ML20206M798
| ML20206M798 | |
| Person / Time | |
|---|---|
| Site: | Rancho Seco |
| Issue date: | 04/07/1987 |
| From: | Callan L, Dyer J, Howell A, Isom J, Martin T, Pierson R, Sharkey J, James Smith, Danielle Sullivan NRC OFFICE OF INSPECTION & ENFORCEMENT (IE) |
| To: | |
| Shared Package | |
| ML20206M774 | List: |
| References | |
| 50-312-86-41, IEB-79-27, IEB-80-04, IEB-80-4, IEB-85-003, IEB-85-3, NUDOCS 8704200196 | |
| Download: ML20206M798 (65) | |
See also: IR 05000312/1986041
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OFFICE OF INSPECTION AND ENFORCEMENT
DIVISION OF INSPECTION PROGRAMS
Report No.: 50-312/86-41
Licensee: Sacramerito Municipal Utility District
P. O. Box 15830
Sacramento, California 95812
Ducket No.: 50-312
Facility Name: Rancho Seco
Inspection Conducted: December 1, 1986 - February 12, 1987
Inspectors: blY
- J. E. Dybr, Inspection Specialist, IE
4bf67
Jate
Team Leader
TDXl &
T.~0. M in, Inspec ~ ore Specialist, IE
9kh7
Date
/ M V 8[
"A. T. fjdwelT, Inspection Specialist, IE Date
W wn
' *J' A. Isp, Inspection Specialist,
-
Ybby
Date
0 2+' b!! Yl4lB7
R. C. Fier n, I spection Specialist, IE Date
/ .
A N. Eharkey, IMpection Specialist, IE
hlM
i Ddte
bD. Str ' tli, spection Specialist, IE
'lbb7
'Date
J.
c. [1 4' d 7
- D. J. Spilivan, Jr., Ins ~pt c'thon Specialist, IE
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[fo te' i
Accompanying Personnel: *L. Miller, RV; *W. Ang, RV; *A. Johnson, RV;
- B. Faulkenberry, RV; *S. Miner, NRR; *G. Overbeck,
WESTEC; *G. Morris, WESTEC; *D. Prevatte, WESTEC;
- P. flilliken, WESTEC; *E. Dunlap, WESTEC; *S. Kobylarz,
WESTEC; *R. Pettis, IE; *T. Lee, NRR.
Approved-by: V7 2
- L. J. Call { Chief, Performance Appraisal Section IE IDote
- Attended Exit Meeting on February 12, 1987.
8704200196 870410
PDR ADOCK 05000312
O PDR
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Scope:
A special, announced inspection was performed of the activities and programs
established by the licensee to support plant restart and to ensure the safe
operation of the plant after restart. The problem identification and resoletion
phases of the Systems Review and Test Program were reviewed for eight selected
systems.
Results:
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Seventeen unresolved items and 27 open items were identified in this report
and will be followed up by the NRC.
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. TABLE OF CONTENTS
Augmented Systems Review and Test Program Inspection
at Rancho Seco
(Inspection 50-312/86-41)
Page
1.0 INSPECTION 0BJECTIVES.............................................. 1-1
2.0 SUMMARY OF SIGNIFICANT FINDINGS ................................... 2-1
3.0 DETAILED INSPECTION FINDINGS ...................................... 3-1 r
3.1 System Review and Test Program ............................... 3-1
3.2 Selected Review of System Design Features .................... 3-10
3.3 Engineering Programs ......................................... 3-15
3.4 Surveillance and Inservice Testing ........................... 3-21
3.5 Operations and Training ...................................... 3-26
3.6 Maintenance .................................................. 3-30
3.7 Quality Programs ............................................. 3-33
3.8 Restart Organization and Management .......................... 3-36
4.0 UNRESOLVED ITEMS .................................................. 4-1
5.0 MANAGEMENT EXIT MEETING ........................................... 5-1
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1. INSPECTION OBJECTIVES
The objectives of the Augmented Systems Review and Test Program team inspection
at Rancho Seco Nuclear Generating Station were to (1) assess the adequacy of
the licensee's activities in support of plant restart and (2) evaluate the
effectiveness of the licensee's established programs for ensuring safety during
plant operations after restart.
To accomplish the first objective, the team reviewed the Rancho Seco Systems
Review and Test Program (SRTP) which was developed to upgrade 32 important
plant systems by identifying problems, correcting the identified deficiencies
and testing the systems to verify proper operation. The team reviewed the
problem identification and resolution phases of the SRTP as documented in
revision 1 of the selected system status reports, but the testing program
could not be reviewed as it was not adequately developed at the time of this
inspection. The following 8 systems were selected from the 32 SRTP systems
for detailed review by the inspection team:
(2) Main Feedwater
(3) Instrument Air
(4) Emergency Feedwater Initiation and Control (EFIC)
(5) 4160 Volt AC
(6) 480 Volt AC
(7) 120 Volt AC
(8) 125 Volt DC
To accomplish the second objective, the team reviewed the programs as implemented
for the eight selected systems for the following functional areas:
(1) Systems Design Change Control
(2) Maintenance
(3) Operations and Training
(4) Surveillance and Inservice Testing
(5) Quality Assurance
(6) Engineering Programs
(7) Restart Management
The specific findings in each area are presented as observations that the
inspectors believe to be of sufficient importance to be considered in a
subsequent evaluation of the licensee's performance. Some observations may
be potential enforcement findings. These observations, referred to as
unresolved items, will be followed up in future NRC inspections.
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2. SUMMARY OF SIGNIFICANT FINDINGS
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, The more significant findings pertaining to the adequacy of the System Review
and Test Program (SRTP) and the effectiveness of programs to ensure continued
safe operations after restart are summarized below. Although some strengths
were identified in each of the areas inspected, the following sumary focuses
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on the significant weaknesses identified during the inspection. Section 3
provides detailed findings, both strengths and weaknesses, in each of the areas
inspected. The ' observation numbers in brackets after the individual summary
items are provided for reference to the corresponding discussion in Section 3.
I 2.1 System Review and Test Program Concerns
, 2.1.1 Although the SRTP problem identification process appeared generally
effective, the inspection team identified instances where the licensee's
- investigation into the identified problems lacked sufficient engineering
- and operational depth. The following are examples of technical concerns
with the AFW system identified by the team that had remained undetected through
the licensee's problem review process.
1 (1) Past testing of the AFW pumps has not demonstrated them to be capable of
providing the flow required by Technical Specifications. [3.4.2(1)]
(2) The condensate storage tank (CST) pressure relief valves appeared to have
been set above the design pressure of the tank and were not receiving the
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required inservice testing and the CST vacuum breakers appeared to be
incorrectly sized. [3.2.1(2)and3.4.2(4)]
(3) The turbine overspeed trip setting for the dual drive AFW pump appeared
to be set above the maximum speed rating for the electric motor connected
to the common shaft. [3.1.1(1)]
(4) The SRTP evaluation of pump damage due to the runout condition experienced
during the December 26, 1985 event did not consider potential pump
degradation. Additionally, the proposed AFW system design for restart,
with the Emergency Feedwater Initiation and Control (EFIC) System
modifications, was still susceptible to pump runout under certain
l situations. At the exit meeting, the licensee committed to install
flow limiting devices in the AFW system to prevent pump runout. [3.1.1(5)]
2.1.2 At the time of the inspection, the SRTP priority system and restart
plan did not identify all problems that were to be corrected before restart.
. The team identified several problems that affected safe plant operation and
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were not currently scheduled for completion before restart. At the exit
meeting, the licensee committed to correct the identified problems affecting
safety and provide the NRC with a list of all problems that would be corrected
before restart. [3.1]
! 2.1.3 Selected System Status Reports (SSRs) did not appear to be properly
1 controlled considering their importance as basis for the NRC development of
the restart Safety Evaluation Report (SER). [3.8.1(3)]
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j 2.2 System Design Change and Engineering Concerns ,
! 2.2.1 The following deficiencies were identified with modifications being
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accomplished during this outage and not reviewed by the SRTP:
(1) After installation of the larger BA and BB batteries, certain circuit
breakers on 125 Vdc buses SOA and SOB will apparently be too small for
interrupting short circuit current. [3.2.2(1)]
(2) Inadequate implen,entation of design requirements resulted in the Interim
Data Acquisition and Display System (IDADS) computer inputs being incorrect
for the 125 Vdc bus failure and the AFW pump runout alarms. [3.2.2(6)]
(3) Modifications to the instrument air system appeared to provide incomplete
analyses for environmental qualification, specify incorrect components to
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accomplish the intended design function, and incorrectly display installation
of components on the fabrication drawings. [3.1.2]
2.2.2 Examples of deficiencies were noted in the design calculations reviewed
j by the team including the use of incorrect methods, assumptions, design inputs
and acceptance criteria. Additionally, in some instances calculations did
- not exist to support the design analyses. [3.3.4]
2.2.3
Significant
used for plant deficiencies
operations were
and design noted in the
engineering control [3.3.3
projects. of sy] stem drawings
} 2.3 Programmatic Concerns
- 2.3.1 The surveillance and inservice testing program was found to have
deficient procedures, improper procedure implementation, and inadequate
- evaluation of test results. [3.4]
2.3.2 Deficiencies were identified with the implementation of administrative
procedures for the control of plant systems and equipment status tracking.
[3.5.1]
2.3.3 The Rancho Seco quality assurance (QA) program had previously been
identified as a major problem area. Improvements had been initiated in the
QA program, but the team identified significant deficiencies in this area
because the improvements were not implemented at the time of the inspection.
These improvements were delayed as a result of QA involvement with the SRTP
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process and, consequently, the QA program was not ready to support an operating
plant. [3.7]
- 2.3.4 Licensee corrective action programs had not been managed effectively
in the past and at the time of this ins)ection adequate management attention was
still not being applied to this area. 3.7.3]
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3. DETAILED INSPECTION FINDINGS
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3.1 System Review and Test Program
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The activities in support of the System Review and Test Program (SRTP) were
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reviewed for each of the eight chosen systems to assess (1) the adequacy of the
- activities proposed to resolve. identified problems, (2) the appropriateness of
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the scheduled resolution of identified problems with respect to restart, and
! (3) the thoroughness of system testing recommendations. Identified problems,
- proposed resolutions and assigned scheduling priorities were documented in
l systems status reports (SSRs). In general, the SSRs were found to be gooo
assessments of known system weaknessess. Although the team found some apparent
weaknesses, the types of problems identified by the licensee are indicative of
a quality program that has improved the safety at Rancho Seco. The following
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subsections further describe the depth of review provided by the SRTP and
weaknesses observed by the inspection team.
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3.1.1 Auxiliary Feedwater System
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2 The auxiliary feedwater (AFW) system status report identified 55 problems, of
l which 36 required resolution before restart. The team had the following
concerns:
(1) Problem 31 identified that the turbine driven AFW pump P-318 was not
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adequately
Pump P-318tested
is a dual anddrive the turbine (electricoverspeed setpoint
motor / steam may)be
turbine pump incorrect.with both
drivers on the same shaft. The licensee identified that the high overspeed
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setpoint of the turbine may overpressurize the AFW system. The engineering
analyses to resolve this issue were in progress and not reviewed by the
team. Additionally, there were no periodic testing requirements and
previous overspeed tests conducted after maintenance activities did
i not measure system pressure because the turbine was uncoupled from the
, pump shaft during the test The team identified the additional concern
1 that the turbine overspeed setpoint may be too high to protect the electric
! motor on the common shaft. The overspeed trip point for the turbine driver
may be as high as 4650 rpm. The motor was designed to National Electric
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Manufceturers Association (NEMA) MG-1 standards that specify that it be
capable of withstanding overspeeds of 20% over synchronous speeds (NEMA
MG-1, Part 20.44). Synchronous speed is 3600 rpm, yielding a rated
, event could damage the motor, potentially rendering the pump inoperable.
l The licensee committed tu confirm with the manufacturer that the motor
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can withstand the turbine overspeed conditions or reduce the turbine
overspeed setpoint.
Problem 31 also discussed testing the turbine to determine the time duration
, required between stopping and restarting the turbine without causing an
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overspeed trip. Stopping the turbine is accomplished by shutting the steam
1 admission valve (FV-30801), which trips a solenoid valve to depressurize
the. governor control oil, thereby shutting the throttle valve. If the
steam admission valve is reopened before the control oil pressure bleeds
down and the throttle valve shuts, the turbine could overspeed and trip.
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The testing recommended in Section 4 of the SSR was to be performed with
the turbine uncoupled and did not require measuring the time required for
control oil to depressurize and shut the throttle valve. Consequently,
it did not appear that the issues concerning motor overspeed, system
overpressurization, or minimum required shutdown time before restarting
the turbine would be answered by the proposed tests. The resolution of
issues concerning the AFW pump turbine overspeed trip setpoint and testing
will remain'open pending followup by the NRC (50-312/86-41-01).
(2) Problems 27 and 48 identified that emergency operating and casualty
procedures should be revised to stop the AFW pump if flow could not be
controlleo by other means. The team was concerned that the proposed
procedure revisions outlined in the SSR documents did not include a caution
that restarting the turbine too soon after stopping it may cause a turbine
overspeed trip. The licensee stated that they intended to include the
caution in the revised emergency operating and casualty procedures after
obtaining test information to resolve problem 31. This item will be
followed up by the NRC headquarters or Region V offices as part of item
50-312/86-41-01 concerning AFW turbine overspeed testing.
(3) Problem 54 stated that the AFW flow rate to a once-through steam generator
(OTSG) may exceed the maximum allowable flow of 1800 gpm. This was a limit
imposed by Babcock and Wilcox (B&W) to prevent tube damage or failure of
steam generator tubes due to flow induced vibration. This problem was not
- scheduled for resolution before restart, even though a B&W analysis
identified that a flow of 2130 gpm to an OTSG at 600 psig was possible.
The team's review of the B&W analysis indicated that it may not be
sufficiently conservative considering the Ranch Seco specific design and
other scenarios could produce higher flows even with the new emergency
feedwater initiation and control (EFIC) system. The EFIC system at Rancho
Seco is similar to the EFIC system installed at Crystal River which controls
AFW flow based on OTSG level and not flow rate. An event recently occurred
at Crystal River Unit 3, where flow to a single OTSG exceeded 1800 gpm.
The team was concerned that a similar event could occur at Rancho Seco.
During the exit meeting on February 12, 1987, the licensee comitted to
perform analyses that are expected to allow reduction in the required AFW
flow such that flow limiting devices can be installed. This item will
remain open pending hRC followup inspection.(50-312/86-41-02).
(4) Problem 3 indicated that the existing flow instrumentation on the full-flow
test line did not provide accurate measurement because downstream piping
was subjected to main condenser vacuum. This problem was not scheduled
for resolution before restart. Because reliance could not be placed on
the full-flow test line flow indication, the licensee opted instead to
measure condensate storage tank level change with time to perform AFW pump
performance testing. For reasons stated in Section 3.4.2(1) of this report,
this alternate method could conceal that the AFW pumps may not be providing
the flow required by Technical Specifications. During the exit meeting
on February 12, 1987, the licensee committed to installing appropriate
modifications prior to restart to improve the accuracy of the full-flow
test line indication such that AFW pump flow can be measured directly.
This item will remain open pending followup by the NRC (50-312/86-41-03).
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- (5) Problem 43 was concerned with potential . damage to the AFW pumps due to
i runout that occurred during the plant transient on December 26, 1985.
The resolution statement indicated.that the pump vendor would be contacted
to provide a determination of whether any degradation occurred to the
internals of the AFW pumps during the 17 minutes the pumps operated in a
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runout condition. However, the licensee informed the team that instead
of contacting the venoor, they planned to resolve this problem based on
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a study performed in February 1984 in response to IE Bulletin 80-04,
" Mein Steam Line Break with Continuous Feedwater Addition," which indicated
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that the pumps could survive beyond 30 minutes operating at maximum pump
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runout flow conditions. This study did not address the extent of damage
or long term pump degradation that could occur when operating at pump
runout conditions. During the inspection, the licensee committed to
resolve this issue with the pump vendor. Additionally, the team was
- concerned that pump runout could still occur with the AFW system design
i proposed for plant restart. As discussed in Section 3.1.1(3) of this report, i
l the licensee committed to perform analyses that are expected to allow
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reduction of the required minimum AFW flow such that flow-limiting devices
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Can be installed. The determination of the effects of having operated an
AFW pump at runout will remain open pending NRC followup of the licensee's
i corrective actions (50-312/86-41-04).
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l (6) Problem 55 indicated that AFW pump performance calculations were required
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to establish the minimum required AFW pump head to provide 760 gpm to
1 a steam generator at 1050 psig pressure. Calculation Z-FWS-M2081, "AFW
System Minimum Head Requirements," Rev. O, dated January 12, 1987, was
performed to resolve this problem statement. It concluded that the minimum
. required head as measured at the pump discharge was 1087.3 psig with a net
flow to the steam generator of 760 gpm. The calculation further stated
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that if the condensate storage tank is at a level greater than the minimum
Technical Specification limit corresponding to 250,000 gallons the required
head should be decreased by a pressure representing this difference in
level. However, this conclusion was incorrect because the required head
, should instead be increased by this amount. This error could have caused
i a non-conservative error of as much as 17 psig in the acceptance criteria
l for the performance testing. Additionally, the calculation contained an
j incorrect conversion factor to convert from psi to feet of water. In
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attempting to change the conversion factor for water at 70*F to water at
J 90*F, an incorrect relationship was used causing the weight densities to
i be reversed. This error resulted in a 6.6 psig error in the non-conser-
- vative direction. Instead of requiring that the pump develop 1093.9 psig,
j the calculation only requires 1087.3 psig. The licensee acknowledged these
l errors during the inspection and agreed to correct the calculation. This
! item will remain open pending NRC followup inspection to confirm that the
errors have been corrected and that appropriate acceptance criteria are
reflected in surveillance testing procedures for the AFW pumps ,
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(50-312/86-41-05).
