ML20198H510
| ML20198H510 | |
| Person / Time | |
|---|---|
| Site: | Davis Besse  |
| Issue date: | 09/04/1997 |
| From: | Richards S NRC (Affiliation Not Assigned) |
| To: | Jeffery Wood CENTERIOR ENERGY |
| References | |
| 50-346-97-201, NUDOCS 9709180176 | |
| Download: ML20198H510 (5) | |
See also: IR 05000346/1997201
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UNITED STATES
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NUCLEAR REGULATORY COMMISSION
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September 4, 1997
Mr. John K. Wood
Vice-President - Nuclear, Davis-Besse
Centerior Service Company
c/o Toledo Edison Company
Davis-Besse Nuclear Power Station
5501 North State Route 2
Oak Harbor, Ohio 43449-9760
SUBJECT: DAVIS-BESSE DESIGN INSPECTION
(NRC INSPECTION REPORT N0. 50-346/97-201)
Dear Mr. Wood:
A design inspection at Davis-Besse was performed by the Special Inspection
Branch of the Office of Nuclear Reactor Regulation (NRR) during the period
April 14, 1997 through June 20, 1997, including on-site inspections during
May 5-9, May 19-23, and June 9-20, 1997.
The team selected for inspection the
high pressure injection (HPI) system and the low pressure injection (LPI)
functions of the decay heat removal system (DHRS).
The purpose of the
inspection was to evaluate the capability of the systems to perform safety
functions required by their design bases, the adherence to the design and
licensing bases, and the consistency of the as-built configuration with the
updated safety analysis report (USAR).
The results of this inspection are presented in the enclosed report.
The
inspection team noted that the mechanical, electrical, and instrumentation and
control designs of the HPI and LPI systems were adequate to provide the
required emergency core cooling flow to mitigate design basis accidents, and
concluded that the systems were capable of performing their safety functions.
The team identified some weaknesses in the design process and installation of
,
the systems.
For example: reverse flow testing of check valves DH81 and DH82
on the two LPI pump suction linas from the borated water storage tank (BWST)
and seat leakage testing of stop check valves HP31 and HP32 on the HPI pump
recirculation lines were not done; and although your staff had identified the
deterioration of the BWST level transmitter support hardware in 1994, no
action was taken to remove, examine, and replace the hardware until the
inspection team expressed its concern on the condition of the supports.
The
team referred to NRR staff for evaluation the issue of the acceptability of
the use of normally open safety-related valves as safety class interface
between the HPI system and local pressure gages that were not seismically
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Other issues-identified by the team included USAR discrepancies, weaknesses in
periodic testing of battery chargers, lack of testing of inverters, not
including certain electrical components in-the environmental qualification
program, and not revising an installation detail drawing after modifying the
actuators for DHR cooler outlet and bypass valves.
You have initiated measures to address the-team's concerns.
In order for the
NRC to coordinate follow-up inspections, please provide within 60 days of this
letter a schedule for completion of your corrective actions for the open items
listed in Appendix A of the enclosed report.
Any enforcement action resulting from this inspection will be handled by the
NRC Region III office via separate correspondence.
As with all NRC inspections, we expect that you will evaluate the
applicability of the results of this inspection and the specific findings to
other systems and components.
In accordance with 10 CFR 2.790(a), a copy of this letter and the enclosure
will be placed in the NRC Public Document Room.
Should you have any questions
concerning the attached inspection report, please contact the project manager,
Mr. - A.G. Hansen at (301) 415-1390, or the inspection team leader, Mr. S.K.
Malur at (301) 415-2963.
Sincerely,
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Stuart A. Richards, Chief
Special Inspection Branch
Division of Inspection and Support Programs
Office of Nuclear Reactor Regulation
Docket No.:
50-346
Enclosure : NRC Inspection Report No.: 50-346/97-201
cc:
see next page
- _ - _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _
Hr. John K. Wood
-2-
Other issues identified by the team included USAR discrepancies, weaknesses in
periodic testing of battery chargers, lack of testing of inverters, not-
including certain electrical components in the environmental qualification
program, and not revising an installation detail drawing after modifying the
actuators for DHR cooler outlet and bypass valves.
You have initiated measures to address the team's concerns.
In order for the
NRC to coordinate follow-up inspections, please provide within 60 days of this
letter a schedule for com)letion of your corrective actions for the open items
listed in Appendix A of tie enclosed report.
Any enforcement action resulting from this inspection will be handled by the
NRC Region 111 office via separate correspondence.
As with all NRC inspections, we expect that you will evaluate the
ap)licability of the results of this inspection and the specific findings to
ot1er systems and components.
In accordance with 10 CFR 2.790(a), a copy of this letter and the enclosure
will be placed in the NRC Public Document Room.
Should you have any questions
concerning the attached inspection report, please contact the project manager,
Mr. A.G. Hansen at (301) 415-1390, or the inspection team leader, Mr. S.K.
Malur at (301) 415-2963.
Sincerely,
ORIGINAL SIGNED BY
Stuart A. Richards, Chief
Special Inspection Branch
Division of Inspection and Support Programs
Office of Nuclear Reactor Regulation
Docket No.:
50-346
Enclosure :
NRC Inspection Report No.: 50-346/97-201
cc:
see next page
DOCUMENT NAME: G:\\DBESSE.RPT
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capability of the make-up system.
Information on the HPI flow and the time at
which the flow is required to be initiated to mitigate the consequences of the
accident was not available.
The licensee has initiated efforts to obtain this
information from B&W.
(Inspection Follow-up Item 50-346/97-201-01)
B&W calculation 32-1171604-00 includui the HPI flow as a penalty in the
calculation cf the core reflood rate because inclusion of the HPl flow
increases the pressure in the reactor vessel, and therefore, increases the
reflood time.
Section 1.2.1 of the HPI system description SD-038 stated that
for a large break LOCA, the minimum HPI flow shown in Table 1.2-1 of SD-038
was required, but did not discuss the conservatism in the B&W evaluation due
to consideration of HPl flow.
The licensee stated that system description 40-
038 would be revised to properly characterize the conservatism in considering
full HPI flow,
b. HPI System In.iection Flow Rate and Pumo Surveillance Testina
The team reviewed the licensee's calculations for HPl system hydraulic
resistance, piping isometric drawings, and pump surveillance test procedures
and acceptance criteria, to evaluate HPl system capability to provide the
limiting flow specified in Table 1 2-1 of system description S0-038.
Calculations 36.017, "HPI Flow vs. Reactor Coolant System Pressure," Revision
03, and C-NSA-52.01-001, "HPI Flow Rate As a function of RCS Pressure,"
Revision 01, determine the HPl injection flow rates.
The pressure drops in
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both the pump suction and discharge lines for standard flows of 100, 200, and
500 gpm, the lump head for these flows from the original test performance
curves, and t1e RCS pressure at the HPl nozzle, were determined in these
calculatibns. The RCS pressure versus HPl flow rate had also been measured by
test, and the test results were provided in calculation C-NSA-52.01-003, "HPI
Pump Acceptance Criteria," Revision 03.
The team compared the data in these
documents and noted that the calculated values were conservative with respect
to the actual measured values.
The data for developing HPI flow rate versus
RCS pressure curve was provided in Calculation C-NSA-52.01-004, "HPI System
Resistance Curves," Revision 0.
Calculation C-NSA-52.01-007, "HPI System
Curve with Instrument Error," provided the best-estimate HPI flow curve with a
7% flow reduction to account for degradation of the pump and a further flow
reduction of 1.5% to account for instrument error.
This best ostimate HPI
flow curve enveloped the minimum flow required by the B&W analysis _ to mitigate
an accident.
Calculation C-NSA-52.01-003, "HPI Acceptance Criteria," developed acceptance
criteria for the surveillance test for the HPI pumps.
Because of system
limitations for periodic surveillance testing at full-HPI flow, the test is-
conducted at about 400-gpm.
The HPl pump performance test performed during
plant startup showed that the pump delivered a total flow of 820 gpm or 410
gpm per injection leg at an RCS pressure of 400 psig.
The results from tests
DB-SP-03218. "HPI Pump 1 Quarterly Pump and Valve Test," dated March 17, 1997
and DB-SP-03219 "HP1 Pump 2 Quarterly Test," dated April 25, 1997, show that
the pump will deliver about 380 gpm at a pump discharge pressure of 1500 psig.
The original pump test curves showed that the pumps delivered a flow of 380
gpm at a pump pressure of about 3500 ft. or about 1515 psig.
The latest pump
tests showed minimal degradation of the aump performance since its
installation.
The teaN concluded that t1e TS 4.5.2 requirement of HPI flow of
375 gpm in each injection leg at 400 psig at the core flood nozzle was
satisfied taking into consideration the system hydraulic resistance.
The team concluded that the HPI system had been designed to provide the flow
required for accident mitigation, assuming a 7% degradation in pump flow
capacity, and that the surveillance tests verify the system capability,
c.
HPI Pumo Net Positive Suction Hejd
The team reviewed calculatioin 36.010. "LPI, HPI, CS NPSHA from BWST,"
Revision 0, and 36.031, "HPI Pump NPSHA at a Possible 1020 gpm Flow,"
Revision 0, along with piping isometric drawings M-233A, " Emergency Core
Cooling Systems - Borated Water Supply," Revision 15, and M-233B, " Emergency
Core Cooling Systems - Pump Suction Piping," Revision 19, to verify the
available net positive suction head (NPSH ) for the HPI pumps when taking
suctionfromtheBWSTatpumprunoutcondltion.
