ML20140F837
| ML20140F837 | |
| Person / Time | |
|---|---|
| Site: | Perry  |
| Issue date: | 06/10/1997 |
| From: | NRC (Affiliation Not Assigned) |
| To: | |
| Shared Package | |
| ML20140F796 | List: |
| References | |
| 50-440-97-201, NUDOCS 9706130253 | |
| Download: ML20140F837 (83) | |
See also: IR 05000440/1997201
Text
.
.
.<
U.S. NUCLEAR REGULATORY COMMISSION
OFFICE OF NUCLEAR REACTOR REGULATION
i
Docket No.:
50-440
License No.:
Report No.:
50-440/97-201
Licensee:
Centerior Services Company
7
Facility:
Perry Nuclear Power Plant, Unit 1
Location:
P.O. Box 97, A200
Perry, Ohio 44081
Dates:
February 17-March 27,1997
Inspectors:
Morris Branch, Team Leader, Special Inspection
Branch
Robert Hogenmiller, I&C Engineer *
,
'
Robert Najuch, Lead Contractor Engineer *
'
Dennis Vandeputte, Mechanical Engineer *
Arvind Varma, Electrical Engineer *
Maty Yeminy, Mechanical Engineer *
- Contractors from Stone & Webster Engineering Corporation
Approved by:
Donald P. Norkin, Section Chief
Special Inspection Branch
Division ofInspection and Support Programs
Oflice of Nuclear Reactor Regulation
4
,
4
9706130253 970610
ADOCK 05000440
G
- - . .
.
-- .
. -
. - - -
_
_ . - .
--
, - . . . _ . . -
_ . - . .
.
.
j
Table of Contents
4
EXECUTIVE SUMMARY
i
.
.
.
.
.
El.1 Inspection Scope and Methodoloey .
1
..
.. . .
.
I
El.2 High-Pressure Core Sprav . .
1
..
.
..
.
El.2.1 System Description and Safety Function
1
El.2.2 Mechanical
.2
.
...
.
.
El.2.3 Electrical .
12
..
..
..
El.2.4 Instmmentation and Controls
. 15
.
. ..
El.2.5 System Interfaces
19
.
.
.
El.2.6 System Walkdown
. 24
.
.
El.2.7 USAR Review
.26
.. .
.
.
El.3 Emereency Closed Cooline . .
. 28
..
. .
.
.
El.3.1 System Description and Safety Function
. 28
.
El.3.2 Mechanical
30
.
.
. .
.
El.3.3 Electrical .
38
.
..
.
El.3.4 Instrumentation and Controls
.38
.. .
.
.
El.3.5 System Interfaces
. 40
...
.
El.3.6 System Walkdown
.42
. . .
.
.
El.3.7 USAR Review
44
i
.
.
.
.
,
E1.4 Design Control
. 44
.
.
.
Appendix A
List of Open Items
. . A- 1
.
.
.
l
Appendix B
Exit Meeting Attendees
B-1
{
..
.
.
.
Appendix C
List of Documents Reviewed ,
C-1
Appendix D
List of Acronyms
. D- 1
.
..
.
.
Attachment 1
Slides Used During Public Exit
. Attachment 1-1
.
.
.
_
_
___
'
.
,
EXECUTIVE SUMMARY
From February 17 through March 27,1997, the staff of the U.S. Nuclear Regulatory Commission
(NRC), Oflice of Nuclear Reactor Regulation (NRR), Special Inspection Branch, conducted a
design inspection at Perry Nuclear Power Plant, Unit 1 (PNPP-1). The inspection team consisted
of a team leader from NRR and five contractor engineers from Stone & Webster Engineering
Corporation (SWEC).
The purpose of the inspection was to evaluate the capability of the selected systems to perform
the safety functions required by their design bases, the adherence of the systems to their design
and licensing bases, and the consistency of the as-built configuration and system operations with
the updated safety analysis report (USAR). For the purpose of this inspection, the team selected
the high-pressure core spray (HPCS) and emergency closed cooling (ECC) systems, on the basis
of their importance in mitigating design-basis accidents (DBAs) at PNPP-1. In particular, the
inspection focused on the safety functions of these systems and their interfaces with other
systems.
For guidance in performing the inspection, the tearn followed the applicable engineering design
and configuration control portions ofInspection Procedure (IP) 93801, " Safety System
Functional Inspection"(SSFI). The team reviewed portions of the plant's Updated Safety
Analysis Report (USAR), design-basis documents, drawings, calculations, modification packages,
surveillance procedures, and other documents pertaining to the selected systems.
The team identified the following issues, some of which challenged the capability of the systems to
perform their complete scope of design basis accident mitigation actions. Where appropriate, the
licensee took immediate corrective or compensatory actions to ensure system operability.
The licensee changed the ECC surge tank sizing basis from a 7-day supply to a 30-minute
supply, with operator actions required outside the control room to initiate makeup from the
emergency service water (ESW) system. The team concluded that this change constitutes a
potential unreviewed safety question, as defined in Title 10, Section 50.59, of the Code of
FederalRegidations (10 CFR 50.59) since the probability of occurrence of a malfunction of
equipment important to safety was increased. As a result of this change, operators could
incur a calculated total radiological exposure of approximately 12 rem within the first 90
minutes following a DBA. Additionally, the safety evaluation that supported the change did
not adequately assess the potential for operator error, or surge tank overpressurization and
adjacent area flooding when makeup from the ESW system fills the tank water-solid.
The operation of the suppression pool cleanup (SPCU), essentially on a continuous basis, is
-
not consistent with the facility description presented in the USAR and is not supported by a
safety evaluation. Operation in this mode does not support the net positive suction head
(NPSH) evaluations specified by Regulatory Guide (RG) 1.1, as presented in the USAR.
This condition has existed since initial licensing of PNPP-1, as a result ofinsufficient
analysis and corrective actions in resolving design deficiencies concerning improper
i
- _
,
.
connection of SPCU piping downstream of the HPCS suppression pool suction valve rather
than upstream. The HPCS/SPCU system interface design and an additional issue regarding
application of pipe crack criteria (rather than pipe break criteria) to nonsafety, non-seismic,
moderate-energy piping systems were referred to the NRC staff for further review.
The actual droop setting of the Division III emergency diesel generator (EDG) deviates
-
from the vendor's recommended setting and constitutes an undocumented modification.
The team was concerned with the treatment of droop bias with respect to Technical
Specification (TS) acceptance criteria and the efrect on end user mechanical equipment.
When droop is considered as a bias, HPCS pump surveillance test results do not meet design
flow requirements for all accident situations.
The HPCS and reactor core isolation cooling (RCIC) suction piping and the condensate
-
storage tank (CST) instrument lines installed between the CST and the concrete
containment dike are not adequately protected against external missiles, and the licensee's
protective provisions were not consistent with the USAR description. On the basis of this
team finding, the licensee determined that the HPCS and RCIC suctions from the CST were
inoperable, and they realigned the systems to the suppression pool. In addition, the licensee
instructed plant operators to maintain HPCS and RCIC suctions aligned to the suppression
pool until the issue could be resolved.
In addition, the team identified the following issues which indicated programmatic deficiencies:
The team identified deviations from licensing commitments regarding presem and past
-
testing / inspection and cleaning of the HPCS room cooler.
Inconsistencies exist in the plant's design and licensing bases, with regard to ECC surge
.
tank makeup and monitoring; passive single failure definitions; and application of pipe crack
1
criteria (rather than pipe break criteria) to nonsafety, non-seismic, Category 1, moderate-
energy piping outside containment.
i
In several instances, the licensee had difliculty in retrieving design-basis information. This
.
concern contributed to the licensee's inappropriate "use-as-is" disposition of plant hardware
problems concerning the lack of overfrequency protection for the HPCS pump and
inadequate protection of exposed equipment against the effects of tornado missiles.
The team identified weaknesses in the licensee's development and control of calculations, as
well as the review and approval processes. These included se!ection ofincorrect codes
prescribed by the American Society of Mechanical Engineers (ASME) for evaluation of the
HPCS overfrequency protection relay removal and ECCS heat exchanger tube wall
thickness. Other weaknesses included non-conservative system modeling regarding
overpressure protection, flooding analysis, and system performance associated with the ECC
surge tank; and non-conservative assumptions in the HPCS vortex and NPSH calculations .
Within the electrical area, the licensee did not adequately maintain design-related
ii
.
_
.
-
.
-.
.
_.
.
.
calculations in accordance with Nuclear Engineering Instruction (NEI) 0341,
" Calculations." Moreover, in some cases, the calculations were inconsistent with the
USAR.
The team identified test control weaknesses. For example, analyses of test results for valve
leakage at the interface between the ECC and nuclear closed cooling (NCC) systems failed
to adjust measured leakage rates for predicted accident system pressures. In addition, when
the licensee used testing to verify calculation assumptions, feedback of test results to close
out calculation assumptions was not always timely.
1
During the course of the inspection the licensee documented many of the issues in their corrective
action program. The number and nature of the items documented on potential issue forms (PIFs),
represented very good sensitivity regarding problem identification.
l
i
iii
. - .
>
.
.
III. Engineering
El
CONDUCT OF ENGINEERING
1
El.1 Inspection Scope and Methodo:ory
The primary objectives of the design inspection at Perry Nuclear Power Plant, Unit 1 (PNPP-1),
were to evaluate the capability of the systems to perform their safety functions required by design
bases and to verify whether the licensee, Centerior Services Company, has maintained the plant in
compliance with its design and licensing bases. As the subject of this inspection, the staff of the
U.S. Nuclear Regulatory Commission, Office of Nuclear Regulatory Regulation (NRR), selected
)
the high-pressure core spray (HPCS) and emergency closed cooling (ECC) systems, because of
their importance in mitigating design-basis accidents (DBAs) at PNPP-1. In particular, this
inspection focused on the safety functions of the selected systems and their interfaces with other
systems throughout the plant. For guidance in performing the inspection, the team fo!! owed the
applicable engineering design and configuration control portions ofInspection Procedure (IP)
93801, " Safety System Functional Inspection" (SSFI).
Appendix A iden'.ifies the open items and issues resulting from this inspection, while Appendix B
lists the individuals who attended the exit meeting on April 22,1997. Appendix C lists the
documents reviewed by the team, and Appendix D defines the various acronyms used in this
report
El.2 Ilieh-Pressure " ore Spray (IIPCS) System
El.2.1 System Description and Safety Function
The HPCS is an emergency core cooling system (ECCS) capable ofproviding coolant at either
high or low reactor pressure. The system is initiated in response to either low reactor water level
(level 2) or high drywell pressure. The HPCS system maintains the reactor vessel water level
above the top of the active fuel for small-break loss-of-coolant accidents (LOCAs). Cycling the
HPCS injection valve at high and low reactor water levels controls the reactor vessel level.
For larger breaks that result in reactor depressurization, the HPCS works in conjunction with
other ECCS equipment and provides spray cooling of the core. The system includes a motor-
driven centrifugal pump that takes suction from either the condensate storage tank (CST) or the
suppression pool. The suppression pool provides the water supply for continuous operation of
the system, and suction from the CST automatically transfers to the suppression pool when the
CST water supply is exhausted or when the suppression pool level is high.
1
_.
.
_
- _ - . _ .
. . _ -
_
.
__
._
_
-
__
.
.
The HPCS system also serves as a backup to the reactor core isolation cooling (RCIC) system in
the event that the reactor becomes isolated from the main condenser and feedwater flow is lost
during operation.
As designed, the suppression pool cleanup (SPCU) system interfaces directly with the HPCS,
taking suction from the HPCS suppression pool suction line between the containment isolation
i
valve and the pump. Therefore, during SPCU system operation it is necessary to align the HPCS
system suction to the suppression pool (instead of the CST, as described in the Updated Safety
'
Analysis Report (USAR)).
i
The HPCS system operates using normal offsite auxiliary alternating current (AC) power or
power provided by its own Division III emergency diesel generator (EDG). This EDG is
,
4
'
designed to achieve its rated speed within 13 seconds, and the HPCS system is designed to
achieve its rated flow within 27 seconds.
El.2.2 Mechanical
!
El.2.2.1 Scope of Review
In evaluating the mechanical design of the HPCS system, the team reviewed the basic system
design as depicted in plant documents. Specifically, the team reviewed sections of the USAR,
technical specifications (TS), plant procedures, General Electric (GE) system specifications,
calculations, piping and instrumentation diagrams (P& ids), physical drawings, training manuals,
maintenance records, inservice inspection (ISI) records, and setpoint data packages. In addition,
the team assessed the capability of system equipment to perform its intended functions. The
j
review also included a system walkdown, during which the team witnessed a system test in the
control room and conducted interviews with the system engineer, design engineers, and control
]
room personnel.
El.2.2.2 Findines
!
a. HPCS Functions
PNPP uses a " Design-Basis Documentation Hierarchy" desk guide to identify sources of
information to define and maintain the current design consistent with the plant's design bases.
This desk guide cautions the user to verify the accuracy of any information contained in plant-
,
related documents. As of this inspection, the licensee had not yet generated design-basis
,
documents (or the equivalent) for the PNPP systems.
.
l
To facilitate the inspection process, the team requested that the licensee identify the functions of
the HPCS system. The licensee described the HPCS functional design bases through references
to multiple GE design specifications, the USAR, the process flow diagram, a station blackout
(SBO) technical assignment file, and HPCS design change packages (DCPs). Together, these
.
2
_ _ . _ _ . _ _
.
_ _ ... _ _ _ _ __
_ _ _ . _ _ _
_
..
_ _ .
_ _ - . _
'
.
.
4
I
references identified a variety of HPCS functions, including core cooling to prevent fuel damage
for large- break LOCAs, core makeup water for small-break LOCAs, backup for RCIC, SBO
4
makeup water to the vessel, and support ofvarious transients and accidents (identified in Chapter
15 of the USAR) including anticipated transient without scram (ATWS).
b. CST Volume Design Basis
i
GE Design Specification 22A3131 AD, "High-Pressure Core Spray," Revision 6,
.
Requirement 4.3.1, states that each boiling-water reactor (BWR) unit must maintain a condensate
i
water storage reserve of 150,000 gallons. The team requested that the licensee provide the design
basis for the GE-imposed 150,000 gallon requirement, since the basis was not apparent. In
i
response, the licensee contacted GE, and GE indicated that the required volume reflected the
water inventory makeup required for RCIC to remove reactor decay heat during the first 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />
1
following reactor shutdown, assuming that the safety relief valves (SRVs) maintain reactor
i
pressure. The HPCS system is classified as a backup system to RCIC; therefore, requirements
i
applicable to RCIC also apply to HPCS. The CST is classified as a nonsafety-related source of
i
water and, consequently, is not credited for accident mitigation.
i
~
c. NRC Bulletin 96-03, ECCS Suction Strainers
i
!
On May 6,1996, the NRC issued Bulletin 96-03 to all operators of nuclear power plants.
!
Specifically, this bulletin warned the operators of potential plugging of emergency core cooling
!
suction strainers by debris. In the bulletin, the NRC staffidentified three options to resolve this
j
issue, including installation of a large-capacity passive strainer, a self-cleaning strainer, or a
!
backflush system.
1
In its response to the NRC Bulletin, PY-CEI/NRR-211IL, dated November 4,1996, Cleveland
4
{
Electric Illuminating (CEI) stated that some events could block the ECCS strainers at PNPP-1
i
with insulation from the drywell. This blockage will result in an insuflicient net positive suction
l
head (NPSH) for the ECCS pumps, leading to subsequent failure to meet the core cooling
requirements. To address this problem, CEI proposed to install a large passive strainer design
(Bulletin 96-03 option 1), which is a floor-mounted strainer that circles the suppression pool.
4
CEI intends to install the new strainer dpring the next refueling outage (fall 1997). The licensee's
corrective action for this issue appears to be appropriate, and implementation of the licensee's
corrective actions is being controlled through the bulletin commitments.
.
p
j
d. Review of HPCS System Vortex Formation While Aligned to the CST
!
Calculation P11-12,"P11 - Level Setpoints in Condensate Storage Tank for E22 and E51
Instruments" dated March 12,1985, determined the CST low-level swapover se' point required to
t
i
ensure that the HPCS system has adequate NPSH and that no vortex occurs before suction valve
i
swapover to the suppression pool. The team reviewed this calculation and idendfied the
following concerns:
i.