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3.1.2 Instrument Air System
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. The instrument air system status report identified 31 problems, of which 12
l were to be corrected prior to restart. Six of these related to providing
i reliable backup air for various valve control functions for the main feedwater
i (MFW) and AFW system EFIC modifications. The team considered the prioritization
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f given these problems to be acceptable, but had technical concerns in the .
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i following five areas associated with the addition of backup air supplies:
l (1) The overpressure protection for the main and startup feedwater control
i valve actuators appeared inadequate. Pressure in the supply air bottles
i could be as high as 2400 psig, while the valve actuators were rated for
j 150 psig maximum air pressure. A pressure control valve maintained the
i pressure at the valve actuator at less than 150 psig. Pressure relief,
in the event of pressure control valve failure, was achieved by a relief
! valve built into the pressure control valve and a rupture disk in the air
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line to the actuator. .However, the relief valve was set for 200 psig
4 dnd the rupture disk Was designed to relieve at 225 psig. Application of
' air pressures as high as 200 psig to these actuators could cause failure
i of the actuators or failure of the valves themselves. This could cause
loss of the isolation function required in these MFW lines to mitigate
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steam generator overfill. The licensee committed to reducing the setpoint
i of the overpressure protection devices to 150 psig.
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(2) The safety-related pressure control valves, excess flow valves, and
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adjustable check valves for the backup air supplies for the EFIC modifica-
tions were not seismically qualified. At the conclusion of the inspection,
analyses were in progress by the licensee to qualify this equipment.
- (3) The check valve design chosen for the backup air system appeared to be-
the incorrect design. The EFIC backup air modifications contained excess
i flow valves that were intended to act as check valves to isolate the
i backup air supply frop the normal air supply. However, as originally
specified, these valves could pass up to 5 standard cubic feet per minute
(SCFM) in the reverse direction without the valve closing. Such a condition
could occur if the pressure control valves for the backup air bottles did
not provide tight shutoff under normal conditions or if a low level pressure ,
- cecay situation existed in the normal instrument air supply. In wither
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case the backup air bottles could be bled down unnecessarily, potentially
j compromising the availability of this supply. The backup air system was
i designed to provide at least a 2-hour supply of air. Calculations performed
i to determine the bottle pressures corresponding to the 2-hour and 3-hour
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alarm points considered normal' air usages and some unknown leakages, but
failed to consider the potential backflow through the excess flow v61ves,
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Consequently, leakage through these check valves could~ prevent the backup
dir supplies from fulfilling their design function.
The inspection team's position was that check valves allowing no backflow
! would be the appropriate choice in this application. The licensee main-
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tained that the system could be made to work as is, and the following
!, commitments were made to resolve the team's concerns:
j (a) The actuation setpoint for the excess flow valves will be reduced
i from 5 SCFM to the minimum practicable setpoint which will still
allow sufficient flow in the normal direction from either the
l normal air or backup air system to actuate the valves being
J supplied at their required speeds. This will be determined by
preoperational testing.
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(b) The final setpoint flows will be factored back into new 2-hour and
3-hour required supply pressure calculations.
(c) Operating procedures will be established to monitor backup bottle
pressure on a daily basis and to take remedial action if excessive
leakage is indicated.
(d) Periodic testing procedures will be established to determine if
excess flow valves are within the limits established by (a) and (b)
above.
The team determined that the licensee's commitments described above could
provide the necessary assurance of the reliability of the backup air system.
(4) The pressure control valves for the EFIC backup air system appeared to be
an inappropriate design for their specified application. Pressure control
valves were installed to regulate backup air to the valve actuators if the
nonnal air supply pressure dropped below 90 psig. Above this pressure the
valves should provide tight shutoff to prevent loss of air from the bottles.
The currently specified pressure control valves were not designed for tight
shutoff under zero demand conditions. Should these valves leak through,
either the excess flow valves addressed in Section 3.1.2(3) above will not
actuate, in which cose the air will flow into the normal air system, or the
leakage will be sufficient to close the excess flow valve and the pressure
to the volve actuators will build to the point that the relief valve or
rupture disk will actuate, dumping the backup air to atmosphere. It was
the team's position that the specified pressure control valves were
inappropriate for this application because they unnecessarily diminish
system reliability. The licensee maintained that these valves were
appropriate and the system reliability would be acceptable. Additionally,
the licensee maintained thet commitments documented in Section 3.1.2.(3)
would compensate for these valves.
(5) The fabrication drawings for the EFIC backup air supply for the pressure
control valves and the excess flow valves were found to show the velves
installed with an improper orientation. However, the in/out ports for
the excess flow valves were properly labeled despite the volve outline
being shown backwards. In the case of the excess flow valves, the drawing
orientation error had been discovered during fdbrication and the valve
was installed correctly. However, the fabrication organization had not
provided feedback to the design organization of the error and the drawings
had not been changed. This could cause problems later in plant life should
the pressure control valves be replaced using the same fabrication drawings.
These drawings were being corrected at the conclusion of the inspection.
The apparent failure by the licensee to ensure that safety-related components
of the instrument
associated drawings airwere
system weremaintained
properly seismically (qualified and to ensure thatas discussed in
3.1.2(5), respectively) will remain unresolved pending followup by the NRC
(50-312/86-41-06).
3.1.3 Main Feedwater System
The main feedwater (MFW) system status report review was limited to examination
of the system problems with emphasis on safety-related espects of the system.
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Unlike the AFW and instrument air systems, a detailed examination by the
inspection team of engineering activity to resolve system problems or modifi-
cations was not performed. Of the 55 problems identified in the SSR, 10 were
scheduled to be completed before restart. Although the problem description
and the testing recommendations were not very detailed, the team, in general,
found them to be adequate. However, the following list of MFW problems were
not scheduled for resolution prior to restart, but were considered by the
inspection team to significantly affect plant reliability and should be
resolved before restart:
No. Problem Statement
6 Faulty MFP Lovejoy Control Response
9 MFW Startup Flow Control Valves Stick Closed
Occasionally and Have Slow Response to OTSG
Level Change
12 NFW Flow Control Valve Positioning During Transients
18 Correct Casualty Procedure C.26 For MFP Operation
With Low Condenser Vocuum
19 Correct Casualty Procedure C.10 For Action On Loss
Of One MFP
22 Update P&ID M-580, Sheet 1
31 MFP Control From Lovejoy to Bailey H/A Station Is
Not Performing As Designed
45 MFP Governor Is Slow To Respond
The licensee had made a similar determination prior to the start of this
inspection and a Restart Manager Memorandum dated February 3,1987 authorized
release of resources to resolve these problems. These problems and their
resolution will be reviewed by the NRC (50-312/86-41-07).
3.1.4 Emergency Feeowater Initiation and Control (EFIC) System
The inspection team's review of the EFIC System SSR focused on the technicel
adequacy of engineering change notice (ECN) - 5415 to install this new system
and the various sub-ECNs. Reviews were conducted of the following sub-ECNs of
ECN-5415:
Sub ECN Description
A Installation of OTSG Level Taps
B Installation of OTSG Level Transmitters
C Installation of new Main Steam Line Pressure
Transmitters / Deletion of Pressure Switches
Q Signal Conversion Cabinet Indication Loop Modifications
AC Installation of MOVs on two ADV Isolation Valves
AH Installation of HISS Console Extension
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The following concerns were identified during the review:
(1) The excess flow check valves located in the steam generator low level
sensing line to separate the EFIC system from Integrated Control System
.
(ICS) were not environmentally qualified. These valves contain age-
'
sensitive material (Viton 0-rings) and will be located in a harsh
temperature and radiation environment. During the inspection, the
i
'
licensee initiated actions to qualify these valves. This item will be
followed up in a future NRC inspection (50-312/86-41-08).
!
l (2) The EFIC system design appeared susceptible to inadvertent initiation
i upcn a single failure of an OTSG level sensing line. This appears to
- deviate from the Rancho Seco Updated Safety Analysis Report (USAR) Section
- 7.1.1.1, " Single Failure," which stipulates that no single failure will
initiate unnecessary protective system action except when satisfying
, this criteria could prevent protective action with a single failure. Both
l the OTSG 1evel and pressure instrumentation appear susceptible to initation
i on a single failure of a sensing line. The OTSG level instrumentation has
- two low level and two high level taps, each of which provides inputs to
l two channels of the EFIC initation logic. Similarly, the steam pressure ,
- instrumentation has one tap in each steam line which supplies two channels
! of the initiation logic. A single failure in the commori sensing line at
'
any of the level or pressure taps will satisfy the two out of four initation
logic for the EFIC system and start the AFW system. -
I The team acknowledges that the probability of a failure of the common
sensing lines for the OTSG high level tap or steam pressure taps is small,
but the probability of spurious initiation due to the failure of an OTSG
low level common sensing line may be enhanced by other design features.
! First, excess flow valves are installed in the common instrument lines at
! each of the taps. They were originally not environmentally qualified and
l are intended to close upon failure of downstream piping to minimize the
! effects of a potential break. However, they will actuate closed at a flow
i rate well below that of a line break. Second, there were mechanical
) fittings downstream of the excess flow check valves which are subject to
i leakage. If leakage through any of these joints or at any of the
i instruments themselves reached the setpoint of the excess flow valve, it
j will actuate closed, isolating the lower legs of the level instruments
associated with that level top and producing the same spurious initiation
'
<
, effects as a failed correon sensing line.
l The team was concerned that EFIC system sensing instrumentation was
- currently designed such that certain failures will initiate unnecessary
1 protection system action and potentially cause transients. Additionally,
j it appeared that the deviation from Section 7.1.1.1 of the USAR was not
identified in the 10 CFR 50.59 evaluation for the EFIC system modification.
These concerns will remair. unresolved pending followup by the NRC
(50-312/86-41-09).
) (3) The licensee's planned test program as outlined in the EFIC System SSR did
- not' verify that whenever any channel was placed in the maintenance bypass
i position, the remaining channels would not be inhibited or degraded. The
i team considered that such testing would be appropriate to demonstrate that
I the channels which provide signals for the same protective function, be
j independent and physically separated such that the likelihood of interactions
i
3-7
i
i
l
_ - _ - - - _ _ _ _ _ _ - _ _ _ - _ _ _ _ _ - _ _ _
i
1
. O
between channels during maintenance is reduced as required by Institute of
Electrical and Electronic Engineering (IEEE) Standard 279-1971, " Criteria
for Protection Systems for Nuclear Power Generating Stations." During the
inspection, the licensee indicated that post-modification testing would
incorporate appropriate provisions to fully test the maintenance bypass
feature. This item will remain open pending followup by the NRC
(50-312/86-41-10).
3.1.5 125 Vdc System
Battery replacement, new diesel generators, and changes to the 120 Vac vital
bus system loads for the EFIC system modifications were all identified in the
system status report as the major changes that affected the 125 Vdc system.
Additionally, 22 valid problems were identified by the licensee, and the team
agreed with the actions and scheduling of resolution for all but four of these
problems. The following problems were discussed with the licensee who agreed
that they should be completed before restart:
(1) Problem 6 identified several deficiencies with operating procedure A.61,
"125 Volt DC System", which affect safe plant operation.
(2) Problem 9 identified instances where battery room temperatures exceeded
l design temperatures in the summer months, but did not identify that
l battery temperature could go below minimum design temperatures in the
winter months. The team noted that battery temperatures in batteries BC2
and BA2 were several degrees below the minimum temperatures used in design
calculations [see Section 3.4.4(1)]. The proper control of battery
temperature can impact the various design analyses of the 125 Vdc
system as identified in Section 3.2.2(1) of this report.
(3) Problem 20 identified that the power filter capacitors had reached the
end of their useful life for only one of six Class 1E battery chargers
in the auxiliary building. However, problem 20 did not identify that the
other five chargers also required capacitor replacement. New capacitors
had been ordered for all six battery chargers to replace the existing
components, but the SSR only identified charger H4BB as requiring capacitor
replacement and this was scheduled for resolution after restart. The
licensee stated that the problem statement and resolution of the SSR would
be expanded to include the refurbishment of all six aging Class 1 battery
chargers before restart.
(4) Problem 22 identified open nonconformance reports (NCRs) that were not
scheduled to be resolveo prior to restart. Two of the NCRs (S-5504 and
S-5548) concerned deformed vital battery terminal posts. The team
determined that these two NCRs affected the operation of the safety related
battery.
The implementation of the corrective actiuns discussed above for the 125 Vdc
system will remain open pending review by the NRC (50-312/86-41-11).
3.1.6 120 Vac Vital Power System
The vital 120 Vac power system was being modified during this outage to
transfer new loads to the buses located in the Nuclear Services Electrical
Building (NSEB). The team reviewed the 15 problems in the SSR identified by
the licensee and agreed with all but the following items:
3-8
. _ _ _ _ _ . - _ _ _ .- ._. _ __ _ _.
- . - - - - - . .-- - _ . - - - . --
L
. .
2
(1) Problem 7 identified that the licensee's response to IE Bulletin 79-27,
i " Loss of Non-Class-1E Instrumentation and Control Power System Bus During
4 Operation," needed updating. The licensee's proposed resolution was to
l analyze the existing electrical systems and determine actions to be taken -
after restart. The team was concerned that the 120 Vac systems modifica-
!
tions installed after issuance of IE Bulletin 79-27 did not comply with
the requirements for indication in the control room and that current
i casualty procedures did not provide the diagnostic problem solving '
corrective actions required by this bulletin. .At the exit meeting, the
- licensee agreed to implement the recommendations of their study of IE
t Bulletin 79-27 prior to restart. This commitment appears to upgrade the
j following problems to be accomplished before restart:
Problem 2 - No control room indication on opening of vital 120 Vac breakers.
!
}
Problem 5 - Casualty procedures do not exist for loss of 120 Vac vital
j buses. .
.
(2) Problem 6 identified that operating procedure A.62, "120 VAC Vital System " '
did not list a load schedule and was not scheduled for completion prior
to restart. The team considered the load schedule important for reliable
.j plant operations.
! (3) Problem 12 identified that there was no positive local indication of
individual circuit breaker position on the 120 Vac panels. The tripped -
'l and shut positions of the breakers were too close to distinguish by
relying solely on the visual indication of the breaker switches. The
i
team considered positive indication of individual 120 Vac circuit breakers
j to be important for safe plant operations.
I
At the exit meeting the licensee committed to resolve the issues identified
above with the 120 Vac vital system before restart. .This issue will remain
i open pending followup inspection by the NRC (50-312/86-41-12).
I
! 3.1.7 480 Vac System
}
There were no major modifications identified for this system. Of the 43
problems in the SSR identified by the licensee, the team agreed with the
priority and resolution of all but the items listed below:
l (1) Problem 10 identified that no 480 Vac loads were alarmed for loss of
power. The licensee planned to perfom a study after restart to determine
which loads should be alarmed. There was no schedule for completing
the alarm installation for those loads identified by'the study. The team
determined that the study and required alarm installation should be ,
accomplished before restart.
j (2) Problem 11 identified deficiencies with various casualty procedures for the
t 460 Vac system that should be corrected before restart. l
(3) Problem 16 identified poor local indication for some 480 Yac system ,
3
< circuit breakers caused by defective springs which should be replaced l
'
before restart. l
l
'
3-9
_ ..- _ . _ _ _ _ .-. _ _ . _ _ . _ _ _ _ _ __. _ _ _ _ _ __ _ __ _ _,_
. d
- (4) Problems 25, 33 and 34 identified deficiencies with Procedure A.59, "480 Vac
System Operating Procedure," which should be corrected before restart.
(5) Problem 46 identified a discrepancy with drawing E-108, Sheet 30, that
was used for plant operations and should be corrected before restart.
(6) Problem 26 identified that there was no indication for loss of 480 Vac
circuit brehker control power and should be corrected prior to restart.
'
This item will be resolved as part of the actions required by IE Bulletin
.
79-27 discussed in Section 3.1.6(1) of this report.
.
(7) Problem 19 identified inconsistencies with the alarms for losses of the
i various 480 Vac system load centers and motor control centers (MCCs) which
may confuse the operators. This item should be resolved prior restart.
.
l The resolution of the items identified above pertaining to the 480 Vac system
- will remain open pending followup by the NRC (50-312/86-41-13).
- 3.1.8 4160 Vac System
The installation of safety-related diesel generators GEA2 and GEB2 and the
,
tie-in to the 4160 Volt busses were identified as the major modifications for
i this system. Of the 42 valid problems identified in the SSR, the team agreed
l. with the priority and resolutions of all but the four listed below:
I (1) Problem 8 identified instances where protective relays in the switchgear
- ' had been modified by slotting a hole on the magnet base to help with
calibration of the relay. The licensee did not know how this would affect
i the seismic and environmental qu611fication of the switchgear. This
- problem should be resolved before restart.
!
! (2) Problem 25 identified that there was no indication for loss of de control
i power to the 4160 Vac switchgear. This issue should be resolved prior
to restart as part of the implementation of IE Bulletin 79-27 respunse
,
items oiscussed in Section 3.1.6(1) of this report.
> (3) Problem 32 identified that there was no procedure for operation of the
i startup transformers. Specifically, there was no formal procedure
I identifying the required system checks for the transformers that should
} be performed before they are placed in service. This procedure should
i be develuped and issued before restart.
l (4) Problem 33 identified deficiencies with the casualty procedures for the
electrical transformer cooling system which should be corrected before
j
restart.
The resolution of identified problems with the 4160 Vac system before restart
i will remain open pending followup by the NRC (50-312/86-41414).
'
3.2 Selected Review of System Design Features '
i To assess the completeness of the licensee's identification of system problems,
l safety-related design features were reviewed by the inspection team on a sampling
! basis. The design features selected for review were not the subject of a
!
- 3-10
- . - _ - - - -,.- . - -_- .. -- . _ - _ - - . - - - - -
. .
l
problem identified in system status reports. The findings and observations
resulting from these reviews are discussed below, categorized by engineering
discipline.
