a main steam
line break within the penthouse area) on the EFW system con-
current with a single active failure were not analyzed. Similarly,
the team found no design analysis performed to assess the impact
on other safety-related equipment of high-energy line breaks within
the EFW steam piping. In response to this observation, the licensee
showed the team a March 12, 1981, letter to the NRC, written before
the design package was prepared. Without apparent design analysis,
this letter concluded that a break in the steam supply piping for
the turbine-driven EFW pump would not adversely affect other critical
10 l
_ _ - _ _ _ _ _ _ - _ _ _ .
EFW components and that once the break is isolated, the plant could
be brought to a safe shutdown condition, assuming a concurrent
failure of the motor-driven EFW pump by using the normal feedwater
system or the high-pressure injection system. The team concluded
that the design configuration being assessed by the licensee in the
March 1981 letter was not the same as that described in the actual
design package (i.e., check valves not installed, see observation 1
of this section). The single failure postulated by the licensee may
not have been the most severe (i.e., loss of bus resulting in loss
of motive power to isolate the break and loss of the motor-driven
pump). The team also concluded that the assessment did not address
the consequences to EFW piping and components of other high-energy
line breaks.
b. .Although the EFW system was upgraded to be safety-related by the
design change packages reviewed, design analysis was not performed
nor was an engineering review of original architect engineering
analysis performed to determine if safety-related room cooling was
required while both EFW pumps were operating. In response to the
team's concern, the licensee provided design analysis used to
establish the environmental equipment qualification pressure and
temperatures. Review of these analyses indicated that they are for
three high-energy line breaks outside containment. These breaks
are two letdown line breaks and a main feedwater line break. Although
the consequences of high- energy line breaks outside of containment
need to be considered in developing equipment environmental conditions
for qualification purposes, those consequences may not be the most
, severe condition under which safety-related EFW equipment must operate.
The lack of design analysis in the cases cited above appears to be contrary
to the requirements of ANSI N45.2.11, Sections 4.1 and 4.2, which require
that design analysis be performed in a planned, controlled, and correct
manner and that there exist traceability from design input through to
design output. This item was discussed with the licensee and will remain
unresolved pending followup by the NRC Region IV (50-313/86-01-04).
6. Numerous calculations and design analyses reviewed failed to meet the design
control requirements of ANSI N45.2.11 by not documenting inputs and assumptions,
by not ensuring a correct methodology was used, and by not ensuring that the
calculations were sufficiently completed to permit verification without recourse
to the originator. The following examples pertain:
a. Calculation GE-83D-1032-01, dated January 25, 1984, established
an emergency duty cycle for the station batteries and determined
the battery size required to replace the existing batteries.
This calculation referenced industry standard IEEE 485 for
,
sizing large lead storage batteries; however, it only included a
correction factor for aging and neglected any correction factors
i
for operation at minimum temperature. Procedure 1307.006, "007
l
.
! 11
.
_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _
Quarterly Surveillance," monitors cell electrolyte temperature
and contained an acceptance criteria of 60 F as the minimum
battery temperature. Manufacturers normally rate their batteries
at 77*F. This 17'F temperature difference would result in a loss
of capacity of approximately 11% according to the industry
standard referenced in the calculation. This calculation
concluded that the battery was sufficient for an 8-hour
discharge. The following additional weaknesses were observed in
this calculation:
(1) No justification was included in the calculation to
permit the reduction of the safety-related inverter loads
from 75 amperes to 10 amperes after 30 minutes into the
design discharge.
(2) NOV starting currents had not been considered as part
of the first minute discharge loads.
The team reviewed the battery sizing performed by the
manufacturer on March 17, 1984, and noted:
(1) The manufacturer's sizing calculation used cell discharge
current capabilities that were substantially lower than
those for the same size battery cell used by the licensee
in both the 1983 or 1984 calculations.
(2) The manufacturer's calculations were based on a different
4-hour profile than what was used by the licensee.
(3) The manufacturer's calculation noted that no correction
factors were included for temperature compensation because
no minimum operating temperature requirement was specified
by AP&L.
b. Calculation 830-1032-05, dated July 9,1985, revised the battery
sizing calculation (discussed in observation 6.a) to include a
de power panel load study, a revised inverter de load demand
based on actual measured inverter loads, and MOV motor inrush
currents. The calculation again concluded that the batteries
would adequately supply an 8-hour duty cycle. The team noted
that temperature correction again was not included in the calcu-
lation of the required cell size. The following weaknesses were
noted with the determination of the new inverter loads:
(1) These loads were based on a measured inverter loading
during normal plant operation and did not appear to
consider maximum design values.
(2) The de loads were not measured but calculated from the
inverter output ac load using assumed inverter efficiencies.
These calculated dc loads were 20 to 30 amperes less than
the values the team read from the inverter dc input current
anneters while the plant was in a normal shutdown mode. The
licensee initially stated that the team's readings were in
error because of the inaccuracies of the inverter de meter
l
l
12 ;
1
1
_ _ - _ _ -
j
_ . . - . -. _ -. .-. _. . -- . - _ _ . _ . _ - -
but then agreed that the assumed inverter efficiencies were in
error.
c. Battery. sizing calculation 83-1032-06, dated January 24, 1986, was
developed in response to the team's concerns and was performed to
verify that the A50 batteries would meet the Unit-1 FSAR minimum
requirement for a 2-hour discharge.
l
-
The team noted that a new manufacturer's cell discharge charac-
teristic curve (D-699-1A, 6/84) was attached to this calculation
,
to justify the latest cell discharge capability. These new cell
capabilities were greater than those used by the manufacturer in
the 1984 calculation but less than those used by AP&L in its -
1983, 1984, and 1985 calculations. This n.ost recent calculation
also included the correction factors for aging and minimum
i operating temperature. The inverter load values used were based
j on a measurement taken during plant shutdown without justification
, as to why a margin should not be used for meter inaccuracy or
1
increased load during a design-basis event.
4 d. Calculation 80-1083A-02, dated January 14, 1986, was developed
to detemine the voltage at the terminals of newly installed dc
, -motor-operated valves. This calculation assumed that the
voltage available for operating the valve motor was solely a
, function of the capacity removed from the battery; no consideration
was given to any loss of the battery's capability because of aging
,
or minimum acceptable operating temperature. This calculation was
superseded by Calculations 80-1083A-04 and 83D-1032-07, both dated
, January 24, 1986, and prepared in response to the concerns of the
'
inspection team. These calculations correctly developed a battery
voltage profile based on the corrected rate of discharge and the
- actual capacity removed from the battery. The voltage drop from
the batteries to the motor control centers had also been factored
into the calculation of motor terminal voltage. New feeder lengths,
based on the cable pull slips from the motor control centers to
the valves (longer than those used in the original calculation,
80-1083A-02) were also included.
'
The original M0V terminal voltage calculation acceptance criteria
was based on a telecon between AP&L and the valve actuator manufac-
turer. These latest calculations (80-1083A-04 and 830-1032-07) did
not reference any new acceptance criteria but concluded that the
resulting lower torque developed was still sufficient even with the
lower voltage at the valve motors. The team noted that these latest
calculations showed the torque developed at valve CV-2870 was
7.32 ft-lbs and that the acceptance criteria used in the original
calculation for this valve was 10 ft-1bs. The team requested con- i
'
firmation that the acceptance criteria referenced in the original
calculation was sufficient to operate the ANO valves under design
requireme.nts. AP&L was not able to produce a valve-actuator
sizing analysis during the inspection to confirm the required
motor starting torque.
$
13
.- -. . ,. . -- . - - . _ . - . , . . . - - - - - - _ - - _ .