3
-
.
,
The licensee based the calculation on a flow rate of 700 gpm for RCIC and 1550 gpm for
.
HPCS, as substantiated by P&ID D-302-012, " Condensate Transfer and Storage System."
The licensee combined the HPCS and RCIC flows since both would be taking a suction
from the CST through a common line. The team questioned the licensee's use of the 2250
gpm flow rate for calculating CST suction line vortex value since a higher flow rate would
be a worst case. Operiting data on the referenced drawing and in the GE Design
Specification 22A313) AS, Revision 3, specifies a maximum HPCS flow rate of 6110 gpm at
200 psi backpressure in the reactor vessel and 7800 gpm at mnout flow. The team also
cordinned that HPCS Process Diagram 4549 20-001, Revision 9A (USAR Figure 6.3.1),
" Accident, System Iriection at Rated Core Spray, Suction from CST," specified the same
high-flow requiremerts for HPCS.
Additionally, the CS T water level setpoints did not address continued drawdown of the CST
.
as the transfer from the CST to the suppression pool takes place. HPCS suction from the
CST continues as the suppression pool suction isolation valve first strokes open, and the
CST suction isolation valve then strokes closed.
On the basis of the teatr's concerns, the licensee issued Potential Issue Form (PIF) 97-0416. The
engineering evaluation on the PIF indicated that the licensee had previously evaluated the
adequacy of the swapover setpoint as part of the system-based instrumentation and control
inspection (SBICI)in 1995, and found it to be acceptable. In resolving the issue in 1995, the
licensee stated that the primary function of HPCS was to alleviate the consequences of a small line
break, when the reactor is at pressure and the required HPCS flow is 1550 gpm. For a large-
break LOCA during which the HPCS will deliver full flow, the licensee contended that
suppression pool swell caused by the LOCA will lead to a transfer of suction to the suppression
pool as a result of the suppression pool high-water level swapover setpoint. However, the
licensee could not identify design-basis documentation that would substantiate the assertion that
pool swell negated the need for the CST level to cause the suction swap during high-flow
conditions, as specified in the GE design documentation. The licensee further indicated that
startup tests, performed at a flow rate of 7200 gpm and a CST level 2 feet below the current
setpoint, verified that no vortex formed before swapover to the suppression pool.
The licensce revised the calculation using a HPCS flow rate of 6110 gpm; however, the team
questioned the revised calculation, since the licensee did not include RCIC flow. Ultimately, the
licensee revised the calculation to consider valve . stroke time and the worst-case pump runout
flow of 7200 gpm. To support the current setpoint, the licensee had to use a less conservative
methodology, which considers operation in the region where vortex formation is possible. In so
doing, the licensee found that air could enter the pipe and travel 380 feet inside the pipe, but the
air would not reach the pump before swapover to the suppression pool. The licensee did not
change the current setpoint level as a result of the revised analysis.
10 CFR Part 50, Appendix B, Criterion III states that the design control measures shall provide
for verifying or checking the adequacy of the design. The licensee's Operations Quality Assurance
4
.
.
Program, USAR 17.2 commits to compliance with Regulatory Guides and Standuds as listed in
USAR Table 1.8-2. USAR Table 1.8-2 commits to following ANSI 45.2.11 - 1974 for Quality
Assurance Requirements For The Design of Nuclear Power Plants. Nuclear Engineering
Instruction NEI-0341 Revision 5 " Calculations" applies to all calculations to establish design
bases or to change design documents. Paragraph 6.2, Calculation Revisions states " Design
Engineer are to monitor calculations to determine if a revision is required e.g. receipt of
new/ revised design input, confirmation of assumption etc." Paragraph 6.3 Review and Approval
states " Verification / review and approval of calculation should precede use of the results for
design, but mus: be completed prior to the component, system, or structure being declared
operable."
The team concluded that the licensee's use of non-conservative flow rates and not considering the
impact of valve timing within the original calculation to resolve the issue in 1995 were
inappropriate. The licensee used nonconservative modeling of HPCS flow at 6110 gpm and did
not include RCIC flow in their initial response to the team's concern. The final calculation which
used HPCS pump runout flow was the appropriate value. These issues represent a weakness with
respect to Criterion III," Design Control," established in Appendix B to Title 10, Part 50, of the
Code offedera/ Regulations (10 CFR Part 50). Additionally, the team questioned the licensee's
basis for not resetting the CST low-level setpoint to provide a margin and preclude the entry of
vortexing into the pipe. Consequently, the team identified this item as Unresolved Item (URI) 50-
440/97-201-01.
e. HPCS Pump Net Positive Suction Head (NPSH)
The team reviewed Calculation E22-1,"NPSH Calculation-HPCS System with DCC-02,"
Revision 0, to verify that the licensee had fulfilled all NPSH-related requirements defined in
USAR Table 6.3-1. The team verified that the calculation used the correct pump runout flow
(7800 gpm), containment pressure (0 psig), maximum pool temperature (212*F), maximum CST
temperature (120 F), suppression pool water level (589 feet), suction strainer clogging (80%
plugged with 9.2-foot pressure drop), and equipment elevation. However, the calculation did not
consider the operation of the SPCU system (as discussed in Section El.2.5.2 of this report) and
had to be revised in order to demonstrate acceptable HPCS NPSH.
f. Keep-Full Pump
Test results for the HPCS keep-full pump (from TXI-229, dated March 19,1996) showed that the
pump was not capable of delivering the 40 gpm flow at 32.5 psi pressure specified in USAR
Section 6.3. The pump delivered 32.4 gpm flow at 34.5 psi which equates to a value less than
specified in the USAR. This degraded condition has existed since July 24,1993, when the
surveillance test was conducted. After identifying this condition, the licensee issued PIF 96-1609,
which requested evaluation of this coadition, as well as establishing new US AR acceptance
criteria. The licensee considered the pump operable even though it was not capable of meeting
US AR flow and pressure values.
5
. _ -
-
.
.
l
!
j
j
The licensee indicated that, even though the keep-full pump was degraded, it was capable of
l
maintaining system pressure above the alarm setpoint. The licensee further indicated that, if the
alarm is received, operators would attempt to raise system pressure in accordance with Alarm
Response Instruction (ARI) H13-P601-16. Revision 4. If unsuccessful, they would confirm that
l
l
the system is filled by checking its fill status (SVI-E22-Ti l83) every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or by performing
l
SOI-E22A, "HPCS High-Point Vent." The licensee had not determined the rate of discharge line
l
pressure decay when the pump is not operating. Consequently, the arbitrary time period of 24
hours may exceed the time at which voids are introduced in the system. To address this issue, the
l
licensee issued PIF 97-0513, documenting that if the keep-full pump was inoperable, performing
i
the SVI once every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> may not account for a pressure decay and may create voids in the
pipe.
The team concluded that the degraded condition of the keep-full pump since 1993 represents
untimely corrective action to resolve the condition or revise the USAR. Consequently, the team
identified this issue as URI 50-440/97-201-02.
,
g. Suction Relief Valve
The HPCS suction relief valve relieves suction pressure by directing flow to the dirty radwaste
system that is outside containment. This design deviates from GE Specification 22A3131,
l
Revision 5, Section 4.2.3.15, which specifies that the pump suction pressure relief valve should
relieve to the suppression pool inside contamment.
During construction, the applicant issued Field Deviation Disposition Request (FDDR), KL1-
4006, dated September 15,1983, stating that from an HPCS standpoint, this new route would not
degrade the safety or reliability of the HPCS system. Although the disposition included
evaluation of potential water inventory loss from the suppression pool, the licensee failed to
document 10 CFR Part 100 release consequences. The licensee stated that an unacceptable
radiological release from a failure of the relief valve was not considered credible. Since, for a
small-break LOCA when the HPCS suction may be pressurized by back-leakage from the reactor
as the HPCS cycles, no fuel damage was postulated in accordance with 10 CFR Part 100. For
large breaks with the reactor depressurized below 100 psi, back-leakage from the reactor vessel
will not cause pressurization to the relief valve setpoint. The licensee issued PIF 97-351 to
document the lack of traceable documentation as to the acceptability of this deviation from the
design specifications. The team considered the licensee's review of this issue acceptable and that
this was a case where the licensee did not adequately document the design basis of the relief valve
!
and the acceptability of the deviation.
l
l
h. Pump Performance / Surveillance Testing
l
l
On February 20,1997, the team witnessed system surveillance test SVI-E22-T2001, which
verified that the HPCS pump is operable by measuring and verifying that the listed pump
parameters are within acceptable limits. This test satisfied the HPCS pump operability
i
6
i
..
i
l
'
.
.
,
requirements of Technical Specifications 3.5.1.4 and 3.5.2.5, and included measurements of
suction pressure, differential pressure, flow rate, and vibration.
The pump fulfilled its test acceptance requirements and satisfied the vendor's performance curve.
In addition, the team reviewed historical records of surveillance testing, which demonstrated that
the equipment typically passed its acceptance criteria and when problems have been noted, the
licensee had initiated appropriate corrective actions.
I. Motor-Operated Valves-GL 89-10
To verify whether the licensee fulfilled the commitments expressed in response to Generic Letter
(GL) 89-10, the team reviewed a sample calculation performed as part of the commitment
program. The sampled calculation, MOV C-0047, "AC Voltage Drop Calculation for Butterfly
MOVs," Revision 3, was performed to determine worst-case motor terminal voltage for the AC-
powered safety-related butterfly motor-operated valves (MOVs). The resulting voltage values
were later used in another calculation to determine the torque output of the butterfly MOVs. On
the basis of this review, both the calculation and the fmal determination were considered
adequate. Item j (below) discusses the effect of the GL 89-10 program on the HPCS injection
valve.
j. Injection Valve Stroke Time
USAR Table 6.3-1 requires the HPCS system to inject at rated flow within 27 seconds. Related
tests record three intervals following a LOCA signal, including the time for the Division III diesel
generator to start and reach rated RPM, the time for the injection valve to reach the full- open
position, and the time for the pump to reach rated flow. The tests do not individually evaluate the
valve opening time and the time required for the pump to reach full flow, but these intervals are
added to diesel start time and are acceptable if the total time is within the required 27 seconds.
The opening time for the injection valve is allowed to reach 29 seconds, since the valve is opened
sufliciently at 27 seconds to allow rated flow to the reactor.
Records of previous valve injection tests showed that the overall time interval was within the
allowable limit, such that even ifeach time interval would have been separately evaluated (not
benefitting from the short diesel start time), it would still have passed its respective acceptance
criterion.
k. IIPCS Testing Mode Operation
GE Design Specification Data Sheet 22A3131 AS and USAR Section 6.3 specify that the liPCS
l
must deliver rated flow to the reacter within 27 seconds after receiving an initiation signal. From
l
the normal operation standby condition, this requires the HPCS injection valve to stroke open and
'
develop the rated flow to the reactor within the 27-second time constraint. The team reviewed
the ability of the HPCS to perform its safety function under the full-flow testing mode of
,
f
7
,
l
l
l
_.
-
- ~
_
-
-
-.
-
-
.
.
1
'
operation. Specifically, while in the test mode of operation HPCS valve realignment would be
necessary in order to establish injection flow to the reactor. Test valves aligned in the test mode
receive closure signals upon HPCS initiation to realign the HPCS for injection to the core.
The licensee had previously noted that the stroke times for the test valves would not support
j
realignment and the 27-second injection time. In particular, Surveillance Procedure SVI-E22-
l
T2001 allows test valve closure times of 60 to 80 seconds, depending on valve size. These stroke
!
times exceed the 27-second time constraint for the HPCS to reach rated flow and indicate that the
,
j
HPCS cannot be considered operable when it is in the test mode configuration.
Surveillance Instruction SVI-E22-T2001, " Precautions and Limitations," indicates that the HPCS
l
should be operated in accordance with SOI-22A. Revision 5 of SOI-22A, effective June 28,
!
1995, requires that the HPCS must be declared inoperable (in accordance with a standing
instruction dated March 8,1995) whenever it is in a secondary mode of operation. Before
March 8,1995, there had been no directives to declare the HPCS inoperable during full-flow
testing.
After recognizing that the HPCS was inoperable while in the test mode the licensee's investigation
failed to determine if other equipment (RCIC, LHSI, LPCS, etc.) was operable as required by TS
when HPCS is inoperable. If the related equipment was inoperable while HPCS was inoperable
because of testing the plant could have been operating in violation ofTS. The licensee issued
PIF 97-0560 to investigate concerns regarding past operability of other systems during HPCS test
performance to determine if the plant had been operated in accordance with the TS.
The team concluded that while undergoint, full-flow testing, the HPCS could not reach rated flow
within 27 seconds of HPCS initiation because of the slower closure of test valves diverting HPCS
injection flow from the reactor. This condition has existed since the initial operation of PNPP-1.
The licensee recognized this operability condition in 1995. Resolution of PIF 97-0560 will
determine if a TS violation has occurred during HPCS testing for the period from plant stanup to
the issuance of the standing order in 1995. The team identified this issue as URI 50-440/97-201.-
l
03.
1. Overfrequency Protection Relay Removal / System Overpressure Protection
GE Design Specification 22A3131, Revision 5, Requirement 4.4.10, specified that the main HPCS
pump circuit breaker shall automatically disconnect the pump motor load if the electrical bus
frequency exceeds 105% of the rated frequency. This specification provides HPCS discharge
piping overpressure protection, as required by Section III of the American Society of Mechanical
l
Engineers (ASME) Code. However, during construction of the PPNP-1, the architect / engineer
(AE) decided not to install the HPCS pump motor overfrequency protection relay, on the basis of
l
FDDR KLI-3890, dated May 28,1985. The licensee's SSFI of the HPCS system in 1992,
'
recognized that the basis for not installing the relay identified in the FDDR was not well founded.
Consequently, the licensee performed Calculation E22-19," Justification for Elimination of HPCS
,
8
!
_
-
l
l
.
.
Overfrequency Relay," Revision 1, dated July 23,1992, to evaluate the efTect of not installing the
relay. The team reviewed this calculation and identified the following concerns:
The licensee's calculation referenced Section III, NB-3654.1, of the ASME B&PV Code m
e
l
order to justify exceeding the system design pressure by 10% in the event that the Division
III EDG frequency goes above 60 IIz. The licensee's calculation did not identify the
l
specific edition or addenda of the Code that was used to justify their decision not to install
the overfrequency/ overpressure protection relay. Design Specification (DSP) E22-1-4549-
I
00, Revision 3, dated April 18,1986, referenced that the 1974 ASME B&PV Code with
addenda up to and including the winter 197S issue, was the applicable Code for this system.
Section NB-3654.1 of the 1974 Code did not apply to overpressure allowance and was the
l
wrong reference. Although the 1974 Code did contain a provision for overpressure
allowance in NC-3612.3 the NB portion did not contain a similar allowance. It was
inappropriate for the licensee to apply this current NB code reference to the entire discharge
piping from the pump to the reactor vessel since NC portions of the Code applied to
equipment within this boundary. Additionally, the licensee did not evaluate the
overpressure condition on components within the boundary.
The licensee's calculation methodology provided a relief path to limit pressure using the
.
minimum flow valve and its actuation circuitry as overpressure protection devices. The
team questioned the licensee's use of this equipment for overpressure protection since
compliance with the requirements with ASME Code Section III, Article NC-7000,
" Protection Against Overpressure." could not be demonstrated for this valve and its
actuation circuitry.
The licensee's design control process requires that the NSSS review modification and
engineering decisions that afTect system still under their Jesign authority. Based on the
information reviewed by the team it was not evident that GE reviewed or approved the final
design.
The licensee issued PIF 97-0575 to document concerns regarding the overfrequency protection
relay removal calculation and to justify continued operability. The team determined that the
calculation methodology, code application, and review / approval process did not ensure design
quality as specified in the USAR Section 17.2, QA program and 10 CFR Part 50, Appendix B,
Criterion III," Design Control." The licensee stated that they would reevaluate the possible need
to install the overfrequency relay as part of the effort to resolve PIF 97-0575. Additionally, the
team determined that the licensee's improper disposition of the 1992 discovery of this issue
constitutes ineffective 10 CFR Part 50, Appendix B, Criterion XVI, corrective action.