1
3.2.1 Mechar.ical Systems l
(1) The following design features were reviewed and appeared to be technically
correct:
(a) Seismic qualification package for AFW system flow control valves
CV 20527 and CV 20528.
(b) AFW pump available net positive suction head.
(c) Desigr analysis that confirmed the adequacy of a missing anchor
bolt observed during a system walkdown.
. (d) Arrangement of the AFW turbine steam supply piping with respect to
the single failure criterion.
(e) Preliminary seismic analysis for qualification of motor operators
for the main steam dump block valves.
(2) Weaknesses were identified in design features associated with the
condensate storage tank (CST) overpressure and vacuum protection schemes.
It appeared that the adequacy of these design features were not verified
when the AFW system was upgraded to safety grade.
(a) Procedure AP.152, "Feedwater and Condensate Systems," Revision 19,
allowed the set pressure of the relief valves for the CST to be set
as high as 2.5 psig. According to the tank supplier's drawings, the
maximum allowable working pressure and the design pressure for the
tank are both 2.0 psig. Because the CST is a closed tank, the pressure
inside the tank increases as water is added. It appeared to the
inspection team that this would routinely cause the pressure in the
CST to increase above the 2.0 psig design value. The CST is the only
safety-related water source for the AFW system, and Technical
Specifications require that a minimum of 250,000 gallons of water be
available in the tank. The team considered the CST relief valve
'
setpoint upper limit of 2.5 psig to threaten the structural integrity
of the tank.
-
(b) The CST vacuum breakers may not provide adequate underpressure pro-
1
tection for the tank. The sizing analysis for these valves was
i
performed in 1975 by the architect / engineer. The design basis event
that this analysis considered was makeup to the hotwell with both
i
vacuum breakers functioning. For this event a negative pressure of
1.3 inches of water on the CST was calculated; however, the tank was
designed for a negative pressure of cnly 1.0 inch of water. The
! excess negative pressure was judged in the analysis to be acceptable
- without explanation. Additionally, the analysis for these valves
- did not consider a single failure of one of the two valves as required
by 10 CFR 50, Appendix A, Criterion 34 or more limiting events such
as hotwell makeup and AFW pumps running together. If this situation
3-11
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, _ - _ . - _ _ - . - _ _ - _.
. <
were considered, it is likely that the negative pressure could
significantly exceed the tank's rating.
The apparent failure to provide adequate relief valve and vacuum breaker
protection for the CST will remain unresolved pending followup inspection
by the NRC (50-312/86-41-15).
3.2.2 Electrical Power Systems
The ac and de Class IE systems were reviewed. The team concentrated on
verifying the adequacy of the voltage available at Class 1E equipment, the
continuous and short circuit duty of the distribution equipment, and cable
sizing criteria in regard to ampacity and voltage drop. The documents reviewed
to support this evaluation consisted of the one line diagrams for the Class 1E
systems for the 4160 Vac switchgear, the 480 Vac load centers, the 120 Vac
vital instrument power panels, and the 125 Vdc power panels. Estimates were
made by the team that confirmed the conservative steady-state loading of the
Class 1E distribution panels.
At the time of this inspection the onsite Class IE ac system was being modified
by the licensee to improve its capacity and reliability. The team reviewed
the future distribution system as it was intended for restart and considered
the licensee's plans acceptable.
The team reviewed selected calculations evaluating the accuracy of input data,
the appropriateness of input assumptions, and the methodology and mathematics
of the calculation details. The calculations reviewed included the main ac
voltage study and short circuit calculations; the 120 Vac system inverter
l study and short circuit calculations; the 120 Vac system inverter loading
and breaker coordination calculations; the de system short circuit and battery
sizing calculations; and selected cable ampacity and voltage drop calculations.
In general, these calculations were found to be adequate; however, several
deficiencies were found as described below:
(1) At the time of the inspection, the batteries in the auxiliary building were
being replaced with new, larger capacity batteries. The licensee performed
sizing calculations to establish the amount of margin that existed for
future load growth. The licensee also performed a de short circuit
calculation to verify the compatibility of the new batteries with the
existing de panelboards. The team found that the de short circuit
calculation, Z-DCS-E0612, Revision 1, dated January 2, 1987, contained
conflicting references for the short circuit capacity of the new batteries.
The less severe value was used in the calculation, without justification,
yielding a margin of less than 200 amperes below the rating of the de panel-
board. If the other reference data attached to the calculation were used,
a short circuit above the panelboard rating Would have resulted. In
addition, the team found that the calculation failed to recognize that
the manufacturer's short circuit data was presented at a nominal 77'F
rating. Batteries are electrochemical devices and, as such, the short
circuit current capability of a battery is dependent upon temperature.
At the maximum allowable temperature presently permitted for the licensee's
' batteries 110*F, the de panelboards could be subjected to a short circuit
!
at least 10% above rating. Failure of a de circuit breaker to clear such
{
a fault could result in failure of the battery, caused by melting of the
l 3-12
l
1
-
a .
l
- lead components within the battery cells. This design deficiency will I
remain unresolved pending followup by the NRC (50-312/86-41-16). l
(2) At the time of this inspection the safety-related batteries in the NSEB
were being loaded to near capacity by transferring loads from the auxiliary
building batteries. To ensure that the NSEB batteries could accept these
additional loads, battery sizing calculation Z-DCS-E0636 Revision 1, dated
January 3,,1987, was prepared. As part of this calculation a new load
profile was developed based on a review of all loads connected to the de
panelboards. The largest loads being odded to the NSEB batteries were the
safety-related inverter loads transferred from the auxiliary building
batteries. Inverters are constant kVA loads and, therefore, draw a larger
current with the decreasing voltage seen during a battery discharge. This
was not addressed in the calculation. Instead of using a voltage typical
of the expected discharge voltage, the calculation assumed a nominal 125
volt input. The correct discharge voltage would have resulted in a load
current drawn by the inverters approximately 10% higher than assumed in
the calculation and would have changed the result of the calculation by
approximately 6%.
This same calculation included correction factors for aging and minimum
design temperature as recommended by IEEE Standard 485, " Recommended
Practice for Sizing Large Lead Storage Batteries for Generating Stations
and Substations." However, the team found that calculation Z-HVS-1940,
Revision 0, dated July 7, 1986, referen:ed as the basis for the minimum
design temperature, did not substantiate the temperature value used in
the battery sizing calculation. This error could contribute an additional
4 to 6% difference in the final result of the calculation. The calculation
had concluded that approximately 10% margin existed for future load growth.
Because of a 25% correction factor included for aging, no immediate problem
existed with the present loads. The team was concerned that the margin
remaining for future loads was substantially less than calculated by the
licensee. The apparent failure to perform an adequate analysis of the
NSEB battery will remain unresolved pending NRC followup inspection
(50-312/86-41-17).
(3) As part of the team's evaluation of the 4160 Vac and 480 Vac systems,
selected input data for the short circuit and voltage regulation studies
were verified. The team found that the voltage regulation calculation
Z-EDS-E0076, Revision 4, dated January 4,1987, was adequate. This
calculation computed the 4 kV and 480 Vac bus voltages for a transmission
voltage range of 244 kV to 214 kV. As a result, the licensee determined
that if the minimum transmission voltage was held at 216 kV, sufficient
margin would be present to ensure that the starting voltage at the motor
terminals would be above the minimum required 75% of motor nameplate
voltage. All major motors in the 4 kV and 480 V systems were considered
and the motors that are most distant electrically, in terms of feeder cable
voltage drop, were the motors selected for the study. The team confirmed
that all buses were loaded to realistic values for this study. A minor
discrepancy was found concerning the voltage transfonnation ratio used in
the calculation for startup transformer number two. The calculation
used a 230 kV to 4.36 kV ratio and the referenced one line diagram
E-101, which indicated a 221 kV to 4.36 kV ratio. The team confirmed
that the calculation correctly used the transformation ratio from the
actual voltage tap selected at the transformer. This item will remain
3-13
-.. . . - - - -. - - . - . -- .- -- - -
!'
. .-
! open pending NRC review of the corrected one line diagram, E-101 ,
- (50-312/86-41-18).
1
! (4) The inspection team was unable to verify that the correct startup
! transformer impedances were used in short circuit current calculation
'
Z-EDS-E0120, Revision 2, December 31, 1986, performed by Bechtel using
j the TE 502 "FAULTX" computer program, Rev. O. The licensee acknowledged
i
that an apparent discrepancy of almost 6 percent existed in the noncon-
i
servative direction and drafted a preliminary calculation indicating that
- under worst case conditions a margin of about 1 percent between breaker
j rating and the available short circuit current would still exist at the
- motor control centers. The apparent failure to use the proper data in
this calculation will remain unresolved pending NRC followup inspection
}
- (50-312/86-41-19).
(5) One power cable was found not to be sized in accordance with USAR commit-
ments. USAR Section 8.2.2.11.H.11 stated that power cables are sized for
i. 125% of full load current of the equipment served. In response to inspec-
i tion team concerns about power cable thermal insulation, the licensee
'! developed a preliminary calculation that showed one power cable, between
i battery charger H4BAC and de Bus SOA, was found marginally acceptable
i based upon actual load currents and would not have satisfied the 125%
) USAR criteria. The apparent failure to meet a USAR commitment will
d remain unresolved pending followup by the hRC (50-312/86-41-20).
(6) The team reviewed the electrical schematics supporting the auxiliary
j of an apparent breakdown in the interface between the designers and the
- interim data acquisition and display system (IDADS) computer group.
i
- (a) The electrical distribution system in the NSEB was monitored in the
j control room by IDADS. The dc bus voltage was an input to the
- computer as a 125 volt analog signal. The IDADS computer group
! incorrectly interpreted this as a bistable input and set the bus
- failure alarm at zero volts, eliminating alarms at degraded bus
i voltages. The correct setpoint should have been no lower than 105
j volts.
j (b) The AFW pump runout alarm was developed by a combination of a pump
l low discharge pressure signal and a delayed pump running signal
j from the motor circuit. The purpose of the delay was to provide
-
time for the pump to come up to speed so that an unintended alarm
j
would not be received on startup. Although the logic diagram, 1205, ,
-
Sheet 3. Revision 6, indicatea the required time delay, this feature
I had not been provided in the actual circuit, either by hardware or by
{ computer software.
j These examples of an apparent failure to correctly translate intended
i design features into plant systems will remain unresolved pending followup
} by the NRC (50-312/86-41-21).
,
i (7) Electrical protection provided for equipment in the AFW system was reviewed.
} The team determined that adequate overload protection was provided for the ,
l 1000 horsepower auxiliary feedwater pump motors. However, no thermal
overload protection or overload alarms were provided for the safety-related
{
i
I
'
l 3-14
i
. .
motor operated valves. Although these features are not a regulatory
requirement, having neither of these features is not censistent with
general industry practice. The inspection team was concerned with the
potential for undetected degradation of a valve operator's motor that
would cause the motor to fail when subjected to design basis conditions.
The licensee stated at the exit meeting that this matter would be reviewed
for consideration at Rancho Seco. This item will remain open pending NRC
review of the licensee's resolution (50-312/86-41-22).
3.3 Engineering Programs
During the inspection, the team examined a large cross section of engineering
design and output documents. The documents reviewed by the team are identified
in Appendix B of this report. The review of these documents and technical
discussions with the licensee's engineering staff formed the bases for the
following observations.
3.3.1 Nuclear Engineering Procedures Manual
Rancho Seco implemented a Nuclear Engineering Procedures Manual in 1985 to
provide an integrated system of procedures and references for design and
construction. This manual, although not entirely complete, contained over
500 procedures covering topics such as administration, design control, pro-
curement, design criteria, design guides, specifications, system design bases,
and Construction procedures. At the time of this inspection the system design
basis section was approximately 25% complete; however, overall this comprehen-
sive manual was considered a strength.
In addition to numerous procedures identified in Appendix B of this report, the
following procedures from the Nuclear Engineering Practices Manual that affected
general design process were reviewed:
4101, " Design Process," Revision 0
4106, " Design Calculations," Revision 0
4109, " Configuration Control," Revision 5
4110. "Interdiscipline Document Review," Revision 1
4112, " Drawing Change Notice," Revision 1
With the exception of the deficiencies identified in Section 3.3.3, the licensee's
procedures governing design and modification control activities were considered
odequate.
3.3.2 Safety Evaluations
The licensee's procedures governing the performance of safety evaluations were
reviewed; Quality Control Instruction (QCI) 5. " Safety Review of Proposed
Facility Changes," Revision 2, and QCI 18, " Safety Review of Proposed Procedures
and Procedure Changes," Revision 1. A review of several safety evaluations
indicated that these procedures were being properly implemented. However, these
procedures lacked detailed guidance for determining the existence of an un-
reviewed safety question and lacked requirements governing the qualifications
of personnel making and reviewing 10 CFR 50.59 determinations. These weaknesses
were identified by the licensee and addressed in draft procedure QCI 5 " Safety
l Review of Proposed Changes, Tests and Experiments." This item will remain open
pending NRC review of the implementation of this draft procedure (50-312/86-41-23).
3-15
i
i
l
.
- l
l
3.3.3 Drawing Control Program l
l
The following deficiencies were found in the drawing control program: j
l
(1) No procedure existed to control the distribution of updated drawings. 1
Nuclear Engineering Procedure (NEP) 4109, " Configuration Control," l
Revision 5, had a transmittal form for drawing changes but had no specific I
instructions for its use. At the time of this inspection, the licensee <
'
l had prepared draft procedure AP.85 " Site Control Document," intended to
control the distribution of updated drawings. This draft procedure
addressed issues such as controlled distribution lists, field use of
controlled drawings, stamping conventions, drawing change notice (DCN)
distribution, control room drawing distribution, and handling and distri-
bution of controlled aperture cards.
(2) The controlled drawing files were not being maintained up-to-date. The
licensee used drawings on yellow paper to indicate the construction
completion of modifications made to the plant. One or more yellow drawings
were then incorporated into new revision white drawings. The licensee's
control of these yellow drawings was found to be inadequate. A comparison
Was made of the yellow drawings on file for drawing numbers M-500 to M-599,
which are the system piping and instrument diagrams (P& ids). This
comparison was made between site document control (SDC), the control room,
and the controlled crawing file room in Trailer 0 used by the nuclear
engineeringdepartment(NED). The following deficiencies were found with
these drawing files:
(a) Drawing M-562, "P & I Diagram Waste Gas System," Revision 23, was found
in SDC and the NED. However, a yellow drawing, detailing DCN 37, was
outstanding against drawing M-562, Revision 23. The applicable yellow
sheet necessary to determine the effect of this DCN was not available
at either SDC or the NED. The control room had Revision 24 of drawing
M-562, which had incorporated DCN 37.
(b) Dr6 wing M-532 " Steam Generator System," Sheet 1, Revision 6, had
three applicable yellow drawings for DCNS 19, 20, 41d 26 as indicated
4 by the SDC yellow drawing file. In the NED, the aperture card for
M-532 incorrectly indicated that only DCN 19 was applicable to this
drawing. The yellow drawings for DCNs 20 and 26 were not available
in the NED, nor in the control room for DCN 26.
,
(c) The NED had drawing M-533, "High Pressure Feedwater Heater System,"
Sheet 4, Revision 10, and the control room had Revision 9 of this
same drawing.
(d) Drawing M-541, " Plant Cooling Water System," Sheet 1, Revision 4,
was found in the control room. However, a yellow drawing, detailing
DCN 5, was outstanding against drawing M-541, Revision 4. The
applicable yellow sheet necessary to determine the effect of this
DCN was not available in the control room.
3-16
. -. -. .. - -- -. _ - . . -.
. .
1
(e) Drawing M-543, " Component Cooling Water System," Sheets 1 and 2, 1
P.evision 2, was found in the control room. However, a yellow drawing, '
detailing DCN 5A, was outstanding against drawing M-543, Revision 2.
The applicable yellow sheets necessary to determine the effect of this
DCN were not available in the control room.
l
During this inspection, the licensee management representatives agreed to
perform a complete verification of their drawing files and committed to
conduct a quality assurance (QA) audit of SDC activities. The failure of the
licensee to have a procedure to control drawing distribution and to maintain
current drawing files will remain unresolved pending followup by the NRC
(50-312/86-41-24).
3.3.4 Engineering Calculations
The team was concerned that in many instances the general quality of design
calculations did not meet the requirements of American National Standards
Institute (ANSI) N45.2.11. " Quality Assurance Requirements for the Design of
Nuclear Power Plants," Section 4.2. Of over thirty calculations reviewed,
approximately 80% contained errors or inconsistencies of varying aegrees of
significance. Approximately 7% had errors that, had they gone undetected,
could have had a nonconservative effect on plant design.
(1) The following are examples of calculation deficiencies where incorrect
results were obtained or an incorrect method was used for design
>
calculations:
(a) Calculations to detemine the minimum AFW recirculation flow were
l
performed in 1972, 1974, and twice in 1984, each giving different
results, and each still ir, effect. It appeared that only the 1974
calculation was utilized, yet the other calculations had not been
superseded, and there were no annotations to this effect on any of
the calculations. Furthemore, there was no mechanism for dis-
tinguishing preliminary from final calculations. The recirculation
flow determination was on important input to the determination of
AFW pump operability as discussed in Section 3.4.2(1) of this report.
(b) Calculation Z-FWS-M-2081, Revision 0, dated December 23, 1986, was
performed to determine the acceptance criteria for AFW pump discharge
) pressure routine testing. According to the calculation, the minimum
acceptable discharge pressure was to be adjusted to account for the
level of the condensate storage tank. The arithmetic sign for this
,
adjustmentwasincorrect[Section3.1.1(5)].
(c) Calculations Z-IAS-M2084, M2085 and H2086, Revision 0, dated
December 30, 1986, incorrectly applied the perfect gas law.