. - _ - . ~-. , . . - . -.-
e. Calculation 83D-1032-02, dated February 17, 1984, was prepared
to show the acceptable short circuit withstand capability of the
existing de distribution system components with the new larger
batteries. This calculation justified a potential problem that
the power panels that were rated only for 10,000 amperes could
'
potentially experience a short circuit slightly higher than
rating. The team identified other de components, such as the
battery chargers, that were not included in the analysis but
could add to.the short circuit. The licensee noted that the
calculation did not include consideration of the existing fuses
or additional cabling to the new battery disconnect switches
that would ensure that current would remain below the panel
rating.
f. Calculation 84E-0083-12, dated November 19, 1985, included a
protective relay study for breaker A311 feeding the EFW pump
motor. This calculation failed to document the source of the
safe stall time, starting time, or locked rotor current used in
the calculation,
g. No calculations were perfonned by the ifcensee to determine
motor-operated valve overload heater sizing. The team noted
that the heaters that were installed for the dc motor-operated
valves were selected by the motor control center vendor,
apparently based upon a continuous duty motor. The de motors
used on the AN0-1 valve actuators are short-duty-rated motors.
The team estimated that heaters selected in accordance with the
valve actuator manufacturer's recommendations could be
approximately five sizes smaller than those presently installed
' at ANO. These smaller heater sizes would still permit a valve
stroke time approximately twice the acceptance time required by
,
the valve surveillance procedures.
Calculations did not consistently identify inputs and assumptions or
provide sufficient detail to permit technical review and verification
without recourse to the originator. These calculation deficiencies,
j as discussed in subparagraphs 6.a through 6.g, above, appear to be
'
contrary to the design control requirements of ANSI N45.2.11, Section
4.2. Similarly, contrary to the design control requirements of
'
Section 6.2, the verification process did not consistently confirm
that inputs were correctly selected, that assumptions were reasonable
and appropriate, and that an appropriate design method was used.
This item will remain unresolved pending followup by NRC Region IV
(50-313/86-01-05).
7. A large number of controlled design documents and drawings contained
errors and omissions. Based on the number and type of discrepancies i
identified, the implementation of configuration control activitics
were considered weak. The following examples pertain:
a. Piping and instrumentation diagrams were found to have incorrect
valve positions, incomplete locked positions indicated, and
<
missing instrumentation bubbles.
14
- -. . . - - - _ . - . - _ - - . , - _ _ - - , . - _ . _- -- - 2
The following deficiencies pertain to drawing M-204, Sheet 3 of
4, " Piping & Instrument Diagram, Emergency Feedwater," Revision
2:
'
(1) Manual valve CS-2802C was indicated as normally open;
however, the valve was actually normally closed.
(2) Manual valves FW-11A and FW-118 in the pump recirculation
lines to EFW pumps 7A and 78 were shown as nomally open
valves; however, these valves were actually locked open
valves.
The following deficiencies pertain to drawing M-206, Sheet I of
,
2, " Piping & Instrument Diagram Steam Generator Secondary
System," Revision 45:
(1) EFW turbine steam supply valves CV-2617 and CV-2667 were
'
indicated as normally closed; however, these valves were
actually normally open.
'
(2) CV-2619 and CV-2676, block valves for atmospheric dump
,
valves associated with steam generators 8 and A,
'
respectively, were indicated as normally open; however, the
valves were actually nomally closed.
(3) When CV-2617 and CV-2667 were changed from normally closed
to nomally open valves, Note 4 of the P&ID was not revised
or deleted. Note 4 states, with respect to the bypass
valve around CV-2667, that a " single failure analysis
requires only one bypass valve. A bypass around CV-2617 is
not required."
The following deficiencies pertain to AP&L Drawing M-202,
" Piping & Instrument Diagram, Main Steam," Revision 33:
(1) Instrument bubbles were not shown for the handswitch and
selector switch for CV-2613 and CV-2663 (EFW turbine steam
admission valves).
l
(2) CV-2613 and CV-2663 were shown as nomally open valves;
- however these valves are actually normally closed. ;
-
!
The following deficiencies pertain to AP&L Drawing M-212, Sheet
,
I of 2 " Piping & Instrument Diagram, Plant Makeup Domestic
! Water Systems," Revision 29:
l (1) Condensate storage tank supply isolation valve CS-19 was
j shown as a normally open valve; however it was actually a
l locked-open valve.
(2) CV-4201, the heating steam supply valve to the condensate
storage tank, was shown as normally open when it was
actually normally closed.
l
15
b. The piping design specification for AN0-Unit 1, M-84, " Piping
Class Drawing," Revision 22, contained errors and was not
adequately controlled. The following deficiencies pertain:
(1) DCP-80-10838 identified that a revision to the piping
design specification was required to add a new piping
classification identified as Class DBD. Drawing control
records did not indicate that a change was in progress as
would be indicated by assignment of a modified drawing
revision number for the affected pages as required by AP&L
Design Document Control Procedure 1032.11.
(2) Pages 1 and la, the list of effective pages, of the pipe
design specification M-84 were compared with the Document
Control copy of M-84. Eight errors were identified
corresponding to missing pages or incorrect revision
numbers. The team also found an uncontrolled copy of M-84
in use which differed from the controlled copy by one page,
c. The Instrument Index, a controlled design document, contained
errors and omissions. In particular, the document omits
approximately 22 safety-related EFW instruments and does not
identify 30 other items as safety-related. The following
safety-related EFW instruments were not listed in the Instrument
Index:
CV 2869, CV 2870, F0 2800, F0 2801, HS 2869, HS 2870, I/P
2618 I/P 2668, SS 2613, SS 2617, SS 2619, SS 2620, SS 2626,
SS 2627, SS 2663, SS 2667, SS 2670, SS 2676, ZS 2613-1, ZS
2663-a, ZS 2869, and ZS 2870.
The following safety-related EFW instruments were in the
Instrument Index but were not Identified as safety-related:
CV 2613, CV 2619, CV 2626, CV 2627, CV 2663, CV 2666, CV
2676, CV 3850, CV 3851, HS 2619, HS 2676, HS 2800, HS 2802,
HS 2805, HS 3850, HS 3851, SV 2613, SV 2663, ZS 2617, ZS
2619, ZS 2626, ZS 2627, ZS 2667, ZS 2676, ZS 2800, ZS 2802,
ZS 2803, ZS 2806, ZS 3850, and ZS 3851.
The team noted that the licensee was currently in the process of
identifying all safety-related plant equipment on a component
level basis to create a new Q-list. This effort appeared to be
extensive and should resolve any future concerns of safety-
related component classification.
d. The following draf ting errors or incorrect information were noted
on controlled drawings.
(1) On drawing M-2C6, Sheet I of 2, " Piping & Instrumenta-
tion Diagram, Steam Generator Secondary System," revision
45, a cloud around a portion of the drawing that was
previously revised was not removed (see H-7 of the
drawing) . The licensee used clouds on drawings to indicate
the area of the drawing that was last changed.
16
-
. - . . . .. - -- . -
!
i
I-
(2) Drawing M-402, Sheet 3 of 4, " Functional Description &
Logic Diagram Condensate Feedwater System," Revision 14,
contained the following incorrect statement: " Suction
- lines are furnished with 5 motor-operated valves, CV-2800,
l CV-2801, CV-2802, CV-2803, and CV-2806, and a solenoid
l operated valve CV-2804." However, CV-2801 and CV-2804 did
! not exist in the current system configuration.
1
(3) The logic diagram for CV-2869 was described as " Emergency
F.W. Pump 7A Auto Recirc Valves" when in fact it was-the .
EFW pump 78 full-flow test isolation valve. Auto '
recirculation valves were FW-10A (pump 7A) and FW-108 (pump
l 78).