The team's review, however,
indicated that on the basis of the pump performance characteristics and the
pressure drop in the discharge line, pump runout will not occur.
Consideration of the-pump runout in the evaluation was conservative.
With conservative assumptions regarding low water level and temperature in the
BWST, the NPSH at pump runout conditions of 900 gpm and 1020 gpm were
cal ~ulatedas%9.5feetandabout44feetrespectively.
The required net
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positive suction head (NPSH,) at a pump flowrate of 1020 gpm was about 35
feet.
Therefore, there was adequate margin in the NPSH
As stated above,
becauseofhighhydraulicresistanceinthedischargepi. ping, the HPl pumps
are not expected to reach runout conditions.
The team reviewed calculation C-NSA-52.01-ll, "HPl NPSH on CTMT Emergency Sump
Recirculation," Revision 0, to determine the NPSH for the HPl pump operating
inthepiggy-backmodetakingsuctionfromtheLPlpumpdischarge.
The
calculated total hydraulic losses were based on actual test measurements and
calculated values.
The calculation estimated the NPSH, at about 200 feet
which was much greater than the NPSH,,
The team concluded that sufficient NPSH margin was available for the HPI pumps
when taking suction from either the BWST or the containment emergency sump in
the piggy-back mode,
d.
System Boundaries and Safety Class Interfaces
The team verified that appropriate system boundaries and safety c;4ss
interfaces were considered and incorporated into the design for the interfaces
between the HP! system and RCS, make-up and purification system, and DHR
system.
Locally mounted pressure gages PI 1519 and 1520 were installed in the high
pressure injection (HPI) system with one normally open manual isolation valve
in each sensing line from the system piping.
Each isolation valve was an ASME
Code, Section 111, Class 2 valve and was the boundary between the Class 2
system piping and the non safety-related sensing line and pressure gage.
The
pressure gage was not seismically qualified and its pressure boundary could
fail in a seismic event.
However, the sensing line was designed to seismic
class I requirements, and the line and the pressure gage were provided with
seismic class I supports.
Because the pressure gage was not seismically
qualified, the team questioned the acceptability of a normally open valve as
boundary between ASME Class 2 piping and the prassure gage although the gage
was seismically supported.
This issue has been referred to NRR staff for
further evaluation.
(Inspection follow-up Item 50-346/97-201-02)
e.
Pipina Desian Pressure and Temperature
The team reviewed the HPI system piping and instrumentation diagram (P&lD)
H-033. Revision 25, system description SD-038, Revision 02, piping class
specification M-200,' Revision 05, and piping isometric drawings to verify the
piping design pressure and temperature classification for the suction,
discharge, minimum recirculation, and test lines.
The team determined that
the pressure and temperature classifications were acceptable except for the
following:
Piping isometric drawing H-233D, "HP Injection System - Auxiliary
Building," Revision 22, provided a table of operating pressure and
temperatures for various lines that were not consistent with the Piping
Design Table, in specification M-200.
The licensee stated that the
operating temperature and pressure shown on drawing M-2330 were not used
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in the piping design, and initiated DCN M-233D-12 to delete this
information from the drawing.
Specification M-200 listed the maximum working pressure for lines CCB-19
and CCB-12 as 2500 psig and 1650 psig respectively.
These two lines are
connected and have no isolation devices between them, and therefo,*e, the
pressure in both lines should be identical.
However, the team noted
that piping stress calculation No.54 for line CCB-12 used the correct
value of 2500 psig as the service pressure in the line.
The licensee
issued a saecification change notice SCN) M-200-05-15 to correct the
error in t,1e maximum operating pressur(e for line CCB-12 in specification
M-200.
Specification M-200 listed the maximum design pressure for piping CCB-2
between the HPl pump discharge check valves and the motor-operated
containment isol'. tion valves as 2600 psig, whereas the pressure for
piping downstieam of the containment isolation valves was listed as 2500
psig which is the RCS pressure.
Specification M-200 did not
explanation for the difference in the design pressure values. provide any
The
piping stress analysis used a pressure of 2600 psig which is the ASME
Code allowable pressure for the pipe.
The licensee issued SCN M-200-05-
16 to clarify in specification M-200 the basis-for the higher pressure
rating in the portion of line CCB-2 upstream of the containment
isolation valve.
The maximum service pressure and temperature rating for line CC6-2 from
HPl pump 1-1 discharge to the pump discharge check valve HP22, and from
HP22 to motor-operated isolation valve HP 2C And 2D was listed in Spec.
M-200 as 1650 psig at 260'F.
The same values are also applicable for
the HPl pump 2 discharge line.
The maximum service pressure in these
lines should be 1850 psig which was the maximum expected pressure when
the HPI system was operating in the piggy-back mode.
The stress
analysis for this portion of CCB-2 line was performed at a pressure of
1650 psig and a temperature of 260'F.
The stress analysis was,
therefore, performed using a lower pressure than the expected value.
This discrepancy was identified by the licensee during the inspection
>
and was documented in potential condition adverse quality report (PCAQR)
P -0825 for reevaluation of this portion of the CCB-2 line to address
the increased service pressure in the pum) discharge line.
lne team
determined that the pressure rating for t.1e valves, fittings, and piping
for this portion of the pipe enveloped the pressure of 1850 psig, and
the small pressure increase from 1650 to 1850 psig should not
significantly impact the pipe hangers and supports.
f.
Environmental Oualification of Eouloment in ECCS Rooms 105. 113. and 115
The team reviewed USAR Table 3.6-11, procedure NG-EN-00306, " Environmental
Qualification Program," Revision 02, calculation C-NSA-000.02-005, " Main
Feedwater 1.ine Breaks and Cracks in the Auxiliary Building," Revision 01, and
selected electrical schematic drawings for electrical equipment in ECCS rooms
105,113, and 115 to verify the environmental qualification (EQ) of the
electrical components.
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The environment in the ECCS rooms becomes harsh due to high temperature in the
event of a niain feedwater line break (MfWLB), auxiliary steam line break or a
break in the steam generator blowdown line in the auxiliary building.
Except
for the MFWLB accident for which the HPl system is required to operate to
bring the reat. tor to safe shutdown conditions, the ECCS systems are not
required to operate.
In the event of a LOCA, the radiation levels in the ECCS
rooms increase.
The team's review of electrical components in the ECCS rooms that are powered
from the Class lE bus indicated that some safety-related electrical
components, such as sump pump motors, sump level switches LS-4621, LS-4623,
LS-4625, associated hand switches, and electrical boxes were not listed in the
EQ Master List.
These components are required to operate under harsh
environ:nental conditions.
Failure of these components could jeopardize Class
lE circuit integrity and operation of associated safety-related equipment.
The licensee provided a list justifying exemption of some of these components
from the EQ program.
This list was not an EQ Exempt List that was described
in procedure NG-EN-00306, ' Environmental Qualification Program," Revision 2.
The licensee agreed that sump pumps and associated level instruments and local
control stations should have been included in the EQ program in accordance
with procedure NG-EN-00306.
The licensee issued PCAQR 97-0796 to address the environmental qualification
of these components in the ECCS rooms and additional required documentation,
and concluded that there was no operability concern because identical local
control stations and level instrumentation components have been qualified for
harsh environments and the materials commonly used for sump pump motor
windings had been demonstrated to be qualified for calculated radiation levels
in the ECCS rcoms.
(Inspection Follow-up item 50-346/97-201-03)
g.
Calculations
The licensee provided a total of 19 mechanical system calculations for the HPl
system, which accounted for all the mechanical calculations performed by the
original architect-engineer and the licensee. Of these calculations, the team
identified only eight that appeared to support the current design basis.
If
the calculations that support the design basis are not explicitly identified
as such and the other calculations are not archived, superseded, or identified
as historical information, the team was concerned that data from the
calculations that are not part of the design basis could inadvertently be used
for future design changes or as input to operational decisions.
The licensee stated that as a part of the design basis validation program, the
existing calculations will be reviewed for adequacy and it will be ensured
that they reflect the current plant design,
b.
System Modifications
The team selected modification 96-006, " Installation of High Point Vent in HPI
Pump 2A Discharge Line" for review.
The design of the system was such that a
section of the HP1 pump discharge line could be drained following maintenance
or testing of the system and the small trapped air volume in that segment
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could only be flushed out after a pump start.
The modification installed a
vent to ensure proper refilling of the discharge piping. The ter.m concluded
that the design of the modification, safety analysis, t .d closeout of the
modification was adequately performed.
El.2.2.3
Conclusions
The team concluded that the HPI system design was adequate to provide the
required flows assumed in the B&W analysis for SBLOCA and MSLB/MFWLB
considering a M reduction in the pump flow capacity.
The system provided
sufficient NPSH for the HPI pumps when taking suction from either the BWST or
the containment emergency sump.
Except for the locally mounted pressure gages
at the suction of the HPl pumps, the system incorporated appropriate
boundaries and class breaks with interfacing systems.
This issue has been
referred to the NRR staff for evaluation.
The team noted several
discrepancies in piping specification M-200 regarding piping design pressure
and temperature classification.
The team noted that exclusion of some
electrical equipment in the ECCS rooms was a weakness in the EQ program.
The
team was concerned that lack of proper identification of design bases
calculations could result in the use of information from calculations that
have been superseded and do not support the system design.
El.2.3
Electrical Design Review
El.2.3.1
Scope of Review
for the electrical design review, the team focused on the essential power
supplies to the HPI and DHR systems.
The areas examined, such as emergency
diesel generators, 4,160-volt AC buses. 480-volt unit substations and motor
control centers (MCCs) -125-volt DC system, and the 120-volt vital AC system,
were common to both systems.