(2) The following are examples of calculation deficiencies where assumptions
were either incomplete, incorrect, nonconservative, unjustified or not
properly documented:
(a) Calculations Z-IAS-M2084, M2085, and H2086, all Revision 0, dated )
December 30, 1986, concerning backup air bottle sizing, did not '
3-17
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_ - - . - - _ .__ __ ___
. 4
i
assume leakage back through excess flow valves as described in Section .
3.1.2(3) of this report.
(b) Calculation Z-FWS-M1742, Revision 0, dated Se ember 26, 1985,
concerning motor-operated valve stem nut acce ability, assumed
uniform thread loading. This is not considered a valid assumption
in general industry practice.
(c) Calculation Z-FWS-M0254, Revision 0, dated February 9,1984,
concerning AFW system pressure drop, inappropriately assumed friction
factors for clean pipe and assumed no pressure drop for AFW ring
(d) Calculation 2-FWS-K1798, Revision 0, dated January 13, 1986, concerning
steam trap loads, assumed an ambient temperature of 75 F which is not
conservative because the piping is located outdoors.
(e) Calculation Z-IAS-0123, Revision 0, dated November 17, 1986, concerning
AFW flow orifice differential pressure, used a fluid temperature of
68'F. Calculation Z-FWS-I-0091, Revision 0, dated March 7, 1985,
concerning the same subject, used a fluid temperature of 115'F.
.
(f) Calculation Z-IAS-M2085, Revision 0, dated December 30, 1986,
concerning backup air bottle sizing gave no basis for 5 cycles of
valve operation in 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />.
(g) In calculation Z-FWS-M2045, Revision 0, dated October 25, 1986,
concerning AFW system resistance, the flowpath chosen as " worst
Cdse" Was not justified.
(h) In calculation Z-FWS-M1798, Revision 0, dated January 13, 1986,
concerning load on steam traps, 900 psig was assumed to be a
conservative pressure with no explanation.
(i) In calculation Z-FWS-1742, Revision 0, dated September 26, 1985,
concerning worn valve stem nut acceptability, the assumption that
the nut had a single lead thread contradicted data item 1 that stated
that the thread is a double lead.
(j) Calculation Z-FWS-M2081, Revision 0, dated January 12, 1987, con-
cerning minimum AFW pump head requirements, assumed AFW pump
recirculation flow of 60 gpm at rated flow conditions with no source
of this data identified.
(k) Calculation Z-FWS-M2081, Revision 0, dated January 12, 1987, con- I
cerning minimum AFW pump head requirements, implicitly assumed that
the condensate storage tank is at atmospheric pressure when the tank
is actually closed and can be under vacuum or pressure conditions.
(1)' Calculation 2-DCS-E0636, Revision 1, dated January 3,1987, concerning
NSEB battery sizing, assumed a battery minimum temperature based on the
referenced HVAC calculation (Z-HVS-M1940, Revision 0, dated July 23, l
1986) which did not justify the temperature assumed.
l
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(3) The following are examples of calculation deficiencies where design inputs
were incorrect or not identified: ,
(a) Calculation Z-DCS-E0612, Revision 1, dated January 2,1987, concerning
de short circuit margin, contained conflicting references for the :
'
short circuit capacity of the new batteries [Section 3.2.2(1)(a)].
(b) Calculation M19.29, Revision 0, dated March 5, 1985, concerned AFW
system flows. An orfice was not identified or described, the source
of the system resistance curve was not identified, and the formula
source was not identified.
(c) Calculation Z-FWS-M2081, Revision 0, dated January 12, 1987, con-
cerning minimum AFW pump head requirements, identified the wrong
calculation as the basis for using zero pressure drop through the
(d) Calculation Z-FWS-M1742, Revision 0, dated September 26, 1985, con-
cerning worn valve stem nut acceptability, gave no reference for the
stem nut data on page 6 of the calculation.
(e) Calculation Z-FWS-I-0123, Revision 0, dated November, 17, 1986,
concerning AFW flow orifice differential pressure, used an incorrect
internal pipe diameter of 6.065 inches instead of 5.761 inches.
(f) Calculation Z-DCS-E0612, Revision 1, dated January 2,1987, concerning
dc system short circuit, did not correct the input for maximum
battery temperature [Section 3.2.2(1)].
(g) Calculation Z-DCS-E0636, Revision 1, dated January 3,1987, concerning
NSEB battery sizing, did not correct the input for inverter load for
lower voltages experienced during battery discharge [see Section
3.2.2(2)].
(4) The following are examples of calculation deficiencies where acceptance
criteria were not identified or were incorrect:
(a) Calculation Z-ZZZ-IO132, Revision 0, dated January 1, 1987, concerning
qualification of excess flow valves, had no stated acceptance criteria.
(b) Calculation Z-FWS-M1742, Revision 0, dated September 28, 1985, con-
cerning valve stem nut acceptability, did not identify increased
friction effects or increased bearing stresses at thread faces as
acceptance criteria considerations. It also used incorrect criteria
for determining shear stress acceptability.
(5) The following are examples where the purposes of calculations were not
clearly stated or were in conflict with the actual usage of results:
(a) Calculation Z~ZZZ-10132, Revision 0, dated January 1, 1967, concerning
qualification of excess flow valves, was documented as having been
performed for the purpose of environmental qualification. This
calculation did not address environmental qualification.
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(b) The stated objective in calculation Z-FWS-I-0091, Revision 0, dated
March 7, 1985, concerning AFW flow orifice bore sizing, was to
!
calculate the beta ratio and bcre diameter of orifice plates.
However, this calculation appeared to be an independent check of
a vendor's calculation to confirm orifice differential pressure.
(6) Some calculations could not be understood without recourse to the originator
Ncause of a lack of explanation of logic, non-use of dimensional units,
and references used that were not cited. Examples were calculations
Z-IAS-M2084, M2085, and M2086, Revision 0, dated December 30, 1986,
concerning backup air bottle sizing; calculation Z-FWS-M1798, Revision 0,
dated January 13, 1986, concerning steam trap loading; and calculation
Z-FWS-M1742, Revision 0, dated September 28, 1985, concerning valve stem
nut acceptability.
(7) The following are examples where calculations were either not available or l
not performed: '
(a) Seismic analysis for condensate storage tank and appurtenances.
(b) Seismic and environmental qualification of excess-flow check valves
and seismic qualification of backup air pressure control vahes and
adjustable check valves [see Sections 3.1.2(2) and 3.1.4(1)].
(c) Establishing the basis for the 0 to 1300 gpm flow range for AFW flow
instrument to meet a Regulatory Guide 1.97 commitment.
(d) Determining the setpoint corresponding to the condensate storage tank
level alarm when only 40 minutes of water remains in the tank.
During the inspection, in response to the team's concerns, the licensee initiated
a program to increase the level of confidence in calculations not reviewed by
the team to ensure that calculations are of appropriate quality. The signifi -
cant points of the program are (1) complete review of all calculations by
system design engineers to ioentify obsolete calculations and incorrect
references, (2) have a calculation review tearn independently review a broader
selection of calculations associated with restart for technical adequacy, and
(3) develop good practice guidelines for preparing calculations, including
techncial and documentation concerns. The failure to perform adequate calcula-
tions will remain unresolved pending NRC followup inspection (50-312/86-41-25).
3.3.5 Design Output Document Control
The licensee's control over design output documents that make up design change
4
packages was considered weak. Numerous completed design change packages were
reviewed, and none of these contained a listing or inventory of the design
output documents that the completed design change package was supposed to contain.
Under these circumstances, a person doing the closeout checking or subsequent
review of design changes could not be certain that the completed package
contained all the necessary documents or that all the requireo considerations
had been addressed in the change.
3-20
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i .
3.4 Surveillance and Inservice Testing
The team conducted a technical review of the surveillance and inservice test
(IST) programs as implemented on the AFW,125 Vdc and 4160 Vac systems. The
test procedures for the other five selected systems were being revised and were
not available for review during the inspection. This review included an
evaluation of the technical adequacy of the testing procedures and test results ,
'
to verify system components functioned as required by Technical Specifications.
The scheduling of testing to meet the periodic requirements of ASME Section XI
dnd Technical Specifications were not reviewed. The specific observations made
by the inspection team are discussed below.
3.4.1 Prograntnatic Testing Concerns
The team identified the following conceras about the licensee's test program
that pertain to all the reviewed systems:
(1) The licensee was operating without an approved Inservice Testing (IST)
program. The current IST program apparently expired on April 17, 1986
and the licensee could not pruvide a documentation that an extension
beyond this date had been approved. A new submittal was in the preliminary
stages of development and was not available for the team to review. The
apparent failure to have an approved IST program will remain unresolved
pending followup by an NRC inspection (50-312/86-41-26).
(2) The licensee's trending program for pump and valve test data appeared
inadequate. For an example, the Inservice Inspection Data Log used for
the AFW pumps' history file had no entries for 1985 and 1986 despite
surveillances performed during this period. The team was concerned that
failure to trend test data precluded using this information to detect
pump degradation. The apparent failure to trend pump and valve test data
will remain unresolved pending followup by the NRC (50-312/86-41-27).
3.4.2 Auxiliary Feedwater System Testing
The test data and technical adequacy of the following AFW system test procedures
were reviewed during the inspection:
- SP 210.01A, " Monthly Turbine / Motor Driven Auxiliary Feed Pump P-318
Surveillance and Inservice Test," Revision 23
SP 210.01B, " Monthly Motor Driven Auxiliary Feed Pump P-319 Surveillance
and Inservice Test," Revision 23
SP 210.010. "Quorterly Steam and Auxiliary Feed System Velve Inspection
and Surveillance," Revision 09
SP 210.01F, " Cold Shutdown Auxiliary Feedwater Pump Flow Test and Check
Valve Full Stroke Test," Revision 08
- SP 210.01H, " Refueling Interval Auxiliary Feedwater System Auto Start
Test for Loss of Four Reactor Coolant Pumps and SFAS Actuation,"
Revision 02
SP 210.011, " Auxiliary Feedwater Check Velve Integrity Test," Revision 01
3-21
. 4
- SP 210.01J, " Refueling Outage Main Steam to Auxiliary Feed Pump Turbine
Check Valve Integrity Test," Original
- SP 213.01, " Inservice Test and Inspection of Pumps," Revision 12
- SP 214.01, " Inservice Testing and Inspection of Valves," Revision 06
- SP 214.02, " Inservice Testing of Relief / Safety Valves " Revision 02
SP 214.03, " Locked Valve List," Revision 33
A.51, " Auxiliary Feedwater System," Revision 31
- STP.1025, " Auxiliary Feedwater Turbine Test with Auxiliary System
l Supply," Draft
The following concerns were identified as a result of this review:
(1) AFW pump flow had not been determined accurately or acceptably during
surveillance testing. Technical Specification 4.8.1 requires that the
AFW pumps be capable of delivering 780 gpm to a steam generator at 1050
psig and that this be verified on a monthly basis. Surveillance Procedures
SP 210.01A and SP 210.01B established acceptance criteria for the AFW pump
flow rates at 840 gpm to account for 60 gpm recirculation flow diverted to
the main condenser. The AFW pump capacity was determined by measuring the
change in CST level over a period of time when the CST was isolated from
everything except the AFW pump being tested. The surveillance procedures
allowed the use of either the installed level instrument (LI 35803) or a
temporary clastic tubing sightglass connected along the side of the CST.
Using these testing methods, the measured capacities for the punips have
been as low as 847 gpm indicating marginal AFW pump performance. The team
had the following concerns about the licensee's past determinations of
pump capacity using this method:
(a) There did not appear to be an adequate basis for the recirculation
value of 60 gpm. Testing performed in 1974 indicated that recir-
culation flow could be in the range of 37.0 gpm to 70.5 gpm.
Additionally, calculations dated November 6,1972, (unnumbered) and
February 9,1984 (Z-FWS-M0254) indicated that minimum recirculation
flow rates could be 86 gpm and 89 gom, respectively. The team was
concerned that actual recirculation flows greater than 60 gpm would
be non-conservative ano could affect the determination of pump
operability.
(b) The accuracy of the installed CST level instrument, LI 35803, had not
been validated using a two-point calibration check since its replace-
ment on August 4, 1984. Consequently, the licensee had not verified
that the level instrument wobid respond properly over the test range.
Single point validations performed with the plastic tubing revealed
that often there was a wide discrepancy between the two readings. On
these occasions LI 35803 was aligned to agree with the plastic tube
level. These differences could have been due to the level instrument
tape slipping its track during a level change in the tank.
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4
- .
1
(c) The plastic tubing sightglass may have been vented to atmosphere during
testing while the CST was pressurizeo by nitrogen to approximately
'
2 psig. Testing under this condition would generate a non-conserva-
tive error in the pump capacity test when the level in the CST tank
was lowered. The inspection team's concern that, in fact, the
plastic tubing sightglass was vented during testing is based upon
,
the following evidence: (1) interviews with operations personnel
, and instrument and controls (I&C) technicians revealed that in several
,
cases the sightglass was vented during normal plant operations,
(2) there was no procedural guidance or requirement for connectin ,
the plastic tubing sightglass to the CST during testing; and (3) g
data recorded for the level instrument validations indicated levels
! as high as 47 feet when the tank overflow line was at 43 feet 9 '
inches, suggesting that the tank was pressurized and the sightglass
vented when the data was recorded (the licensee stated that this
could also result from a difference in the zero reference for the two
measurementmethods). The surveillance records reviewed by the team
were ambiguous regarding the status of the sightglass or even if
the sightglass was used instead of LI 35803 as the measurement device
for the AFW flow tests.
The inspection team identified the potential calibration problems with
, LI 35803 to the licensee on January 13, 1987. Subsequently, the licensee
issued Licensee Event Report (LER) 87-05 to confirm the team's concern and.
further identified problems with correcting the CST level change for
miscellaneous flows during testing. The issues concerning the plastic
tubing sightglass and the validity of the 60 gpm recirculation flow were
identified to the licensee after issuance of LER 87-05. This item will
remain unresolved pending followup by the NRC (50-312/86-41-28).
(2) The acceptance criteria for the stroke times of identical air operated AFW
flow control valves, FV-20527 and FV-20528, were different. The licensee
was unable to justify this difference. The team was concerned that this
difference may represent a maintenance problem or an undocumented design
modification. This will be carried as an open item pending clarification
by the licensee (50-312/86-41-29).
.
'
(3) The following deficiencies were identified with the AFW surveillance
I
procedures:
'T
(a) Procedure SP 210.01A failed to check the backseat of AFW pump discharge
check valve FWS-048. The procedure incorrectly specified that the
, cross connect valve, HV-31827, be shut during the test lineup. With
- this valve shut the downstream side of the check valve was isolated
from its pressure source, AFW pump P-318. This condition has existed
since September 22, 1985, when SP 210.01A, Revision 21, was approved.
In addition, licensee reviews of revisions 22 and 23 had not detected
this error.
(b)- SP 210.01A, Revision 23 and SP 210.01B, Revision 23 did not specify
i
fixed locations for bearing temperature measurements of the AFW pumps.
l This was contrary to the provisions of American Society of Mechanical
Engineer (ASME)Section XI, Article IWP-4310 and the NRC Safety
Evaluation Report (SER) of September 25, 1984, which granted relief
from certain IST requirements for pumps and valves specified by ASME
3-23
_ _ _ . _ _ _ _ _ _ . . _ _ . . _ __. - . -
- 6
Section XI. Further, the failure to ensure fixed locations for these
temperature measurements invalidated the data with respect to its
value for providing trending information.
(c) SP 213.01, Revision 12, did not specify ALERT or ACTION RANGES for
pump differential pressure or pump flow for AFW pumps P-318 and P-319.
This did not meet the requirements of ASME Section X1, Article
IWP-3000. Additionally, failure to provide alert or action ranges
for suction pressure for pumps P-261, P272, P-291, P-318, P-319,
P-472 and P-482 was previously identified in NRC inspection report
50-312/85-23.
(4) Testing of the CST pressure relief valve, PSV-35804A, had apparently
exceeded the periodicity specified by SP 214.02. According to licensee
records, PSV-35804A was last tested on August 20, 1977, although SP 214.02
specified a required testing periodicity not to exceed five years.
The apparent failure by the licensee to develop and implement adequate procedures
for testing of the AFW system will remain unresolved pending followup by the NRC
(50-312/86-41-30).
3.4.3 4160 Vac System Testing
The following procedures, comprising the 4160 Vac system surveillance program,
were reviewed for technical adequacy:
- SP 206.02A, " Refueling Interval Diesel Generator "A" SFAS Start Test,"
Revision 04
- SP 206.028, " Refueling Interval Diesel Generator "B" SFAS Start Test,"
Revision 04
- SP 206.07A, " Nuclear Services Buses 4A and 4A2 Monthly Voltage Protection
Surveillance," Revision 02
SP 206.07B, " Nuclear Services Buses 4B and 4B2 Monthly Voltage Protection
Surveillance," Revision 02
- SP 206.08A, " Nuclear Services Bus 4A Voltage Protection Calibration ;
Surveillance," Revision 01
- SP 206.08B, " Nuclear Services Bus 4B Voltage Protection Calibration
Surveillance," Revision 01
EM.126A, " Refueling Testing and Maintenance of Diesel Generator "A","
Original
- EM. 126B, " Refueling Testing and Maintenance of Diesel Generator "B","
Original
EM. 144, " Testing of Protective and Control Relays," Revision 09
- EM. 177A, " Function Test of Nuclear Services Bus "A" and "A2" Unloading
Scheme," Revision 08
3-24
, .
' EM.1778, " Function Test of Nuclear Services Bus "B" and "B2" Unloading ;
. Scheme," Revision 09 ;
1
EM.196A, " Monthly Test of Nuclear Services Buses 4A and 4A2 Voltage l
Protection," Revision 04 i
EM.196B, " Monthly Test of Nuclear Services Buses 4B and 482 Voltage
Protection," Revision 03
EM. 198A, " Calibration and Testing of Nuclear Services Buses A and A2
Unloading and Voltage Protection," Revision 01
- EM.198B, " Calibration and Testing of Nuclear Services Buses B and B2
Unloading and Voltage Protection," Revision 01
These procedures were determined to be adequate for demonstrating system func-
tionality and operability.