Consequently, the team identified this issue as URI 50-440/97-201-04.
l
l
l
9
.
.
m. Fuel Oil Storage Tank Chemistry / Water Removal
To verify that the fuel oil storage tank undergoes periodic water removal and chemistry analysis,
the team reviewed SVI-R45-T1323, dated January 15,1997, and RPI-l 103, dated January 24,
1997. The team also reviewed the history of water removal and chemistry analysis and
determined that little or no water has been detected in the tank's sump, and the chemistry analysis
results of the oil have been acceptable.
n. Testable Rupture Disc
The testable rupture disc (TRD) on the safety-related exhaust of the Division III EDG is designed
to provide pressure reliefin case the nonsafety-related portion of the exhaust or silencer is
blocked, restricted, or inoperable. The team reviewed the des;gn of the disc as depicted by
j
Drawing D-301-801, Revision A; Calculation R48-8, "EDG Exhaust Vent Valve Size,"
Revision 1; Calculation R48-11," Standby and HPCS DG Exhaust Vent Valve," Revision 2;
Calculation R48-17, " Seizure of EDG Exhaust Vent Valve Bearings " Revision 0; and
Calculation R48-13,"EDG Exhaust Vent Valve Setpoint Calculation (with DCC-003),"
Revision 0.
Through this review, the team determined that the disc is not tested during diesel operation when
realistic operating temperatures and pressures are present. The disk is tested using a test device
to measure the force necessary to lid the disk. This test force is calculated using area of the disk
and allowed back-pressure that should cause the dist to lift. The design of the disc is sensitive to
temperature differential across the disc and the resulting displacement of the locking mechanism.
Also, the disc is susceptible to warping, which causes fluctuations in the amount of force required
to open the disc.
During the test on February 19,1997, the Division III disc lifted at 750 lbs force. At a diameter
of 30 inches, this translates to 29.4" water gauge (WG), which was greater than the allowable
exhaust pressure of 10" WG. For this test failure and similarly times when the disc has opened
with a force greater than the allowable, the licensee identified the problem as being related to
testing and did not determine that the disc and the diesel may have been inoperable. In one case,
where the disc was locked closed, the licensee determined that the EDG was inoperable.
The team identified that the TRD test and operational failures appeared to be design related.
Additionally, the team considered that the licensee's corrective actions were deficient, since TRD
reliability problems appear repetitive. There have been more than 12 failures to date, more than 6
years after the first failure to open, and almost 12 years after the disc opened too early. The
licensee's corrective actions have not resolved the problems.
The team questioned the basis for the TRD setpoint value specified in the test procedure. In
response, the licensee stated that numerous vendor letters have provide conflicting values for
j
acceptable EDG back-pressure. In a letter from Engine Systems, Inc. dated October 15,1996,
i
1
10
!
.
.
!
the engine vendor published a maximum back-pressure value of 5" WG. GE the NSSS, allowed a
maximum back-pressure value of 10" WG. The licensee also indicated that another letter from
l
MKS Power Systems ( the system service rep.), dated October 13,1995, allowed a back-pressure
of 15" WG during a transient, which equates to an engine power reduction of 0.5%. This value
!
was later translated to 18.5" WG at the location of the TRD and was used to reevaluate high lift
forces experienced during testing.
The licensee established the allowable back-pressure value of 10" WG using the assumption that,
during EDG operation, the nonsafety-related exhaust may become blocked, causing a back-
pressure sufficiently high to cpen the safety-related exhaust equipped with the TRD. However,
the nonsafety-related exhaust may become blocked before the diesel engine starts. In that case, a
high back-pressure may prevent the engine from starting. The licensee had no documentation
from the vendor to justify that the back-pressure setpoint for the TRD would be acceptable for
both situations. At the conclusion of the inspection, the licensee had not obtained vendor
verification that the current setpoint was acceptable for both situations.
The licensee is currently testing the Division III TRD every month until repeatable data
demonstrate that the TRD is reliable. The root cause evaluation for PIF 97-0325, which
documented the latest failure of the Division III EDG TRD, identified that the TRD design is the
most likely cause of the numerous failures. Additionally, the root cause identified that previous
corrective actions have been inefTective in preventing failure recurrence and improving reliability.
The licensee indicated that a TRD design modification was considered in 1990, but was never
implemented. However, because of recent failures, the licensee now plans to implement the
design modification during operating cycle 7.
10 CFR Part 50, Appendix B, Criterion XVI, requires that conditions adverse to quality (such as
failures, malfunctions, deficiencies) must be promptly identified and corrected. However, to date,
the licensee's actions have not been timely or efTective in ensuring reliable operation of the EDG
TRD. Consequently, the team identified this issue as URI 50-440/97-201-05.
El.2.2.3 Conclusions
The team concluded that the mechanical design of the HPCS system was generally acceptable,
and the system was capable of performing its safety function as evidenced by the surveillance
testing reviewed, although some margins may be small. For example, the HPCS pump is
sequenced onto the emergency bus during a loss of off-site power at a bus voltage of 75% in
order to meet the required injection times. During surveillance fall-flow testing the HPCS system
is inoperable because of test valve design (50-440/97-201-03). The current HPCS suction
swapover setpoint from the CST allows air to travel into the suction pipe (50-440/97-201-01).
Additionally, as discussed in Sections El.2.3.3.a and El.2.5.2 of this report, EDG operation in
speed droop and continuous operation of the SPCU system further impact the margins associated
with HPCS flows and timely delivery of water into the reactor vessel. Other findings indicate that
'
a lack of rigor exists in the licensee's documentation and understanding of the design bases, and
11
._ .-.
. _
.-
.
.-
-.
_
_
.
.
.
maintenance of the design- and licensing-basis configuration (50-440/97-201-04). Additionally,
resolution of the Division Ill EDG TRD testing failures was not timely (50-440/97-201-05).
El.2.3 Electrical
El.2.3.1 Scope of Review
The team reviewed the electrical design for normal and emergency operation of the HPCS pump
motors, selected MOVs, circuit breakers, fuses and interlocks. The team also compared the
design drawings to the system description manual (SDM), as well as applicable sections of the
USAR, TS, and surveillance test procedures (SVIs), in order to verify consistency among the
documents. In addition, the team reviewed the calculations related to voltage drop, electrical
loading, and coordination of selected HPCS components and associated electrical components. In
conducting this review, the team sought to determine the adequacy of the available voltages,
equipment loading, protective system coordination, and electrical isolation and independence.
El.2.3.2 System Description and Safety Function
The station's direct current (DC) system supplies power to plant instrumentation and controls
under all modes of plant operation. In addition, upon loss of AC power, the DC system provides
power for emergency lighting and turbine generator auxiliary loads. Batteries, battery chargers,
and distribution equipment for the Class IE 125-V DC system are located in separate rooms in a
seismic Category I structure.
No interdivisional ties are provided between the divisions associated with Unit I or Unit 2.
Maintenance tie buses connect only the same divisions of the two units. In addition, maintenance
tie bus circuit breakers are normally open and are manually operated under administrative control.
They permit isolation of the battery and normal battery charger associated with either Unit 1 or
Unit 2 for maintenance or equalization of the battery.
The Class IE, Division I and Division II 125-V DC system batteries are sized to supply the
required DC loads for a minimum of 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> without the final discharge voltage decreasing to less
than the design minimum of 1.75 volts / cell. The 125-V DC system and the associated loads and
controls supplied by the 125-V DC system are designed to operate from 140 V DC (maximum
corrected equalizing charge of 2.33 volts / cell) to 105 V DC (rated discharge to 1.75 volts / cell).
The Division III 125-V DC power system provides a continuous, independent 125-V DC source
of control and motive power, as required for HPCS system logic, HPCS diesel generator control
and protection, and all Division III-related 125-V DC controls. It includes a 60-cell, lead calcium
battery (100 ampere hours at 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />), and battery chargers. The Division III 125-V DC system
is classified as Class IE. The system is independent of all other divisional batteries, and there is no
l
manual or automatic connection to the Division I or II battery systems. A manually operated
12
,
.
.
-
maintenance tie between the Unit I and Unit 2 Division III DC systems is provided for
maintenance or equalization of the battery.
El.2.3.3 Findings
The team verified that the HPCS is powered from a separate emergency power bus and that the
licensee considered the electrical loading of the individual components in the Division III EDG
capacity calculations. The sequence and timing for loading the HPCS pump and valves onto the
EDG was consistent with the USAR.
The system design documents reviewed by the team adequately supported the design, except for
the discrepancies and open items discussed in the following paragraphs.
a. IIPCS Diesel Generator Droop Setting
The Division III diesel generator (DG3) is the emergency source of power for Bus EH13. Bus
loads consist of the HPCS pump, valves, and auxiliaries. DG3 is designed to operate in the
isochronous mode (i.e., as the sole supplier of power to the bus) when the bus is isolated from the
grid, and in the parallel mode when the bus is tied to the grid during testing.
The diesel starts upon receipt of a LOCA initiation signal, and the generator connects to an
isolated EHl3 bus. Loads (such as h10Vs) are permanently connected to the bus and operated in
turn as dictated by the startup and operating sequence of HPCS. The HPCS and emergency
service water (ESW) pump loads are sequenced onto the bus at preset times. As the HPCS
system continues to operate, load changes consist of hiOV operations as the HPCS cycles
between full flow to the reactor and minimum recirculation flow to the sup; ression pool, as
determined by reactor vessel level indication. DG3 continues to operate in this isochronous mode
to supply emergency power. To parallel with the grid, DG3 must be manually synchronized, with
its output breaker closed while the normal bus supply breaker from offsite power remains closed.
The speed of DG3 is controlled by a Woodward UG-8 mechanical governor, and the mechanical
droop setter for the governor is local to the governor. The manufacturer recommends setting the
droop to zero when operating in the isochronous mode, as shown in Section 12 of the General
hiotors " Electro-hfotive Division 6454E4 Turbocharged Engine hiaintenance hianual," PNPP
File 114-G. The licensee indicated that, during initial plant startup, the DG3 droop setting was
kept at zero when in the standby mode. When the diesel was tested, it was paralleled to the grid
after adjusting its droop setting to accor iodate operation in the parallel mode. After the diesel
was shut down and returned to the star.dby mode, the droop setting was returned to zero.
The licensee was not able to determine when the change in droop setpoint occuired but present
practice at PNPP-1 is to maintain the DG3 droop setting at a value of 20 on the dial face at all
times. This setting of 20 equates to -2% of rated speed when the diesel is loaded (-1.2 Hz).
PNPP engineers explained that this practice was established as a convenient way to preclude the
13
-
-
- - - .
_
.. ._
.
. - _.
-
.
l
,
.
l
possibility of the droop being inadvertently left set at an incorrect value. Instrument Maintenance
Instruction (IMI) E3-23, Section 5.2.4, Step 23, dated June 12,1991 (in effect at the time of this
l
inspection) instructs plant personnel to " Reset speed droop control, if necessary, to 20." The
!
team had the following concerns regarding the licensee's established practices:
The diesel generator was originally qualified to Regulatory Guide (RG) 1.9, Revision 0, and
the licensee was unable to locate documentation to demonstrate the qualification setting at
other than the vendor recommendation of zero droop. The licensee also could not produce
any documentation to support the current setpoint or the impact ofisochronous mode
operation at a droop setting other than zero. The licensee confirmed that no specific testing
i
had been performed with this droop setting to revalidate the diesel generator qualification
and confirm acceptable operation. USAR Table 1.8-2 commits to following ANSI 45.2.11 -
1974Property "ANSI code" (as page type) with input value "ANSI 45.2.11 -</br></br>1974" contains invalid characters or is incomplete and therefore can cause unexpected results during a query or annotation process. for Quality Assurance Requirements For The Design of Nuclear Power Plants.
ANSI 45.2.11 - 1974 requires that changes from specified design inputs or quality standards
'
including the reasons for the changes shall be identified, approved, documented, and
i
i
controlled. The team concluded that the change in the droop setting constituted an
undocumented modification, and identified this issue as URI 50-440/97-201-06.
In a related but separate issue, the licensee had previously issued PlF 97-0165 on
January 28,1997, to assess the impact on the mechanical systems of operat'ing any of the
diesel generators within a frequency band of* 1.2 Hz (or * 2% of rated speed). The
licensee had not conducted any such analysis before that time. The licensee documented
their review of PIF 97-0165 in a calculation that showed that, at a frequency of 58.8 Hz, the
HPCS pump would be unable to develop minimum discharge pressure by 4 psig. The team
noted that the calculation treated droop as a bias and added it to other errors to calculate the
total loop error. The other errors (including the TS-allowed 2% of rated speed error)
were appropriately treated as random and were statistically added. The team agreed with
this approach.
The licensee provided the inspection team with surveillance test vA;. charts showing
performance of the diesel generator during testing with normal accident loads. In providing
these test results, the licensee's purpose was to substantiate the position that the diesel
generator operates within TS values at a droop setting of 20. These charts showed that,
during startup and load sequencing, the voltage and frequency disturbances associated with
load variations were within the tolerances specified in RG 1.9. However, because droop
l
was set at 20, the frequency was shown to decrease as the load increased, to 59.15 Hz at a
load of 2200 kW. The licensee also demonstrated that, with other loads associated with the
pump operating at runout flows, the full-load projection for DG3 was 2250 kW, with a
corresponding speed equated to approximately 59.1 Hz (compared to the TS lower limit of
58.8 Hz).
l
The licensee modified the original position and, at the conclusion of the inspection, planned
to revise the original PIF 97-0165 evaluation. The licensee stated that it was inappropriate
14
i
l
.
.
to add droop as a bias to the other errors in calculating the total loop error, since the TS
allow EDG surveillance testing to be considered acceptable if the EDG starts and operates
at 60
1.2 Hz unloaded. As demonstrated by surveillance testing, droop causes the bus
frequency to drop as DG3 is loaded. The licensee noted that the procedure used to shut
down DG3 after testing involved reducing the load to approximately 100 kW while
'
observing that the speed increases to slightly above 60 Hz. At this point the diesel generator
is stopped. The licensee is using this administrative control to ensure that the TS would be
met by setting up DG3 to start the next time at 60 + Hz. Because droop biases bus
frequency approximately 2%, the team concluded that the licensee's position (that droop
should not be considered as a bias added to the other errors in calculating the total loop
error) was inappropriate. The licensee held discussions with GE at the conclusion of the
inspection in an attempt to gain additional HPCS flow margins to allow droop to be added
l
as a bias as originally planned. Consequently, the team identified the need to review this
calculation aller revision as URI 50-440/97-201-07.
b. Battery Surveillance Testing
SVI-E22-T5217, "18-Month Battery Surveillance Test Data," dated October 7,1996, for
Battery lE22-S005 showed that individual cell voltage for Cell 60 dropped below 1.75 V to
1.32 V at the end of test (127 minutes). The licensee concluded that lower voltage for Cell 60 did
not constitute an unusual situation. Institute of Electrical and Electronics Engineers (IEEE) Std.
450-1980, "Large Lead Storage Batteries for Generating Stations," Section 6.4.4, allowsjumping
out individual cells if the voltage begins to approach 0. This review of discharge test data
,
indicated that this cell's capacity is in the high 90% range, well within the acceptance limits of the
test. The performance of this cell, while somewhat below average compared to other cells in the
,
battery, did not significantly affect overall battery capacity, which was verified to be 106%.
El.2.3.4 Conclusions
The team concluded that the electrical design for components that perform the engineering
safeguard functions of the HPCS was adequate and operating within the design limits. However,
further analysis of droop bias effects on mechanical equipment performance is needed (50-440/97-
201-07). The deviation from the vendor recommendation for DG3 droop setting without a
documented basis constituted an undocumented modification (50-440/97-201-06).
El.2.4 Instrumentation and Controls G&C)
El.2.4.1 S_ cone of Review
In evaluating the HPCS I&C area, the team reviewed design documentation, conducted
interviews, and performed walkdowns of the HPCS system. The team concentrated on protective
functions that maintain reactor core cooling and vessel inventory during and after a LOOP /LOCA
or LOCA. In addition, the team assessed the design for the ability to meet USAR commitments
15
-.