Therefore, a separate discussion of the
inspection of electrical aspects of the DHR system is not included in the
report.
The team reviewed USAR Section 8.0, TS 3/4.8 " Electrical Power," system
descriptions, Design Criteria Manual (DCM) Section Ill.D " Electrical,"
electrical calculations and drawings, specifications and procedures for
electrical requirements and mnstruction, one modification work order (MWO)
package, PCAQRs, and other miscellaneous electrical documents.
The team assessed portions of the following that are applicable to the HPI and
DHR systems: essential power systems including switchgears, transformers,
motors, raceway, panels, cables, terminations; regulatory and standard
compliance; channel separation; voltage drops and available voltages; controls
and interlocks; alarms and indications; protective device setpoints; field
installations; modifications; labeling and identification; fire stops; drawing
and record changes; and seismic and environmental considerations.
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El.2.3.2
Findings
The team reviewed the emergency diesel generator (EDG) system description,
capacity calculations, elementary diagrams, protective relay setpoints, and
electrical equiament.
The calculations showed that EDG loading was properly
estimated and t1e EDGs had adequate capacity margin.
This was ver fled by the
records from the SFAS integrated time response test performed in % y 1996.
The electrical loads including the ECCS loads were sequenced onto the EDG
within the required time, and the dr.op in output voltage and frequency and
their recovery were acceptable.
The team reviewed the system description, drawings, protective relay setpoints
and coordination calculations, and other aspects-of the 4160-volt AC system
with emphasis on undervoltage protection schemes.
The calculations indicated
that the undervoltage setpoints were adequate for proper operation of the
electrical loads and for shedding loads in the event of a loss of off-site
power.
The team reviewed the system descriptions for i,he 480-volt unit substations
and motor control centers, art,tection settings and coordination, cable
ampacities and derating met 1ods, calculations for voltage drops, and valve
operations under reduced voltage. The team reviewed selected HPl and LPI
elementary diagrams and SFAS actions and equipment interlocks.
The team had
no concerns regarding the 480-volt system.
Except for the testing of battery chargers and invertars discussed in the
following paragraphs, the team had no other concerns regarding the 125-volt DC
and the 120-volt vital AC systems,
a.
Battery Charaers
3
The electrical distribution system functional inspection (EDSFI) finding
346/92007-06 stated that the battery charger surveillance requirements were
different from the charger design commitment described in USAR Section
8.3.2.1.3.
The USAR stated that each " charger is capable of supplying all
steady-state DC loads required under any conditions of operation while
recharging the battery to a fully charged condition over a period of 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />
from a discharged condition of 105 volts per battery." TS 4.8.2.3.2.c.4
requires a verification at least once per 18 months that the " battery charger
will supply at least 475 amperes at a minimum of 130 volts for at least 8
hours."
The licensee revised procedure DB-ME-03002, " Station Battery Service and
Performance Discharge Test" to include Enclosure 7: " Battery Charger Current
Readings During Recharge Following Test Discharge." The revised procedure did
not require that the load box that was used to discharge the battery be used
again to simulate a worst-case steady-state load on the battery and battery
charger while the battery was being recharged.
The licensee provided
Enclosure 7 test result readings for the four batteries for the team's review.
The team noted that the initial reading was close to 600 amperes which was the
current-limited full rating of the charger.
The charging current dropped to
less than 475 amperes within 45 to 60 minutes and dtcreased to near zero
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within 1-1/2 to 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> and remained at near zero for the rest of the 12-hour
charging cycle,
it was apparent that without using the load box to simulate a
steady-state load, the procedure did not verify the USAR commitment.
The team
also noted that the two backup chargers DBCIPN and OBC 2PN were not normally
used for recharging and they were not tested. (Inspection Follow-up Item 50-
346/97-201-04)
b.
Testina of Inverters and Associated Components
The team reviewed the inspection and testing of the power supplies for the 120
VAC essential instrumentation distribution panels Yl, YlA, Y2, Y2A, Y3, and
Y4.
Four channels of essential instrumentation are fed by these panels and
supply vital 120 VAC to systems, such as reactor protection, safety features
actuation, radiation monitoring, auxiliary shutdown, and others as shown on
drawing E-7.
The channel 1 esseniial instrumentation distribution panels Y1 and YlA are
normally supplied by inverter YVI, which converts 125 VOC to 120 VAC.
This
inverter is rated at 10 kVA a.d operates at about 60% of full load, supplying
loads that do not significantly t.hange during postulated abnormal events.
The
inverter YVI is normally energized with 125 VDC from regulated rectifier YRF1
which, in turn, is supplied from the 480-volt essential MCC E12A.
If the 480-
volt feed is de-energized during a transient, such as a loss of off-site
power, the inverter is transferred without interruption to a 125-VDC supply
from the Channel I battery.
When the 480-volt feed is restored the inverter
will transfer back to the regulated rectifier supply.
Should the inverter
itself fail, a static transfer switch within the inverter will switch the 120-
VAC panels' from the inverter to a 480-to-120-VAC constant voltage transformer
(CVT) XYl.
The CVT powers the buses until the inverter is restored.
An
additional function of the CVT is to provide fault-clearing power during
problems in the 120-VAC circuits.
Channels 2, 3, and 4 have a sin.ilar
configuration.
The regulated rectifiers, inverters, and constant voltage transformers are not
mentioned in the technical specifications.
Therefore, there was no commitment
to perform surveillance tests on these Class IE equipment, and no periodic
surveillance tests are performed to demonstrate the load carrying capabilities
of the regulated rectifier, inverter, static transfer switch, or CVT or to
demonstrate the operability of special functions.
The existing preventive
maintenance procedures for cleaning and visual inspection, the continuous
monitoring of CVT availability during normal operation, and the continuous
supply of normal loads by the regulated rectifier and inverter, do not
demonstrate the specified capabilities or the available margins under abnormal
conditions of the 120 volt AC system.
(Inspection Follow-up Item 50-346/97-
201-05)
c.
Electrical Installation Procedures
The team reviewed maintenance procedure DB-ME-09512. " Installation Procedure
for Raceways Carrying Electrical Cables," to evaluate implementation of
raceway criteria.
All safety-related cables at Davis-Besse are routed in
Class IE conduits.
Procedure DB-ME-09512 provided few specific requirements
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and guidance for the installation of conduits.
The team had numerous comments
on this procedure relating to safety-related aspects, such as material
requirements, seals and fittings, codes and standards, conduit supports,
installation practices, and acceptance criteria.
The team also reviewed
electrical specification 7749-E-14. " Electrical Construction and
Installation," several sheets of drawings E-302A and E-1037P dealing with
electrical standards and details and grounding details, and maintenance
procedure DB-MM-01001 " Installation Procedure for Essential Electrical Hangers
and Supports." The team did not find specific installation requirements or
guidance in these documents.
The licensee issued PCR 97-1596 to revise
procedure DB-ME-09512 to resolve the team's comments.
The team reviewed maintenance procedure DB-ME-09500, " Installation and
Termination of Electrical Cables," because the licensee stated that the
instructions for wiring within panels were covered by this procedure.
This
procedure did not include installation requirements, such as physical
separation and color coding stated in USAR subsection 8.3.1.2.25, and
separation of low level signal wiring from power or control wiring stated in
panel specifications.
It appeared that no other criteria document or
procedure addressed such requirements.
El.2.3.3 Conclusions
The team concluded that the essential power supplies for the HPI and LPI
systems were capable of performing their safety functions required by their
design bases, adhere to the licensing bases, and are consistent with the
commitments in the USAR.
Calculations for protective relay setpoints,
coordination, voltage drops
EDG loading, battery loading, and others were
conservative in approach, used appropriate methodology, produced reasonable
results, and were consistent with the_ design bases.
Design bases documents
-
cover the performance requirements, design requirements, developmental and
code references, component descriptions, technical _ specifications, and limits.
Some weaknesses in raceway installation and panel wiring procedures were
identi fied.-
The functional and performance requirements appeared to be consistent with the
USAR, technical specifications, system descriptions, and calculations and
analyses.
The battery charger capability testing did not fully comply with
the intent of the commitment in the USAR as identified in an EDSFI finding.
The team also questioned the lack of testing of some features of inverters and
associated components.
E1.2.4
Instrumentation and Control Design Review
El.2.4.1 Scope of Review
The scope of the instrumentation and control design assessment consisted of a
review of HPI system documents, such as sections 6 and 7 of the USAR,
technical specifications, system description, P&lDs, loop diagrams,
operational schematics / control logic diagrams, four setpoint calculations and
loop uncertainty analysis, six instrument data packages, maintenance,
surveillance, and operating procedures, and one modification package.
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El.2.4.2 Findings
'
The system design documents reviewed by the team adequately supported the
design bases, except for the items discussed in the following paragraphs,
Reactnr Coolant low Pressure (SFAS level 2) Actuation Setooint
a.
The reactor coolant pressure instrument loop provides low reactor coolant
pressure input for the SFAS Actuation Level 2 permissive for HPl operation.
The team noted inconsistencies in the' reactor coolant low pressure setpoint on
the various documents that were reviewed.
Technical Specification Table 3.3-4
specifies a trip setpoint of 1620.75 psig and an allowable value of 1615.25
psig.
This was based on the low pressure trip value of 1585 psia considered
in the B&W SBLOCA analysis (calculation 32-1159744-0, dated June 16,1986)
with an addition of 2.03% for instrument error.
A subsequent reanalysis (B&W
calculation 32-11178648-00, Revision 1) Justified a value of 1515 psia, but
this value was not considered in the technical specifications.