3.4.4 125 Vdc System Testing
A review of the 125 Vdc system surveillance program was performed. The
following concerns and comments were noted during the review:
(1) The team was concerned that the proposed surveillance procedures failed
to ensure that hattery cell temperature was above the minimum design
temperature specified in the battery sizing calculations. On January 13,
1907, the team observed battery room and cell temperatures below their
minimum design values for the NSEB batteries. The licensee was in the
process of upgrading their battery maintenance and surveillance procedures
to be in line with the industry recommendations contained in IEEE Standard
450, "Recoranended Practice for Maintenance Testing and Replacement of
Large Lead Acid Storage Batteries." This effort should correct the
concern identified above.
(2) The inspection team observed th61 the electrolyte level for most of the
cells of the BA battery in the auxiliary building were outside the specified
acceptance range. This is significant because the battery manufacturer
specified the battery cell capacity assuming the electrolyte level to be
at the full mark. The licensee's procedures required the electrolyte level
to be maintained within 1/8 inch of the full mark, but on January 13, 1987,
the team found numercus electrolyte levels that were 3/4 to 1 inch below
the full mark. A review of weekly battery surveillance records indicated
that this battery was consistently noted as having low electrolyte levels
since it was installed in July 1986. No nonconformance reports for this
condition had been issued prior to this inspection and no corrective
action was evident. In reponse to the team's concern, Occurrence
Description Report 87-93, was issued on January 23, 1987.
(3) The team reviewed annual maintenance reports for the auxiliary building
batteries as required by Maintenance Procedure EM.161, " Station Battery
Charger Routine." The teum found numerous incorrect entries in both the
required and actual values on the data sheets. These entries involved
current limits, over voltage relay setpoints, equalizer voltages, and
float voltage settings. Additionally, the applicable load design data
sheet (Drawing E1011, Sheet 93) referred to in the procedure did not
3-25
,
i
contain all the required values. The licensee had recently undertaken
a training program to ensure complete and accurate maintenance records.
Further, recently 1mplemented Procedure MAP 002, " Control of Maintenance
Activities," dated February 4,1987, requires a review of all completed
work packages by a maintenance engineer.
The inadequacies identified above regarding battery surveillance and testing
will remain unresolved pending followup by the NRC (50-312/86-41-31).
3.5 Operations and Training
In the area of operations, the inspection team evaluated the adequacy of
operator shift manning and experience; control of ongoing activities; normal,
casualty, and emergency operating procedures; and licensed operator training.
This evaluation focused on how each of these elements interfaced with the
operation of the eight selected systems reviewed during this inspection.
Additionally, the team assessed the adequacy of operations department activities
required to support plant restart. The team was unable to determine the
adequacy of the majority of the nonnal and casualty procedures because the
procedure revision effort was incomplete. Similarly, the team could not
assess restart simulator training effectiveness because the training had not
been performed, nor was the team able to walk through the selected systems to
assess operator knowledge because of the extensive modification activity in
progress.
3.5.1 Control Room Operations
The inspection team observed various aspects of control room operations. The
following observations were made during the course of the inspection:
(1) The inspection team observed two control room shift turnovers (January 7
and 9,1987) and considered them thorough and effective. Ongoing discussions
with control room operators throughout the period of the inspection revealed
that their overall level of knowledge and professionalism appeared adequate.
Access to the control room was effectively controlled.
(2) The team reviewed 10 MFW and AFW system safe clearance tag control sheets.
Safe clearances were administratively controlled by Procedure AP.4A, " Safe
Cleerance Procedure Danger Tags," Revision 5. Several deficiencies were
noted where the administrative requirements of Procedure AP.4A were not
properly implemented:
(a) The applicable piping and instrumentation diagram (P&ID) used to
establish the clearance boundary was not noted for clearance No.
31519.
(b) The date and time the tags were attached were not referenced for
clearance No. 31777.
(c) Partial clearance of tags was noted for clearance Nos. 31808 and 31889,
but the reasons for tag clearance were not listed in the " REMARKS"
section for the two clearances.
3-26
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, .
(c) Two different job supervisors for the clearances listed in (c) did
not sign the "RE-ISSUED T0" block after the clearances had been
re-issued following a partial clearance. :
!
(e) Missing initials and component positions for both the " ATTACHED" and l
" REMOVED" sections of the Clearatice Request / Authorization Fonn were l
noted for Nos. 31465, 31808, and 31889.
Although the specific safe clearalice administrative deficiencies noted
above did not pose a threat to plant safety, the team was concerned that
the lack of attention to detail manifested by these deficiencies could
lead to situations where plant operators and supervisory personnel are
provided ambiguous or incorrect safety system status. In such situations,
,
operators may not respond appropriately during normal or off-normal
evolutions, thereby resulting in conditions that could be adverse to safe
plant operations.
(3) A review of the Abnormal Tag System maintained in the control room was
conducted by the team. These tags were issued and maintained in accordance
with Procedure AP.26, " Abnormal Tag Procedure," Revision 12. Several
weaknesses were observed with the implementation of this procedure:
(a) Approximately 60 abnormal tags were greater than one year old at the
time of the inspection and required a nonconformance report (NCR)
to be issued against them. Of these 60 tags, approximately one-third
did not have an NCR written against them. AP.26 required writing a
NCR to provide an administrative method for the plant nuclear engineering
department to determine if the temporary plant modification should be
made permanent. The inspection team was concerned that the failure
to issue the required NCRs reflected not only a lack of procedure
compliance but also a potential for allowing minor plant modifications
to occur without plant engineering involvement.
(b) Contrary to the provision of AP.26 which prohibit using abnormal
tags to implement setpoint changes, two cases were noted where
abnormal tags were used to change M0V torque switch settings. This
was an additional example of an insufficient level of plant
engineering involvement in determining the adequacy of a change to
plant systems or system equipment components.
(c) Several instances were observed in which monthly reviews required by
AP.26 had not been documented or performed, particularly by mechanical
maintenance and the operations department.
(d) System quality assurance (QA) class was not designated for several
tags as required by AP.26. This is significant because all QA Class
1 system abnonnal tags require the approval ci~ the Plant Review
Committee (PRC) within one working day after the tag is issued.
(4) The. Information Sticker Log, administered by Special Order 86-35, was
instituted as part of the corrective action following an incident in
November 1986 where a bank of pressurizer heaters were burned up because
operators relied on instruments that were out of service. The purpose
of this log was to establish controls for hanging information stickers
-
3-27
. i
dnd tracking the status of system instrumentation and components. The
team found three weaknesses related to this process.
(a) Two stickers were still hanging even though they had been cleared
from the log several weeks before.
(b) Four stickers did not have the associated work request number listed
in the' log.
(c) No monthly audit, as required by the governing procedure (Speciel
Order 86-35), had been conducted since the log's inception in
November 1986.
Based on the examples discussed above regarding administrative deficiencies
in the safe clearance tag system, the abnormal tag system, and the information
sticker log, the team concluded that the Rancho Seco operations personnel did
not always exhibit the requisite attention to detail that would ensure adequate
control of plant and system status. The resolution of these administrative
weaknesses will remain unresolved pending followup by the NRC (50-312/86-41-32).
3.5.2 Operating Procedures
The Operations Department had a major program in progress to upgrade the
operating, casualty, annuncidtor, and emergency operating procedures (EOPs).
A full-time procedure writing staff of approximately 10 licensed operators
had been supporting this effort. The team could not assess the overall adequacy
of the upgraded procedures because many selected procedures had yet to be
rewritten or were in draft form at the time of the inspection. Delays in
procedure revisions were attributable primarily to incomplete modification
work. However, the inspection team reviewed in detail Operating Procedure
A.51, "Auxilidry Feedwater System," Revision 31 and draft Revision 32, and
noted the following weaknesses:
(1) The AFW pump P-318 turbine overspeed alarm on the Interim Data Acquisition
Display System (IDADS) in the control room was not listed in either the
current or draft procedure A.51 as an indication of turbine overspeed.
(2) The AFW System Status Report (SSR), Revision 1, identified AFW pump motor
stort time limitation inconsistencies among A.51, Surveillance Procedure
SP 210.01, and the vendor technical manual. The team also found the AFW
system training manual guidance to be inconsistent. Discussions with
licensee personnel revealed that the licensee had contacted the vendor,
but could not resolve the issue because of a lack of sufficient information
from the vendor.
The adequacy of revised plant operating procedu m s, as well as the specific
Wedknesses noted above for A.51, will remain open pending followup by the NRC
(50-312/86-41-33). .
3.5.3 AFW Pump Runou*
The alarm indication used for a runoet condition of the AFW pumps provided
ambiguous information. Runout is a high flow, low pressure condition that
can lead to ext.essive vibration and pump degradation. The runout alarm, as
installed, will actuate on low discharge pressure only. During pump startup
3-28
.
- _
-
, .
when pressure is low, the alarm was intended to be bypassed with a time delay
until the pump reaches rated speed [Section 3.2.2(6)]. The annunciator
response procedure for the runout alarm instructed the operator to throttle
back on AFW flow on receiving this alarm without checking other indicaticns.
The inspection team was concerned that a condition could exist that the runout
alarm could be received if the AFW pumps failed to come up to rated speed
thereby indicating low discharge pressure but not pump runout. In this case,
the operator may take inappropriate corrective action by throttling back AFW
flow. The lack'of precise inoication of pump runout without having compensatory
procedural guidance and training will remain open pending followup by the NRC
(50-312/86-41-34).
3.5.4 Licensed Operator Training
The review of the licensee's restart licensed operator training program
focused primarily on training for the systems being modified; training on
priority-one operating, casualty, and emergency operating procedures (EOPs);
simulator training; and other training commitments identified in the Rancho
Seco Action Plan for Performance Improvement. In general, the team found that
there were sufficient training mechanisms in place to support the operations
department preparation for startup. The team was unable to evaluate the
implementation effectiveness of this training program, because: training on
revised AFW operating procedures and E0Ps had not been accomplished; no
simulator training had been performed; and not all of the modifications
training had been completed. During the inspection, the team developed two
Concerns.
(1) System training manuals have been in distribution throughout the plant-for
past several years. These manuals were not controlled, nor were they
maintained current by the training department. As a result, these manuals
did not, in many cases, reflect the as-built condition of the plant. Since
initial distribution, significant modifications to plant systems have
altered system configuration and operating parameters in many instances,
as evidenced by the recent modifications to the AFW and instrument air
systems. Even though much information in these manuals is no longer
dccurate, the inspection team noted that licensed operators, plant
engineers, and other site personnel routinely refer to them. The team
Wds Concerned that incorrect information obtained from these manuals
may guide plant personnel to erroneous conclusions or actions. At the
exit meeting the licensee indicated that the policy regarding the use of
these training manuals would be reviewed and appropriate action taken.
(2) The training department has established a program to ensure that operations
personnel receive the appropriate level of training on the large number of
operations department procedures that are being written or revised. In l
general, procedures that are undergoing minor revisions will be placed
into the Operator Reading Assignment Program, and new procedures or
procedures undergoing major revisions will either be placed into the
classroom training cycle or be " walked through" in the plant or at the
simulator. After reviewing the licensee's tentative list of procedures
j that require classroom training, the team noted that the following procedures
were undergoing major revisions but were not intended to be included in
the classroom training cycle:
3-29
<
_ _ . _ . _ , . _ . . -
. - . - -
' . ;
,
.
A.58 "4.16 KV Electrical System," Revision 9
' A.59 "480 V Electrical System," Revision 22
A.61 "125 Volt DC System," Revision 8
A.62 "120 Volt AC System," Revision 9
4 A.73 " Reactor Non-Nuclear Instrument System," Revision 9
B.4 " Plant Shutdown and Cooldown," Revision 41
C.110 " Loss of 480 V Bus 3A1," Revision 2
C.112 " Loss of 480 V Bus 382," Revision 2
C.143 " Loss of 480V MCC S2El," Revision 6
The team was concerned that these procedure revisions may be too complex
to be adequately addressed by the Operator Reading Assignment Program.
The resolution of the training concerns discussed above will remain open pending
followup by the NRC (50-312/86-41-35).
,
3.6 Maintenance
.
l The inspection team reviewed the revised maintenance procedures and related
documentation for both preventive and corrective maintenance for the eight
! selected systems. The licensee's efforts for enhancing the reliability of
safety-related equipment for the selected systems were also reviewed, with
3
particular emphasis on the motor operated valve (MOV) refurbishment program.
4
3.6.1 Motor Operated Valve Overhaul and Refurbishment Program
i
The licensee has identified significant design and maintenance problems during
MOV refurbishment and testing. The team focused on the results to date on the
- MOVs that are subject to the requirements of IE Bulletin 85-03, " Motor Operated
Valve Common Mode Failures During Plant Transients Due to Improper Switch
, Settings." The team considered the licensee's effort in this area to be note-
worthy. The scope of the original program has been expanded well beyond the
bulletin requirements to encompass all plant MOVs, a total of 173 valves.
However, the team was concerned with the nature of the licensee's M0V overhaul
dnd refurbj5hment fincings.
(1) As of January 13, 1987, 15 out of 20 valves subject to IE Bulletin 85-03
had faileo testing because of under/overthrusting conditions. An over-
thrust condition was defined as exceeding the allowable limits for the
valve or operator in either the open or closed direction. Within the valve
operator, individual limits could also be exceeded for the motor or spring
pack. Overall, 38 out of 69 MOVs tested failed to meet the design thrust
values. The licensee considered any MOV assembly that exceeded the valve
or operator limits to be inoperable as outlined in Sacramento Municipal
Utility District (SMUD) letter JEW 86-667 issued in October 1986. Final
resolution of the MOV thrusting issue may require MOV spring pack replace-
ment, different operator gearing, complete MOV assembly replacement, or
, valve replacement. Each failed MOV must be handled on a case-by-case basis
i because of the unique variables in its plant application. In the interim,
l M0V. assemblies that have been categorized as underthrusting have had the
torque switch set at the highest possible setting, pending final resolution.
Conversely, MOV assemblies classified as overthrusting have had the torque
switch set at the lowest value.
1
1
3-30
f
- - - , , , - -r- - , . - , -m. -,,- ~ , - - - - - - - - - -, ..m. -~w - --w-- , - - - , - - - - ,
- .- -- . - -- -_ - - - .
!
.
l b
(2) During testing the licensee identified four DC powered MOVs, including
FV-30801 (steam admission valve to P-318), with undersized electrical
cabling. These MOVs had been converted from ac power to de power during
this outage by ECN A 5415U. However, because of apparent inadequate-design
review, the electrical cabling from the motor control center to the MOV
.
l'
motor was not evaluated for postulated accident conditions at minimum
available voltage.
>
Following the conclusion of the onsite inspection, the licensee documented the i
MOV operability problems that have resulted from the expanded MOV refurbishment
and overhaul program in Licensee Event Report (LER)87-006, dated February 17,
1987.
3.6.2 Maintenance Procedures
The inspection team reviewed the following technical procedures for repair of
plant equipment:
i
l
EM.117, "Limitorque Maintenance," Revision 8
EM.117A, " Testing of Limitorque Motor Operated Valves Using M0 VATS "
,
Revision 1
- M.103, " Valve Inspection and Maintenance," Revision 1
4 M.22, " Auxiliary Feed Pumps and Turbine," Revision 4
M.114 " Maintenance Cleanliness Control," Revision 6
' M.115, "Limitorque Valve Actuator SMB00, and SMB000 Corrective
Maintenance Procedure," Original and Revision 1
,
M.116, "Limitorque Valve Actuator SMB-0, SMB-1, 2, 3, 4 Corrective
Maintenance Procedure," Original
] " Control of Mechanical Measuring Devices," Revision 2
! MT.013,
In general, the procedures appeared to be technically adequate. However, the
'
following two weaknesses were noted:
(1) MOVs with a relatively fast stroke time use a motor brake to overcome
- stem inertid after the valve has been stroked, thus preventing the valve
disc from becoming wedged in the main seat or on the back seat. However,
no preventive maintenance procedures or requirements had been established
to periodically inspect the brake rotating friction disc for excessive
wear. The brake vendor, Dings Company, specified a rotating friction
,
disc thickness of 0.180 to 0.190 inch. During the inspection, the licensee
'
revised their M0V corrective maintenance procedures to include preventive
maintenance activities for the brakes. However, Procedure M.115
"Limitorque Valve Actuator SMB 00, and SMB 000 Refurbishment and Corrective
'
Maintenance Procedures," Revision 1, stated that the rotating friction
disc should be replaced if the disc was not 0.080 to 0.190 inch thick.
Additionally, M.115 did not include or reference Vendor Instruction
Bulletin Number 4603 that specified rotating friction disk replacement
criteria of one-sixteenth inch total wear. Failure of the motor brake
i could result in jamming the valve disc in its seat, thus preventing further
i valve manipulation.
1 (2) Specific maintenance procedures applicable to safety-related air-operated
t
valves (e.g., FV-20527, FV-20528, FV-20575, and FV-20576) had not been
ceveloped. The adequacy of air-operated valve maintenance procedures was
of particular interest to the inspection team in light of the December 26,
3-31
.
=g-y. e-w- mi -ww<=.----- --r----x- - , - . - -=--rt-" -w "MP-*B'"+" 4 - + " - ' " *
. ;
1985 overcooling event. During that event, the manual operator for the
A AFW (ICS) air-operated flow control valve (FV-20527) failed, in part,
because the hanawheel was improperly mounted.
The weaknesses noted with corrective maintenance procedure M.115 and the lock
of maintenance proceaures for air-operated valves will remain an unresolved
item pending followup by the NRC (50-312/86-41-36).