_
,
.
and to operate within TS limits. Attributes reviewed comprised instmment installations,
instrument setpoints, instmment power and AC and DC control power provisions, and remote and
i
alternative shutdown provisions. Documents reviewed included appli:able sections of USAR
Chapters 1, 3, 5, 6, 7, 8, and 9; TS; SDMs; vendor documents; P& ids; logic diagrams; electrical
j
wiring diagrams; instrument installation drawings; calculations; calculation change records; PIFs;
action requests (ARs); condition reports (CRs); nonconformance reports (NRs); and DCPs.
l
El.2.4.2 Findings
'
Missile Protection of CST Suction Piping for HPCS/RCIC and Tank Level
a.
lustrumentation
The CST is a nonsafety-related, non-seismic tank located outdoors inside a concrete dike
structure. At 2 feet,0 inches thick, and 23 feet,8 inches high, the dike is a seismic Category I
structure designed to withstand externally generated tornado missiles, and creates an annular
space of 8 feet,0 inches, between the tank and the dike wall with a capacity to retain the total
inventory of the CST. A concrete room to house CST level instrumentation is provided, designed
and fabricated to the same standards as the dike, and includes a labyrinth entrance for missile
,
protection.
The CST is a source of clean water for the RCIC and HPCS systems. GE Design Specification
Data Sheet 22A3131 AS; Functional Control Diagrams (FCDs); CEI Drawing No. D-308-311,
Sheets 1-4; the HPCS SDM E22A; and USAR Section 6.3 designates the CST as the normal
source of water for the HPCS. When the water level in the CST is drawn down to the low-level
setpoint, the HPCS suction lineup is transferred to draw from the suppression pool as the safety-
t
related source of water.
Instn. mentation monitoring the water level in the CST to effect the transfer to the suppression
poolis safety related. Two safety-related class IE powered transmitters (IE22-N054C and IE22-
N054G) monitor CST water level with a one out of two logic for the suction transfer.
RCIC and HPCS share a common ASME Section 111 suction line from the CST. This suction
piping exits the side of the CST above the 11om stab, bends downward 90 to penetrate the floor
slab in the annular space between the CST and the dike, and is then routed underground to the
Auxiliary Building.
USAR Section 3.5.1.4 states that, safety-related systems and components which are located
outside of Category I structures are provided with unique missile barriers. USAR Table 3.5-7
indicates the HPCS and RCIC piping to the reserve water in the CST is underground, covered
with a minimum of 4.5 feet of compacted earth for protection against external missiles. However,
both the instrument sensing lines and the RCIC/HPCS suction piping are exposed inside of the
dike wall and are unprotected from missiles originating from natural phenomena such as seismic
events or tornadoes. During the CST walkdown, the team identified two non-seismic stacks on
16
.-
..
-
.
.
.
.
.
the top of the Auxiliary Building that may have the potential to fall and hit the CST, CST water
level instrument piping, and RCIC/HPCS suction piping.
Calculations 22:08 and 22:11 address the tornado missile design of the dike wall and document
that protection from externally generated tornado missiles is provided for the instrumentation
located inside of the instrument room along the dike wall. However the CST water level
4
instrument piping and the RCIC/HPCS suction piping inside of the dike were not addressed in the
calculations. Both are vulnerable to damage by either gravitational and tornado-generated
missiles. The instrument lines are routed close together so that a single missile could strike both
of them. In the case of the suction piping, the effect of the piping being struck by any missile
would be either the loss ofits pressure boundary and leakage of the CST inventory into the dike
area, or crimping the line and restricting the flow. No analysis existed to substantiate the
licensee's current protection of this equipment from tornado missiles.
The licensee acknowledged this fmding and issued Pli 97-0561 to address the adequacy of the
tornado missile and seismic protection design for the CST level instrument piping and HPCS
suction piping installed between the CST and the concrete containment dike. The licensee
conducted an immediate operability review for the HPCS and RCIC systems. The CST level
instrument piping and HPCS suction piping installed between the CST and the concrete
containment dike were considered to be inoperable. In accordance with TS 3.3.5.1 and 3.3.5.2, if
,
the HPCS and RCIC suction valves are lined up to the suppression pool, these systems need not
'
'
be considered inoperable. As a result, the licensee issued instructions to the operators to maintain
a line up of the HPCS and RCIC suction valves to the suppression pool. Operation in this lineup
would continue until further analysis substantiates the acceptability of the design of the CST level
instrument piping and HPCS/RCIC suction piping inside of the concrete containment dike or
corrective measures can be implemented to upgrade the design condition.
-
The licensee's initial review of the issues described in PIF 97-0561 (Calculation 1:05.7), indicated
'
that, on the basis of probability, the equipment in question did not need to be protected. This
probability of damage approach was questioned by the team since Section 3.5.1.4 of the Perry
Safety Evaluation Report (SER) (NUREG-0887) used a probability of 1 that a tornado-generated
missile would strike exposed equipment. During subsequent discussions the licensee informed the
.
team that Section 3.5.1.5 of the NRC's Standard Review Plan (SRP) allowed the use of
probability. Use of SRP Section 3.5.1.5 which addresses external not tornado generated missiles
was not appropriate for this review. The team determined that the licensee resolution of this issue
was inadequate and informed the licensee. After further review, the licensee agreed that the PIF
'
resolution was not in accordance with their licensing bases and was therefore unacceptable. The
PIF resolution effectively changed the plant from that described in the USAR and should have
been supported by a safety evaluation pursuant to 10 CFR Part 50.59. PIF 97-0738 was issued
and a walkdown of equipment was initiated by the licensee. The team, therefore, informed the
licensee that the current missile protection design for equipment subjected to tornado-generated
missiles was efTectively a change to the plant from that described in the USAR and represented a
a
17
't
1
i
-- -.
-
. .
. - .
-
- - . _ . -.
_
-
.
.
.
.
potential unreviewed safety question. In addition, the team identified this issue as URI 50-
440/97-201-08.
b. Condensate Storage Tank Low-LevelInstrumentation
The two safety-related CST low-level transmitters are both mounted inside boxes located in an
unheated concrete instrument room. The instmment lines from the transmitters to the CST are
routed through a single penetration in the concrete dike to the storage tank. Once through the
dike the instrument lines are exposed to the elements outdoors. The instrument lines are wrapped
with electrical heat trace from their connection to the transmitter to their connection to the shutoff
valves at the CST. The heat trace is fed from a nonsafety-related power source. PIF 96-0425
,*
documented a case where a nonsafety-related transmitter with the same location and heat trace
design as the safety-related transmitters froze. The freezing occurred at the transmitter box. Th:
heat trace was deemed adequate. Leaks in the box insulation and lagging were the cause of the
i
problem. All of the heat traced lines have thermocouples for monitoring the operation of the heat
J,
trace. These thermocouples did not repon any abnormal temperatures and checked out as normal
during subsequent walkdowns.
'
The team inquired about the use of nonsafety-related power feeds for heat tracing the CST level
instruments. The licensee responded that all heat trace throughout the plant is fed from
nonsafety-related power sources. In all cases, their performance is monitored by nonsafety-
related temperature monitors. The installations are checked on operator rounds for abnormal
t.smperature conditions and operability of the heat trace and temperature monitors. However, PIF
96-0425 noted that, during the incident in which the lines froze as a result of a short in the heat
trace cable, the failure remained undetected because of a failure of the temperature monitoring
element.
Protection of the line from freezing is lost during loss of AC power events, because the heat trace
is powered from nonsafety-related electrical power sources. In this case, off-normalinstructions
(ONIs) required the operators to monitor the instrument line temperature. ONI-RIO provided a
table of time limits versus on the outside air temperature. From O'F to 16 F an hour and a half
time limit was provided to transfer the CST inventory to the suppression pool in anticipation of
the instrument lines freezing. For an outside air temperature less than O'F the ONI required that
the inventory be transferred immediately.
El.2.43 Conclusions
The HPCS review identified a design deficiency which has existed since the original design phase
of the plant. A section of HPCS suction piping where the piping exits the CST and the CST level
instrumentation piping inside of the concrete dike have not been protected against gravitational
and tornado-generated missiles, as described in the US AR (50-440/97-201-08).
18
.
- .-.
.
_-
,
.
'
\\
El.2.5 System Interfaces
j
El.2.5.1 Scope of Review
j
in this portion of the design review, the team considered the safety /nonsafety system interface
,
between the HPCS and SPCU systems, the HPCS room coolers, and the Unit 2 batteries, as well
as the HPCS room flood provisions.
El.2.5.2 Findings
}
a. Suppression Pool Cleanup
The PNPP design of the SPCU system interfaces directly with the HPCS. SPCU takes suction
from the HPCS suppression pool suction line between the containment isolation valve and the
j
pump. This arrangement requires that the HPCS system be aligned to the suppression pool
instead of the CST during SPCU system operation. This system arrangement was the subject of
4
Engineering Design Deficiency Repon (EDDR) 10, dated February 13,1984, which was reported
,
J
to the commission via letters dated April 30 and June 8,1984. EDDR 10 stated that the root
cause of the deficiency was that the SPCU piping was improperly connected downstream of the
'
HPCS suppression pool suction valve rather than upstream. This indicates the intended design
was to have the SPCU system suction interface between the containment penetration and the
containment isolation valve. EDDR 10 states the SPCU suction valves F010 and F020 (G42)
,
system are normally closed, and if open, automatically close on a LOCA signal corresponding to
reactor water level 1 at which time the SPCU system would receive an isolation signal. Under the
intended design, HPCS would be aligned to the CST and SPCU could be operated from the pool
with the HPCS suppression pool isolation valve closed. Under the as built configuration SPCU
operation required HPCS alignment to the pool. With HPCS initiation at reactor vessellevel 2
and SPCU isolation at reactor vessel level 1, EDDR 10 indicated that HPCS would be inoperative
until the reactor water level reaches level 1. The action taken to correct this situation was to
change the isolation signal to close SPCU suction valves whene
"P('S is initiated.
This solution corrected the isolation signal problem only. The mechanical configuration which
requires HPCS alignment to the suppression pool for SPCU operation was left unchanged. As
indicated in the FDDR, the SPCU suction valves F010 and F020 (G42) system were intended to
be normally closed. The SPCU system was not intended to be normally in operation. This is
'
consistent with USAR Section 6.2.4.2.2.2, " Justification with Respect to General Design
Criterion (GDC) 56," which states that the suppression pool cleanup return line is used for
suppression pool return flow during periods of suppression pool cleaning and mixing. The US AR
states that containment isolation requirements for the retum line is satisfied, in pan, on the basis
that the line is normally closed. In response to team questions, the licensee indicated that SPCU is
essentially always in operation and HPCS is essentially always aligned to the suppression pool.
The team noted this alignment is not consistent with the HPCS classification and function to
backup the RCIC system, including initially take suction from the CST as the preferred source of
19
,
-
-
.
.
water. Although the licensee indicated that the suppression pool alignment is the safety-related
alignment for normal operation, the team considers this to be inconsistent with the facility
operation as described in the USAR. Because the licensee did not develop a safety evaluation as
required by 10 CFR Pan 50.59 for continuous operation of the SPCU system which was different
than that described in the USAR, the team identified this issue as URI 50-440/97-201-09
The team reviewed the ability of the SPCU system to support HPCS operation by isolating the
suction valves upon HPCS initiation. GE Design Specification 22A3131 AD, Requirement 4.4.1,
specifies that the HPCS system must be capable of starting and delivering rated flow into the
vessel within 27 seconds following receipt of an initiation signal. Two butterfly valves, F010 and
F020 (G42), powered from Division I and II power supplies isolate the SPCU suction from the
HPCS system. The closing time for these valves is 35 seconds without consideration of power
supply startup timing. This exceeds the 27 seconds required for HPCS to reach full flow. The
team noted the HPCS system would be operating in parallel with the SPCU system until the
SPCU suction valves completed their stroke. This consideration was not consistent with the
mechanical design calculations for HPCS (in particular, Calculation E22-1, "NPSH
Calculation-HPCS System"), nor with the description in USAR Section 6.3.2.2.1 for NPSH
calculations in accordance with RG 1.1. PIF 97-0526 was issued by the licensee to document this
finding.
The licensee initiated a review of the HPCS NPSH calculations to address the effects of SPCU
operation with a normal operating flow rate of 2000 gpm. The team noted that the piping from
the isolation valves to the SPCU pump is nonsafety but seismically-supported, while piping
downstream of the SPC'U pump is nonsafety, nonseismic, and also not seismically supponed. The
team questioned the ba,is for the assumption of a 2000-gpm normal flow rate. The licensee
referred to a letter (PY-DIDR-072), entitled " Revision of Break Type Criteria for Moderate-
Energy, Nonsafety-Related, Non-Seismic, Category I Piping Outside Containment," dated May 6,
1982. This letter provided the basis for relaxation of the original PNPP assumption of full
circumferential breaks in moderate-energy, nonsafety-related, non-seismic, Category I piping
outside containment to permit consideration ofleakage cracks only. On the basis of this criterion,
the licensee indicated the 2000 gpm normal flow rate would be bounding. The team concluded
that the issue of pipe break (versus pipe crack) criteria required funher review of the plant
licensing basis. Consequently, the team deferred this issue to the NRC staff for review as URI 50-
440/97-201-10.
The licensee recalculated available NPSH considering both the normal flow rate of 2000 gpm and
an SPCU pump runout condition of 3500 gpm if a pipe rupture downstream of the SPCU pump
was assumed. Preliminary results of this reanalysis indicate neither the 2000 gpm nor the 3500
gpm SPCU flow rate in parallel with HPCS operation would suppon HPCS NPSH requirements
assuming a maximum suppression pool temperature of 212*F as currently stated in the USAR
-
Section 6.3.2.2.1. A reduction in the maximum suppression pool temperature from 212*F to
185*F was required to demonstrate acceptable NPSH results. The licensee stated that 185"F is
above the maximum analyzed suppression pool temperature of 183 F and is consistent with the
20
.
__ _
.
.
assumptions being used for the ECCS strainer moditication in response to IE Bulletin 96-03. The
licensee has issued PIF 97-526 to document and resolve this issue.
l
Also, as a result of the SPCU system taking suction from the HPCS suction line downstream of
the HPCS suction valve, the SPCU valves are not considered containment isolation valves.
Review of the Pump and Valve Inservice Testing Program, Revision 3, and the program for
Primary Coolant Leakage Reduction for Systems Outside Containment, PAP-1111, Revision 1,
verified that the SPCU suction valves are not leak tested. The ISTP requires only stroke time
testing. This could jeopardize the operation of the HPCS system because, if while HPCS was
operating, the SPCU valves developed a significant leak, the HPCS suction valve would have to
,
be closed, terminating HPCS operation.
'
The team concluded that the design of the SPCU/HPCS interface, which would require HPCS
isolation in the event of a SPCU system leak represents an apparent oversight in the design. This
condition has existed since the initial licensing period because of insufiicient analysis and
corrective actions regarding the SPCU deficiencies identified in EDDR 10. The team stated that
<
j
this issue would be reviewed by the NRR technical staff. Consequently, the team identified this
issue as URI 50-440/97-201-11.
b. Surveillance Testing ofIIPCS Room Cooler-GL 89-13
The team reviewed the HPCS Room Cooler with regard to heat exchanger performance test
requirements defined in GL 89-13. The HPCS room cooler is an air-to-water heat exchanger
which rejects heat from the HPCS pump room to the ESW system. The team identified the
following concerns during this review:
PNPP response to GL 89-13," Service Water Problems Affecting Safety-Related
4
+
Equipment," PY-CEI/NRR-l l21, dated January 26,1990, stated that "
The ESW air-to-
l
water heat exchanger (HPCS room cooler) will be inspected and cleaned at each refuel
outage, fin and tube side, as an alternative to performance testing." This commitment to
l
clean and inspect the heat exchangers is identified in the Perry Regulatory Information
j
Management System as commitment Lol181. In a subsequent submittal to the NRC,
Implementation of GL 89-13," Service Water Problems Affecting Safety-Related
i
Equipment," PY-CEI/NRR-1734L, dated April 8,1994, the licensee stated that there are 10
'
ESW heat exchangers at PNPP within the scope of GL 89-13, which have been serviced as
follows. . High-Pressure Core Spray Room Cooler,2 Inspections,2 Cleanings.