Instrument
data package 64B-IShtCO2A3, Revision 4, showed a calibrated setpoint of 1661
psig which was considered by the team to be conservative.
The team also
reviewed calculation C-lCE-48.01-002, Revision 2, which established a loop
uncertainty of 12 psig and a setpoint of 1660 psig.
Although conservative,
this value did not match the results of the B&W analysis and the instrument
data package.
The licensee, however, stated that this calculation, now in its
6th revision, was intended to support a future amendment to the technical
specifications that will establish new allowable values, a new trip setpoint,
and instrument loop uncertainty.
The licensee acknowledged the above
inconsistencies and indicated that this issue will be addressed as part of a
'
future technical specification update and design basis validation program.
b.
HP1 Pumo Flow Test Calculation
Calculation C-NSA-52.01-003, "HP1 Pump Acceptance Criteria," Revision 3,
established the acceptance criteria for the HPl pump quarterly flow test.
The
team reviewed this calculation and noted that the assumed 1.5% accuracy for
the flow indicator for obtaining test data was not consistent with the 2%
calibration tolerance specified in the instrument data package.
The licensee
initiated PCAQR 97-0577 to revise the instrument calibration tolerance to 1.5%
to be consistent with the calculation.
This error did not invalidate previous
test result because the calibration record for the flow indicator that was
used in the test was verified to have an as-left instrument tolerance of
0.75%, which enveloped the required instrument accuracy.
El.2.4.3 Conclusions
The team concluded that the instrumentation and control design for the HPl
system was adequate.
All instrumentation setroints that were reviewed had
adequate margin and the technical specification limits were met and the errors
that were noted by the team were minor.
The team noted an inconsistency in
the RCS low pressure setpoint value in the technical specification, loop
uncertainty calculation, and instrument data sheet.
However, the actual
setpoint was conservative and acceptable.
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El.2.5 System Interfaces
El.2.5.1
ECCS Room Coolers
The team reviewed 50-0280, " System Description for Auxiliary Building
Radioactive Area HVAC System," Revision 2,50-018 " System Description for
Service Water System," Revision 2, and calculations for the ECCS room cooler
capacity to determine whether ECCS room coolers had the capability to maintain
the maximum design room temperature.
The HPI system description SD-038 stated that the normal temperature in the
ECCS rooms was 95'F and the maximum allowable temperature was 125'F.
This
maximum temperature limitation was imposed by the ECCS pump motor bearing and
lubricant.
Calculation C-NSA-032.02-003, " Maximum Allowable Service Water Temperature
with inoperable ECCS Room Coolers," Revision 3, supported the post-LOCA design
room temperature of 125'F for the ECCS rooms.
The team also reviawed
calculation 25.13. "ECCS Pump Room Heat Load / Fan-Coil Unit capacity vs.
Service Water Temperature," Revision 1, and calculation 25.14. "ECCS Pump Room
Heat Load / Fan-Coil Unit Capacity vs. Service Water Temperature for Rm Max.
Design Temp. - 122*F (50'C)," Revision 0, and estimated equivalent heat loads
for an ECCS room temperature of 125'F.
The heat loads used in calculation C-
NSA-032.02-003 were consistent with the team's estimates.
The team concluded
that with the technical specification limit of 85'F for the maximum allowable
service water bay temperature, the combined capacity of both room coolers in
each ECCS room was adequate to limit the maximum room temperature in the ECCS
room to 125'F under post-LOCA conditions.
SD-028C stated that the normally closed (NC) motor-operated valve SW 5425 at
the outlet of the room coolers opened automatically on increasing room
temperature. Modification 95-006 implemented a design change that left the
valve permanently open and power to the motor o)erator was removed.
The
system P&lD showed that the power to the valve ,1ad been removed.
The team
noted that, in accordance with )lant modification procedure NG-EN-00301,
Section 6.4, Action item 8, a c1ange notice should have been issued to update
the system description as part of the closecut of modification 95-006.
The
team noted that Table 2.4-1 in 90-028C showed the rating of cooler E42-1 as
100 Btuh, whereas the correct rating was 180,000 Btuh.
The licensee issued
SDCN-0280-02-005 to correct these errors.
El.2.6 HPI System Walkdown
El.2.6.1
Scope
The team inspected the installed mechanical, electrical, and instrumentation
and control equipment for the HPI system to evaluate their consistency with
drawings, design specifications, and regulatory requirements.
During the
walkdown the team interviewed plant system engineers, and operation-and
maintenance personnel.
The team walkdown covered the HPI pump rooms, control
room, auxiliary shutdown panel, BWST area, cable spreading room, switchgear
rooms, battery rooms, and electrical distribution panels,
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For the electrical walkdown, the team chose three HPI and three LPI cables.
These included two instrument cables, two control cables, one 480-volt power
supply cable to a valve motor operator, and one 4,160-volt pump motor power
supply cable.
Some of the aspects examined included cable sizin
radii, control board and enclosure wiring, separation, raceway, g and bend
seismic
supports, identifications, fire stops and wraps, drawings and records,
environmental considerations, material control, and installation procedures.
El.2.6.2 Findings
a.
Motor Operator Installation for Valve DH63
The team observed that the motor operator installation for isolation valve DH
63 was nonstandard.
This valve was originally designed for manual operation
during the piggy-back mode of HPl operation. A aodification was performed to
add a motor operator to permit remote operation of the valve.
Because of
space limitations, the motor was mounted away from the valve with a connecting
shaft to the valve stem.
The licensee did not perform an analysis to verify
acceptability of the loading on the piping due to the nonstandard mounting of
the motor.
During the inspection, the licensee performed a preliminary piping
and pipe support analysis that showed that the stresses were much below the
allowable value.
The licensee will update the appropriate piping stress
analysis to incorporate the preliminary analysis,
b.
Droundwater leakane
in pump room 115, the team noted that a tygon tube was attached to a vertical
structural support, and was discharging water to a floor drain.
The licensee
explained that groundwater was getting into conduit runs and drains through
holes in the conduits into an area above the non-essential electrical
distribution switchboard MCC F-21.
The tygon tubing drain observed by the
team was a portion of the leak collection system installed to preclude water
intrusion into switchgear and other important plant equipment.
The licensee
explained that the station was maintaining a leak collection log for tracking
leakages and the drainage arrangement was temporary.
Groundwater leakage into
buildings was a larger concern that the licensee was evaluating for potential
corrective actions,
c.
Electrical Construction
The team's comments on electrical installation procedures are discussed in
El.2.3.2.c of this report.
,
The licensee resolved the team's questions during the walkdown on the use of
threadless conduit couplings and conduit unions, the criteria for spacing of
conduit supports, and the radiation resistance and fire loading of PVC
covering on flexible conduits.
d.
HP1 Pump tube Oil Pressure Switch
During the walkdown of ECCS pump room 115, the team noted that the HPl pump
P58-2 lube oil pressure switch PDS-4961 had a material deficiency tag (MTD
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C469, dated May 2, 1995) attached to it, with a caution statement not to bump
the pressure switch.
The function of the pressure switch was to initiate
operation of the backup DC lube oil pump in case of failure of the safety-
Plant personnel were cautioned not to bump-the
switch to preclude its failure or inadvertent actuation.
The team noted that
PCAQR 95-0237 was issued on March 20, 1995, identifying a calibration
stability problem with the pressure switch, but the PCAQR stated that I&C
maintenance was unable to determine the exact cause.
The licensee concluded
that there were no onerability concerns because the pressure switch failure
would cause the DC lube oil pump to start, and would not affect operation of
The licensee stated that the pressure switch would be
replaced in July 1997, with a suitable narrow-range type that was inherently
more accurate and stable.
Recommended changes to the post-calibration
installation techniques would be incorporated in the PM procedure.
The team was concerned that the corrective actions to replace the pressure
switch had not been timely.
The pressure switch for the redundant train (PDS-
4957) had experienced a similar failure in 1994, and was replaced with the
original model w th the same range and setpoint.
The team discussed the
inappropriatenen of the use of a pressure switch with a range of 0-70 psid
for an applimion that required a setpoint of 8 psid with a deadband of 4.2
psid.
The licensee indicated that the feasibility of making the pressure
switches in both trains identical would be evaluated.
e.
Taaaina of Instruments and Associated Valves
The team noted that several instruments, isolation valves, and manifold valves
in the HPl and LPI systems did not have identification tags.
The team also
noted that some devices had more than one tag with different identification
numbers and some tags were attached at the incorrect locations.
Tagging
procedure DB-DP-00023,-Revision 02, applies only to new tr.gs, and existing-
tags not conforming to the requirements of the procedure are considered
acceptable until replacement is necessary,
Based on discussions with plant
personnel, it appeared that the existing instrument and valve tagging
condition had not hindered plant operations or maintenance.
Without a
consistent tagging system, the plant has to rely on operators' familiarity
with the plant's physical configuration.
The licensee acknowledged that this
problem was previously identified, and a program was being initiated to
address the tagging issue on a generic basis.
This program will cover
definition of requirements, standardization, procedure update, and
implementation schedule.
El.2.7
Updated Safety Analysis Report
The licensee had initiated an USAR program in August 1996 to review and update
the USAR,
Concerns resolution request (CRR) forms were prepared for the
identified questions or open concerns in the USAR related to the HPI and DHR
systems.
The team reviewed the CRR forms that had been resolved and approved
by the station review group, and concluded that the USAR issues had been
appropriately resolved.
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The team identified the following additional discrepancies in the USAR:
USAR Section 6.3.1.4 stated that " permissive signal is provided to allow
the manual opening of the sump valves" whereas Section 6.3.5 stated that
"No actions are required by the operator in large pipe LOCA..."