3.6.3 Mainte. nance Program Administration
The team reviewed the licensee's program for administrative control of
preventive and corrective maintenance. This review included maintenance
schedules, documentation of work accomplished, equipment history, and trending
of equipment maintenance. The following procedures were reviewed:
AP.3, " Work Requests," Revision 35
AP.33, " Calibration and Control of Test Equipment," Revision
AP.42, " Maintenance Information Management System," Revision 5
AP.46, " Nuclear Operations Technical Manual Control Procedure,"
Revision 3
AP.51, " Maintenance Instructions " Original
AP.301, " Maintenance Procedure Description and Format," Revision 3
AP.650, " Preventive Maintenance Program," Revision 5
AP 700, " Nuclear Operations Training Program," Revision 4
These procedures were found to be generally adequate and were considered to
provide effective overall administrative controls for plant maintenance. The
team reviewed the implementation of these procedures on approximately 90 work
requests and identifieo the following concerns:
(1) Trending analysis, as described in paragraph 5.7.2 of AP.650, had not
been implemt.nted. AP.650 required that trend analysis generally consist
of a graphic display of parameter (s) plotted versus time to provide a
visual image of any rapid change or a slow gradual trend that may occur.
The licensee's current program for trending Preventive Maintenance Program
data information consisted only of a record of maintenonce measurement
data in columnar format. The licensee stated that implementation of the
trend analysis program, as defined by AP.650, had been postponed until
new computer software was obtained. At the time of this inspection, no
firm commitment date for software acquisition had been established.
Implementation of the trend analysis program will remain an open item
pending followup inspection (50-312/86-41-37).
(2) Equipment history, as described in paragraph 5.7.1 of AP.650 and AP.42,
" Maintenance Information Management System (MIMS)," was divided between
two separate files; preventive maintenance (PM) records and corrective
maintenonce records. Completed PM work requests were entered in MIMS and
functioned as part of the equipment history file. Selected information
from completed corrective maintenance work requests was also entered into
MIMS. The team reviewed the equipnent history files for 12 selected
safety-related components and found the information to be minimally
acceptable. For example, FV-30801 (steam admission valve to the
turbine-driven AFW pump P-318) equipment history contained no information
on corrective or preventive maintenance since 1977. The team was concerned
that recurring equipment problems over a period of a few years that would
3-32
_ _ _ - ._ _ _ _ _ _ _ _ _ . _ _ _ . . __.
s ..
be indicative of an undesirable trend or generic component deficiency could
,
go undetected if the equipment history files were incomplete.
AP.650, paragraph 5.3.2, described the criteria for PM selection and
, frequency, including equipment. history reviews. During the inspection
period, the licensee was in the process of revalidating the basis for
preventive maintenance, particularly vendor recommendations. For example,
the mechanical maintenance department was reviewing all controlled vendor
mdnuals and equipment histories to ensure that the scope of the PM program
was adequate. The team felt that this was a comprehensive and sound
! approach for validating the PM basis; however, a review of existing
equipment history records would provide only limited information
concerning recurring equipment failures. Because the equipment history
a records did not reflect the full spectrum of maintenance activities cver
the life of the plant, the benefits of a comprehensive records review
in revalidating preventive maintenance requirements were diminished.
Interviews with licensee management revealed that they were aware of the
problem and had initiated maintenance technician lectures on the importance
of equipment history and information required for work requests.
(3) The responsibility for determining adequate post maintenance testing was
not clearly established by AP.650 for PM work requests. Revision 35 to
AP.3, " Work Requests," assigned the responsibility for determining adequate
i post maintenance testing to the planning department for corrective
maintenance work requests. Prior to this procedure revision, responsi-
] bility for post maintenance testing rested principally with the maintenance
,
foreman. During the inspection peroid the licensee was developing a
detailed procedure for use by planning department retest engineers for
ensuring adequate post maintenance testing for all maintenance activities. -
3.7 Quality Programs
The inspection of quality programs included a review of quality assurance (QA)
audits, QA surveillances, and corrective action programs. The following Quality
Control Instructions (QCI), Administrative Procedures (AP) and Quality Assurance
Implementing Procedures (QAIP) were reviewed during this inspection:
'
QCI No. 1, " Processing of Nonconforming Reports - NCR," Revision 5
l QCI No. 2, "SMUD Nuclear Operations Quality Assurance Audit Program,"
Revision 2
QCI No. 5. " Safety Review of Proposed Facility Changes," Revision 2
QCI No. 16, " Trend Analysis Program," Draft
AP 22, " Occurrence Description Reports (0DRs) Reporting and Resolution,"
Revision 12 ,
,
QAIP No.1, " Quality Assurance Audit Procedure," Revision 6
- QAIP No. 2, " Quality Assurance Surveillance Procedure," Revision 6
i QAIP No. 6 " Surveillance Oriented QA Surveillance Program (500AP),"
Revision 3
'
3-33
l
1
- -. . _ - - - . _
-.- _ . - .
.,- . - _ . - . -- . _
- - - .._
. <
The licensee was making significant improvements in the various quality programs,
including major revisions to QA procedures, staff restructuring, and an increase
in QA staff size. However, significant deficiencies were identified with the
Operations QA Program because the planning improvements were not implemented ,
at the time of the inspection. These improvements were delayed as a result of )
QA involvement with the SRTP process and, consequently, the program at the time '
of the inspection was not ready to support an operating plant.
3.7.1 QA Audit Program
An independent audit of the QA program, performed in November 1986 by a
contractor to the licensee, identified significant problems regarding missed
audits, insufficient auditor training, inadequate corrective actions, and
inconsistent application of the audit process within the SMUD organization.
Corrective actions were in progress for these audit findings and were scheduled
to be implemented prior to restart. The team had the following additional
observations about the audit program-
(1) The licensee's QA audit tracking program provided the status of all
required audits and identified that several audits had exceeded their
periodicities as identified in procedure QCI-2 and that some audit reports
were not issued until four months after audit completion. Interviews
with audit personnel revealed that these delays were due to the large
SRTP effort and the changing audit report formats being implemented at
the time of the inspection.
(2) The licensee was developing a more technical approach toward auditing.
These audits were termed " vertical audits" and were intended to be
performed by a team that would review all the applicable QA programmatic
aspects associated with a safety system. Four of these " vertical audits"
were scheduled to be conducted prior to startup to provide additional
assurance that plant safety systems were ready to support operation. The
licensee provided the NRC inspection team a draft outline of the audit
scope and objectives. On the basis of the outline, the team determined
that the audit method appeared to be innovative and capable of having a
positive effect on safety.
(3) In some cases, corrective actions associated with past audits appeared to
be ineffective. Audit findings were considered closed when an adequate
response was received that represented a commitment by the audited
organization to correct the problem. The audited organization was not
held accountable for implementing the action. Further, these responses
were often late and did not provide a schedule for implementing the
corrective actions. The commitments were tracked as open items and
received QA followup but no action was taken to ensure that the audited
organization was correcting identified problems. At the time of the
inspection, the QA followup list ,1dentified valid audit findings from
1982 that had not been corrected.
(4) The Management Safety Review Comittee reviewed the audit reports when
published and the audit report cover page after audit findings were closed
by QA. This cover page referenced the correspondence that documented
finding closure but did not summarize what was done to correct the finding.
Audit findings of ten were not closed for several months and, without
further information or supporting documentation for reference, this method
3-34
4
-- - - ,-
- ._ - - - -
b .
of closecut review seemed superficial. At the time of the inspection, the
licensee was in the process of revising their reporting format, tracking
mechanism, and closecut requirements for audit findings, which may improve
this process.
The deficiencies in the QA audit program will remain open pending followup
by the NRC (50-312/86-41-38).
3.7.2 QA Sur'veillance Program
The QA surveillence program was intended to complement the QA audit program
by providing a review of on-going plant activities. However, the team
identified the following deficiencies with the QA surveillance program
procedures and implementation which appeared to detract from this purpose:
(1) Procedure QAIP No. 6 did not require or suggest the use of a checklist
to perform QA surveillance activities. Consequently there was no
inaication that a checklist was used for any of the approximately 30
surveillance reports reviewed during this inspection.
(2) The corrective action mechanism normally used to resolve QA surveillance
findings was considered weak. A review of approximately 30 QA surveillance
.
reports revealed that most of the deficiencies identified were classified
only for QA follow-up activities. As a result, the responsible plant
'
organization was not held accountable and the action taken to correct
the deficiency end to prevent recurrence was not documented. As an
example, QA Surveillance Report 491, conducted in October 1985, identified
several errors on a piping & instrument diagram (P&ID) M-580, " Main Lube
011." This drawing showed components that did not exist in the system
and other components actually installed in the system were not shown.
A note on this surveillance report indicated that QA wculd followup on
these ceficiencies. At the time of this inspection, these deficiencies
were not corrected even though this P&ID was revised in October 1986
and surveillance report 491 was signed off as closed. This issue was still
being carried in the MFW SSR as Problem 22.
(3) ho evidence was found of trending the issues generated from these
surveillonces. Interviews with QA management personnel revealed that
there was no working file of completed surveillance reports available l
in the QA offices, thus making it difficult for licensee managenent to i
review previous reports. l
The licensee statea that the QA surveillance program was being revised to
incorporate these issues. This item will be held open pending followup by
the NRC (50-312/86-41-39).
3.7.3 Corrective Action Program
In addition to the corrective action deficiencies regarding QA audits and
surveillances previously discussed in Sections 3.7.1 and 3.7.2, the following
additional weaknesses were noted in the licensee's corrective action program:
(1) The licensee did not appear to have a mechanism to uniformly ensure that
significant conditions adverse to quality would be reported to the appro-
priate level of management. This oppears to be contrary to 10 CFR 50,
3-35
_ . - . _ .
.. ___
- - - - - - -. - - _.
. 4
Appendix B, Criterion XVI. In some cases, such as reportable events, the
Occurrence Description Report process would escalate management attention
to meet reportability requirements. However, there did not appear to be
any systematic method to identify from all sources problems that could be
considered significant conditions adverse to quality. At the time of the
- inspection, the licensee had issued a draft procedure for review which
dddresSed this problem.
- (2) The licensee's trending program did not attempt to relate deficiencies to
The QA Department issued a monthly "NUMARC Trend Report,"
'
a coninon cause.
which looked at performance indicators, but did not analyze for the root
causes underlying the observed deficiencies or identify similar findings 1
from different sources. An example of this lack of trending and inadequate
corrective actions was that, since 1984, two QA Audit Reports (0-733 and
0-812), four QA Surveillance Reports (163,165,163A and 491), and the
LRS management report of November 1984 have identified problems with the
control of drawings at the station. However, the inspection team still
found significant problems with the drawing control program during this
inspection (see Section 3.3.3).
(3) The teani was concerned about the licensee's re' ponse s to NRC inspection
report findings. At the time of the inspection there were nearly 300
<
open or unresolved items that were in the process of being closed out by
i the licensee, some of which were over 2 years old. Additionally, NRC I
inspection report 50-312/85-23 identified significant problems with the
in-service test program at Rancho Seco in May 1985. The inspection team
identified similar problems with different systems during this inspection
- (see Section 3.4).
, The inspection team concluded that the corrective action programs at Rancho
i Secu had not been managed effectively in the past and that adequate management
j attention was still not being applied to this area at the time of the inspection.
! The lock of effectiveness of the licensee's corrective action program will
remain open pending followup by the NRC (50-312/86-41-40).
4
3.8 Restart Organization and Management
The inspection team evaluated the licensee's existing restart implementation
orgariization and the planning and progress toward achieving the nuclear
organization which will exist at restart. The focus of the inspection was on
the followup of previously identified management problems, the planning and
mdnagensent processes initiated to accomplish required actions related to
restart, and management programs designed to change previous practices at
Rancho Seco.
.
!
3.8.1 Plant Performance and Management Improvement Program
'
'
The inspection team evaluated the Plant Performance and Management Improvement
Program (PP&MIP) to determine its overall integrity, completeness of input, and
consistency of operation. The PP&MIP was implemented by means of Rancho Seco-
Quality Control Instruction 12 (QCI-12) which set forth a phased approach
to performance improvement and restart of the Rancho Seco plant and controlled
,
the major steps in the process: investigation, validation, approval, implemen-
l tation, and closure. The investigation phase provided for a variety of inputs
- into the QCI-12 process, inclucing NUREG-1195, " Loss of Integrated Control
i
t
j 3-36
,
e,- nnn--,--- - - - - w e,- c--. .- , ,-, ,~,----n-w- -- --~a n, e , -- . - - ~ --n w--- -+e----, - -~ ,
_ .. __ _- . _ . ___ _ __ . _ _ .- __ __ _
, .
System Power and Overcooling Transient at Rancho Seco on December 26, 1985,"
- the B&W Owners Group Safety and Performance Improvement Program (SPIP), staff
'
interviews, and systems engineer recommendations and other relevant sources.
During the validation phase, each valid restart item was assigned a priority and
was included in an appropriate System Status Report (SSR). In the approval phase,
i
a management-level board, the Performance Analysis Group, reviewed each item
i in each SSR and assigned action to ensure implementation, testing and closure.
i The end product of the QCI-12 process is the restart System Review and Test
Program (SRTP) which is intended to verify, with emphasis on system test, that-
the actions taken will be sufficient for the Rancho Seco plant to return to
i safe operation.
'
As a result of this review, the team identified three areas of concern regarding
the PP&MIP:
(1) Existing open items from the LRS Management Appraisal Report were not
included in the PP&MIP and the 001-12 process. This report, issued in
!
November 1984, represents a comprehensive management appraisal of SMUD
! and the nucleer organization at Rancho Seco by LRS Consultants, a
i licensee contractor. The LRS Report was specifically identified as
d required input to the PP&MIP on Page 1-8 of the " Rancho Seco Action
Plan for Performance Improvement," Amendment II. This item was discussed
l
with licensee management who agreed to review the open recommendations
! in the LRS Report for possible inclusion into the PP&MIP. This will
remain an open item pending followup by the NRC (50-312/86-41-41).
I
I (2) Although the problem identification phase of the QCI-12 process seemed
j to be generally adequate and apparently functioned with integrity, i
weaknesses were uncovered in the validation and approval phases. As
j discussed in Sections 3.1, 3.2, and 3.3 of this report, the team
identified several examples of a lack of engineering and operating detail ,
! and depth in the QCI-12 review of selected safety systems. At the exit t
j meeting on February 12, 1987, the licensee was informed that, as a result
'
of the apparent weaknesses relating to operating and engineering depth and
l
oetail, additional measures to revalidate the adequacy of those reviews i
l would be appropriate. The licensee shared the same concern and agreed to '
i assess the need for further action. This item will remain open pending
i followup by the NRC (50-312/86-41-42). ,
I
l (3) The SSRs did not appear to be properly controlled considering their use
j as a basis for the NRC Safety Evaluation Report (SER) for restart
i authorization. At the beginning of the inspection, the licensee's '
practices allowed changes to the SSRs after their review by the NRC
- without notifying the NRC. The team considered the SSRs to be commitments
j to the NRC for problem resolution and testing once they were reviewed,
4
and, therefore, any subsequent changes to the SSRs should be controlled.
d
During the inspection, the licensee developed a process for controlling I
! the SSRs and keeping the NRC informed of all changes. This item will
l
remain open pending NRC review of the final procedures implementing the
SSR_ control process (50-312/86-41-43).
1
1
3.8.2 Restart Priority Review Team
The efforts of the QCI-12 Priority Review Team (PRT) were reviewed as part of
the assessment of the integrity of the QCI-12 process. The PRT wcs chartered
i 3-37
i
>
--
. ;
by the Restart Implementation Manager (RIM) to review the engineering-related
Priority 1 items. The PRT was composed of operators who considered each item
in the strict context of the QCI-12 priority criteria. They reviewed 205
Priority 1 items; of these, 92 were found to meet the criteria for Priority 1,
44 for Priority 2, and 35 for Priority 3. Additionally, 34 items were
determined not to meet the criteria for Priority 1, 2, or 3. These findings
were forwarded to the Performance Analysis Group (PAG) with a recommendation
to effect the priority changes. Of the Priority 1 items recommended for
downgrading, the PAG accepted the recommendation of the PRT in 61 cases, but
retained the original priority in 47 cases. The PRT effort represented an
attempt to reduce the number of engineering changes and modifications required
for restart from an operations point of view. The team considered that the
hesitancy of the PAG to concur in all cases was an indication of the integrity
of the QCI-12 process.
3.8.3 "Make It Happen" Program
The team evaluated the "Make It Happen" Program by means of interviews and
document review to determine program content and planning status as it related
to the restart effort. This program was attempting to effect a shift in Rancho
Seco " culture" from one of non-commitment and failure toward one of success and
commitment to a safe and successful startup. The program was intended to
contribute to higher productivity, quality, niorale, and safety by means of
employee and management training, individual coaching, and employee involvement.
Team interviews and document review revealed the following:
1
(1) The program was based upon similar successful attempts to change culture
and behavior in other organizations.
(2) The individuals responsible for the program at the working level had the
appropriate background, training, and experience.
(3) The program had the backing and involvement of plant management up to the
highest level, including the Deputy General Manager.
The team considered that the concept and planning for the "Make It Happen"
Progrcm were satisfactory but that it was too early to judge its progress or
its effectiveness.
3.8.4 Restart Organization and Transition Planning
The team evaluated the existing restart implementation organization and the
progress and planning toward putting a final SMUD nuclear organization in
place. The team was not confident that the planning and progress of the
transition supported the scheduled restart date. The goal was to have this
final organization approved, in place, and manned by May 1987. This goal
appeared unrealistic to the team for the following reasons:
l
'
(1) The existing restart implementation organization contained significant
vacancies. Of seven key management positions, two (Quality Assurance and
Licensing) were not filled by SMUD employees as the principal or deputy.