(4) Drawing M-402, Sheet 3, " Logic Diagram Condensate Feedwater
System," Revision 15, showed a seal-in feature for EFW
valves CV-2620 and CV-2627. This-did not agree with
- schematic E-293, Sheet 1, Revision 8, which showed this
seal-in feature deleted.
(5) Drawing M-402, Sheet 3, " Circuit for EFW Pump Suction
Valves," incorrectly showed the indicating light at the
full travel position in disagreement with all other
circuits and the schenatic E-296. This drawing also did
not include a seal-in circuit around the momentary switches
! in disagreement with the schematic E-296.
(6) Drawing M-404, Sheet 3, "MS ATMOS Dump Valre Logic,"
Revision 3, showed seal-in around manual switch HS 2676
which did not agree with schematic E-442. Revision 5. This
drawing also incorrectly showed a high closing torque
switch shown ic opening circuit.
(7) Drawing E-442, "MS ATMOS Dump Valve Schematic," Revision
5, incorrectly references drawing E-84, Scheme A, which was
for a 480-Vac reversing starter with no engineering
safeguards relays.
(8) Drawing E-86, Sheet 1, " Schematic Diagram EFIC Trip Relay
Assembly," Revision 0, incorrectly identified the right
scheme as a IE to IE trip module assembly, it should be IE
to non-1E.
(9) Drawing E-293, Sheet 1, " Schematic Diagram EFW Steam
Generator Isolating Valves (DC)," Revision 0, referenced l
E-96 for internal wiring of the de reversing starter. The
wire numbers shown did not agree between the drawings for
the negative leads for the series winding or the remote
indicating lights so that one cannot determine if the
remote lights will indicate an open thennal overload relay
contact (device 49). The hand switch contact development I
did not indicate the reference circuit for the switch .
contacts. This was typical of most circuits reviewed by
the team.
17
!
.-. -
_
- _. ---__._ --.-__._-. - - . . . , -
. .
..
(10) Drawing E-293, Sheet 2, " Schematic Diagram EFW Steam
Generator Isolation Valves (AC)," Revision 1, incorrectly
referenced drawing E-96 for internal wiring of this ac
reversing starter. Drawing E-96 was for dc starters.
(11) Drawing E-294, " Schematic Diagram Emergency FW Motor
Driven Pumps," Revision 10, did not indicate an immediate
start signal if the.offsite power is available through
breaker A-309, as indicated in the logic diagram on M-402,
. Sheet 3. The alam circuits for this drawing included a
pump low-discharge-pressure alarm but not the
high-discharge-pressure alarm indicated on logic diagram
M-402. Additionally, the setting of the time delay of
relay 174-311 of 65 seconds disagrees with the setting of
110 seconds indicated on logic diagram M-402.
(12) Drawing E-295, Sheet 1, " Schematic Diagram EFW Turbine
MOVs," Revision 21, referenced motor starter internal
wiring scheme A on drawing E-84. Scheme A2 on drawing E-84
referred to this circuit.
(13) Drawing E-295, Sheet 3, " Schematic Diagram EFW Turbine
M0V's," Revision 1, included a pump low-discharge-pressure
alann but not the high-discharge-pressure alarm indicated
on logic diagram M-402.
(14) Diagram E-295, Sheet 4, " Schematic Diagram EFW Turbine
MOVs," Revision I, was found to be in error. An interlock
in the valve open circuit from the 42R auxiliary contact
was shown to use terminals 8 and 9. According to drawing
E-96, these terminals are actually wired to the 42F
auxiliary contact.
(15) Drawing E-295, Sheet 4A, "EFW Turbine M0V's," Revision 0,
l incorrectly referenced a " green" power supply panel for a
" red" circuit. Howeter, the circuit was actually wired
correctly. The adapter table for this drawing did not
identify the power supplies, and the contact development
for relay 42X-M084 failed to identify the applicable
circuit for contact IH-lG.
(16) Drawing E-315, Sheet I, " Schematic Diagram Steam Genera-
tor Isolation Control," Revision 15, had the following
errors: The contact for relay 63X1/1 was incorrectly shown
as relay 63X/1. The coil for relay 62-3 was incorrectly
labeled 63-3. The time delay for relay 62-3 was shown as
two different valves on the same sheet. The time delay for
relay 62-2 conflicted with the time delay for same relay
shown on drawing E-317-3.
l (17) Drawing E-318, Sheet 1, " Schematic Diagram EFW Recircuit
l Test Isolation Valve," Revision 22, 3/5/85, indicated that
l valve CV-2870 had a 1/3 hp motor. The valve data sheet
i indicated that CV-2870 had a 0.72 hp motor.
l
18
!
. _ _ - _ _ _ - _ . _ _ _
(18) Drawing E-331, Sheet 31, " Schematic Diagram," Revision 1,
1/3/85, incorrectly identifies power panel RS2 as a 120-Vdc
power source. This power panel was actually an ac supply.
The team was concerned that inaccurate design drawings could cause
design engineers to perform design activities incorrectly. For
example, the incorrect depiction of valve position and the lack of
correct locked indication can cause a design engineer to perform
single failure analyses and safety evaluations incorrectly. In at
least one instance, the team noted that drawing errors appeared to
have an adverse effect of safety-related activities performed by an
AP&L contractor. Specifically, a contractor perfoming Q-List
determinations did not identify instruments SS 2619 and SS 2663 as
safety-related apparently because the piping and instrumentation
diagram had those instrument bubbles missing from the drawing.
ANSI N45.2.11, Section 7.1, requires that personnel be made aware of
and use proper and current instructions, procedures, drawings and
design inputs. Design documents and changes to them are to be
controlled to ensure that correct and appropriate documents are
available for use. Contrary to this requirement, drawings affected
by design change packages had not been consistently revised to
accurately reflect the as-installed condition. The drawing
deficiencies identified above will remain an unresolved item pending
followup by NRC Region IV (50-313/86-01-06).
8. The licensee considered the FSAR to be a design document and a
suitable source of design input; however, the FSAR was not maintained
as a design document and was found to contain errors. Energy Supply
Department Procedure 202, " Design Process Procedure," contained a
form to be used to ensure that all appropriate design documents were
revised to reflect design changes. This fom identified the FSAR as
a controlled design input document. The team was informed that the
FSAR was considered to be a design document suitable as a source of
design input for calculations. However, the team determined that the
FSAR was only updated yearly and that engineering ano design
personnel were not in a position to readily know what t' sign changes
were pending incorporation between updates.
The team identified the following errors in the FSAR:
a. FSAR Section 7.2.3 described the integrated control system (ICS)
and stated in subsection 7.2.3.2.4, "...upon loss of all reactor
coolant pumps, and/or both main feedwater pumps, the ICS starts
the emergency feedwater pump and positions control valves to
control flow to the emergency feedwater header." This incorrect
statement should have been revised when the EFIC system was
installed as indicated in Amendment 3 of the FSAR.
b. FSAR Section 9.9 described the compressed air system and states,
" Tables 9-27 and 9-28 list all the air-operated seismic Category
1 valves and ventilation system dampers." However, Table 9-27
did not include the atmospheric dump valves CV-2618 and CV-2668.
These valves were seismic Category 1 and received air from the
instrument air header or instrument air accumulators.