These
two statements are contradictory.
The SFAS set point of 1600 psig for low RCS pressure and the high
pressure injection setpoint in USAR Table 15.4.2-1 did not correspond to
either the analyzed design bases set point of 1570 psig or the technical
specification set point of 21620.75 psig.
The licensee had submitted
license amendment request (LAR) 96-C014 dated April 18, 1997, to the NRC
to revise the technical specifications.
The USAR will be revised after
the approval of the LAR.
USAR Table 7.5-1 indicated that HPl and LPI flow readouts in the main
control room are types A(analog), D(digital), and F(computer).
The
actual instalied readouts are types A and F only.
The licensee issued
UCN 97-066 to revise the USAR.
USAR Section 15.4.4.2.3.2 provided a sequence of events and elapsed time
to justify an assumption of a 35-second delay in injection of water to
the RCS.
The team considered the assumption to be conservative,
however, the timing of sequence of events listed in the USAR did not
correspond to the SFAS integrated time response test, the time delay
analysis provided in B&W analysis 32-1171604, or the licensee's
calculation C-EE-004.01-049. The USAR also considered the time delay
for starting the HPl pumps, although the opening of the motor-operated
injection valves was a more critical contributor to the time delay.
The above discrepancies had not been corrected and the USAR updated to assure
that the information included in the USAR contained the latest material as
required by 10 CFR 50.71(e).
(Unresolved item 50-346/97-201-06)
El.3 Decay Heat Removal System
El.3.1
System Description and Safety functions
The decay heat removal (DHR) system performs both normal operation and
accident mitigation functions.
In its normal operation mode, the system
removes decay heat from the reactor core and sensible heat from the RCS.
The
system also providet auxiliary spray to the pressurizer, maintains the reactor
coolant temperature during refueling, and provides a means for filling and
draining the refueling canal,
in its accident mitigation or LPI mode, the
system injects borated water into the reactor vessel and provides long-term
reactor core cooling after a LOCA.
The decay heat removal system includes the BWST, the containment emergency
sump, the BWST recirculation pump and heat exchanger, the refueling canal
drain pump, the decay heat dropline valve pit, the decay heat removal pumps,
the decay heat removal coolers, and the piping and valves associated with
these components.
Two redundant DHR pumps are arranged in parallel and are
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designed for continuous operation during the period required (nr removal of
decay heat.
Each DHR train has one decay heat removal cooler to remove deuy
o
heat from the RCS during a cooldown.
Operating both coolers provides the
design capability to reduce the reactor coolant temperature from 280'F to
140*F in approximately 22 hours2.546296e-4 days <br />0.00611 hours <br />3.637566e-5 weeks <br />8.371e-6 months <br />.
The BWST contains an available borated water volume between 482,778 and
550,000 gallons with a minimum of 2600 ppm boron in solution and is used for
emergency core cooling and filling the refueling canal during refueling.
The
BWST supplies borated water for emergency cooling to the containment spray
system, the LPI function of the DHR system, and the HPl system.
it also
supplies makeup water to the spent fuel pool cooling system and can serve as a
source for the makeup pumps.
The LPI functions of the DHR system are initiated automatically by an SFAS
signal', and the LPI pumps take suction from the BWST and inject borated water
into the reactor vessel.
The DHR pumps are referred to in this report as LPI
pumps where the emergency core cooling functions of the pumps are discussed.
After a low-low level of 95 inches in the BWST is reached, the LH pump
suction is manually transferred to the containment emergency sump to provide
long-term cooling of the reactor.
In this mode the DHR system removes heat
from the containment by cooling the containment sump water in the DHR coolers
before pumping the water back to the reactor vessel.
During the piggy-back operation of the HPl system, the LPI pumps provide
containment water to the suction of the HPI pumps after the cross-connect
,
i
valves between the two systems are manually opened by the operator.
The spent fuel pool cooling system is not designed to meet seismic Class I
'
criteria. When manually interconnected with the spent fuel pool, the DHR
,
system provides safety-grade cooling and a larger capacity for heat removal
from the spent fuel pool.
El.3.2
Mechanical _ Design Review
El.3.2.1.
Scope of Review
for the mechanical design review of the LPI functions of the DHR system, the
team evaluated the capability or the_ system to provide emergency core cooling
during the injection and recirculation phases of post-accident ECCS operation.
The team reviewed system description SD-042, Revision 2 for th' SHR system,
USAR sections 6.3 and 15.4, drawings, calculations, and operating and
surveillance testing procedures. The team also performed system walkdowns and
discussed _the system design and-installation with licensee-engineering and
operating personnel.
El.3.2.2 Findings
a.
LPI In.iection Flow Rate and LPI Pumo Surveillance Testina
The design basis for LPI injection flow rates as a function of the pressure at
the reactor vessel core flood nozzle is given in Table 1.2-1 of the decay heat
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removal system description SD-042, Revision 2.
The team verified that the
system was designed so that each of the two trains provide the minimum LPI
tiow rate and the flow rate was consistent with data in B&W document 51-
1158934-01, " Functional Requirements for the DH/LPI System," dated August 27,
1985.
Technical specification 4.5.2 has a requirement for verifying the LPI pump
flow rate in each injection leg of 2650 gpm at 100 psig pressure at the core
flood nozzle on the reactor vessel.
T11s requirement was presented in a B&W
1etter dated January 11, 1978.
Interp.11ation of the data in Table 1.2-1 of
SD-042, showed that the LPI flow rate at 100 psig was about 2486 gpm.
Survel11ance test procedures DB-SP-03130 and DB-SP-03137 specified an
accepttnce criteria for the LPI pump tothi developed head between 337.3 feet
and 369.8 feet for flow rates between 2940 and 3060 gpm.
The surveillance
requirement was, therefore, higher than the design basis injection flow rate
at 100 psig in the reactor vessel and was accsptable.
Calculation C-NSA-049.02-010. " Review of Test Data from DB-SP-10065 for Valve
DH14A," Revision 0, showed that the LPI train with the lowest flow could
deliver considerably more than 2650 gpm at 100 psig in the reactor vessel.
This calculation also showed that the surveillance requirement could still be
met with a 10% degradation in the performance characteristics of the pump with
the appropriate reduction in system resistance.
Therefore, the team concluded
that the quarterly inservice testing of the LPI pumps in accordance with ASME
Code Section XI with an acceptance criteria accounting for a 10% degradation
in the pump performance characteristics was acceptable.
The licensee issued system description change notice (SDCN) SDCN-042-02-005 to
clarify the discussion of the LPI system flow requirements,
b.
Net Positive Suction Head (NPSH) Calculation
USAR Section 6.3.2.14. " Net Positive Suction Head Requirement," included a
table listing the NPSH
either the BWST or from, and NPSH, for the LPI pumps drawing suction from
the emergency sump in the containment.
The NPSH for
the LPI pumps when taking suction from the BWST was more than four times,the
NPSH,, and the team reviewed the NPSH calculation 36.010, "LPl.HPl.CS NPSHA
from B'..'ST," Revision 0, to verify the adequacy of the NPSH for the LPI pumps.
Calculation C-NSA-049.01-004, " Vortex Formation with ECCS Pump Suction from
the BWST," Revision 0, assumed conservatively high flowrate from the BWST and
mini"xm BWST level accounting for instrument errors, and concluded that at the
minie m switchover level in the BWST, potential air ingestion into LPI pump
suction of 2% by volume was the maximum to be expected.
In accordance with
Appendix A of Regulatory Guide 1.82, a 2% air ingestion into the suction flow
will cause the pump NPSH to increase by a factor of two.
Because there was
adequate margin in the NESH , the team concluded that there were no NPSH
concerns during the operati,on of the LPI pumps while taking suction from the
BWST.
The licensee had performed calculations C-NSA-049.02-004, " Maximum Pump Flow
for DH Pump 1-1 Under Accident Conditions," Revision 1, C-NSA-049.02 -005,
" Maximum Pump Flow for DH Pump 1-2 Under Accident Conditions." Revision 1, and
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C-NSA-049.02-009, " Mechanical Str j Position for Valve DH14B," Revision 0, to
determine the position of the r .hanical stops for the replacement valves
DHl4A and DH148 located at th
utlet of DHR coolers to limit the system flow
rate and prevent pump run F
in addition, flow testing was done with pump
suction from the BWST to :c. trm the required system flows with the new valve
stops.
This testing revealec + hat the actual system flow resistance was about
25% less than the calculated s lue. A new system flow calculation C-NSA-
049.02-010. " Review of Test Data from DB-SP-10065 for Valve DH14A." Revision
0, was performed using the reduced system flow resistance.
However, no new
NPSH, calculation was performed with suction from the containment emergency
sump and utilizing the revised system flow resistance.
The licensee issued
PCAQR 97-0478 to document and resolve this issue.
Calculation C-NSA-49.02-19, " Modification to Bechtel Calculation 36.35,"
Revision 0, was issued on May 17, 1997, to correct discrepancies in
calculation 36.35, such as use of original pump curves instead of pump curves
consistent with the modified pump impellers, and incorrect pressure drop
through the flow measuring orifice.
The new calculation concluded that
adequate-NPSH margin (2.59 feet for train 1 and 5.01 feet for train 2)
existed for e,ach LPI pump at flow rates limited by the new stop positions in
valves DH14A and DH148.
However, the team noted that the calculation used the
pump inlet flange elevation which was about 2 feet higher than the pump
centerline elevation and a water temperature of 120"F instead of the higher
estimated post-accident temperature of the containment emergen:y sump water.