'
Documentation of the inspections was available, however, there was no documentation to
substantiate the room cooler was cleaned as committed in PY-CEI!NRR-1121 and
conSrmed in PY-CEI/NRR-1734L. The licensee stated that to their knowledge, inspections
we.e done, but no cleaning was done on the HPCS Room Cooler during the time period
claimed in the letter to the NRC. PIF 97-0463 was issued to document this finding. The
licensee conducted a review to determine the potential impact of the inaccurate information.
The licensee stated that the oversight was not material or willful and intended to correct the
21
.
-
- .-
-
-
.
-
.
.
erroneous information in response to fmdings of this inspection. The team concluded that
the missed cleaning and the licensee's subsequent report that the commitments had been
satisfied constitute deviations from the licensing commitments. Consequently, the team
identified this issue as URI 50-440/97-201-12.
Letter PY-CEI/NRR-1734L, dated April 8,1994, also states "With available improvements
in methodology cited above, the HPCS Room Cooler will now be tested, or alternate
monitoring methods will be determined in accordance with Electric Power Research
Institute (EPRI) NP-7552," and "PNPP will maintain the present testing frequencies of once
per cycle until such time as our testing demonstrates that a reduced frequency is warranted."
The HPCS Room Cooler was tested in June 1995. Calculation M39-6, HPCS Room Cooler
Performance Test Results 1995, deemed the test results inconclusive. Since June 1995, no
other operability test was conducted. The licensee stated that there were no intentions to
inspect the room cooler before October 1998 and maybe not until October 1999, even if no
conclusive testing can be achieved by that time. The team noted the licensee has not
established a performance test program for the HPCS room cooler and has reverted to the
inspection program, but has extended the frequency beyond each cycle without a history of
testing to demonstrate that a reduced frequency is warranted. The team considers this a
deviation from the licensing commitment to inspect and clean the HPCS room cooler during
each refueling outage, as stated in the PNPP response to GL 89-13, " Service Water
Problems Affecting Safety- Related Equipment," PY-CEI/NRR-1121, dated January 26,
1990. In addition the team considers this a deviation from the licensing commitment to
maintain test frequencies of once per cycle until such time as testing demonstrates that a
reduced frequency is warranted, as stated in Implementation of GL 89-13, " Service Water
Problems Affecting Safety-Related Equipment," PY-CEI/NRR-1734L, dated April 8,1994.
The team, therefore, identified these deviations as URI 50-440/97-201-13.
c. HPCS Room Cooler Filters
During the HPCS system walkdown, the ter a observed that the room cooler filters were exposed
without any protection from direct impact by water spray or debris. The licensee indicated that
the only spray the filters could be exposed to is from the HPCS piping. Such a piping failure
would render the HPCS system inoperable in which case the filters would not be needed. The
only non-HPCS pipe in the room is the SPCU pipe, whose location cannot jeopardize the filters.
The team reviewed the rcom cooler vendor manual which did not mention of any protection
requirements for the filters. The team also verified that the existing filters possessed all the
required parameters of the original filters.
d. Battery Room Floor Drains
Floor drains in the Unit 2 Division II and as Unit 1 Division III Battery rooms appear to have a
screen beneath the cover and were full of debris. The team was concerned whether the drains
were functional. PIFs 97-0423 and 0424 address cleaning the drains, and verification that a
22
.
.
battery spill into the drain system would not create an environmental hazard The licensee's
documentation of these housekeeping items as well as many other items in the corrective action
process represented good sensitivity as to threshold for problem identification.
.
e. Unit 2 Batteries Used to Support Unit i Operation
Unit 2 Division 111 batteries support the Unit 1 Division Ill batteries during maintenance activities.
PNPP initiated a PIF 96-2833 dated 8-30-96 to evaluate incomplete constmetion of Unit 2
Division III battery room for seismic restraints built in accordance with the design drawings.
Engineering performed a walkdown to identify any potential seismic interactions 'in the Unit 2
Division III battery room. The review concluded that there were no credible hazards (i.e., items
ofconsiderable weight with missing or inadequate anchorage) located within a falldown distance
of the batteries. The nonsafety commodities (e.g., conduit, light fixtures, etc.) adjacent to the
batteries are well supported and do not pose a seismic impact or falldown concern. The vertical
cable drop to the batteries is acceptable. The acceptability is contingent upon the cable and/or
conduit being well supported and of adequate length (i.e., with adequate slack) to accommodate
any differential seismic movement between the battery rack and the conduit.
El.2.5.3 Conclusions
The team identified a variety ofitems regarding the HPCS system mechanical interfaces including
the SPCU system, and HPCS Room Cooler testing.
The operation of the SPCU, particularity on a continuous basis, was not consistent with the
description of the facility as described in the USAR and was not supported by a 10 CFR Part
50.59 safety analysis (50-440/97-201-09). Operation in this mode did not support the RG 1.1
NPSH evaluations as presented in the USAR (50-440/97-7.01-11). Deviations from licensing
commitments regarding cleaning and frequency ofinspections made with respect to GL 89-13
were identified (50-440/97-201-12 and 13).
An additional issue regarding application of pipe break criteria (rather than pipe crack criteria) to
nonsafety, non-seismic, moderate-energy piping systems has been referred to the NRR technical
staff for review (50-440/97-201-10).
El.2.6 System W;lkdown
El.2.6.1 Scone of Review
j
The system walkdown included examinations of the HPCS piping and components not inside the
primary containment, as well as the interface with the CST and the SPCU system and the Division
l
III diesel generator. The walkdown also included interviews with plant operators in the control
'
room.
23
l
\\
.
.
El.2.6.2 Findings
a. Battery Hold-Down Straps
The top and bottom rows of batteries on Unit I and 2 Division III racks did not have the same
number of clamp-down supports. Vendor Drawing M-6709-3, " Rack, 2-Step Seismic For 20-
3DCU-9 Battery," shows 6 supports on each side of the battery cells. PIF 97-0407 documents
this discrepancy. The licensee performed an operability determination and verified that the
observed condition did not afTect battery operability. The licensce's corrective action for PIF 97-
0407 should determine the root cause as to why the brackets were not installed. In addition, the
corrective action should result in a revision to the drawing, supported by a detailed calculation.
The team, therefore, identified this issue as Inspection Followup Item (IFI) 50-440/97-201-14.
b. Battery Conductors
Bending Radius - Unit 1 Division III battery cables IE22D206C and IE22D208C, Unit 2 Division
III battery cables 2E22D208C and 2E22D212C were bent in a 3" diameter or greater,360-degree
coil at the termination point. Engineering Instruction (GEI) 0007, " Cable Termination
Instmetion," Attachment 2, Sheet 2 of 2, Termination Data Sheet (Power Cables)," provides a
Step 7.4, " Training Radius Maintained," Drawing D-215-801, " Cable Pulling Criteria, Bending
and Training Radius," Revision J, specifies that the training radius for these cables (EKA-171,1/C
- 2) is 1.5." Nonconformance Report PPDS-3846, Revision 1, dated May 15,1989,had
previously dispositioned this condition as acceptable.
c. Battery Maintenance-Vendor
The team noted during their system walkdowns that a vendor was performing repairs on
Division I and II batteries and requested from the licensee details and scope of the work in
progress. According to licensee, during the performance of weekly battery surveillance test (SVI-
R42-T5202) and SVI-R42-T5203) on May 20,1996, an electrolyte leak was discovered in the
batteryjars of various cells at the seam on the top cover. PIF 96-2149 was issued to identify and
correct the leakage problem from the cell covers. The leak resulted from a defective seal between
the celljar and the top cover, as well as poor workmanship during battery fabrication. The
electrolyte leak is not a battery failure and does not impact the system function and operability.
j
The manufacturer (Yuasa-Exide) was on site performing the repairs to correct the leakage
problem.
d. Cable Separation
Conduits IR33D98A and IR33D102A in the Division I battery charger room were in contact
,
with each other and were wrapped in 3M insulation. Raceway separation barrier installation
l
drawing SS-201-146, Sheet 143, Revision EE, criteria allows the conduits to be wrapped with 0"
i
separation and therefore the installation was acceptable.
1
24
1
_._ _.___.
__ ____._
.___._ _ _. _ _ _ _
_
_ -
_ . .__ _
,
.
.
s
e. Cable Tray / Raceway / Conduit Fill Walkdown
!
Tray and conduit % fill values for Cable Trays "C" 1951 and 1952 and conduit IR33C2977C in
1
the Unit 1 Division III battery room were checked and found acceptable. Summary ofTray Data
Report CKSR2000, documents tray 1951 as being 31.9% and 1952 being at 38.6% filled.
J
Conduit Summary Report CKSR2200 identifies raceway 1R33C2977C as being 35.9% filled.
The fill criteria specified in USAR Section 8.3.1.4.3 are 50% for tray and 40 percent for conduit.
l
'
.
'
f. Conduit Supports
Unit 1 Division III battery room conduit flex IE22A212C dropped from the ceiling with no
support. Conduit Layout Drawing D-215-004, Sheet 601, Note 6C.2 and Table 3, allow the
maximum conduit length between supports to be up to 10 feet. The conduit in question was field
verified to be 8 feet,6 inches long, and was found to be acceptable.
El.2.6.3 Conclusions
i
With the exception of the battery hold-down straps (50-44/97-201-14), the team considered the
i
electrical equipment and cable installation including separation and fill to be acceptable in
accordance with licensee design drawings.
El.2.7 IJSAR Review
The team reviewed the appropriate USAR sections for the HPCS and associated electrical and
control systems. The team identified the following discrepancies with regard to statements made
in the USAR:
The team's assessment of the basis and design features for flooding due to passive failures
within the HPCS room identified inconsistencies between the actual design and the design
described in SER (NUREG 0887) regarding control of unisolable post-LOCA leakage
within the ECCS rooms. The ECCS room flood capabilities described in the SER were
difTerent from that contained in USAR Section 6.3.1.3. The licensee indicated that the
USAR description and the design basis was consistent with regulatory requirements in this
area. The licensee issued PIF 97-0488 to clarify their design and licensing basis for
detection and protection from passive failures of either the HPCS pump seal or valve
packing during both normal operation and post-LOCA. The licensee's position on this issue
was discussed with NRR technical staff who agreed that clarification of the USAR was
needed.
The team identified the following administrative discrepancies between Calculation PSTG-
0014, " Diesel Loading Division I, II, and III," Revision 3, and USAR Table 8.3-1: The
licensee had previously identified similar discrepancies with USAR Table 8.3-1 and
Calculation PSTG-0014 as documented in PIF 96-2780.
25
.
.
a
a)
USAR Table 8.3-1 identifies loads IM43C001C and 2C as OM43C001C and 2C.
b)
USAR Table 8.3-1, Note 17, second sentence contradicts Note 20.
c)
USAR Table 8.3-1 lists fuel oil transfer pumps IR45C001C and 2C as 0-second loads.
IR45C001C and 2C are 40-minute automatic cyclic loads for both LOOP and LOCA.
d)
USAR Table 8.3-1 identifies a 9-kW load for IE22C004B and does not agree with the
8-kW load in Calculation PSTG-0014.
e)
USAR Sections 8.3.1.1.3.2B6 and 8.3.1.1.3.386 refer to "Section 8.3.1.1.2.8," but
the correct section is 8.3.1.1.2.6.
I
The team identified discrepancies de. scribed below indicated that design and calculation
changes may not be accurately reflected in the USAR:
a)
USA.R Table 8.3-1 lists inrush current for HPCS water leg pump IE22-C003 as 51
amperes, Calculation PRMV-0017, "EHF-1-E Transformer Breaker EH-1305,"
Revision 0, does not reflect inrush currents for the IE22-C003 load.
b)
USAR Table 8.3-1 lists the inrush currents for HPCS fuel oil transfer pumps IR45-
C001C and 2C as 109A, whereas Calculation PRMV-0017 lists the inmsh current as
130A.
c)
USAR Table 8.3-1 lists the inrush currents for HPCS diesel generator room fans
OM43-C001C and 2C as 362A, whereas Calculation PRMV-0017 lists the inrush
current as 376A.
d)
USAR Table 8.3-1 lists the FLA of HPCS diesel generator starting air compressor
IE22-C004B as 13 A, whereas Calculation PRMV-0017 lists the FLA as 11 A.
e)
USAR Table 8.3-1 lists the HPCS ESW pump IP45-C002 is as 75 hp,88.5 FLA, and
557A inrush, whereas Calculation PMRV-0017 lists the same load as 75 hp,
85.4 FLA, and 543 A inrush.
f)
USA.R Table 8.3-1 lists the rating of HPCS diesel generator space heater IE22-D011
as 2 kW, with a load current of 3 amp. Calculation PRMV-0017 lists the same space
heater as 1.6 kW, with the load current of 2.01 amp. Drawing D-206-029/BB,
" Electrical One Line Diagram, Class IE,480-V Bus EFID," lists the same space
heater as 2.4 kW.
26
i
'
i
g)
USAR Table 8.3.11," Penetration Protection," was generated from Calculation ECPC-
0001, " Electrical Penetration 1 T Verification," Revision 2, dated 8-25-92. Input to
2
'
l
ECPC-0001 was from Calculation PSTG-0006, "PNPP Short Circuit Study," Revision
l
1, dated 6-21-85. Calculation PSTG-0006 is currently at Revision 2, dated 5-20-92.
Calculation ECPC-001 and USAR Table 8.3-11 have not been revised to reflect the
impact of PSTG-006, Revision 2. The initial review by engineering has determined
!
that the present ampacity values in Calculation ECPC-001 are conservative with
respect to PSTG-006, Revision 2, and the I T values and clearing times in USAR
2
Table 8.3-1I will not change significantly.
h)
USAR Table 8.3-7 does not reflect the current load profiles of Calculation PRDC-
0005, " Load Evaluation and Battery Sizing of Division I and II Battery Load Profiles,"
.
Revision 3, dated May 23,1996. PIF 97-0425 documents this discrepancy. Currently,
1
all Division I and Il surveillance performance and service tests are performed per
USAR Table 8.3-7. Operability of the plant systems, functions, and equipment are not
l
affected by the inconsistency between USAR Table 8.3-7 and the Calculation PRDC-
0005, Revision 3. The load profiles listed on USAR Table 8.3-7 are greater
(conservative) than the profiles addressed in Calculation PRDC-0005, Revision 3.
Corrective Action 97-0425-001 will revise the USAR Table 8.3-7 for completeness.
The licensee evaluated the above discrepancies by verifying that either the items were
currently being reviewed under an existing PIF or a new PIF was issued. The licensee
issued new PIFs 97-0343,97-0350,97-0395, and 97-0500 to document those items not
captured in the corrective action system.
The licensee had not yet corrected the above discrepancies or updated the USAR to ensure that
the USAR contained the latest information, as required by 10 CFR 50.71(e). Consequently, the
team identified this issue as URI 50-440/97-201-15.
E1.3 Emereency Closed Cooline (ECC) System
El.3.1 System Description and Safety Function
The safety function of the ECC system is to provide a reliable source of cooling water to safety-
related components during and after transient and/or accident conditions. These components
include the control complex chillers: residual heat removal (RHR) pump seal coolers; low-
pressure core spray (LPCS), and RCIC pump room unit coolers; and hydrogen analyzers.
Other ftmetions of the ECC system are to supply cooling water to served components during hot
standby, normal shutdown, and plant testing modes of oper ation and, if required, provide cooling
water to the fuel pool heat exchangers following a DB A, if required.
l
l
!
27
.
.
The ECC system is a closed, intermediate cooling water system consisting of two redundant,
independent loops designated as loops A and B. The primary components of each loop include a
pump, heat exchanger, surge tank, MOVs, and interconnecting piping. A chemical addition tank
is shared by both loops. The ECC heat exchangers are cooled by the ESW system. The
components served by each ECC loop are as follows:
Loop A
Loop B
LPCS Pump Room Cooler
RIIR Pump B Room Cooler
RCIC Pump Room Cooler
RHR Pump B Seal Cooler
RHR Pump A Room Cooler
RHR Pump C Room Cooler
RHR Pump A Seal Cooler
RHR Pump C Seal Cooler
Hydrogen Analyzer A Cooler
Hydrogen Analyzer B Cooler
Control Complex Chiller A
Control Complex Chiller B
Each ECC pump takes suction on its loop suction header and discharges through the shell of an
ECC heat exchanger to the system loads. After serving the system heat loads, the warmed ECC
water returns to the pump suction. The surge tank ensures that an adequate pump suction head is
available and facilitates system fill and makeup. The ECC system is not normally in operation and
is designed as a standby system. A LOCA or loss of offsite power (LOOP) signal automatically
{
starts both ECC pumps, repositions valves to supply ECC water to the control complex chillers,
and isolates the normal, nonsafety-related cooling water supply to the control complex chillers.