19
c. FSAR Section A.7.2 "MS To Emergency Feedwater Pump Turbine
Driver," described the evaluation perfomed to determine the
effects of a high-energy line break in the steam supply to the
EFW turbine pump. The piping and valve arrangement described
did not acccunt for the modification perfomed for the EFW
system upgrade. Specifically, the arrangement described
indicated that CV-2667 and CV-2617 were normally closed
isolation valves such that high energy (conditions above 275
psig and 200 F) did not exist downstream. When DCP 82-D-1050
was issued, this arrangement was changed so that CV-2667 and
CV-2617 were made normally open causing high-energy line
conditions to exist downstream of these valves,
d. FSAR Table 1-1 described design parameters for various
components at AN0-Unit 1. In describing the EFW pumps, the
design head was listed as 1100 psi and the corresponding design
flow was 760 gpm. However, Technical Specification 4.8.1.a
indicated that the pumps must produce 500 gpm at 1200 psi
discharge head. Design conditions based on Calculation
80-D-10838-102 indicated that the operating point for EFW pump
7A was 720 gpm at 1295 psi discharge pressure and for EFW pump
7B it was 610 gpm at 1250 psi discharge pressure.
Although the team observed that the FSAR was not nomally used as a
source of design input, the team was concerned that it was apparently
procedurally pemitted. The team found one instance where the FSAR
was used as a reference for design input instead of appropriate
design documents like drawings and design calculations. Calculation
MB-1-22, " Emergency Feedwater Pump Switchover To Other Water
Sources," Revision 0, referenced the FSAR Section 10 instead of
appropriate design analyses or vendor drawings as its source to
obtain the condensate storage tank depth when 107,000 gallons are
remaining in the tank.
The use of the FSAR as a design document and a source of design input
was considered a weakness. The errors in the FSAR identified above
were discussed with the licensee. This issue will remain open
pending the correction of these errors in the next routine FSAR
revision (5s-313/86-01-02).
B. Maintenance
1. Several weaknesses were noted with the licensee's program for conducting
maintenance and testing on motor operated valves (MOVs) in the emergency
feedwater(EFW) system. These weaknesses included:
Licensee personnel were generally unaware that MOV torque
switches for ANO-Unit I were only bypassed during initial
valve movement and that improper torque switch settings could
prevent the EFW system from completing its safety function.
This lack of understanding was apparently due to a design
difference in M0Vs between Unit-1 and Unit-2. In AN0-Unit 2,
M0V torque switches are bypassed for full valve travel.
20
_ _ _ _ _ _ _
Torque switch settings were made by licensee personnel without
reference to the minimum recommended values provided by the
vendor. The team reviewed selected MOV torque switch settings
and found them to be set low; in one case, the setting was
below the value used for manufacturer testing.
MOV limit switches appeared to be set to bypass torque switches
for an insufficient amount of initial valve travel. The purpose
of these limit switches was to bypass the torque switch until the
valve was fully off its shut seat, thereby providing some assur-
ance that the torque switch would not prematurely stop valve motion.
EFW system M0Vs located in the pump discharge piping were not
tested under flow conditions to ensure that they would operate
as expected in emergency situations.
Five MOVs were found to be missing valve stem housing end caps
and a significant amount of debris was found in the stem
cavities. This increases the potential for valve binding that
could result in premature torque switch actuation to stop valve
motion.
l
Several discrepancies were identified with the M0V maintenance
procedures that could confuse personnel performing maintenance.
Details regarding these weaknesses are provided below:
a. Interviews with licensee personnel revealed that they were
generally unaware that torque switches were only bypassed
during initial valve movement in an automatic initiation of
the EFW system. This is significant because torque switches
improperly set with low values could actuate prematurely,
causing the MOV to stop in mid-stroke during an automatic
initiation. The AN0-Unit 2 auxiliary feedwater system valves
appear to have their torque switches bypassed through full valve
l stem travel during an automatic initiation to ensure that MOVs
l complete their safety function. However, this was not the case
for the ANO-Unit 1 EFW system. Discussions with training instruc-
tors, operating personnel, electricians, maintenance engineers
and supervisors indicated that this difference was not widely
known. This issue was of particular concern because of the
other weaknesses discussed below regarding the setting, testing,
l and bypassing of MOV torque switches.
i
b. Interviews with licensee personnel revealed that torque
switches initially were set by electricians and field engineers
l during M0V installation and later were adjusted by electricians
I during valve maintenance. These interviews also revealed that
engineering judgement was the basis used to initially set the
torque switches and then actual valve operation under no-flow
conditions typically became the basis to readjust the settings.
Limiter plates were installed to prevent setting torque switches
too high and M0V maintenance procedures specifically cautioned
against setting torque switches above the upper limit. However,
MOV maintenance procedures did not address lower torque switch
21
-___
.
limits and vendor reconmendations for minimum set points were
not referenced when the torque switches were set. The torque
switch settings were recorded on Job Order (J0) data sheets and
reviewed as part of the normal J0 closeout, but lower limits for
torque switches settings were not available for the reviewing
parties to compare to the actual settings.
The team reviewed actual torque switch settings for eight EFW
system MOVs. The significant data from this review is provided
below:
Actual Torque
Valve No. Description Operator Switch Settings
10 en Close
CV-2613 P7A Stm Admission SMB-000 1.5 1.5
CV-2617 OTSG B Stm Supply SMB-000 3.5 3.0
CV-2620 P7A to S/G B Isol. SMB-000 2.0 2.0
CV-2626 P78 to S/G B Isol. SMB-00 1.5 1.5
CV-2627 P7A to S/G A Isol. SMB-000 1.5 2.5
CV-2869 P78 Test Recirc Isol. SMB-00 1.5 1.5
CV-2870 P7A Test Recirc Isol. SMB-00 1.5 1.5
CV-3851 Loop II SW Supply SMB-000 2.0 2.0
(
.,. The torque switch adjustment scale ranged from a minimum of 1.0
to a maximum of 5.0. As illustrated by the data in the above
table, the torque switch settings were typically set at the low
end of the scale for the EFW system valves. This was a particular
, concern for the EFW discharge valves (CV-2620, CV-2626, CV-2627
CV-2670,CV-2869,CV-2870). During the onsite inspection, the
licensee was unable to provide recommended minimum torque switch
settings for these M0Vs.
After completion of the onsite inspection, the licensee provided
the folicwing manufacturer test data for the selected valves:
Manufacturer's Torque
Valve No. Test Press Switch Setting
0
1en Close
' 1100 psig
i CV-2613 1.5 1.5
, , ;; CV-2617 1050 psid 2.0 2.0
- CV-2620 1792 psig 2.0 2.0
f
1 CV-2626 1792 psig 1.25 1.25
CV-2627 1792 psig 2.0 2.0
c' CV-2869 1792 psig 1.5 1.5
It is not clear that all the manufacturer's test data was
' -
obtained under flow conditions because the test pressure was
recorded in psig for several valves and the motor run current
measurements were inconsistent with licensee test data obtained
., when the valves were installed. However, it does appear from
these data that the CV-2627 torque switcq open setting was set
'
<
s,
22
t
- __ . - _ _ _ _ _ _ _ _ _ . ___ _ _ -
.
W
m,
below the manufacturers testing set points. Addit.ionally, no
manufacturer test results were available for CV4870 and CV4351 1
because the operators and valves were connected by the 11ccroce
without vendor recommendations for minimum and maximum torque
switch set points. The apparent failure of the licensee to v
'
translate the vendor-supplied M0V de:ign basis data into
'
applicable controlling documents appeared to be contrary to
10 CFR 50, Appendix B, Criterion III. This 3ssue will remain '
-
an unresolved item pending followup by NRC Region IV
(50-313/86-01-07). .
IE Infonnation Notice 84-10. "Moter-Operated Valve Torque
Switches Set Below The Manufacturic's' Recommended Value," raised -
issues that were similar to the findinos outlined above. The
inspection team reviewed the licensee's internal memorandum ' ^
regarding this notice. It stated J. hat 4his issue was not a ,.
problem at ANO because torque limiter plates were usedt < .,
additionally, any changes to torque switch settings were ,- )
reviewed in the J0 closeout process. This reasoning appears - c;
'
inadequate because the limiter plates d10 not prevent setting L
torque switches too low and the licensee did not maintain a * '
list of reconnended minimum torque switch set point values for
comparison at JO closeout.