As a result, the team determined that the calculated NPSH, was underestimated
by about 3.5 feet and was conservative.
The licensee issued RFA 97-0203 to
revise calculation C-NSA-49.02-19 to account for the pump centerline
elevation.
In addition, the team noted that the calculation did not address the scenario
in which one LPI pump supplied both injection lines with the crosstie valves
open.
In this configuration, emergency procedure DB-0P-02000 required the
operator to limit the total injection flow in both lines to 4000 gpm, which
results in a total pump flow of 4100 gpm including pump recirculation flow of
100 gpm.
The actual- flow would be higher if the flow instrument errors were
considered, and NPSH under this condition would be higher.
In view of the
conservatisminthehPSHcalculationdescribedaboveandtheexistingmargins,
the team did not have additional concerns regarding LPI pump NPSH.
c.
ECCS leakaae Testina
During the inspection, the licensee initiated PCAQR 97-0529, and identified
that reverse flow testing of check valves DH81 and DH82 on the two LPI pump
suction lines from the BWST, and the leakage rate through stop check valves
HP31 and HP32 on the HPI pump recirculation lines, were not being tested.
Leakage of post-accident containment sump water through check valves DH81 and
DH82 in conjunction with either leakage through the BWST isolation valves DH7A
or DH7B or failure of the isolation valves to close could result in increased
off-site dose.
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No analyses had been performed to demonstrate that a conservatively high
l
containment pressure under post-accident conditions was not sufficient to
overcome the static head of water in the BWST, thus eliminating the need to
reverse flow test these valves.
The inservice testing (IST) program
documentation for DHRS valves stated that the reverse flow testing of check
valves DH81 and DH82 was not required because isolation valves DH7A and DH7B
would be closed.
The potential leakage through isolation valves DH7A and DH7B
or their failure to close was not considered.
The licensee successfully
tested valve DH82 during the inspection and scheduled the testing of DH81 at a
later date.
The IST program documentation for DHRS valves was revised to
include reverse flow testing of these check valves.
Leakage of containment sump water through stop check valves HP31 and HP32 on
the HPI pump recirculation lines during the piggy-back mode of operation could
result in increased off-site dose because the recirculation lines discharge
into the BWST.
The licensee was evaluating the testing requirements for these
two valves as part of the resolution of PCAQR 97-0529.
The design basis for
valves DH81, DH82, rip 31, and HP32 was apparently not correctly translated into
procedures and instructions as required by 10 CFR 50, Appendix B, Criterion
111. " Design Control," and Toledo Edison Nuclear Quality Assurance Manual,
Section 3.4.6.1. (Unresolved item 50-346/97-201-07)
TS 6.8.4 required that a program be established to reduce leakage from the
ECCS and that integrated leakage irnm each system be tested at refueling
-
intervals or less.
USAR Table 15.4.6.5-2 shows the offsite dose due to an
assumed total post-accident ECCS leakate of 5890 ml/hr.
Procedures DB-SP-
03136, DB-SP-03137, DB-SP-0 3218, and DB-SP-03219 verify external leakage from
components, such as pumps and valves.
Results of the recent tests showed
negligible external leakage from the ICCS.
Because the leakage tests were
performed at a temperature lower than the expected temperatures under post-
accident conditions, the team considered that this test could not verify that
the post-accident leakage from the system would be less than the assumed
value.
The licensee is currently evaluating the issue of testing of internal
and external leakage from the ECCS. (Inspection Follow-up Item 50-346/97-201-
08)
d.
Eressure Interlock Setooint for Valves DHil and DHil
Valves DHil and DH12 are nonna11y closed motor operated valves in the DH drop
line that isolate the RCS from the DHR system.
These valves form the pressure
boundary between the two systems (the design pressure rating of the RCS is
2500 psig whereas the design pressure rating of the DHR system is 300 psig).
The pressure interlock in the valve control is designed to prevent these
valves from being opened when the RCS pressure is above the design pressure of
the DHR system.
The interlock would also cause automatic closure of DHil and
DH12 as the RCS pressure increases past the pressure setpoint.
In addition,
other procedural controls are in place to ensure that these valves are not
moved to their incorrect positions during various plant operating modes,
in TS 4.5.2.d and TS Table 3.3-4, the setpoint for the DHil and DH12 pressure
interlock is stated as <438 psig.
The licensee stated that the setpoint was
in error and that PCAQR 97-0238 was initiated on February 25, 1997, to
20
- _--
,
,
e
disposition this issue.
Nuclear engineering memo 08E-97-00164 and calculation
C-ICE-048.01-002, "SFAS Reactor Coolant Pressure Actuation Setpoints,"
determined a new TS allowable value of <328 psig.
Licensing Amendment Request (LAR) 96-0014 will implement the change to the
appropriate technical specification by replacing the original setpoint of <438
psig with the new allowable value of <328 psig.
The team verified that the
actual setpoints for these valves were 306 psig for DHil and 265 psig for
i
DH12, which were both below the new allowable value,
in response to the
team's question, the licensee stated that the actual valve setpoints had
remained approximately the same since 1977, and therefore, the team concluded
that there was no conchrn of potential overpressurization of the DHR system.
e.
Procedure RA- Q 02820
-
Procedure RA-EP-02820, " Earthquake," governs the operation of the station
after a seismic event.
The team noted that this procedure did not mention the
availability of or refer to other procedures for back-up cooling of the spent
-
fuel pool.
The DHR system is designed as a seismic class I system and
provides a back-up cooling capability.
The licensee initiated arocedure
change request (PCR) 97-1404 to revise the procedure to direct t1e operators
to consider aligning a DHR system train to cool spent fuel in the event the
normal spent fuel pool cooling system was not operable.
.
In addition, the licensee initiated PCR 97-1435 to revise procedure DB-0P-
06012 to provide additional guidance to operators regarding the degradation of
the LPI function of the DHR system if the DHR system is aligned to perform
spent fuel cooling functions during Modes 1, 2, and 3.
El.3.2.12 Conclusions
The team concluded that the LPI system was designed and tested to provide the
required flow rates assumed in the accident analyses.
The system provided
sufficient NPSH for the LPI pumps when taking suction from either the BWST or
the containment emergency sump.
The team noted that reverse flow testing of
check valves DH81 and DH82 and leak testing of valves HP31 and HP32 had not
been performed and this was a weakness in the IST program.
At the time of the
inspection, the licensee had taken actions to test these valves.
.
El.3.3 Electrical Design Review
,
The discussion in Sec'
. El.2.3 of this report covers the electrical design
review of the LPI functions of the DHR system.
j
El.3.4
Instrumentation and Control Design Review
El.3.4.1
Scope of Review
,
The scope of the instrumentation and control design assessment consisted of a
review of LPI system design and associated documents.
The team reviewed the
instrumentation and control portions of sections 6 and 7 of the USAR,
technical specifications, system descriptions, P&lDs, loop diagrams,
i
21
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- - . -
. - - - - - -.
- - - -.
- - .
.- - -
e
.
.
.
operational schematics / control logic diagrams, four setpoint calculations and
loop uncertainty analyses, and ten instrument data packages.
The team also
reviewed the associated surveillance, normal and emergency operating
procedures, and two modification packages.
El.3.4.2 Findings
The system design documents reviewed by the team adequately supported the
design bases, except for the items discussed in the following paragraphs.
'
a.
BWST low-low level Setooint
The BWST level instrument loop provides input for the low-low BWST level (SFAS
Actuation Level 5) permissive to initiate recirculation flow from the
cont:inment vessel emergency sump.
The team noted several inconsistencies in
the BWST Low-Low level trip setpoint value shown in the various documents.
TS
Table 3.3-4 specified a Low-Low level trip setpoint of 89.5 to 100.5 inches,
"with an allowable value of 88.3 to 101.7 inches," measured from the bnttom of
the tank.
USAR Section 6.3.1.4 states that at a BWST level of approximately 8
feet a permissive signal is provided to allow manual opening of sump valves.
Operational Schematic 0S-004, Sheet 1, Revision 20, and Instrument Data
Package 49A-ISL1525A, Revision 1, specify a calibrated setpoint of 95" from
the suction pipe or 99" from the tank bottom.
Calculation C-ICE-48.01-004,
"SFAS BWST Low Level Setpoint," Revision 2, established a loop accuracy value
of 19.5" with a setpoint of 96".
Document RFA 94-0509 dated January 17, 1995, calculated the minimum acceptable
BWST level at which the SFAS Level 5 permissive bistable will trip.
The team
noted the following discrepancies in this document: the zero level reference
point was at the bottom of the tank, while the setpoint calculation assumed a
reference point 4" higher resulting in a conservative calculated setpoint; the
licensee could not retrieve the basis for the instrument string inaccuracy and
bistable tolerance values of 113.5" and 15.5" respectively that were used to
establish consistency with the technical specification trip setpoint; and
although the document performed the function of a calculation or analysis, it
did not comply with the format and review requirements for calculations.
To verify consistency of the setpoint calculation methodology, the team
reviewed a subsequent revision to the instrument string data package and
Revision 3 of the setpoint calculation.
On the basis of review of these
documents, the team determined that the BWST low-low level setpoint of 95" had
adequate margin to account for instrument error, valve stroke time, and
operator delay, and to ensure that enough water from the BWST had been
transferred to the containment to provide the minimum NPSH for the LPI and
containmentspraypumpstakingsuctionfromthecontainmentemergencysump.
The team verified that the permissives and interlocks for the valves on the
suction lines from the BWST and containment emergency sump were acceptable.