This seemed to undermine the concept that SMUD managers would understudy
l
l 3-38
l
. _
._
. - - -- -_.
i .
experienced contractor personnel as the principal or deputy during restart
implementation. The licensee expected that these positions would be filled
l by April 1, 1987.
(2) Implementation of the final nuclear organization has been delayed. The
transition schedule indicated that this organization would be in place by
February 1,1987. The licensee anticipated that it would be in effect on
April 1,1987.
(3) There appeared to be no detailed plan for replacing contractor personnel l
with SMUD employees. The utility made extensive use of contract personnel
in areas critical to restart and the team was concerned that, as the
transition from contractor personnel to utility personnel occurred, system
technical intricacies may be overlooked. Due to the extensive contractor
presence at the site, the average tenure of the systems engineers, design
engineers and QA personnel was comparatively short. This in itself is
not a problem provided turnover of duties is sufficiently detailed and
thorough. The team was particularly concerned that system engineers were
less knowledgeable about their assigned systems than what has been
observed at other utilities. Because these personnel have significant
responsibilities for coordinating the SRTP and modification activities
' for restart, they should be trained and knowledgeable on system design
and testing issues.
(4) The team developed a concern about the current level of at-power operating
experience held by many of the licensed operators. A review of licensed
operator staffing revealed that opproximately 50 percent of the licensed
operators had less than one year of at-power operations experience, and ;
that the current class of licensed operator trainees has never seen the
plant at power during their training program. The team was concerned that
additional experience may be necessary to staff all of the shifts during
the return tu power and subsequent at-power operations, but could not
assess this at the time of the inspection because much of the restart
training, particularly simulator training, had not been accomplished.
After the exit meeting, the licensee provided the team with information
.
regardi.1g their Operations Advisor Program. This program will provide
experienced contractor personnel, all of whom previously held senior
reactor operator licenses on B&W commercial nuclear power plants, as
on shift advisors. If effectively implemen'.ed, this program would mitig6te
the inspection team's concerns regarding the experience level of licensed
operators.
i In the opinion of the team, the factors above complicate the licensee's efforts
to have a complete and mature management team in place by the scheduled restart
dote. The capability of the SMUD nuclear organization to support the schedule
,
restart date will remain an open item pending followup by the NRC
(50-312/86-41-44).
4
,
4
'
3-39
!
l
. . _ - - - . = - , - - - - . - - . . _ _ - - . _ _ . _ . . . _ _ - - _ __ . - - _ - - _ - - - - . _ _ . - _
- - - - . _ _ . _ _ _ _ ,, N--_m _ ----N-__,____
e
I
t
I
_ _
l
l
\ .
4. UNRESOLVED ITEMS l
'
Unresolved items are matters about which more information is required in order
to ascertain whether they are acceptable items, violations, or deviations.
Unresolved items identified during this inspection are discussed in detail l
in Section 3 and summarized below:
Item No. Subject Section
86-41-06 Instrument Air System Modifications 3.1.2
86-41-09 EFIC System 10 CFR 50.59 Analysis 3.1.4(2)
86-41-15 Condensate Storage Tank Overpressure and 3.2.1(2)
Underpressure Protection
86-41-16 DC Circuit Breaker Sizing Calculation 3.2.2(1)
'
86-41-17 Battery Sizing Calculations 3.2.2(2)
86-41-19 AC Circuit Breaker Sizing Calculation 3.2.2(4)
86-41-20 Underrated DC Cables 3.2.2(5)
86-41-21 IDADS Computer Alarm Modifications 3.2.2(6)
86-41-24 Plant Drawing Contrul 3.3.3
86-41-25 Design Calculations 3.3.4
86-41-26 IST Program Approval 3.4.1(1)
86-41-27 Surveillance and Inservice Test Data Trending 3.4.1(2)
86-41-28 AFW Pump Capacity Tests 3.4.2(1)
86-41-30 AFW Surveillance Test Prucedures 3.4.2(3)
'
86-41-31 DC System Surveillance Testing 3.4.4
,
86-41-32 Administrative Control of Plant Systems 3.5.1
E6-41-30 Corrective Maintenance Procedures 3.6.2
!
'
.
4-1
1
I e
5. MANAGEMENT EXIT MEETING
The inspection team leader and selected inspectors conducted an interim exit
with licensee management on January 15, 1987 to provide a summary of issues
,
identified during the first onsite inspection period. A final exit meeting
was conducted at the conclusion of the onsite inspection on February 12, 1987
at the Rancho Seco Nuclear Generating Station. The licensee's representatives
at this final exit meeting are identified in Appendix A. Mr. B. Faulkenberry,
Deputy Regional Administrator, Region V, represented NRC management at this
meeting. The scope of the inspection was discusseo and the licensee was
informed that the inspection would continue with further in-office data review
and analysis by team members. The licensee was informed that some of the
'
.
observations could become potential enforcenent findings. The observations
were presented for each area inspected, and team members responded to questions
from the licensee's representatives.
5-1
J
-
e _ __ _
\ '
.
'
APPENDIX A
.
PERSONS CONTACTED
The following is a list of persons contacted during this inspection. There
were other technical and administrative personnel who also were contacted.
All personnel listed are SMUD employees.
P. Anderson - Electrical Maintenance Engineer
+D. Army -
Manager, Maintenance
G. Aron - Systems Engineer, Auxiliary Systems
+*R. Ashley - Manager, Licensing
S. Bagga - I&C Engineer
M. Basu - Electrical Group Leader
+S. Batch - Testing Coordinator
B. Beebe - NSS Principal I&C Engineer
T. Beeves - I&C Engineer
l. J. Briskin -
Staff Assistant
A. Brown - Superintendent, I&C Maintenance .
- J. Bufis - Assistant Director, Systems Review and Test Program
R. Columbo - Operations Supervisor
D. Compton - Licensing Engineer
- B. Conklin - Lead Engineer, Steam Plant Systems Review and Test Program
+*G. Cranston - Manager, Nuclear Engineering
- B. Croley - Plant Manager (incoming)
R. Crosby - Management Specialist
R. Daniels - Supervisor, Electrical Engineering
+*J. Field - Director, Systems Review and Test Program
L. Fossum -
Deputy Manager, Implementation
+F. Gowers - Deputy Manager, Training
'
J. Hayes - Electrical Engineer
M. Heronimous - Operations Shift Supervisor
J. Irwin -
I&C Maintenance
S. Jacobs - Electrical Engineer
- J. Janus - Staff Assistant
P. Johnson - Plant Utilities Principal I&C Engineer
T. Khan - Supervisor, Mechanical Systems i
+F. Kellie - Superintendent, Radiological Protection
- J. King - Systems Engineer, Steam Plant
+S. Knight - Manager, Quality Assurance
+J. Lingenfelte- - Assistant Director, Systems Review and Test Program
C. Linkhart - Superintendent, Electrical Maintenance
C. Linquist - I&C Maintenance Supervisor
+J. McColligan - Inspection Coordinator
D. McGrath - Mechanical Maintenance
D. Micherone - Electrical Engineer
S. Miller - Deputy Supervising Electrical Engineer
R. Nakao - Licensing Engineer
R. Pate - I&C Engineer
+*K. Perkins - Restart Implementation Manager
- D. Poole - Nuclear Plant Manager (outgoing)
<
M. Price - Superintendent, Mechanical Maintenance
A-1
4
, - . n -- . . , - _ _ . -
c ,_ , .-.-,y_., ,._, r -- . , - , ., .
- l
- J. Rockley - Assistant Test Director, Systems Review and Test Program
S. Redeker - Manager, Operations Department .
T. Robertson - Plant Modifications Manager
G. Roy - Staff Assistant
F. Sheehan - Electrical Group Leader
+J. Shetler - Manager, Implementation
+S. Siebenaler - Systems Engineer, Steam Plant
T. Singh - Electrical Group Leader
- E. Stockman - Systems Engineer, 4160 Vac
N. Thibodaux - Surveillance Specialist
F. Thompson - Supervisor, Technical Training
D. Tipton - Superintendent, Project / Procedure Operations
A. Tuduty - Management Specialist
P. Turner - Manager, Training
+J. Vinquist - Executive Assistant
+*J. Ward - Deputy General Manager, Nuclear
R. Weber - Management Assistant
J. Wheeler - Senior Electrical Maintenance Engineer
- L. Wittrup - Systems Engineer, EFIC
J. Zott - Fire Protection Principal Engineer
.
\
- Personnel attending January 15, 1987 exit meeting.
+ Personnel attending February 12, 1987 exit meeting.
A-2
l
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. _ - - . _ _ . - . . . , - . ., - -- , - , . - . . - - . .
t ' .
APPENDIX B
.
SYSTEMS DESIGN DOCUMENTS REVIEWED
GENERAL ARRANGEMENT DRAWINGS
DRAWING NO. TITLE REVISION
E6.02.1A-41 P.C.B. Internals 0
E7.01-9-51 Plan Arrangement 480V Bus Duct --
ONE LINE DIAGRAMS
DRAWING NO. TITLE REVISION
SK-E132-2 125 VDC and 120 VAC Distribution System N/A
E-108, 120 VAC System Panels 7
Sheet 12
E-107, 125V DC System Panels 4
Sheet 2
E-105, One Line Diagram
Sheet 1 480 Volt System 7
" " "
"
2 7
" 5
36 480 L.C. SWGR S3A2
"
14 460 Volt System 21
"
37 480 L.C. SKGR S3 B2 3
"
8 480 Volt System 26
" " " "
10
8A
" " " "
2
25
" " " "
27 5
" " "
"
31 0
" " "
"
9 24
" " " "
9
9A
" " " "
26 3
" " " " 3
28
" " " "
0
32
E-104, One Line Diagram
Sheet 4 4160 Volt System 6 i
'
" " " "
10
. 1
" " " "
2 9
Sheet 6 4160 Volt Switchgear 54A2 2
Sheet 3 4160 Volt System 11
Sheet 7 4160 Volt Switchgear S4B2 3
B-1
-- ... , . . . -
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. -
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P&I DIAGRAM
REVISION !
DRAWING NO. TITLE
M-552 Htg., Vent., & Air Condition Systems 19
M-532 Steam Generator Svstem 23
M-532 Steam Generator System 6
Sheet 1
M-533 High Pressure Feedwater 8
Sheet 3 System
M-536 Condenser System 24
M-590 Plant Air System 34
Sheet 1
M-590 Plant Air System 2
Sheet 2
M-530 HP& Auxiliary Turbines 0
Sheet 2
M-530 HP& Auxiliary Turbines 1
Sheet 2A
M-532 Steam Generator System 3
Sheet 2
M-532 Steam Generator System 4
Sheet 3
, PIPING, HANGER & ASSEMBLY, AND LINE DIAGRAMS
DRAWING NO. TITLE REVISION
20609-1"-DB Reactor Building-Steam Generator 0
E-205A 6" Level Sensing Nozzle
M-331 Feedwater Line 8
M-334 Feedwater Pipe Support Attachments 4
M-486 Rigid Hanger Assemblies 0
Sheet 5-21
M-486 Under Support Assemblies 3
Sheet 6-3
M-487 Under Support Assemblies 1
Sheet 9-136
M-872 Valve Designation List --
Sheet 1
32133-20"DB Piping Isometric & Supports for 19
632133-30"-DB Valves Plus-500 & Plus 501
32134-20"-DB Piping Isometric 11
Sheet 1
M19.09.5-1 BYT-F Installation Dimensions --
M19.09.6-1 Flow Straightener --
M22.02-8-SI 1/4" to 2" Bolted Bonnet --
'
Sheet 1 Globe Valve Forged
B-2
. _____
.t + .
20610-1"DB Reactor Building Steam Gen. 0
-
E-205A 6" Level Sensing Nozzle
20611-1"-DB GEN. E-205B 0
20612-1"-DB GEN. E-205B 0
20601-1 3/4"-CA GEN. E-205A 0
Sheets 1,2
and 3
20601-1 1/4"-DB. GEN. E-205A 0
20602-3/4-CA GEN. E-205A 0
Sheets 1,2,
and 3
20602-1 1/4"-DB GEN. E-205A 0
20603- 3/4"-CA GEN. E-205A 0
Sheets 1,2
and 3
20603-1 1/4"-DB GEN. E-205A 0
20604- 3/4"-CA GEN. E-205A 0
Sheets 1,2
and 3
20604-1 1/4"-DB GEN. E-205A 0
20605-3/4"-CA GEN. E-205B 0
Sheets 1.E
and 3
20605-1 1/4"-DB GEN. E-205B 0
20606-3/4"-CA GEN. E-2058 0
Sheets 1,2
and 3
'
20606-1 1/4"-DB GEN. E-205B 0
20607-3/4"-CA GEN. E-205B 0
Sheets 1,2
and 3
20608-3/4"-CA GEN. E-205B 0
Sheets 1,2
and 3
20607-1 1/4"-DB GEN. E-2058 0
206C8-1 1/4"-DB GEN. E-205B 0
l
STRUCTURAL STEEL, SUPPORTS AND REINFORCED CONCRETE PLAN DRAWINGS
DRAWING NO. TITLE REVISION
0-275 Reactor Bldg. Area 1 West Partial 8
EL (-) 24'-0"
C-351 Steam Generator Lateral Supports 9
B-3
. - - - -- -
.-
- . . - -
, - i
EQUIPMENT OUTLINE & DETAIL DIAGRAMS
.
DRAWING NO. TITLE REVISION
. N6.03-2 Steam Generator Outline 3
N6.03-3 Longitudinal Section Thru Steam 2
Generator
N6.03.-40 List of Material Steam Generator 2
N6.03-70 . List of Drawings 2
E26.03-10-51
LOAD DESIGN DATA SHEET REVISION
E-1011, Sheet 93 7
VENDOR DRAWINGS
DRAWING N0. TITLE REVISION
5392, Sheet 1 ConSeco DWG Condensate Storage Tank H
PRESSURE INSTRUMENT DATA
SHEET REVISION i
I-1454, Sheet 1 0
I-1454, Sheet 2 0
1-1416, Sheet 1 thru 4 0
PIPING DESIGN SPECIFICATION
M-870, Sheets CA-1, CA-2, DB-1
VALVE ASSEMBLY, OUTLINE DRAWINGS & DETAILS
DRAWING N0. VALVE TAG N0. REVISION
M22.43-1, Sheet 1, HV-20517 & 20518 0
M22.43-2, Sheet 1 HV-20517 & 20518 0
M22.43-3, Sheet 1 HV-20517 & 20518 0
M22.18.1-18 14-11N1 (6") 0
M22.35.2-1 HV-20581 0
HV20582
,
h22.38-6, Sheet 1 FV-20531 0
'
M22.44A-1, Sheet 2 HV-20521 0
HV-20522
N21.01.95 PV-20561 2
PV-20562 A,B,C
PV-20563 -
PV-20564
PV-20566
PV20571A,B C i
1
B-4
- i
,
- -- .- -
.-. . . , . , - , - - --
-s v .
INSTRUMENT INSTALLATION AND ASSEMBLY DETAILS
.
DRAWING NO. TITLE REVISION
I-1192, Instrument Tubing 0
Sheets 1,2 Tray Installation for
I-1193, Main Steam
Sheet 1 Pressure Transmitters 0
OTSG & 'A' & 'B'
PT-20545 B&D and
PT-20546 B&D
Sheet 2 OTSG 'B' 0
PT-20545A, PT-20545C
Sheet 3 OTSG 'B'
PT-20546A, PT-20546C
M19.115B-1 Rosemount Model 1153 6 0
Sheets 1,2, Pressure Transmitters
and 3
M19.115A-12 Pressure Transmitters 0
Isolated Gauge & Diff.
Pres. Switches PG3200
M19.115B-2, Model 353C Conduit Seal 0
Sheet 1
'
I1194, Sheet 3 Safety Cat. Inst. Air Sys. O
I/P Mounting Detail
I-1196 Safety Cat. Inst. Air Sys.
Sheet 4 OTSG 'A' ADVs 0
Sheet 5 OTSG 'B' ADVs 0
Sheet 6 OTSG A&B Reactor Yard Area 0
I-1415,
Sheet 1 "B" Main FW Line 32134-20" 0
" "
2 "A" " " 32133-20" 0
1-1157, Check Valve EFV-250 STSES 0
Sheet 6A
I-1157 Thermal Instrument Enclosure 0
Sheet 7
and 9
'
I-1191, EFIC OTSG E-205A Level 0
Sheet 1 Transmitters 0
M19.115A-7 Press Transmitter 0 1
PD3200, PDH3200 l
B-5
l
__ __-
-. . - - _ _ _ _ _ _ _ _ _ _ _ _ _
. .
i
'
M19.115A-11 Diff. Press. Transmitter 0
PD3200, PDH3200
ANALYSES AND MISCELLANE0US DOCUMENTS
ECCS Analyses .