- 4
c. Interviews with licensee personnel'and a review of the MOV 'e'
maintenance procedures revealed that limit switches were
set to bypass torque switches for only a minimal amqunt of
initial valve travel. Licensee procedures for opyrator models '
'
SMB-00 and SMB-000 directed thatethedimit switches should he set ,,
1-2 turns off the fully open or closed position. This minimi -
'
N
amount does not appear to be adequate to compensate for the ' '
effects of coast or backlash in the operator. This could result -
,'+
s
in excessive valve backseating or the limit switch acteting 7~ "
before the initial starting torque is fully removed fecm the 4
operator, which could cause the torque switch to premturdly s
stop the valve motion. The licentde stated that this issue
was currently under review as part of their respon59 to IC "
~
-
Bulletin 85-03, " Motor Operated. Valve Common Mode Failures'
During Plant Transients Due To ' Improper Switch Settings," but' )!
no short-term actions had been< initiated to correct this ' '
-
potential deficiency. ~
,
, ~
_
d. Interviews with licensee personnel, reviewr. of, maintenance and - .
'
. .,
periodic testing procedures, and inspection ~of post-modification ~
'1
test packages revealed that not all EFW system MOVs have been . -l
tested to ensure they will operate prope-ly under flow conditkns. i
During the 1984 outage, new steam admissing and pump discharge , Q
MOVs were installed as part of DCP 80-1083. It appeared'that no -
tests were conducted to verify proper M0'i operation during flow
conditions nor were any engineeripg evalu~ations conducted.to - &
l
Verify that torque and lir'it switch settings were adequate-
An exception to this was the EFW turbine steem admission',v41ves
. , I
(CV-2613, CV-2663) which were tested routineiy'under system flow .
l
conditions during both manual and automatic EFW system initiation.
-
'
g ,
l
,
23
,
%
a" . - _ _ . .
_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ ____ _
However, the EFW pump discharge valves (CV-2620, CV-2626, CV-2627,
CV-2670, CV-2869, CV-2870) had apparently never been fully tested
under system flow conditions either by post-modification tests,
pcst-maintenance tests, periodic surveillance checks, or by
actual system initiation. The EFW steam generator isolation
valves (CV-2620, CV-2626, CV-2627, CV-2670) and the full-flow test
isolation valves (CV-2869, CV-2870) are not normally repositioned
for EFW system initiation. These valves are expected to operate
against full-flow conditions only when an EFW initiation occurs
during system flow testing or if a steam generator isolation
signal is received during EFW system operation.
10 CFR 50, Appendix B, Criterion XI, requires that components be
) tested to demonstrate that they will perform satisfactorily in
service. This testing shall include proof tests prior to
installation, pre-operational tests, and operational tests, as
appropriate. The apparent failure to adequately test the EFW
system discharge piping M0Vs under flow conditions either by I
pre-installation, post-modification, periodic surveillance, or
post-maintenance tests was considered to be contrary to 10 CFR
50, Appendix B, Criterion XI. This issue will remain an unresolved
3 item pending followup by NRC Region IV (50-313/86-01-08).
e. During the walkdown of the EFW system, the team identified five
MOVs that were missing stem housing end caps. Three valves
I
(CV-2617, CV-2667, CV-2870) appeared to be missing the screw cap,
and two valves (CV-2800, CV-2802) had their end caps sheared off.
A significant amount of dirt and foreign material was observed
in the stem cavities of these valves. Debris in the stem cavity
could work down into the operator and foul gears or affect bearings,
preventing proper valve operation.
f. The team reviewed three M0V maintenance procedures: Procedure
1402.160, "Limitorque Motor Operated Valve SMB-000 Maintenance,"
Revision 3; Procedure 1402.161, "Limitorque Motor Operated Valve
SM8-00 Maintenance," Revision 1; and Procedure 1402.71, "EIM
Motor Operated Valve Maintenance," Revision 2. The following
inaccuracies were noted with these procedures:
(1) All three procedures referenced drawing E-195 for a des-
cription of the M0V limit switch (LS) operation. This
drawing did not show the Limitorque LS contact scheme and
the EIM LS scheme incorrectly showed contact "LSO/G" as
being closed continuously throughout valve travel.
4
(2) The procedures failed to identify CV-2663, CV-2620,
and CV-2870 as dc-powered MOVs. Further, the procedures
failed to include CV-2663, CV-3850, CV-3851, CV-2627,
CV-2626, CV-2869 and CV-2870 as Q-listed valves. (See
Design Changes, observation 7.c for further discussion
of the licensee's Q-list.)
(3) Procedures 1402.160 and 1402.161 had an incorrect drawing
showing a reversed position of the open and closed
adjustments for torque switches.
h
24
.
.
_ _ _ _ _ _ _ _ _ _ _ .
_ - _ _ _ _ _ _ _ _ __ -
. .
.
..
(4) Procedure 1402.161 incorrectly listed CV-385. and CV-2620
as model SM8-00 operators when they were actually model
SMB-000.
(5) All three procedures incorrectly stated that closed
limit switches should be set to operate off the shut seat
to allow for coastdown. This was incorrect because in the
closing direction the motor is stopped by the torque switch
and the limit switch should be set to provide adequate bypass
of the torque switch when unseating the valve or to indicate
valve position.
(6) Procedure 1402.71 incorrectly stated that CV-3850 can
be modulated when the valve was actually designed with a
seal-in feature to prevent throttling.
(7) Pro;edure 1402.71 had no requirement for independent
verification of removal of a test jumper. The test fumner,
when installed, bypassed the seal-in feature of tb JV and
would interfere with nonnal valve operations.
At the exit meeting the licensee stated that these procedures were
in the process of being corrected. This item will remain open pending
inspector review of the licensee's corrective action (50-313/86-01-03).
Collectively, the weaknesses described in observations 1.a through 1.f
were evidence of an inadequate program for maintenance and testing of
MOVs. Based on the information available to the team during the
inspection, the licensee could not verify by testing or engineering
evaluaticn that the current limit and torque switch set points for
MOVs in the EFW system were adequate to permit proper valve operation
under flow conditions.
2. The team reviewed mechanical and electrical maintenance training and
on-the-job training (0JT) for technicians who worked on EFW/EFIC com-
ponents. The emphasis of this review was on M0V training. Mechanical
maintenance training consisted of generic pump and valve training with
no special emphasis on EFW components. Electrical maintenance training i
was conducted in a laboratory where hands-on motor control center and
M0V work could be accomplished. The electrical maintenance laboratory
had eight MOV actuators installed (Limitorque, Rotork, and Electrodyne), I
six of which were wired and operable. Technicians were able to gain '
hands-on practice in setting limit and torque switches and in making
other actuator adjustments and settings. Maintenance training was i
considered good overall; the presence of operable actuators in the .
electrical maintenance laboratory was considered a strength. I
The licensee was in the process of initiating a new OJT program for
maintenance technicians. At the time of the inspection first-line
supervisors in the electrical maintenance shop were using the records '
from the old 0JT program to record and determine technician qualifica-
tions for assignment to a maintenance task. Both the old and the new
OJT program appeared adequate for this purpose.
25 l
-
- _ - ___ _ -_- __
- . ~ . . _ - . . . .- - _.. - _._ =. .. . -
3. The team noted weaknesses with the maintenance and testing of EFW system
pump P7A conducted at the conclusion of the 1984 cutage. During a 1-month
period the pump was disassembled and reassembled three times as follows:
December 23, 1984 - Pump P7A was reassembled after outage maintenance
and testing (JO 76916).
l January 7-8,1985 - Pump P7A thrust bearing was replaced after overheating
- during surveillance testing (JO 81212).