The ECC system is designed to perform its required cooling function following a DBA, assuming
any single active or passive failure and LOOP and is protected to withstand the efTects of natural
phenomena including earthquakes and tornadoes. The system is classified as Safety Class 3 and
Seismic Category I, except for its portions that are associated with the chemical addition tank and
piping downstream of vents and drains.
El.3.2 Mechanical
El.3.2.1 Scope of Review
The mechanical design review of the ECC system included design and licensing documentation
reviews, system walkdowns, and discussions with the cognizant system and plant design
engineers. The team reviewed applicable portions of the USAR and TS; the SDM section;
process flow diagrams and other drawings; 12 calculations; 8 DCPs; system operating, inservice
and surveillance test procedures; CRs; PIFs; and operating experience reviews (OERs). The
scope of the review included verification of the appropriateness and correctness of design
28
_ _ . _ . _ _
-_
_ _
_
_
_
_
.
.._
.
.
assumptions, boundary conditions, and system models; confirmation that design bases are
according to licensing bases; and verification of the adequacy of testing requirements.
Specific topical areas covered during the mechanical design review include system
thermal / hydraulic performance requirements (e.g., heat removal capacity, pump and system
cmves, and pump NPSH); system design pressure and temperature; overpressure protection;
surge tank design parameters; component safety and seismic classifications; component and piping
design codes and standards; and single failure vulnerability.
El.3.2.2 Findinus
.
!
The team verified that each loop of the ECC system was capable of removing the design heat
loads from served safety-related components during and following a DBA. The system appeared
to have adequate flow and heat transfer margins to accommodate future equipment degradation,
as evidenced by the difTerence between the required and designed flow rates (1820 gpm versus
,
2300 gpm) and the current position of valves that are throttling ECC flow to served components.
i
'
The safety classifications and specified codes and standards were appropriate. The design
i
pressures and temperatures specified for piping and components, and the provided overpressure
j
protection features were adequate. Complete independence of the two ECC loops was verified
j
i
where no single active or passive component failure would prevent the system from performing its
'
safety function. However, the team identified USAR clarity and inconsistencies in the manner in
which passive failure was defined. Specifically, USAR Section 1.2.1.2 item I indicates that
passive failures only apply to electrical failures. Whereas, USAR Section 6.3.2.6 refers to passive
j
failures as valve stem and pump packing failures. Clarity is needed to define what is the Passive
.
Failure Design. The licensee is addressing these inconsistencies in PIF 97-0566, and the matter is
designated as IFl 50-440/97-201-16.
'
,
i
The system design documents reviewed by the team adequately support the design and licensing
bases, except for the discrepancies and open items discussed in the following paragraphs.
1
a. Surge Tank Emergency Makeup Design Basis
4
USAR Section 9.2.2 currently states that the ECC surge tanks are designed to maintain a 7-day
i
supply of water, with normal system leakage, without the need to provide makeup water.
Expected normal system leakage is stated as 0.5 gallons per hour (gph) from pump seals and valve
stem packing. However, an event that occurred in 1993, as reported in Licensee Event Report
.
(LER)93-021, identified a previously unrecognized post-accident leakage path from the ECC
system. This path would be through closed valves P42-F295A,B and P42-F325A,B that isolate
the ECC system from the nonsafety-related nuclear closed cooling (NCC) system following a
DBA. The NCC system is the normal cooling water source for the Control Complex chillers.
whereas the ECC system cools the chillers afler an accident. The licensee has established
allowable leakage limits for the subject va!ves at 3.0 gpm for ECC Loop A and 3.5 gpm for Loop
!
B, derived in Calculation P42-24," Maximum Allowable Leakage from P42 System," Revision 1.
29
.
-
._
,
.
.
These limits are on the basis ofoperator action taking place within 30 minutes afler the DBA to
manually initiate emergency makeup to the surge tanks from the ESW system. Without this
makeup, the surge tanks would empty, NPSH for the ECC pumps would be lost, and the ECC
system would be disabled.
In compliance with 10 CFR 50.59, the licensee prepared Safety Evaluation 96-128, dated October
10,1996 to evaluate the USAR and procedural revisions associated with the change in the surge
tank sizing basis from a 7-day supply without necessary makeup to a 30-minute supply. The
safety evaluation was also used as a basis for the use-as-is disposition of PIF 96-2846, associated
drawing change notice (DCN) 5541, and USAR change request (CR)96-150. The safety
,
evaluation concluded that the change did not constitute an unreviewed safety question, primarily
because of the licensee's belief that the modified design continued to satisfy the review procedures
4
!
stated in SRP Section 9.2.2, Part III, which states:
"The system is designed to provide water makeup as necessary. Cooling water
systems that are closed loop systems are reviewed to ensure that the surge tanks
have sufficient capacity to accommodate expected leakage from the system for
seven days or that a seismic source ofmakeup can be made available within a time
frame consistent with the surge tank capacity (time zero starts at low-level
alarm)."
Overall, Safety Evaluation 96-128 was comprehensive and well written. However, the team's
,
review of the safety evaluation identified a number of concerns that, collectively, caused the team
to challenge the conclusion of the safety evaluation, as described below:
'
Multiple operator actions would be required to read the local surge tank level gauges (at
30 minute intervals), locally open valves P45-F508A,B to establish makeup flow from the
ESW system, and subsequently close those same valves if the surge tanks have completely
filled with water and are overflowing. Within the first 90 minutes after a DBA, the
licensee calculated that total operator radiological exposure would be about 12 rem. The
cumulative operator exposure over the entire duration of the accident was not calculated.
'
NUREG-0737, item II.B.2, " Design Review of Plant Shielding and Environmental
Qualification of Equipment for Spaces / Systems Which May be Used in Post-Accident
i
Operations," establishes the guidelines of GDC 19, " Control Room", as the dose rate
criterion to be applied for vital areas that are infrequently accessed under post-accident
conditions. This criterion is 5 rem whole body, or its equivalent to any part of the body,
for the duration of the accident. Therefore, a minimum of three separate operators would
be needed to carry out the required actions for the first 90-minute period without
exceeding the GDC 19 dose criterion.
The safety evaluation did not adequately assess the potential for operator error (omission
or commission). It discounted the possibility of operator error, primarily because of the
simplicity of the required actions and operator familiarity with the required activities.
'
,
30
.
.
4
However, working conditions immediately following a DB A would be stressful, and there
is no emergency lighting in the areas where actions would be required, necessitating the
use of portable light sources. Thus, the team considered a single-operator error to be
credible. The licensee stated that a single- operator error would result in the failure to
provide makeup to only one surge tank. The licensee does not consider credible the
postulated failure of the operator to provide makeup to both surge tanks, even though a
single procedural step covers filling both ECC surge tanks.
The safety evaluation did not address the potential for surge tank overpressurization when
makeup from the ESW system fills the tank water-solid. The probability of this occurring
is increased, since the operator would'open the makeup valves and then leave the surge
,
l
tanks untended and unmonitored for at least 30 minutes. Preliminary licensee calculations
indicate that the maximum makeup water flow rate from the ESW system is approximately
117 gpm, resulting in a surge tank pressure of about 4 psig. This exceeds the surge tank
atmospheric design pressure, but will not exceed the maximum pressure retaining
1
capability of the tank, as calculated by the licensee. Therefore, the surge tank will not fail
as a result of filling it water-solid with makeup from the ESW system.
The safety evaluation cited American National Standards Institute /American Nuclear
Society (ANSUANS) 58.8-1984, " Time Response Design Criteria for Nuclear Safety-
Related Operator Actions," as the basis for choosing the 30-minute operator action time,
although the safety evaluation notes that Perry is not committed to meet this standard.
However, not all of the provisions of the standard have been met regarding safety-related
operator actions taken outside the control room:
-
No emergency lighting is provided in the two separate areas where the operator
'
must read the local surge tank level gauges or manually operate the ESW makeup
valves. The use of portable light sources is required.
-
No safety-related surge tank level indication is provided in the control room to
inform the operator that actL,n is needed or to provide ir. formation and feedback
regarding the success of performed actions. The hign/ low surge tank annunciators
that are provMed '. ine control room are not safety related and cannot be relied
upon to provide valid post-accident information. The surge tank level will only be
known at 30-minute intervals when an operator is dispatched to read the local-
level gauges.
The team also reviewed the plant's original SER (NUREG-0887), dated May 1982, and noted
that NRC acceptance of the ECC system design appeared to be dependent (in part) on the ability
to initiate ESW makeup to the surge tanks by manual action from the control room. This SER
31
_
.
.
I
cceptance was consistent with information presented in the Perry Final Safety Analysis Report
(FSAR) at that time, which stated:
"This is a remote manual function requiring operator action in the control room."
In FSAR Amendment 17, dated March 6,1985, still before receipt of the operating license, the
FSAR was revised to indicate that initiating surge tank makeup from the ESW system was locally
performed. Subsequent SER supplements did not specifically address this change.
.
On the basis of the reviews described, the team concluded that the change to the ECC surge tank
sizing basis from a 7-day supply to a 30-minute supply, with operator actions required outside of
{
the control room to initiate makeup from the ESW system, may constitute an unreviewed safety
'
question, as defined in 10 CFR 50.59, because it--
Increases the probability of an occurrence of a malfunction of equipment important to
safety. Reliance on operator action at 30 minutes afler the accident, under stressful and
'
hazardous working conditions, increases the probability that the operator will not correctly
perform the required actions.
,
Increases the consequences of an accident. Total cumulative operator exposure has
>
+
increased by 12 rem, and the potential exists that an individual operator's exposure may
exceed the GDC 19 limits specified by NUREG-0737, Item II.B.2.
.
This issue was reviewed by NRR technical staff who also determined that a potential unreviewed
safety question existed. This item is designated as URI 50-440/97-201-17.
The team identified several additional deficiencies that were also related to the licensee's Safety
Evaluation 96-128. The flooding analysis performed for surge tank overflow used a non-
conservative flooding rate of 60 gpm, on the basis of the minimum calculated ESW makeup flow
to one ECC surge tank. The team noted that since the operating procedures would direct the
i
operator to initiate ESW makeup to both tanks, the flooding rate should consider the flooding of
l
both tanks (i.e.,120 gpm). The licensee issued PIF 97-0406 to address this discrepancy.
Ilowever, the team also pointed out that if the ESW makeup flow rate was calculated using
assumptions that maximized rather than minimized the flow, the flooding rate would be higher.
Preliminary calculations by the licensee determined a maximum ESW makeup flow rate to each
surge tank to be 117 gpm, or a total flooding rate of 234 gpm. 10 CFR Part 50, Appendix B,
Criterion III, " Design Control," requires that licensees correctly trar.. late the design bases into
specifications, drawings, procedures, and instructions. The team concluded that the licensee's use
of the non-conservative flooding rate in Safety Evaluation 96-128 failed to meet this requirement.
~
Consequently, the team identified this failure as URI 50-440/97-201-18.
'
32
.
,
USAR Section 9.2.2.2 (page 9.2-24) states that, "In the event that demineralized water makeup
does not automatically fill the surge tank, a low-level indication with an alarm is annunciated in
)
the control room to indicate that operator attention is required." Similarly, USAR Section 9.2.2.5
(page 9.2-12) states that "The surge tanks have high- and low-level indication." The actual
design includes only a level alarm in the control room with level indication local at the tank. The
team considered these statements to be unclear and possibly misleading, since they could imply
that surge tank level indication is provided in the control room. These same statements were
made in the original FSAR. The licensee issued PIF 97-0469 to clarify that surge tank level
indication is only locally provided at the tanks.
b. Non-Conservative ECC Leak Rate Test Procedure
The team reviewed test procedure PTI-P42-P0008, Revision 1, "P42 Leak Rate Test Procedure."
The purpose of this procedure is to determine an approximate leakage rate through the valves that
isolate the boundary between the ECC system and the nonsafety-related NCC system valves P42-
F295A,B and P42-F325A,B. The team determined that the procedure was not conservative
because the prescribed test conditions were not representative of post-accident ECC system
operation. The test differential pressure (approximately 60 psi) was one half of the value that the
i
subject valves would experience after an accident. Additionally, the test pressure was bemg
j
applied in the reverse direction from normal accident conditions. The test procedure and
'
acceptance criteria did not adjust the leakage measured under test conditions to expected leakage
.
under post-accident differential pressures. The licensee issued PIF 97-0578 to address these
concerns and their initial review determined that current valve leakage, when adjusted to account
for the higher post-accident differential pressure, would still be acceptable (3.0 gpm for ECC
,
Loop A and 3.5 gpm for Loop B). The responsible system engineer also noted that a new
surveillance procedure (SVI-P42-T2004) was currently being prepared that would correct the
deficiencies noted above.10 CFR Part 50, Appendix B, Criterion XI, " Test Control," and
<
Criterion V, " Procedures" as implemented by the licensee's Operational QA Program, US AR
Section 17.2, requires that testing be performed in accordance with written test procedures which
incorporate the requirements and acceptance limits contained in applicable design documents.
The team concluded that the existing ECC system leak rate test procedure failed to meet this
requirement, and designated this failure as URI 50-440/97-201-19.
c. ECC Pump Minimum Flow Requirement
During the review of design documentation, the team noted a discrepancy in values cited for the
minimum required ECC pump flow rate. ECC system operating procedure SOI-P42, Revision 7,
Section 2.0, stated a minimum flow value of 560 gpm; however, the Ingersoll-Rand certified
pump curve (PDB-B0002, Revision 1) indicated that the minimum required continuous flow was
800 gpm. The team was concerned that the pump was being allowed to operate at a minimum
continuous flow rate that is less than that required by the pump vendor. The licensee issued PIF
l
l
97-0470 to address this concern. The licensee's investigation determined that the pump vendor's
technical manual specified a minimum flow equal to 25% of the best efliciency point or 575 gpm.
i
l
33
J
.
l
l
l.
,
The change from 800 to 575 gpm was previously evaluated in 1990 in CR-90-106, and PIF 97-
0470 identified appropriate changes to the design documentation and operating procedures.
Resolution of this issue should occur through PIF 97-0470 corrective action resolution.
Consequently, the team identified this issue as IFI 50-440/97-201-20.
'
d. IIcat Exchanger Tube Thickness and Heat Transfer Coefilcient
Calculation P42-33, " Evaluation of Heat Transfer Coeflicient and Minimum Required Wall
Thickness for ECC Heat Exchangers IP42-B0001 A/B," Revision 0, dated May 1,1996,
evaluated the minimum wall thickness required for the tubes of the heat exchanger. In particular,
the licensee based the calculation on acceptance criteria consistent with the ASME B&PV code,
and established the minimum overall heat transfer coeflicient on the basis of the fouling factor and
the number of tubes being plugged. The team reviewed the calculation for the minimum wall
thickness determination and sampled the input data used in the heat transfer computer model and
identified the following concern:
Calculation Section 5, " Method of Analysis," considers the heat exchanger as a
pressure vessel and concludes that the rules of ASME B&PV Code,Section VIII,
are applicable. This code selection conflicts with the manufacturer's heat
exchanger specification sheet that indicates the ASME code requirements as
ASME Section III, Class 3. The ASME Form N-1, N Certificate Holders Data
Report for Nuclear Vessels identifies the applicable ASME Code asSection III,
1974 Edition, Winter 1975 Addendum, Class 3. The calculation provided no
'
technical basis tojustify the use of ASME Section VIII criteria for an ASME
Section III component. PIF 97-0531 documents this condition and a comparison
between the criteria of Sections Ill and Vill. This review indicated Sections III
and VIII use the identical code methodology and the calculation results are
unchanged. The team concluded that the review and approval of this calculation
with reference to inappropriate construction codes without technicaljustification
represents a weakness with respect to 10 CFR Part 50, Appendix B, Criterion III,
" Design Control." Consequently, the team identified this item as URI 50-440/97-
201-21.
c. Evaluation of ECC IIeat Exchanger Test Performance
Calculation P42-31,"ECC A Heat Exchanger Test Results-1995," Revision 0, dated
September 15,1995, evaluates the test data recorded during performance of PTI-P42-P001 on
August 10,1995, to assess measurement uncertainty associated with data acquisition and
analytical methods. The team's review of this calculation identified the following concern:
Section 3, " Assumptions," identifies two open assumptions, one assumption
,
i
requires the test data /results be confirmed via test document acceptance signatures
and the second as.lumption assumes test instrumentation to be within calibration
34
.