Energy Feedwater System Upgrade
B&W Document Nc! 77-1125999-01
Singer Model 94020 Shand & JURS
Breather Valve Description Product
Data Sheet 94020
Singer Model 92020 Shand & JURS
Automatic Tank Level Gage Product
Data Sheet 92020
SMUD Nuclear Engineering Procedure NEP 4106
Singer Model 31410 Synchro Tr6nsmitter
Product Data Sneet 31410
Singer Model 92302 Shand & JURS
Liquid Level Indicator Product Data Sheet 92302
Shand & JURS Model 93704 Limit Switch
Assembly Instructions93-704
Singer Model 94210 Shand & JURS
Emergency Vent Product Dat6 Sheet 94210
SALP Report No. 50-312/86-29
MAINTENANCE, SURVEILLANCE, OPERATING PROCEDURES & TESTS
PROCEDURE NO. SUBJECT REVISION
A.62 120 Volt AC Vital System S
A.61 125 Volt DC System 7
AP.167 Electrical Equipment 4
A.58 4160 Volt Operating Procedure 9
A.59 480 Volt Operating Procedure 21
EM.104A Weekly Station Class 1 0
Battery Pilot Cell Test
EN.105A Monthly Station Class 1 0
Battery ICV, Specific
Gravity and Ti;mperature Test
EM.106 Station Battery Test 5
Discharger and Equalize Charger
EM.161 Station Battery Charger Routine 1
1.301 Transmitter Calibration Draft
MT.006 Safety Valve end Relief Valve 2
Setpoint Verification
B-6
'*
$ O
,
SP.210.01A Monthly Turbine / Motor Driven 23
AFP P-318 Surveillance and
Inservice Test
STP.959 Battery BB Performance O
Capacity Test
SP.210.01B Monthly Motor Driven Auxiliary 23
Feed Pump P-319 Surveillance
and Inservice Test
AP.152 Feedwater and Condensate 19
Systems
AP.160 Plant Air System 6
AP.150 Main and Auxiliary Turbine 14
System
A.51 Auxiliary Feedwater System 31
STP.111 Auxiliary Feedwater Header --
Hot Full Flow Test
STP.18 Auxiliary Feedwater System --
Testing
A.51, Sheet 21 Auxiliary Feedwater System Rev. 32
Draft
HZYSB Alarm 9
TEST SPECIFICATION
MODIFICATION NO. ECN NO. REVISION
123 R-0859 0
123 A-5743 0
ELECTRICAL
CALCULATION N0. SUBJECT REVISION DATE
Z-EDS-E0076 Class 1E System Voltage Study 4 1/04/87
Z-EDS-E0111 Derating 250MCM & 350MCM Cable 0 1/30/85
Z-EDS-E0120 Short Circuit Study (AC) 2 12/31/86
Z-VBS-E0523 Load Study for 120V VBS 1 11/05/86
Z-VBS-E0659 Breaker Coordination for VBS 2 1/03/87
Z-DCS-E0544 Voltage Drop in Cables (DCS) 1 12/31/86
Z-DCS-E0600 Battery & Battery Charger Sizing 2 . 1/03/87
Z-DCS-E0612 125 VDC Short Circuit 1 1/02/87
Z-DCS-E0636 Analysis of Existing Batteries 1 1/03/87
Z-DCS-E0678 125 VDC Short Circuit 0 1/04/87
Z-FWS-E0681 M0V Terminal Volts 0 1/04/87
H VAC
CALCULATION NO. SUBJECT REVISION DATE
Z-HVS-M1918 Service Bldg. Battery Cooldown 0 6/16/86
Z-HVS-M1940 NSEB Battery Room Cooldown 0 7/23/86
B-7
. . _. .-. .-
.
o ~ i
MECHANICAL
CALCULATION NO. SUBJECT REVISION DATE
Z-IAS-M2084 ADV Backup Bottled Gas Sizing 0 12/30/86
Z-IAS-M2046 Inst. Air Requirements for 0 10/29/86
ADV's to Cold Shutdown
Z-IAS-M2004 CCW Valves-Backup Air 2 12/30/86
Z-IAS-M2085 T8V'S Backup Bottled Gas 0
Sizing
NA CST Vacuum Breakers Open 1/13/75
and Relief valves
Z-MCM-M1620 Condensate Line Seismic 0 10/15/85
Analysis
Z-FWS-M1742 NOV Stem Nut Thread Strength 0 9/26/85
Z-FWS-M1726 AFW Pump P-318 NPSH 0 8/1/85
Z-FWS-M1798 Condensate Load on Steam 0 1/13/86
Trops
2-FWS-M0253 AFW System Pressure Drop 1 2/1/84
Z-FWS-M0254 AFW System Pressure Drop 0 2/1/84
Z-FWS-M1727 AFW P-318 Impeller Moment 0 8/1/85
Of Inertia Increase
Z-FWS-M0438 High Pressure FW System 2 11/17/86
Z-FWS-M2081 AFW System Min. Head 0 12/23/86
Requirements
Z-FWS-M2045 AFW System Resistance and 0 10/25/86
TDH Requirements
N26.03-5-1 Field Erected Tank Vessel A 3/13/72
Pipe Supports
INSTRUMENTATION & CONTROL
'
CALCULATION NO. SUBJECT REVISION DATE
Z-FWS-10102 Min Flow Required for AFW 1 1/13/87
Z-FWS-10091 Bore Calcs. for AFW Flow 0 3/7/85
Orifice Plates
2-FWS-10123 AFW Flow Orifice DP 0 10/31/86
Z-FWS-10072 AFW Sys. Pressure Drop at 0 10/14/85
Min. Flow
Z-FWS-10052 AFW Flow Element FE-31801 1 9/13/84
M19.09 AFW Flow Element FE-31801 0 9/8/80
7-ZZZ-IO132 Seismic Qual. of Excess 0 1/14/87
Flow Check Valves
Z-PCS-IO111 Computer Input Resistor 0 8/27/86
Sizing
CIVIL
CALCULATION No. SUBJECT REVISION DATE
Z-ZZZ-C0863 Seismic Qual, of Instr. 0 1/14/87
Air Valves
B-8
_
i - .
QUALIFICATION
.
REVIEW RECORD SUBJECT
SQ-001 AFW-CV-FV-20527 & 20528
SYSTEM STATUS REPORT REVISION DATE
Auxiliary Feedwa'ter System 1 11/25/86 l
Emergency Feedwater Initiation and Control System 1 12/5/86 i
Main Feedwater System 1 12/5/86 l
Instrument Air System 1 11/24/86
120 Volt AC Vital Power System 1 12/5/86
125 Volt DC Vital Power System 1 12/5/86
480 Volt AC Distribution 1 12/5/86
4160 Volt AC Distribution 1 12/5/86
SYSTEM DESIGN
BASIS SUBJECT REVISION DATE
5421 Electrical Distribution Open
System (EDS) 480V
5455 Plant Switchgear Open
System (Medium Voltoge)
5482 Vital Bus System (120VAC) Open
5417 Direct Current System (DCS) Open
DESIGN BASIS
REPORT SUBJECT REVISION DATE
ECNA-5415, Rev. 3 Emergency Feedwater 2 11/4/86
Initiation & Control
System (EFIC)
ECNA-3660, Rev. 5 Electrical Distribution 9 12/17/86
System Changes for
NUREG 0737 and NUREG 0696
Requirements
LESIGN GUIDE SyBJECT REVISION DATE
5204.24 Cable Derating Practice Initial 8/7/85
issue
5204.38 Design of DC Power Circuits Initial 8/7/85
issue
5204.40 Application of Battery Initial 8/13/85
Systems in a Nuclear issue
Plant
5204.48 Application of Value Initial 10/15/85
Electric Motor Actuator issue
B-9
- ._ .
. -__
.
, - t
5204.54 Overcurrent Protection Initial 10/15/85 '
Coordination issue
DESIGN CRITERIA SUBJECT REVISION DATE
5104.1 Electrical Systems Design 1 7/24/86
5104.2 Selection and Sizing of 2 11/14/86
'
Power and Control Cables
5104.4 Electrical Motors and Initial 10/15/85
Starters issue
5104.6 Independence of Electric Initial 9/27/85
Systems
ECN # TITLE REVISION
A-5415 Installation of Emergency Feedwater 3
Initiation and Control System
. A-5415A Installation of Steam Generator Level Taps 0
1
A-5415B Installation of Steam Generator Level 2
Instruments
A-5415C Installation of Steam Generator Pressure- 1
Instruments
A-5415D Implementation of FC-3473-03 For NI/RPS
A-5415E Power & Interconnecting Cabling to EFIC 2
and TIE Cabinets
A-5415F Implementation of FC-3478 Rev. 5 for SFAS 1
A-5415J AFW (Upgrade) Valve Modification 2
A-5415K EFIC Internal Modifications 0
'
.
A-5415L Interconnecting Cabling Between EFIC and 0
New Termination Boxes
A-5415M Installation of EFIC Control of AFW P-319 1
and Modification of the Power Supply
For P-319
A-5415N Installation of EFIC Control and Modification 1
of Power Supply of AFW P-318 and Steam
Supply Valve HV-30801
4
ECN # TITLE REVISION
A-5415P Installation of Remote EFIC Control on 0
Shutdown Panel HZSD
A-5415Q Installation of Auxiliary Feedwater Flow 0
and Pumps Discharg Pressure on HISS Panel
A-54155 Installation of Termination Boxes and 0
Interconnecting Cabling Between Termination
BoxesandHISS(E) Console
A-5415T Auxiliary Feedwater Test Valve FV-31855 1
Modification
A-5415V Modification of Power and Control Circuits 1
of AFW Valves SFV-20577 and SFV-20578
A-5415Y Modification of Power and Control Circuits 1
of AFW P-318 and HV-31826 and HV-31827
A-5415W Installation of EFIC ANALOG Control and
Position Indication Loops for AFW FV-20527
and FV-20528
B-10
.-
- - _ - _ - - - . -. - - -
i - o
A-5415X Installation of ANALOG Control and Position 0
. Indication Loops for AFW FV-20531 and FV-20532
A-5415Y EFIC MFW Valve Closure Controls and Change 0
of Block Valve Power Supply
A-5415Z ANALOG Control of ADV From EFIC Cabinets 0
A-5415AA Installation of Power end Controls to AFW 0
HV-20581 and HV-20582
A-5415AB Installation of Motor Operators on Main 0
feedwater Isolation Valves
A-5415AC Installation of Motor Operators on (2) ADV's 0
A-5415AD Installation of Motor Operated Turbine 0
Bypass Isolation Valves
A-5415AE Modification of Main Steam Cross Tie Valve 1
HV-20565 Controls
A-5415AF Adjustable Time Delay of EFIC Initiation 0
A-5415AG Floor Penetration and Support of New HISS 0
Panel for EFIC
A-5157 Auxiliary Feedwater Runout Alarm 0
A-5233 Diesel Driven Air Compressor Installation 1
A-3285 NGS & IAS Cross-Ties 1
A-5743 Instrument Air Back-up for the ADV's 5
R-0859 Instrument Air Back-up for TBV's CCW and 2-
Feedwater System Control Valves
R-0804 N2 & IAS Cross-Ties 0
A-3062 Main Steam to Auxiliary Pump Turbine 0
R-0894 Bushings for Tilt Disc Check Valves 0
R-0040 Upgrade P-318 Impeller 0
SECTION SUBJECT
8. Electrical Systems
8.1 Design Bases
8.2 Electrical System Design
8.3 Tests and Inspections
10.2 System Design and Operation
7. Instrumentation and Control
7.1 Protection Systems
7.2.3 Integrated Control System
TECHNICAL SPECIFICATIONS
Surveillance Standards
SECTION SUBJECT
4.6 Emergency Power System Periodic Testing
B-11
- - -_
o ~ r
LIMITING CONDITIONS FOR OPERATION ,
SECTION SUBJECT
3.4 Steam and Power Conversion System
3.7 Auxiliary Electrical Systems
SYSTEM DESCRIPTION
EFIC Auxiliary Feedwater System Description, Revision 1, and Associated
Figures. Auxiliary Feedwater System, B&W Document No. 15-1120580-04
The diagrams listed below may also be affected documents of ECN's previously
listed and therefore will be modified by applicable DCN's.
Schematic, Wiring, Control Logic, Cable Block, Elementary, and Loop Diagrams
DRAWING N0. TITLE REVISION
N28.03-CS, IE-1E Tie Cabinet 0
Sheet 2 ASSY. H4EIB1
E206, Atmospheric Dump Valves
Sheet 164 PV-20571 A,B, and C 0
Sheet 165 PV-20562 A,B, and C 0
1-54, Atmospheric Dump Valves
Sheet 27 PV-20571 A,B, and C 0
Sheet 28 PV-20562 A,B, and C 0
E-382, Wiring Diagram
Sheet 1 EFIC Channel A H4FWA 0
Sheet 2 EFIC Channel B, H4FWB 0
E-342, Wiring Diagram 14
Sheet 7 Miscellaneous Devices
1-205, Control Logic Didgram 6
Sheet 3 P-318 and P-319
E206, EFIC Initial / Test Matrix
Sheet 166 Channel 'A' 0
Shett 167 Channel 'B' 0
E203, Auxiliary Feedwater
Sheet 50C Isol. Valve HV-20577 4
Sheet 50Q Isol. Valve HV-20578 0
E205, Elementary Diagram'
Sheet A Feedwater & Condensate 13
Sheet 1A Test Valve HV-31855 1
Sheet 18C Block Valve HV-20530 0
Sheet 18D Block Valve HV-20529 0
Sheet 20A MOV HV-20560 & HV-20565 0 :
l
Sheet 20C MOV HV-20569 & HV-20596 0
Sheet 20E M0V HV-20597 & HV-20598 1
B-12
i
_ . -
, - _ _ _ _ _ _ _ . , - ~ . - _
i o .
'
Sheet 20H MOV HV-31826 0
Sheet 201 MOV HV-31827 0
Sheet 21 VLV HV-30801 13
Sheet 24 Main Feedwater Control and 13
Start-up Valves
Sheet 27 Spare 4.16 Kv Breakers 4B10 6
Sheet 29 Emer. FW Control Valves 4
Sheet 29A Emer. FW Control Valves 1 ,
Sheet 43 AFW Pump P-319 0
Sheet 44 AFW Pump P-318 0 !
Sheet 49 Isolation Valve HV-20581 0 )
Sheet 50 Isolation Valve HV-20582 0 .i
l
Sheet 51 Control Valves FV-20531 & FV-20532 0
Sheet 52 Isolation Yalve HV-20515 0
Sheet 53 Isolation Valve HV-20516 0
Sheet 54 SG EFIC LVL. Control CH 'A' and 0
EFIC Shutdown & Reset CH. 'A' & 'C'
Sheet 55 SG EFIC Level Control CH. 'B' and 0
EFIC Shutdown & Reset CH.' B'& 'D'
Sheet 65 EFIC Initiation Signals to
Tie Cabinets
E-324, Control Console HISS 18
Sheet 1
E-324, Console HISS Plug 0
Sheet 4 Connector Channels A&C
E-342 EFIC System Terminal 0
Sheet 87 Boxes H7J3826 & H7J3827
N28.02-109, Emergency Feedwater 0
Sheets 1&2 Initiation Control System H4FWA
E-382, EFIC Channel A 0
Sheet 1 H4WA
h28.02-91 Emergency Feedwater Initiation 0
Sheet I thru & Control System H4FWA, E-311,
Sheet 5 Control Panel
h25DE Emergency Shutdown Panel
Sheet A
N28.03-16, Power Distribution 0
Sheet 1 (IE- 1E)
N28.03-10, Tie Cabinet Assembly 1
Sheet 1 (IE-1E)
E-382,
Sheet 6 Tie Cabinet A1, H4E1A1 0
Sheet 7 Tie Cabinet B1, H4E181 0
B-13
1
, - - - . - - - - , - - . , . . _ , - - - , - . . . -- -
_- _
a %* J
N28.04-8, Tie Cabinet Assembly 0
Sheet 1 (IE-1E) -
N28.03-15, Power Distribution 0
Sheet 1 (IE-1E)
I-53, AFW Safety Grade Flow 1
Sheet 6 FT- 31802, FT-31803
I-54, EFIC Process Analog 0
Sheets 1 thru 8 Signals, Steam Gen. A&B
Pressure, CH. A,B,C,0
I-53, AFW Safety Grade Flow 0
Sheet 7 FT-31902, FT-31903
Sheet 10 Disch, Press. PT-31801,
PT-31803
Sheet 11 Disch. Press. PT-31901, PT-31903
i
1-1421 EFIC Steam Generator 0
Level Setpoints
i
- I-54, EFIC Process Analog 0
i Sheet 9 Signals Steam Generator A Narrow
'
Range level CH. A
l E-205, Main Steam failure Feedwater 3
'
Sheet 24A Valve Isolation 'B'
4
E-342, Misc. Instruments 0
Sheet 82
'
. E-206, ADV Isolation Valve --
'
Sheet 168 HV-20517
& 169 (
E-206, Turbine Bypass 1 solation -- !
Sheet 170 Valve HV-20521 q
6 171
1-54, EFIC Process Analog Isolation --
g
Sheet 9 SG 'A' Narrow Range LYL.CH. A 0 ;
" " " " " " " i
10 B 0
" 11 C 0 ;
" 0 0
-
12
" " " "
"
13
"
'B' A 0 .
" B 0
14
" C 0
15
" 0 0
16
" "
j
"
17
"
'A' WIDE
"
A 0
"
16 B 0
!
B-14
l
1
. . . . - , _ _ _ - - - - ,. , . . - , , - -. . . . - . - , _ - - - . - . . . - - - _ ~ _ . - - . . . , . . , . - - .- ~ - - .
m
I
so o
,
1-54, EFIC Process Analog Isolation
Sheet 19 SG 'A' WIDE Range LYL.CH. C 0
20 D 0
."' 21
"
'B' " " "
"A 0
"
22 B 0
"
23 C 0
"
24 D 0
E-208,
Sheet 13 B Electrical Auxiliaries 3-
" " 13
Sheet 15 " " --
Sheet 68 "
Sheet 8A
" 3
Sheet 20A Nuclear Service Bus Loading 'A' 4
Sheet 20D 4Kv S4A Bus Potential 3
Sheet 50 Electrical Auxiliaries
"
4
" 3
Sheet 56
Sheet 9 Electrical Auxiliaries 16
sheet 20E 4Ky SAB Bus Potential 2
Sheet 57 Electrical Auxiliaries 3
Sheet 57A Nuclear Service Bus Loading 'B2' 0
E-203, Reactor Auxiliaries 10
Sheet 3 Decay Heat Removal Pumps P-261A,8
h23.01-57 S.F.A.A. Digital Subsystem 2
Typical Unit Control
N23.01-26, S.F.A.S. Backlighted 3
Sheet 4 Pushbutton Switches and
Control Switches
E5.02-5-51 HK Stored Energy Breaker 51
E6.02-2 4160 Volt Switchgear 6
l
B-15