January 11, 1985 - Pump P7A balance drum shims were replaced at
the direction of the mechanical naintenance
superintendent (JO 75648).
The following deficiencies were noted with the maintenance and testing
of EFW pump P7A during this sequence:
l a. . A new thrust bearing and balance drum shims were installed as
l part of JO 76916; however, the steps of Section 7.2 of Procedure
- 1402.09, " Emergency Feedwater Pump Maintenance," Revision 1,
l which described this process, were marked N/A by the maintenance
I technician. It appeared that the prescribed maintenance proce-
l dure was not followed for this involved maintenance activity.
!
I b. The post-maintenance testing conducted on pump P7A during this
l period appeared incomplete. Procedure 1402.09 provided detailed
guidance for taking post-maintenance vibration readings in the
, horizontal, vertical, and axial directions and required that
L they be compared to a set of pre-maintenance vibration results,
r Despite this detailed guidance, the following post-maintenance
l testing deficiencies were identified:
1
(1) The testing documented for the December 1984 maintenance
(JO 76916) was not conducted until January 17, 1985.
These data were not representative of the pump configura-
tion after JO 76916 since the thrust bearings- and balance
'
drum shims were replaced again before testing was conducted.
(2) The testing documented on JO 81212 was missing some axial
- measurements and there were no pre-maintenance data for
l comparison. A note at the end of the test data sheet
stated that operations personnel had conducted the test
as a surveillance test and axial readings were omitted
because they were not required for the surveillance test.
(3) There were no post-maintenance test data recorded on
JO 75648 for maintenance conducted on January 11, 1985.
Interviews with licensee maintenance persr.nnel revealed that there may be
,
inadequate coordination of post-maintenance and surveillance tests. The
l- surveillance tests were conducted in all cases to determine operability;
but post-maintenance tests apparently were not always performed in accordance
with procedural guidance. The team was concerned that post-maintenance testing <
!
,
l
26 i
i, _, _ _ , - , . . _ . _ . _ , _ _ _ _ _ _ _ _ . _ _ _ . _ _ _ _ _ _ _ _ _ _ . - .
. - - - - . _ . . -- --
l
requirements may not always be satisfied by surveillance tests and that
i both test programs should be accomplished to ensure equipment reliability.
The apparent failure by the licensee to follow procedures for the main-
. tenance and testing of EFW pump P7A will remain an unresolved item pending
followup by NRC Region IV (50-313/86-01-09).
4. The inspection team conducted a detailed walkdown of the EFW system
to verify that the system layout was as depicted in the system arawings
(P& ids), that the system was aligned as required by licensee procedures,
and to evaluate the material condition and cleanliness of the system. The
following references were used:
.,
System Drawings (P& ids):
M-202, " Main Steam," Revision 33
M-206, " Steam Generator Secondary System," Revision 45
7
M-204, " Emergency Feedwater," Revision 2
Procedures: i
1106.06, " Emergency Feedwater Pump Operation," Revision 25
1102.01, " Plant Preheatup and Precritical," Revision 32
-
The team found that the system layout was as depicted in the system ;
- drawings and that the system was aligned as required by the proce-
du res. The team considered plant cleanliness and material condition
to be generally acceptable. However, several weaknesses were noted
during the walkdown: ,
a. Inconsistencies were found between the system drawings
and Procedure 1106.06 concerning the position c.f four
valves:
'
! Position Per Position Per
Valve No. Procedure 1106.06 P& ids M-202, M-206
CV-2613 Shut Open
CV-2663 Shut Open
4
CV-2617 Open Shut
CV-2667 Open Shut
!
The valves were found in their correct positions as specified
in Procedure 1106.06. Additionally, the system drawing (M-202)
i identified one steam trap as "ST-75" instead of "ST-60" as
identified by the component label plate and the valve lineup
,
procedure.
,
j b. The team noted the following as related to material condition
4 and cleanliness:
i (1) A significant amount of dirt and foreign material was i
! noted in the steam cavity of several MOVs as discussed in
maintenance observation 1.e.
,
27
. ._ - _-- _ _ _ _ , - _ _ _ _ _ _ , _ _ _ _ , _ _ _ _ _ . _ . _ _ __ . _ _ -- _ , . - _ . . - - - _
(2) Valves CS-2803 and CS-28048 had missing operator handwheels.
(3) Numerous vent and drain valves had no pipe caps.
(4) Valves MS-6886, MS-6872, and MS-1053 had no label plate
identification.
(5) Valve HV-166 was mislabeled as HV-160.
(6) Valve MS-1053 had a body-to-bonnet steam leak. This
condition was not previously documented by the licensee.
(7) The cleanliness of the penthouse room containing the
EFW system main steam piping was poor in comparison to the
generally good appearance of other spaces containing EFW
system components.
c. Several of the concrete expansion anchor bolts associated with these
seismic pipe supports in the EFW system were noted to be nonperpendicular
to the surface into which they were installed. Additionally, the washer
on an installed concrete expansion anchor on pipe support 3-EFW-116-H20
was noted to be so loose that it would rotate easily by hand. A later
review of this pipe support installation by the licensee revealed that
seven of the concrete expansion anchors had less than the required
imbedment depth. The details of these issues regarding concrete
expansion anchors will be followed up by NRC Region IV and documented
in NRC inspection report 50-313/86-02.
C. Surveillance Testing
1. The licensee was unable to provide the team with calibration data docu-
menting the initial post-installation calibrations and functional checkout
of condensate storage tank (CST) level indication transmitter LIT-4203.
A determination of the set point and set point accuracies for the CST low
level annunciation function of CST level indicator switch LIS 4203 also
was not available. Additionally, surveillance procedures were not
developed to periodically calibrate condensate storage tank (CST) level
instrumentation. This instrumentation is used by the licensee to verify
that greater than 16.3 feet of water is available in the CST as required
by Technical Specification (TS) 3.4.1.3. It also provides indication that
alerts the control room operators to manusily switch-over the EFW water
supply from the CST to the service water system, if necessary. The
CST level instruments were instclled by DCP 80-1083 and DCP 84-1045 as
part of recent EFW upgrade modifications and were considered by the
licensee to be functional following the 1984 refueling outage.
Subsequent to these findings, the licensee conducted calibrations on all
CST 1evel instrurients and initiated Plant Engineering Assistance Request
86-301 to determine set point and set point accuracies for LIS-4203. The
apparent failure to calibrate the CST 1evel indicator after installation
is contrary to 10 CFR 50, Appendix B, Criterion XI, which requires that
testing be performed to demonstrate that components will perform satis-
28
_ _ _ _ _ _ _ _ _ _ _ _ ______ _ _.
factorily in service. This issue was discussed with the licensee and
will remain an unresolved item pending followup by NRC Region IV
(50-313/86-01/10).
2. Several components were identified by the inspection team for which 18-
month test requirements were not incorporated into surveillance test pro-
cedures. However, in all examples (except for the CST level instrumen-
tation discussed in observation 1, above) post-installation functional
testing performed at the completion of the 1984 refueling outage and
before restart constituted sufficient initial surveillance testing. The
licensee had no apparent administrative controls to ensure the incorpora-
tion of these surveillance requirenants. The team considered that the
licensee's failure to maintain administrative tracking of omitted
18-month surveillance requirements constituted a programatic weakness
that could result in the incomplete surveillance testing of EFW components
during the next refueling outage. Specifi weaknesses with EFW component
surveillance procedures were found in the following areas:
a. Surveillance procedures were not developed to functionally verify
that the steam admission valves (CV-2667 and CV-2617) to the turbine-
driven EFW pump actuate to the required position on an emergency
feedwater initiation and control (EFIC) vector logic valve comand.