-
22
l
_ _J
-
- _ _ _ _ _ _ _ _ _ _ _ - _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . _ _ _ _
.
.
To resolve the team's concerns, the licensee indicated that document RFA 94-
0509 would be reissued as a calculation and would include verification of
assumptions and references.
Also an evaluation of interfacing documents and
other affected calculations would be performed.
(Inspection follow-up Item
50-346/97-201-09)
The team also reviewed the BWST level instrument setpoints for high and low
level alarms and determined that they were acceptable,
b.
Hiah Containment Pressure (SFAS level 3) Actuation Setooint
The containment pressure instrument loop provides input for the high
containment pressure (SFAS Actuation Level 3) permissive to initiate LPI
operation.
In the reviewed documents the team noted inconsistencies in the
containment high pressure trip setpoint.
TS Table 3.3-4 provided a trip
setpoint of 18.4 psia, with an allowable value of 18.52 psia.
Justification
for these technical specification values were provided in Rechtel letter BT-
11388, "TM1 Action Plan, Section ll.E.4.2, Containment isolation
Dependability," dated January 7, 1981.
Instrument Data Package 59A-ISP2000,
Revision 5, showed the actual calibrated setpoint as 17.4 psia, providing a
margin of 1 psia.
The licensee was unable to provide supporting documentation
for this margin but considered 1 psia as a reasonable value to account for
instrument loop inaccuracies, in addition to a built-in margin of 1 psia in
the technical specifications as evaluated in the Bechtel letter.
The team was
concerned that no loop uncertainty calculation had been performed to document
that the combined instrument inaccuracies would not exceed the setpoint
margin.
The team noted that calculation C-ICE-48.01-001, "SFAS Containment Pressure
Actuation," Revision 0, established a loop accuracy value of 1.5 psia (which
exceeded the 1 psia margin discussed above) and a setpoint of 18.625 psia.
However, the licensee stated that this calculation was intended to support a
future licensing amendment that would implement a new setpoint and revised
technical specification values.
The licensee acknowledged the weakness in the I&C calculation and indicated
that this issue will be addressed as part of a planned DBD reconstitution
program at DB.
(Inspection Follow-up Item 50-346/97-201-10),
c.
RG 1.97 Indication for BWST level
Emergency procedure DB-0P-02000 required monitoring of BWST level indicators
L1-1525A, B C, and D, on the main control room vertical panel C5716 to permit
manual switchover of the DH pump suction from the BWST to the containment
emergency sump.
The team noted that these indicators were powered from a
Class lE bus and seismically mounted, but they were classified as non safety-
related.
The indicators are classified as a Type A Category 1 variable
requiring full Class lE qualification in accordance with RG 1.97 because they
provide primary information to permit control room operators to take manual
control actions,
23
i
l
,
.
,
!
The team also noted that there were four other BWST level indicators (LI-
'
1525Al, Bl
Cl, and 01) located on the safety-related SFAS cabinets in the
main control room. The team considered it appropriate for the operators to
monitor the safety-related BWST level instruments during post-accident
conditions.
The licensee initiated PCR 97-1397 to revise the procedure DB-OP-
02000 to include monitoring of the safety-related level indicators in the SFAS
cabinets when performing the DH pump suction switchover operations.
d.
Document Discrepancies
The team identified the following document discrepancies:
Drawing 05-004, Sheet 1, did not show the correct ccior coding and
instrument symbols for FYlDH2A and FYlDH28.
The licensee issued DCN 05-
004-0054 to correct the drawing.
Drawing E-30-23 showed an incorrect model number for containment
pressure transmitter PT-2001.
DCN E-30-23-35 was issued to delete this
information from the drawing, because it was provided in M-7201.
Section 1.2.1.3 of system description 50-042 stated that a safety-
related alarm shall be provided if the dropline valves were open and
power was not removed.
The annunciator system is non-safety related.
The licensee issued SDCN 42-02-004 to correct the system description.
Section 1.1.1.1 of system description 50-042, stated that valves DHil
and DHl2 were associated with pressure switch PSH-RC284.
However, only
valve DHil was interlocked-with the pressure switch. The licensee
issued SDCN 42-02-005 to correct this discrepancy.
El.3.4.3 Conclusions
The team concluded that the instrumentation and control design for the LPI
'
system was adequate.
All=setpoints that were revie,4ed had adequate margins
and technical specification limits were met.
However, some inconsistencies
were observed between the technical specifications, loop uncertainty
calculations, and data sheets.
The basis for the current setpoint for BWST
low-low level documented in RFA 94-0509 was not appropriately verified and
approved, although the current setpoint was acceptable.
The licensee
initiated corrective actions for the discrepancies identified by the team.
El.3.5 LPI System Walkdown
El.3.5.1
Scope
The team inspected the installed mechanical, electrical, and instrumentation
and control equipment for the LPI system to evaluate their consistency with
drawings, de.ign specifications, and regulatory requirements.
During the
walkdown the team interviewed plant system engineers, and operations and
,
maintenance personnel.
The team walkdown covered the HPI pump rooms, DH
24
..
..
. . . . .
-
____ _ _ _ - _ _
,
.
cooler room, control room, auxiliary shutdown panel, BWST area, cable
spreading room, switchgear rooms, battery rooms, and electrical distribution
panels.
The results of the electrical walkdown are discussen ti' Section El.2.6 of this
report.
El.3.5.2 Findings
a.
Control of Temoorary Shieldina
During the plant walkdown, the team noted a temporary shielding installation
on a pipe near valve DH134 in decay heat cooler room 113.
The line was
currently not in use and had apparently become a potential crud tra).
This
shielding had temporary shielding request tag No. 94-0003, dated Fearuary 3,
1994, attached to it.
This installation had been in place for overthree
years.
Request for assistance (RFA) 94-0042 that was issued to evaluate this
temporary shielding installation was approved for temporary use on,y by Design
a
Engineering / Civil on January 26, 1994.
The team inquired whether this
installation had been periodically reviewed and approved by engineering and
whether the attachment of shielding to the piping was analyzed from the poisit
of view of seismic II/I concerns.
The licensee stated that the shielding had
not been reviewed since its initial installation and that its attachment to
the piping had not been seismically analyzed.
The licensee reviewed the original calculation done in response to RFA 94-
0042,-and concluded that the RFA was still applicable for use on a temporary
basis, and the attachment of the shielding to the piping considering the
seismic loads was acceptable.
Installation of temporary shielding was controlled by procedure DB-HP-01802,
" Control- of Temporary- Shielding." This procedure was currently in the process
of.being enhanced and will address the concerns raised by the inspection team
regarding periodic review of installed tempora /y shielding packages to ensure
installation requirements continue to be met, and-inclusion of complete
descriptions of the installation and fastening methods in the shielding
request documents to ensure seismic considerations were fully understood by
all parties involved in the preparation, review, and approval of these
requests,
b.
BWST Level Transmitters
The team reviewed the instrument installation details and instrument data
packages and performed verification walkdowns of the BWST level transmitters.
The transmitters were properly spanned, compensated, and were calibrated to
account for boron concentration and differences in elevations.
During the walkdown of the four BWST level transmitters in tho valve pit and
the shed next to the BWST, the inspection team noted that the transmitter
mounting brackets, nuts, and bolts for transmitters LT-1525B and LT-1525C.were
'
severely rusted while the mounting hardware for LT-1525A and LT-15250 showed
A
25
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_ _ _ _ _ _ . _ . _ _ _ _ _ . _ _ - - . _ . _ . _
_
_
._ .
_ _ _ _ _ _ _ _ _ _ _ .
.
.
.
.
signs of corrosion to some degree.
The team was concerned that structural
integrity of two of four transmitter supports could be degraded.
The licensee initiated work requests WR-97-1286 and WR-97-1247 to repair
transmitters LT-1525B and LT-15250.
The team noted that PCAQR 94-0840 dated
September 28, 1994, had previously identified corrosion of LT-15258 and
LT1525-0 based on a seismic qualification walkdown of the components in the
BWST pit, and the licensee had concluded that the condition of the transmitter
supports was acceptable.
The licensee conducted another inspection on January
13, 1997, and concluded that the supports were still capable of meeting
operability requirements.
However, the team noted that the PCAQR and
corresponding evaluations only' addressed the transmitters in the BWST pit and
did not include the two transmitters in the shed, one of which (LT-1525C) had
been severely corroded.
The licensee also issued work requests WR-97-1546 and WR-97-1550 to repair
supports for transmitters LT-1525A and LT-1525D.
The team expressed its
concern about the delays in initiation of corrective actions and the licensee
stated that the focus was on rectifying water leakage in the pit which took a
I
long time to accomplish ~and had delay 3d implementation of any corrective
action and closecut of the PCAQR.
During the implementation of the work.
request, the licensee will examine the removed hardware to verify that the
corrosion was not severe enough to have had the potential for failure of the
supports,
in this instance, the licensee's measures to assure that conditions
adverse to quality are promptly corrected as required in 10 CFR 50, Appendix
B, Criterion XVI, " Corrective Action," were not adequate. (Unresolved item 50-
346/97-201-11).
The team noted that some piping insulation and protective metal covers had
been removed from the HPI pump recirculation and test return lines to the BWST
and were left on the catwalk near DH-7A & B valve operators.
The licensee
stated that this material was wet at the time of inspection of the BWST valve
pit.
The piping insulation should have been reinstalled in accordance with
the niaintenance work package in response to corrective actions for PCAQR 94-
0840, but did not get included in tne process.
The licensee reinstalled the
required piping in w1ation after the team questioned the acceptability of the
uninsulated sections of the piping.