.
limits. Post-test calibration was specified to confirm this second assumption. The
team noted that this calculation was used as the basis for equipment operability
evaluations and outstanding assumptions, open for 18 months, could affect the
conclusions. The tbam requested information on how these calculations were
controlled to ensure that open assumptions are verified and closed. At the request
of the team, the licensee pursued the status of Calculation P42-31 open
assumptions and found that the post-test calibration indicated that the
instrumentation for 1 of 8 temperature measurements on both the ECC inlet and
outlet were out of calibration. The licensee indicated that Engineering should have
been notified via memo that the test instrument was out of calibration at the .
completion of the post-test calibration. However, no documentation of such
notification was evident. Calculation P42-31 was re-evaluated on the basis of the
)
remaining valid instrumentation readings, with only a minor difference in the
l
results attributable to the small error in the measurements and the statistical
methods used. PIF 97-0543 documents the concern with calculation with open
assumptions and includes a panial listing identifying 44 calculations with
unconfirmed assumptions. Identified calculation titles indicate that at least 13 of
these calculations involve equipment performance testing, including Division I and
Iljacket water heat exchanger testing in 1994. Other calculations appear to
involve equipment qualification, sizing, and modifications. The team concluded
that the issues oflong-term unconfirmed calculation assumptions and failure of the
post-test calibration to alert Engineering to instrumentation that is out of
'
calibration represent weaknesses with respect to 10 CFR Part 50, Appendix B,
Criterion III, " Design Control." Consequently, the team identified this issue as
URI 50-440/97-201-22.
El.3.2.3 Conclusions
The team concluded that the mechanical design of the ECC system was generally acceptable, and
the system was capable of performing its safety fimetion with operator intervention. However,
the team also concluded that the safety evaluation associated with a change in the design bases for
the ECC system surge tank, from a 7-day supply to a 30-minute supply which relied on extensive
use of early manual operator intervention, was inadequate. The resultant change to the USAR
effectively changed the plant from that described in the USAR. Because the change resulted in an
increase in the potential for failures not previously analyzed and an increased in accident
consequences the NRC determined that a potential USQ exist and NRC approval was required
(50-440/97-201-17).
The flooding rate determined by safety evaluation 96-128 and supponing calculation to be
acceptable used non-conservative values (50-440/97-201-18). Mechanical modifications that
were reviewed by the team were appropriate for resolving the identified problems, and the
modifications did not change the design bases of the system. However, the temperature control
valve modification was not totally effective, as discussed in Section El.3.5 of this report. Other
i
35
.
__
_
-
-_.
_.
.
.
i
l
l
l
deficiencies identified during the team's review of design documentation included a non-
conservative test procedure for determining ECC system leakage (50-440/97-201-19);
inconsistent design information regarding the ECC pump minimum flow requirement (50-440/97-
201-20); inappropriate code references for heat exchanger evaluations (50-440/97-201-21); and
l
issues of unconfirmed calculation assumptions and test control (50-440/97-201-22).
l
The licensee initiated actions to address these items through their condition reporting and
'
corrective action program.
El.3.3 Electrical
El.3.3.1 Scooe of Review
The team reviewed the electrical design for normal and emergency operation of the ECC system,
selected MOVs, circuit breakers, fuses, and interlocks. The team also compared the design
drawings to the SDM, applicable sections of the USAR, and TS to verify consistency in the
documents. In addition, the team reviewed the calculations related to voltage drop, electrical
loading, and coordination for selected ECC components and associated electrical components to
determine the adequacy of the available voltages, equipment loading, protective system
coordination, and electrical isolation and independence.
El.3.3.2 Findings
The team verified that the ECC system was powered from a r.eparate emergency power bus and
that the electrical loading of the individual components had been considered in the emergency
diesel generator Division I and II capacity calculations. The sequence and timing ofloading of
ECC pumps and valves onto the respective EDG was consistent with the USAR.
The team determined that the electrical design requirements were appropriate and consistent in
the reviewed documents. No unacceptable conditions were identified during this review.
El.3.3.3 Conclusions
The team concluded that the electrical design of components that perform engineered safeguard
functions of the ECC system was adequate and operating within the design limits.
El.3.4 Instrumentation and Controls (I&C)
El.3.4.1 Scope of Review
The team evaluation of the ECC I&C consisted of design documentation reviews, interviews, and
a walkdown of the ECC system. The review concentrated on protective functions to provide
nuclear safety-related components with a reliable source of cooling during and after a
!
l
i
36
,
,
i
LOOP /LOCA or LOCA. The design was assessed for the ability to meet USAR commitments
and to operate within TS limits. Attributes reviewed comprised ofinstrument installations,
instmment setpoints, instrument power and AC and DC control power provisions, and remote and
altemative shutdown provisions. Documents reviewed included applicable sections of USAR
Chapters 1, 3, 5, 6, 7, 8 and 9; TS, the SDM, vendor documents; P&lDs; logic diagrams;
electrical wiring diagrams; instrument installation drawings; calculations; calculation change
records; PIFs; ARs; CRs; NRs; and DCPs.
,
El.3.4.2 Findings
a. Remote Shutdown Design
The team reviewed the provisions made in the design of the ECC system to operate the system
from outside the control room if the control room had to be vacated. Division A was designated
as the remote shutdown division. Division B was designated as the alternate remote shutdown
division. The ECC system is required for safe shutdown of the reactor. The controls of the
Division A ECC pump can be transferred to the remote shutdown control panel. The transfer
scheme included transferring an alternate source of control power to the ECC pump breaker. The
controls for the Division B ECC pump did not have provisions to transfer control to the
alternative remote shutdown control panel. The pump must be started manually using the control
switch at the ECC pump breaker. No provisions were made to provide an alternate source of
,
control power for the Division B pump controls. The PPNP Appendix R requirements allow 72
hours for repairs to be conducted utilizing only onsite resources for alternate remote shutdown.
j
The design corresponded to that described in the PNPP Appendix R safe-shutdown analysis.
1
None of the ECC system valves for lining up the system flows and isolating the ECC system from
i
the nuclear closed cooling (NCC) system, other non-divisional systems or separating the two
j
divisions had provisions for transferring their control out of the control room to the remote and
alternate remote shutdown control panels. The repositioning of these valves is procedurally
i
controlled. Operators manua!!y deenergize and realign these valves as required. The Appendix R
analysis and the respective procedures were reviewed to verify the inspection observation. The
specific tasks to be performed to manually position the valves were reviewed. Extensive operator
action was required to realign the valves. The valves appeared to be accessible from the floor
level without using ladders. Normal lighting in the area was sufficient for operators to execute
their required task.
b. Surge Tank Low-Level Alarm Setpoint
Calculation P42-5," Emergency Closed Loop Cooling Water System Surge Tank Sizing," was
issued to verify that the surge tank had sufficient capacity to accommodate the water expansion
within the ECC system and to determine the capacity of the surge tank at the low-level setpoint
compared to the original design requirement of 250 gal. The calculation used a setpoint value of
667 feet,9 inches, taken from the Master Setpoint List. Calculation P42-T04," Emergency
37
_
_
_.
_
.__
_-.
.
.
.
!
Closed Cooling Surge Tank Level Hi/Lo Alarm," calculated the uncertainties associated with the
j
level switches that actuates the alarm. P42-T04 referenced Magnetrol Drawing D119-03 for the
setpoint values and noted that the setpoint and reset values are fixed and set at the factony. P42-
l
T04 gives different values from P42-5 for the setpoints of 667 feet,6.75 inches, for tank A and
l
667 feet,7.875 inches, for Tank B. The difTerence between the two numbers was attributed to a
difference in the elevation of the tanks. The difference from the setpoint value in P42-5 was not
explained.
The licensee issued PIF 97-0540 to address the above setpoint value disagreement.
)
i
El.3.4.3 Conclusions
The Perry Appendin R resolution for remote shutdown ability, made extensive use of manual
operator action a feature of their design. Calculation P42-5 incorrectly referenced the setpoint list
as the source document for the low-level setpoint value.
El.3.5 System Interfaces
El.3.5.1 Scope of Review
The team selected the following systems that interface with the ECC system and verified that the
interfacing system design information for supporting the function of the ECC system was
appropriately considered; the ESW system which supplies cooling water to the tube side of the
ECC heat exchangers, provides emergency makeup to the ECC surge tanks, and cross-ties to the
Unit 2 ECC system piping to provide cooling water to the fuel pool heat exchangers following an
accident; the NCC system which provides normal cooling water to the Control Complex chillers
and the fuel pool heat exchangers; and the Two-Bed Demineralized Water System which provides
normal makeup to the ECC surge tanks.
In addition to reviewing the interfacing system design information for the above systems, the team
examined installation of the interfaces during the ECC system walkdown.
'
El.3.5.2 Findings
System interfaces were generally acceptable and consistent with the ECC system design and
licensing bases, except for the items discussed in the following paragraphs.
a. ECC Temperature Control During the Winter
Under accident conditions LOCA and/or LOOP), the ECC system supplies cooling water to
l
control complex chillers A and B. These chi.'ers represent approximately 90% of the ECC system
heat load during accident conditions. The cooiing water supplied to these chillers mus: be
l
maintained above 55'F to prevent the chillers from tripping because of a low refrigerant
38
.
,
.
.
-
.
.
l
\\
,
,
l
i
,
'
temperature. The ECC system heat exchangers are cooled by the e5 W system that draws water
directly from Lake Erie.
As previously reported in LER 94-005, in the winter, when the lake water was cold and the heat
l
loads on the ECC system were low (i.e., the system was operating to support surveillance
l
testing), the ESW system flow to the ECC heat exchangers overcooled the ECC system below
55'F. This could have caused both control complex chillers to trip. It should be noted that this
condition would not have occurred during post-accident ECC system operation, when maximum
heat loads would be imposed on the system. In response to this event, the licensee installed a
temperature control valve (TCV) in each ECC loop (reference DCP 94-0027). This three-way
l
TCV causes ECC flow to bypass the heat exchanger, as necessary, to maintain ECC system
temperature above 55*F with minimum heat loads on the ECC system.
Recent experience, as documented in PIF 96-1265, indicates that the TCV modification has not
been totally effective. Because of the configuration of the heat exchanger bypass piping,
previously unrecognized heat transfer phenomena result in the cooling of the ECC water even
when the ECC flow totally bypasses the heat exchanger. To :ompensate for this marginal design
modification, administrative controls had to be reinstated to limit ECC system operation under
minimum heat load (i.e., surveillance testing) conditions, thereby placing a burden back onto the
operators. In addition, because the ECC system temperature element is located on the ECC heat
exchanger discharge pipe and in close proximity to the heat exchanger outlet (as confirmed during
the system walkdown), the measured temperature can be significantly influenced by the same heat
transfer phenomena noted above and does not always represent the true ECC system temperature.
If the ECC system is idle and the ESW system is operating, the ECC temperature element may
give a false low-temperature alarm in the control (the alarm setpoint is 60*F). This is a nuisance
alarm that diverts the operator's attention and is meaningless when the ECC system is not actually
operating.
As previously noted, the ability of the ECC system to perform its safety-related function is not
impacted by these temperature control deficiencies since the expected post-accident heat loads
would maintain system temperature above 55 F. The licensee has recognized the temperature
control shortcomings and has planned several actions to address them. These include the
performance of tests to better understand the heat transfer phenomera involved and to determine
the feasibility of operating the control complex chillers at lower ECC condenser inlet temperatures
that would allow a lowering of the ECC low-temperature alarm setpoint. The team found these
actions appropriate and did not have any further questions.
b. Cross-Tie Between Unit 1 ESW and Unit 2 ECC Systems
The Unit 2 ECC system was originally designed to supply safety-related cooling water to the
common fuel pool cooling and cleanup (FPCC) system heat exchangers following a DBA. Since
l
Unit 2 is not operational, piping cross-ties were insta!!ed between the Unit 1 ESW system and the
Unit 2 ECC system such that the Unit 1 ESW system can supply safety-related, post-accident
l
l
39
_
._
.
.
1
cooling water to the FPCC heat exchangers. As noted in USAR Section 9.2.2.6, manual actions
are required at greater than 10 minutes following a DBA to establish the ESW-to-FPCC system
alignment. The team reviewed Section 7.5 of system operating instruction SOI-G41, " Fuel Pool
Cooling and Cleanup System," which identifies these manual operator actions. The team noted
,
that the procedure calls for the venting of certain ECC piping and the FPCC heat exchangers to
eliminate voids that could result in water hammer when ESW is admitted to the Unit 2 ECC
system piping.
The team questioned whether post-accident operator radiological exposure during the
performance of the venting activities had been assessed by the licensee in accordance with
'
NUREG-0737, Item II.B.2. The licensee responded that a dose assessment had not been
performed; however, PIF 97-0248 has recently been issued to generically address the lack of dose
assessment and specified operator travel paths for all accident mitigating actions required by plant
3
procedures. Proper disposition of this PIF should satisfy the guidance given in NUREG-0737.
This licensee identified item did not appear to be willful, was not reasonably preventable by
previous corrective actions, and should be corrected in a reasonable time frame commensurate
with the requirements of the licensee's corrective action program. Followup of the licensee's
resolution of these deviations from commitments, stated in USAR Section 12.6 and Appendix 1 A,
j
to satisfy NUREG-0737, item II.B.2. is identified as URI 50-440/97-201-23.
El.3.5.3 Conclusions
The design of the ECC system interfaces was generally satisfactory and supported performance of
the ECC system safety functions. Two concerns that do not affect the capability of the ECC
system to perform its safety functions (ECC temperature control and post-accident vital area
access assessments) were identified by the team. The licensee has previously been aware of these
concerns and is taking actions to address them (50-440/97-201-23).
El.3.6 System Walkdown
El.3.6.1 Scope of Review
1
The team performed a walkdown of selected portions of the ECC system. Piping and mechanical
components, piping interfaces with the ESW system, and installation ofinstrumentation and
electrical components were examined to verify consistency with plant drawings. Particular
attention was directed to the location and arrangement of the surge tanks, their associated piping
(makeup and venting), and level instrumentation to confirm the acceptability of the post-accident
4
operator actions described in Section El.3.2.2 of this report. The team also visited the control
room to examine instruments and displays used to monitor ECC system operating status.
'
40
.
_ _ _ _ _ _
_
_
-
.
.
.-
.- -
.
.
.
j
i
El.3.6.2 Findings
The material condition of the system and general housekeeping appeared to be good, and no cases
were noted where the system configuration deviated from design or licensing documents. Other
specific observations are discussed below.
a. Sanitary Drain Pipe Installation
The team noted that a 4-inch, cast iron sanitary drain pipe traversed the area above the ECC
Loop B pump and associated piping and valves. This drain pipe was supported primarily by
i
threaded rod hangers, one ofwhich was observed to be missing. The team questioned the ability
i
'
of the drain piping support system to withstand a seismic event, since its failure could result in the
pipe falling and damaging the ECC pump and/or pump motor. The licensee confirmed that the
.
drain piping had been seismically analyzed in Calculation 36:01.3.2.1.5, " Control Complex El.
)
574-10 Nonsafety Sanitary Floor Drains Seismic Support." Review of this calculation indicated
'
that the drain piping was adequately supported and restrained such that it would not fall, and that
the leaded bell and spigot pipejoints would not separate in a seismic event. The licensee issued
i
PIF 97-0455 to evaluate the impact of the missing rod hanger and determined that the piping and
its supports remained capable of sustaining a seismic event without falling down with the support
missing. The PIF also directed that the rnissing support be re installed as a maintenance item.
The team had no funher questions with thi issue.
b. Surge Tank Installation and Arrangement
The ECC surge tanks are located at Elevation 665'in the Intermediate Building. The walkdown
confirmed the following items regarding Safety Evaluation 96-128, as discussed in
Section El.3.2.2 of this report:
i
Valves P42-F578A,B in the ESW makeup lines to the surge tanks are locked open as
indicated on drawing D-302-621, the ECC system P&ID.