These vector logic valve comands function to isolate a faulted steam
generator and to align EFW to the good steam generator. Adequate
testing of this function was conducted by Special Work Plan (SWP)
1409.44 during post-modification testing of the EFW system upgrades;
however, the licensee had not written a surveillance procedure to
periodically perform this functional demonstration as part of the
surveillance test program.
b. Surveillance procedures were not developed to functionally demonstrate
the adequacy of steam generator isolation valve responses to an EFIC
main steam line isolation signal. An EFIC generated main steam line
isolation signal results in closure of the main steam line isolation
valves and the main feedwater isolation valves. Testing of these
responses at least once every 18 months is required to demonstrate j
component operability pursuant to TS 3.4.1.5. A review of approved
periodic surveillance procedures revealed that the response of these
valves to an EFIC isolation signal was not tested. Post-installation
functional testing of the EFIC system perfonned in accordance with )
SWP 1409.44 before unit restart following the 1984 refueling outage
provided a sufficient initial demonstration of these functions.
Retesting of these functions was not required until the next refueling
outage.
The weaknesses in the surveillance testing program discussed in this
observation will remain open pending followup by NRC Region IV
(50-313/86-01-04).
I
3. Additional instrumentation testing and calibration weaknesses were noted
in regard to EFW system components. The following items pertain:
a. Instrumentation and Control Periodic Test, 1304.05 " Emergency
Feedwater Pressure and Flow Instrumentation," Revision 3, did not
29
. . , _ _ _
_
verify that control room annunciators PAL-2811 and PAL-2812 (EFW
discharge pressure low) annunciate when EFW discharge pressure
indication switches PIS-2811 and PIS-2812, respectively, are
actuated at the low pressure set point. The test procedure
instructed the technician to remove the pressure indication
switch from service before calibrating the indicator; as a result,
the annunciator was not verified to respond when the switch low-
pressure contacts change state during the calibration,
b. The licensee had not developed a procedure to routinely functionally
test HS-2646, the Appendix 'R' disconnect switch. HS-2646 is located
in the lower south electrical penetration room and provides a method
for operators to remove de power from CV-2646 and CV-2648. This
ensures that a method is available to remove power from CV-2646 and
CV-2648, when required for an alternate shutdown, thereby failing
these valves to the open position to ensure an EFW flowpath to the
c. The monthly and the 18-month calibration surveillances.of EFIC use
an internal, hardwired self-test to demonstrate proper operation of
the following control module functions:
Steam generator pressure of 1020 psig
- 31-inch low range level with reactor coolant pumps (RCPs)
running (forced flow)
- 312-inch full range level with no RCPs running (natural
circulation)
' 378-inch full range level for reflux boiling
- variable steam generator fill rate based on steam
generator pressure
The team considered that this self-test constituted an appropriate
monthly functional verification of control module operability.
However, there was no provision for periodic validation of self-
test adequacy. Although the self-test was hardwired into the
individual control module, the circuit was composed of components
that may be subject to instrument drift or incorrect setting.
Because this internal test circuitry represents measuring and test
equipment, the ifcensee must provide a means to periodically validate
the test results.
Additionally, the team did not consider the self-test to be an
adequate 18-month channel calibration of the EFIC control module.
In response to this concern, the licensee committed to develop a
more conventional 18-month calibration procedure that will input
test signals to the EFIC control module and verify appropriate
control module responses. Furthennore, after this calibration method
has been completed, the self-test will be performed to validate its
acceptability for continued use as a monthly functional verification
of control module operability.
The weaknesses discussed in observations 3.a 3.b and 3.c will remain
an open item pending followup by NRC Region IV (50-313/86-01-05).
30
4. Weaknesses were identified in the in-service testing program for mechanical
equipment associated with the EFW system. Specifically, certain check
valves listed in Attachment 2 to Procedure 1022.06, "ASME Code Section XI
Inservice Testing Program," Revision 4, as requiring in-service testing
were not identified in the supplements to Procedure 1106.06, " Emergency
Feedwater Pump Operation," Revision 24. Therefore, these check valves
were not documented as having been routinely tested. The following
deficiencies were noted:
a. Valves CS-98, CS-99, CS-261, and CS-262 are check valves in the EFW
pump suction line from the condensate storage tank (CST). These
valves exist two each in parallel lines coming from the CST.
Adequate flow has been demonstrated through these valves in routine
pump flow tests. However, since these two lines are in parallel,
the operability and full stroke response of each individual valve
has apparently not been demonstrated.
b. Valves FW-55A, FW-558, FW-56A, and FW-56B are check valves in the
EFW pump discharge headers. Adequate flow has been demonstrated
through these valves during routine pump flow tests. However, routine
testing of these valves was not documented.
c. Valves FW-10A, FW-108, FW-61, and FW-62 are in the EFW pump minimum
recirculation flow paths. FW-10A and FW-10B are three-way recircu-
lation control check valves that function to provide a recirculation
flow path when steam generator pressure exceeds pump discharge
pressure. Valves FW-61 and FW-62 are check valves installed down-
stream of FW-10A and FW-108. Flow and stroke for these valve
combinations is not routinely demonstrated.
The licensee agreed that Procedure 1106.06 will be revised to identify
specific testing and documentation for these valves. The failure to
provide adequate testing for these valves will remain unresolved pending
followup by NRC Region IV (50-313/86-01-11).
D. OPERATIONS
1. The procedures and drawings related to the normal and abnormal operation
of the EFW system were reviewed. The following weaknesses were noted:
a. Procedure 1106.06, " Emergency Feedwater Pump Operation," Revision
24, contained inaccurate guidance regarding the operation of
motor-operated valves for steam admission to the P7A pump turbine.
Specifically, step 9.3.2 stated that operation of those valves was
". . . the same as the EFW isolation valves." When operating in the
manual mode, momentary actuation of the switch in the control room
will cause the EFW isolation valves to travel momentarily, but
momentary actuation of steam admission valve control switch will
cause that valve to operate to full travel as a result of a seal-in
feature designed into the motor control circuitry.
I b. During a review and walkdown of Procedure 1203.02, " Alternate Shutdown,"
Revision 12, nothing was identified that would clearly prevent
achieving reactor shutdown, but it was noted that substantial
31
,
-
.__ _ _ _ _ _ - _ . . _ .
difficulty would probably be encountered by the operator attempting
to control the atmospheric dumps valves (ADVs) for decay heat removal.
In some cases comunications facilities were located significant
distances away from the alternate shutdown components, such as the
EFW flow control valves and the ADV station. Additionally, the
battery-powered lighting system at the ADV station failed to operate
when the test button was pushed. The licensee had corrective action
in progress, initiated before and during the inspection, to correct
these communications and lighting deficiencies.
2. Procedure 1000.27, " Hold and Caution Card Control," Revision 5, and
associated equipment control logs were reviewed. One deficiency was
identified: there was no record of an independent verification of
equipment status for the initial hanging of tag 11 (breaker 5116) for
tagout 86-1-043 (emergency diesel generator). This was found to be an
isolated instance and the licensee took prompt corrective action to verify
the status of the equipment.
3. During daily tours of the control room, operations crew personnel were
observed to be maintaining plant parameters within specified limits
according to approved procedures. The overall level of professionalism
displayed by the operators was satisfactory, with the exception of relaxed
control of nonessential personnel in the control room. On several occasions,
non-operations personnel were observed to either remain in the control room
after completing official work-related business or were allowed to enter
the control room with no apparent work-related reason for being there.
This condition was observed with the plant both operating and shutdown.
Although no cases were observed of on-watch operators being distracted
from their duties, the potential for such distraction was clearly present.