The licensee stated that during the
period without insulation, the piping heat tracing and use of space heaters in
the area prevented potential freezing problems,
c.
Modification of Valves DH13A/B and DH14A/B
Modification 87-1168 was implemented to replace the single-acting type
actuators on DH cooler discharge valves DH13A/B and bypass valves DH14A/B with
double-acting type actuators.
P&lD M-033A and drawing 05-004 Sh.1 show the
double-acting type actuators that agree with the as-installed condition, but
instrument installation detail drawing Q-084 and the vendor drawing series M-
329 still showed the old configuration with single-acting valve actuators.
The team noted that these drawings were not listM as affected documents in
the modification package,
it was noted that marked-up PalD, isometric
drawings and bills of materials were used to install the modification,
26
,
"
-
.
-4
However, no installation detail drawing or a revision to drawing Q-084 was
included in the modification package.
The installation was consistent with
the information provided in the modification package and was acceptable.
Section 6.6.2.f of plant m,dification procedure NG-EN-00301, states that the
Planner shall verify that applicable documents, such as change notices,
reflect the as-built configuration and had been correctly updated as part of
the post implementation / closeout process.
The licensee acknowledged that in
the modification closecut process drawing Q-084 was omitted in error, and
initiated DCN Q-084-1 to update the drawing.
The licensee stated that vendor drawings for the actuators and associated
control tubing are classified as " fabrication" status, and are not required to
be updated.
X1
Exit Meeting
After completing the on-site inspection, the team conducted an exit meeting
with the licensee on June 20, 1997.
During the meeting the team presented the
results of the inspection. A list of persons who attended the exit meeting is
contained in Appendix B.
.
27
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.
,
APPENDIX A
OPEN ITEMS
This renort categorizes the inspection findings as unresolved items and
j
inspection follow-up items in accordance with the NRC Inspection Manual,
i
Manual Chapter 0610. An unresolved item (URI) is a matter about which more
information is required to determine whether the isste in question is an
acceptable item, a deviation, a nonconformance, or a violation.
The NRC
Region 111 office will issue any enforcement action resulting from their
review of the identified unresolved items. An inspection follow-up item (IFI)
is a matter that requires further inspection because of a potential problem,
because specific licensee or NRC action is pending, or because additional
information is needed that was not available at the time of the inspection.
Item Number
Findino
I_i_tig
lyAt
i
50-346/97-201-01
Ill
HPl flow Requirements for SG Tube Rupture Accident
(Section El.2.2.2.a.)
50-346/97-201-02
IFI
Safety Class Interface at Pressure Gage Isolation
Valves (Section El.2.2.2.d.)
50-346/97 201-03
IFI
Environmental Qualification of Equipnent in ECCS Rooms
(Section El.2.2.2.f.)
50-346/97-201-04 IFI
Battery Charger Surveillance Testing (Section
El.2.3.2.a.)
50-346/97-201-05 IFI
Testing of Inverter and Associated Components (Section
El.2.3.2.b.)
50-346/97-201-06 URI
USAR Discrepancies (El.2.7)
50-346/97-201-07 URI
Reverse Flow Testing of LPI Pump Check Valves and HPI
Pump Recirculation Stop-Check Valves (Section
El.3.2.2.c.)
50-346/97-201-08 IFI
ECC5 teakage Testing (El.3.2.2.c.)
50-346/97-201-09 IFl
BWST Low-Low Level Setpoint Calculations (El.3.4.2.a.)
50-346/97-201-10 IFl
High Containment Pressure Actuation Setpoint
(El.3.4.2.b.)
50-346/97-201-11 URI
Corrective Action for BWST Level Transmitter Support
Corrosion-(E1.3.5.2.b.)
A-1
- ,-.
.
,
APPENDIX B
l
EXIT-MEETING ATTENDEES
[LAE
ORGANIZATION
Toledo Edison
J. Stetz
Senior V.P., Nuclear
J. Wood
V. P., Davis-Besse
J. Lash
Plant Manager
T. Myers
Director, Nuc.-Support Services
R. Donnellon
Director, Engineering and Services
F. Swanger
Manager, D-B Engineering
J. Freels
Manager, Reg. Affairs
J. Rogers
Manager, Plant Engineering
H. Stevens
Manager, Nuclear Safety & Inspections
D. Lockwood
Supervisor, Compliance
C. Kraemer
Engineer, Compliance
A. Stallard
Sr. Ops. Advisor
J. Hartigan
Sr. Staff Engineer, DBE
K. Prasad
Sr. Staff Engineer, DBE
J. Marley
Sr. Engineer, Plant Engineering
A. Wise
Sr. Engineer, Plant Engineering
R. Hovland
Sr. Engineer, Plant Engineering
G. LeBlanc
Sr. Engineer, DBE
P. Jacobsen
Sr. Engineer, DBE
lE
M. Ring
Chief, Engineering Branch, Region III
D. Norkin
Chief, Special Inspection Section, NRR
M. Miller-
-Reactor Engineer, Region Ill
S. Stasek -
Sr. Resident Inspector
S. Malur
Team Leader, NRR
A. Bizzara
Contractor, S&L
M. Sanwarwalla
Contractor, S&L
R. Jason
-Contractor, S&L
K. Steele
Contractor, S&L
L. Rogers
Contractor, S&L
B-1
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.
,
4
APPENDIX C
Auxiliary Building
Alternating Current
A0V
Air-0perated Valve
American Society of Mechanical Engineers
AT0G
Abnormal Transient Operating Guidelines
AUX S/D
Auxiliary Shutdown
AUX
Auxiliary
AUX S/D PNL.
Auxiliary Shutdown Panel
Babcock & Wilcox
BS
Building Spray
BTU
British Thermal Unit
BWST
Borated Water Storage Tank
Core Flood
CFR
Code of Federal Regulations
Core Flood Tank
CTHT
Containment
CV
Control Valve
CVT
Constant Voltzge Transformer
Davis-Besse
Design Base Accident
Design Basis Documentation
DBMMS
Davis-Besse Maintenance Management System
Davis-Besse Nuclear Power Station
Direct Current
DCN
Drawing Change Notice
Document Change Request
DH
Decay Heat
DHRS
Decay Heat Removal System
DP
Differential Pressure
EcCS
EDSFI
Electrical Distribution System Functional Inspection
E0P
Emergency Operating Procedure
Environmental Qualification
Engineered Safety Features
Engineered Safety Features Actuation System
F
Fahrenheit
Field Change Notice
FCR
Facility Change Request
Flow Control Valve
ft., FT
Feet or Foot
Feed Water
gal., GAL
Gallons
gpm., GPM
Gallons Per Minute
C-1
)
-
_ _ _ _ .
______
.
i
High Pressure
High Pressure Injection
HS
Hand Switch
Heating, Ventilating, and Air Conditioning
HZ, Hz
Hertz
Instruments and Control
IFI
Inspection Follow-up Item
IN
Information Notice
In Service Inspection
In Service Testing
kVA
Kilovolt-Ampere
License Amendment Request
LCO
Limiting Condition for Operation
LER
Licensee Event Report
Loss-of-Coolant Accident
Loss-of-Offsite Power
LF
Low Pressure
Low Pressure Injection
M/HELB
Moderate /High Energy Line Break
Measuring and Test Equipment
MCB
Main Control Board
Motor Control Center
MF
Main Feedwater
Motor Operated Valve
MS
MU&P
Make-Up and Purification
MWO
Maintenance Work Order
NC
Normally Closed
NG
Nuclear Group Procedure
NNI
Non-Nuclear Instrumentation
NNS
Non-Nuclear Safety
NO-
Normally Open
Net Positive Suction Head
NRC
Nuclear Regulatory Commission
Nuclear Safety Related
Nuclear Steam Supply System
Once Through Steam Generator
Piping & Instrumentation Diagram
PB.
Piggy-Back
PCAQ
Potential Condition Adverse to Quality
PCAQR
Potential Condition Adverse to Quality Report
Pressure Indicator
Pressure Indicator Controller
Preventive Maintenance
Post Maintenance Testing
PMW0.
Preventive Maintenance Work Order
Power Operated Relief Valve
psi, PSI
Pounds per Square inch
C-2
_
.
.
..
.
.
_-. -
I
o t ,, e
.
i
.t
psia, PSIA
Pounds per Square Inch Absolute
psid,_PSID
Pounds per Square Inch Differential
psig, PSIG
Pounds per Square Inch Gauge
Pressure Transmitter
Polyvinyl Chloride
Quality Assurance
Reactor-Building
RC
Reactor Coolant Pump
REV
Revision
RFA
Request for Assistance
Regulatory Guide
.
RV
Reactor Vessel
S&L
Sargent & Lundy
S\\D
Shutdown
Safety Actuation
Standard Cubic Feet per Hour
SCN
Specification Change Notice
SDCN
System Description Change Notice
Safety Evaluation
SEC
Seconds
Safety Evaluation Report
SF
Spent Fuel
SFAS
Safety Features Actuation System
SFPP
Spent Fuel Pool Pump
S0V, SV
Solenoid Operated Valve
Safety Features Display System
Specification
Safety System Functional Inspection
Temperature Control Valve
Total Developed Head
Toledo Edison
.
TM
TMM
Temporary Mechanical Modification
Temperature Recorder
TS, Tech. Spec.
Technical Specifications
TT
Temperature Transmitter
Uninterruptible Power Supply
URI-
Unresolved Item
Updated Safety Analysis Report
V DC, VDC
Volts DC
V AC, VAC
Volts AC
W
Watts
C-3
j