4. Operator training for the EFW system and the EFIC subsystem was combined
into one module which comprised the lesson plan (AA-21002-040, Rev. 2), a
handout, viewgraphs, a slide presentation and a short video tape explaining
operation of the turbine-driven EFW pump. This material was reviewed
for adequacy and technical accuracy. Minor weaknesses were noted:
a. Page 22 of the handout showed a tabular summary of the EFIC vector
valve commands which was incorrect. However, an identical table on
page 82 was correct,
b. Figure 66.1 of the handout contained several errors. Valves CV-2646
and CV-2645 were not labeled, CV-2648 was mislabeled as CV-2621, and
CV-2647 was mislabeled as CV-2672.
5. The team examined the effectiveness of operator training for alternate
shutdown. This training had most recently been conducted as part of
operator requalification and initial qualification training in October
1985. The training consisted of 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> of classroom instruction, a
walk-through of operator actions at each station, and a simulated shutdown
with shift operators working at the appropriate stations. Overall, the
training for this activity appeared satisfactory. Interviews with operators
revealed operational difficulties at some stations (see paragraph 1.b of
this section).
32
6. The team examined shift technical advisor (STA) training. The present
STA training program appeared to meet only the minimum requirements.
One member of the plant engineering staff was assigned to be STA for both
units on a rotating basis. This individual would usually conduct his
normal job assignments and respond to control room activities on an
en-call basis.
AN0 plans to implement a new STA policy and procedure in mid-1986. The
new program will consist of trained, dedicated STAS on shift rotation
assigned specifically to Unit 1 or Unit 2. The licensee intends for the
STA to have a senior reactor operator license on either Unit 1 or 2. At
the time of this inspection, there were 12 engineers in training for these
STA positions. A review of the new STA program and training material
revealed that it met the NRC requirements for such training. This new
STA program is expected to be a significant improvement over the existing
program.
E. Quality Assurance
The QA audit program was considered weak in determining the effectiveness
of the ANO-Unit 1 QA program. Similar weaknesses to those found in this
inspection report were not identified during a review of the more recent
licensee audits conducted in the areas of training, operations, surveillance
test, design control, corrective action, quality control, and engineering
services. Also included in this review were two overview audits of the ANO-1
plant staff and the AN0-1 QA program conducted by Middle South Services.
The following observations were made relative to the QA audit program:
1. Current guidance in the QA audit / activity plan limits the scope of all
audits to a review of audit areas for regu'atory compliance and program
implementation. This guidance appeared to be interpreted by QA through
the conduct of the audits to mean program and procedural compliance without
emphasis on assessing the quality of the end product.
2. The last two design control audits and an audit of the licensee's ccrporate
engineering staff in Little Rock provided no technical assessments to
evaluate the effectiveness of the licensee's design control program. No
significant findings were identified by these audits.
3. The training audits consisted of programmatic reviews with specific
observations, such as the following, highlighted in the audit reports:
a. Lesson plans were found to be consistent in format.
b. Lesson plans are being maintained in locked storage.
c. The HP Supervisor reviews general employee radiation protection
training quarterly.
No assessments, such as determining the adequacy of the training plans,
the effectiveness of any training acccmplished, or the capability of the
instructors presenting the training, were made.
33
4. The quality control document management system audit did not provide
technical assessments of the QC group's performance.
5. The corrective action audits appeared to have been a superficial review
of the adequacy of the actions taken by the plant in response to identified
deficiencies. It was not apparent that any assessment of the root causes
for the significant deficiencies adverse to quality were perfonned. The
auditors appeared to have focused on the timeliness of the corrective
action taken and the ability of the plant to close a backlog of noncon-
formance reports.
6. Recent staff increases through contractor hirings and permanent staff
additions have provided the QA group with important technical and
operational expertise that could serve as a foundation for future
performance-oriented assessments.
7. The QA staff lackd technical design expertise.
8. The QA manager and QA supervisor exhibited an understanding of the
need for performance-oriented as'iessments and stated that consideration
is being given to conducting more performance-oriented assessments.
In sumary, the ANO-Unit 1 QA audit program had not provided technical and
operational reviews of site quality activities; thus it had not provided plant
and corporate management with important feedback on the quality of the
activities performed that affect the safe operation of the plant.
IV. MANAGEMENT EXIT MEETING
An exit meeting was conducted on January 31, 1986, at Arkansas Nuclear One.
The licensee's representatives are identified in the Appendix. In addition,
Mr. James G. Partlow, Director, Division of Inspection Programs, IE, and Mr.
James E. Gagliardo, Branch Chief, NRC Region IV, attended the exit meeting.
The scope of the inspection was discussed, and the licensee was informed that
the inspection would continue with further in-office data review e.od analysis
by team members. The licensee was informed that some of the observations could
become potential enforcement findings. The team members presented their
observations for each area inspected and responded to questions from licensee's
representatives.
34
_ - - - _ - - - - - _
,
APPENDIX
Persons Contacted
The following is a list of persons contacted during this inspection. There
were other technical and administrative personnel who also were contacted.
- J. D. Vandergift. Training Manager
- R. Tucker, Electrical Maintenance
- H. Carpenter, Instrumentation and Control Maintenance
- D. Jones, Instrumentation and Control Maintenance
- W. H. Jones, Modification Manager
- J. T. Enos, Manager Nuclear Engineering and Licensing
- D. G. Horton, QA Manager
- G. D. Provencher, QC Supervisor
- A. J. Wrape, Electrical Engineering Supervisor
- D. Howard, Special Projects Manager
- J. Levine, Site Director
- T. Cogburn, General Manager Nuclear Services
- D. B. Lomax, Plant Licensing Supervisor
- C. N. Shively, Plant Engineering Superintendent
- P. Campbell, Plant Licensing Engineer
- B. A. Baker, Operations Manager {
- M. Drost, QC Engineering Supervisor
- J. McWilliams, Operations Superintendent
- V. Pettus, Mechanical Maintenance Superintendent {
- E. L. - Sanders, Maintenance Manager
- R. P. Wewers, Work Control Center Manager
- D. R. Sikes, Engineering Services General Manager
- J. G. Dobbs, Engineering Services Electrical Engineer
- W. Cottingham, I&C Engineer
- V. Bardwaj, Electrical Engineer
- R. W. Howerton, Civil Engineering Manager
- W. Greeson, Civil Engineering Supervisor i
- D. Williams, Mechanical Engineering Supervisor l
- R. Lane, Mechanical Engineering Manager
- W. M. Cawthon, Electrical Engineering
C. Cole, Surveillance Testing Coordinator
W. Garrison, Operations Technical Staff
S. Burris, Staff Administrative Assistant
S. Capehart, Shift Operator
J. Clement, Shift Operations Supervisor
S. Fullen, Shift Operator
M. Goad, Training Department instructor
C. Zimmerman, Operations Technical Support
- Attended exit meeting on January 31, 1986.
1
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.
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-
__. _ _ _ _ _ _ _ _ _ _ _ _ . _ _
I
Arkansas Power & Light Company -3-
l
Distribution (w/ report):
.
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ILS
ORPB reading
DI reading
i W. . J. Dircks, EDO
H. R. Denton, NRR
C. J. Heltemes, AEOD
J. M. Taylor, IE
R. H. Vollmer, IE
J. G. Partlow, IE
R. L. Spessard, IE
B. K. Grimes, IE
J. A. Axelrad,.IE
All NRC Regional Administratoi's
'
J. E. Gagliardo, RV
D. M. Hunnicutt, RIV
W. D. Johnson, RIV
G. S. Vissing, NRR '
H. R. Booher, NRR
E. H. Johnson, RIV //5
All licensees (Distribution CF)
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