'
The local surge tank level gauges are approximately one foot above floor level and read in
inches of water level from the tank bottom (verified by the system engineer). The gauges
do not have any markings to indicate the normal tank level range or the high/ low alarm
,
levels.
Should the surge tanks overflow out the vent pipes, the water would discharge directly
onto the top of the tanks, run down the tank sides onto the floor and then to the floor
drain.
ESW makeup valves P45-F508A,B, which the operator must open to initiate emergency
surge tank makeup following an accident, are at Elevation 599' in the Intermediate
Building and are readily accessible from floor level.
41
._ _ .__
..
. _ . _ _
_ _ . _ . _ . . _ .
. .
_ _ _ _ _ _
_
_ _ _ . _ _ _ , _ _ . . _
l
.,
.
No emergency lighting battery packs were observed at either the surge tank or ESW
makeup valve locations.
El.3.6.3 Conclusions
l
The system flow diagram was consistent with the as-built system. The surge tank installation and
arrangement are consistent with system drawings and with the descriptions presented in the
l-
licensee's 10 CFR 50.59 Safety Evaluation 96-128 (see Section El.3.2.2 of this report). The
l
licensee adequately addressed the observed missing drain piping support and concluded that there
was no impact on ECC system operability.
!
El.3.7 USAR Review
The team reviewed the appropriate USAR sectinns for the ECC system, as well as the associated
electrical and I&C-related sections. The team identified the following discrepancies in the USAR:
USAR Table 3.9-30 lists active valves not associated with the nuclear steam supply system
(NSSS). This table has not been updated to reflect several ECC system modifications.
Valves P42-F315A,B,C should have been deleted from the table, since they were
converted from automatic to manual valves by DCP 92-0060. Valves P42-F550 and P42-
F551 should have been added to the table, since they were converted from manual to
automatic valves by DCP 90-0012. The licensee issued PIF 97-0512 to address these
US AR inaccuracies.
i
'
USAR Tables 9.2-18 (ECC Pumps) and 9.2-19 (ECC Heat Exchangers) list two different
values for ECC system operating flow rate (1860 versus 1820 gpm). Since all pump flow
is delivered to the heat exchanger, the two values should agree. The licensee issued PIF
97-0469 to address this discrepancy. Pending resolution, the team identified these USAR
discrepancies as another example of URI 50-440/97-201-15.
El.4 Desien Control
'
.
E.1.4.1 Scoce of Review
The licensee's Design Control Process to satisfy 10 CFR part 50 Appendir B Criterion III as
described in Section 17.2.3 of their USAR, as it related to this inspection was reviewed.
Implementation of the licensee's commitments to ANSI- N45.11 were also evaluated.
42
_ __
-
s
e
1
E.1.4.2 Findings
I
a. Control of Calculations
i
Nuclear Engineering Instruction (NEI) 0341, Revision 5, " Calculations," applies to all
calculations to establish design bases or to change design documents. Paragraph 6.2," Calculation
Revisions," states that design engineers are to monitor calculations to determine if a revision is
required (e.g., receipt of new/ revised design input, confirmation of assumption). Paragraph 6.3,
" Review and Approval," states that verification / review and approval of calculation should precede
use of the results for design, but must be completed prior to the component, system, or structure
being declared operable. If necessary, provide suitable means to ensure operability is not declared
prematurely. Contrary to the above requirements, the licensee has modified various systems as
reflected in design drawings and did not update or revise the calculations:
i
Electrical drawing D-206-029, " Electrical One- Line Diagram, Class IE,480-V
+
Bus EFID," Revision BB, identified the installation of a 10-hp electric motor for
compressor 1E22-C004A. Calculation PRMV-0017 "EHF-1-E Transformer Breaker
EH1305," Revision 0, did not list the compressor motor. The licensee generated PIF 97-
500 to document and resolve this issue and various other calculation discrepancies.
USAR Table 8.3-1 also did not correctly identify the motor loads. In light of the above
discrepancies, Engineering performed an operability evaluation on bus EHF-1-E
transformer breaker EH1305. As a result of this evaluation, Engineering concluded that,
although the revised estimate of 52.6 FLA is greater than 41.5 FLA (on the basis of
4
287 amp inrush as opposed to 251-amp inrush), sufficient margin exists between these
estimated values and the actual 50/51 relay settings. Therefore, operability of breaker
EH1305 is not a concern. Calculation PMRV-0017 was last updated on March 11,1985
(12 years ago), and does not reflect the current plant loads and settings.
Calculation PSTG-0003 "480-V Safety-Related Motor Starting Voltage Drop,"
Revision 2, dated June 29,1995 (page 6), contains an open assumption that required
confirmation. Calculation PSTG-0001,"PNPP Auxiliary System Voltage Study,"
Revision 2, approved on August 24,1995, provided the information to resolve the open
assumption. Although the calculation to close the open item was completed, Calculation
PSTG-0003 remained for approximately I and % years with an open assumption
identified. PIF 97-0497 documents this discrepancy.
Calculation PRDC-0006, " Load Evaluation and Battery Sizing of Division III Class IE DC
System," Revision 0, dated April 8,1991, did not address Division liI HPCS pump
IE22C001 breaker EH1304 spring charging motor load at t=0 second, the load profile for
0-1 min for continuous (L2) load, and the DC control circuit loads (L2 loads) of the
breakers. PIF 97-0511 was written by the licensee to address these concern.
43
.
_
__
_
_ _ _ _ .
.
._ .
. _ .
__. _ _ .
.
.
Ca;culation FSPC-0020," Division III MON Fuse Sizing," Revision 1, dated April 2,
1996, proposes that the fuse size for MPL lE22F001 be changed from 5.6 amps to
3.2 amps and for IE22F004 be changed from 40 amps to 35 amps. Work Order 93-
0004009 replaced the 40 amp fuse on June 30,1994, in accordance with DCP 93-082.
However, the 5.6 amp fuse is stili not replaced by a 3.2-amp fuse. The team considers this
an example of calculation inconsistent with the as-built conditions without reconciliation
of the disparities. The licensee issued Fuse Size Change Requests 97-0001 to document
the need for fuse change-out to the correct size. This approach was found acceptable to
the team since the incorrectly installed fuses would still provide adequate protection.
Calculation PRDC-0004, " Class IE DC Control Circuit Coordination," Revision 2, dated
.
May 30,1995, does not address switch #12 added to drawing D206-051, " Electrical Main
One-Line Diagram, Class IE DC System" Revision RR, dated May 15,1992, in
accordance with DCP 90-0012. The Drawing D206-051 is at current revision WW, dated
April 7,1996. PIF 97-0496 was issued by the licensee as a result of this team finding to
document the discrepancy.
Calculation PRLV-0004, "480-V Breaker Coordination," Revision 2, dated April 30,
1996, was reviewed against associated electrical drawings D-206 series drawings for
480-V motor control centers (MCCs). Various discrepancies and typographical errors
were found between the calculations and the drawings as noted below:
MPL#
Calculation PRLV-0004
Drawing D-206 series
IB21-F065A
6.6 HP
6.4 HP
P42-F551
MISSING
0.13 HP
P45-D004A
7 HP
1 HP
P42F550
MISSING
0.13 HP
M25-C001B
100 HP
60 HP
IG33-F001
3.0 HP
3.9 HP
IM51-F615B
0.13 HP
0.125 HP
PIF 97-0494 was issued by the licensee to resolve the above deficiencies and
typographical errors. Engineering verified that the calculation is still valid for the
overcurrent protective devices of the 480-V switchgear breakers, and adequate protection
'
of the downstream equipment is still provided without premature tripping on short-time
demand. The fuse sizing for the revised loads will be reviewed as part of the PIF 97-0494
44
,
.
disposition and will be addressed in Calculation FSPC-0018, Revision 1; Calculation SPC-
0019, Revision 1; Calculation FSPC-0020, Revision 1;"MOV Fuse Sizing," for Divisions
I, II, and III.
The licensee had not performed a review to determine the extent of the above conditions as they
relate to other (similar) calculations. The licensee generated a generic PIF (97-517) to address
calculation deficiencies in general for accuracy, completeness, level of detail, and consistency with
design drawings and the USAR. The team determined that these calculation control deficiencies
did not meet the licensee's 10 CFR Part 50, Appendix B, Criterion III, Design Control Program
as described in USAR Section 17.2 and identified this item as URI 50-440/97-201-24.
b. Design-basis Documents-Training Manual
The system description manual (SDM) for the ECC system (Revision 8) incorrectly states that the
ECC pump capacity is 2300 gpm at a design pressure of 150 psig. The correct pump rating is
2300 gpm at 130' total developed head (TDH), as shown on the certified pump curve (PDB-
B0002, Revision 1). Since the SDM is intended for training purposes, a PIF was not written, but
the system engineer planned to initiate an appropriate correction to the SDM.
c. Overpressure Protection
Calculation E22-2, " Overpressure Protection Analysis," Revision 0, dated February 23,1983,
performs an overpressure protection analysis on the ASME Section III, Class 2, portion of the
HPCS system. This evaluation was to ensure that no components within the system are subject to
pressures and temperatures beyond the design parameters of the components. The team reviewed
this calculation and identified the following concerns:
The overpressure protection analysis did not identify operating conditions under which
pressure relief devices are required to function including the relief capacity required to
prevent system components from being subjected to pressures exceeding code allowable
values. The maximum pressure considered for the suction piping is 31.25 psig whereas
the suction side reliefis set at 100 psig. Maximum discharge pressure considered was
1130 psig whereas the discharge side thermal relief valve is set at 1560 psig. HPCS pump
discharge piping is designed for 1575 psig so there is no concern with piping
overpressurization. Other concerns with HPCS pump discharge piping protection were
discussed in Section El.2.2.2.1 of this report.
Analysis of the maximum pressure to which the suction piping can be subjected is
.
contingent on the static head from the normal water level of the CST. This yields
nonconservative results by comparison to the maximum overflow level within the CST.
Further, the suction analysis does not evaluate other conditions such as post-accident
alignment from the suppression pool with consideration of containment overpressure, or
45
.
.
conditions of back-leakage from the reactor pressure vessel (RPV), which may result in
pressurization of the suction line.
As the basis for system discharge pressure, the licensee considered a pump TDH at shutoff
.
of 2630 feet and did not consider coincident suction pressure. The pump TDH within the
calculation conflicts with the actual pump TDH at shutofrof approximately 3300' from
Byron Jackson Test T-37225, Revision 1, dated February 7,1979. This test curve reflects
operation at 1780 RPM. Consideration of pump overspeed conditions will further
increase the pump TDH but was not included to ensure that no components within the
system are subjected to pressures beyond the values allowed by the code.
PIF 97-0426 documents the discrepancies noted above. The team concluded that the
methodology, system modeling, and review / approval were inadequate and did not satisfy the
licensee's 10 CFR Part 50, Appendix B, Criterion III, Design Control Program (USAR Section
17.2). Therefore, the team identified this issue as URI 50-440/97-201-25.
d. Inconsistent Pipe Size Calculation
The team identified an inconsistency regarding the size of a section of pipe located between valves
F010 and F001. Calculation E22-A, " System Pressure Drop /Line Sizing," states that the pipe size
is 12" but flow diagram D-302-701 and piping drawing D-304-701 call for a 10"line. The
licensee verified that 10" was the correct size and performed Calculation E22-6, "HPCS Pressure
Drop---Test Mode-CST-to-CST," Revision 0. The new calculation confirmed that using the
correct piping size in the calculation had a negligible impact on the calculated line losses and
therefore they did not intend to correct Calculation E22 A. This appeared to be an appropriate
resolution of the issue.
e. Document Discrepancies
During the review of design documentation, the team identified a number of document
discrepancies and inconsistencies, as itemized below. Although individual items are not significant
safety concerns and do not constitute operability concerns, collectively, they are indicative of
weaknesses in the design control program.
e.1
ECC Heat Exchanger Tubesheet I)rawing
The ECC heat exchanger tubesheet drawings 4549-22-140-1 and 4549-22-140-2 (both
Revision 0) were issued with the as-built tube plugging information missing. The licensee
issued PIF 97-0347 to address this deficiency. The system engineer confirmed that the
ECC heat exchangers do not have any plugged tubes.
46
,
.
e.2
ECC P&lD
l
The ECC system P&lD, drawing D-302-621, Revision BB, had several deficiencies
including a missing safety-class break line at valve P42-F608B, an incorrectly labeled
process arrow (33B instead of 38B), and a note (Note 10) that had been incorrectly
deleted in a previous revision. The licensee issued PIFs 97-0269 and 97-0346 to address
correction of these items.
'
f. Instrument Setpoint Methodology
In Item 14 of Appendix 1B to the USAR, the licensee committed to provide for NRC review and
approval a detailed technical report documenting the basis and methodology for establishing
protection system trip setpoints and allowable values. Specifically, this report would reflect the
work of the Instrument Setpoint Methodology Group (ISMG), as described in CEI letter PY-
CEI/NRR-0368L, dated October 17,1985. In conjunction with GE Topical Report NEDC- 31336, " General Electric Instrument Setpoint Methodology," dated October 1986, this letter
constitutes the followon action to the licensee's commitment. The USAR, Appendix IB, Item 14,
was updated to reflect the ongoing NRC review of the topical report. CEI letter PY-CEI/NRR-
0969L, dated March 3,1989, revised the CEI schedule for fmal closure of commitment 14. Use
of the topical report received NRC approval on March 23,1993. The licensee commenced
updating the affected setpoint and allowable value calculations.
The licensee issued Instrumentation and Control Design Guide D-1, Setpoint Calculation
>
Methodology, and Desk Guide ICS-005 to control the process for preparing calculations for I&C
setpoint parameters covering nominal setpoints, allowable limits and analytical limits, leave-as-is-
zone tolerances and reset values. Attachment 2 to the licensee letter PY-CEI/NRR-1706L, dated
October 15,1993, listed the instmment channels to be evaluated. The licensee based this list on
initiating functions found in the USAR Chapter 6 and 15 analyses. The licensee conducted
analyses for these reactor protection systems and engineered safety feature trip functions and
established an ongoing program to apply the setpoint methodology to other related setpoints.
NRC letter, dated July 18,1995, approved the licensee application of the GE methodology to
Perry Nuclear Power Plant. The setpoint calcolations for HPCS and ECC were reviewed in this
inspection and found to be in either conformance or scheduled to be updated to be in agreement
with the setpoint methodology design guide. The new calculations reviewed were found to be of
better quality than the older ones.
g. Review of Licensee's System-Hased I&C Inspection
In early 1995, the licensee conducted an in-house audit of selected instrumentation and controls
that included some HPCS instrument loops. This we.s done in preparation for anticipated
inspections by the NRC. The audit was conducted la accordance with NRC Inspection Procedure 93807. The audit included a detailed review of the design and field installation of the associated
instmment and control systems, setpoint calculations, mechanical system interfaces, calibration
i
47
-
-
-.-- - . - . . - - . - -
.
-.
-.-
.- - -
_ _ . -
.
.
procedures, testability, isolation and bypass status iwicators, maintenance and equipment
installation. The scope of the audit and the methodology for evaluation of the design addressed
the line-items of the NRC Inspection Procedure. Findings were documented on PIFs and
processed as potential issues in accordance with the licensee corrective action program.
The HPCS instrument loops evaluated in the licensee audit were reviewed by this inspection team.
The scope of the licensee audit covered all attributes reviewed in this inspection. No additional
findings resulted beyond the observations recorded by the licensee.
h. Design-basis Documents -Desktop Guide
While the " Design-Basis Documentation Hierarchy" desktop guide may provide guidance where
various sources of documentation may be found, the team encountered examples where the design
bases could not be established as readily as expected, or the design-basis documentation had
various inconsistencies. Examples include description of HPCS functions, the CST water volume
design basis, vortex limitations within the CST, the HPCS suction relief valve design basis, and
use of ASME Codes during deficiency resolution.
The team identified several instances in which the licensee had disculty in retrieving design-basis
information. This problem directly contributed to the licensee's inappropriate "use-as-is"
disposition of plant hardware problems associated with the lack of overfrequency protection for
the HPCS pump and inadequate protection of exposed equipment against the efTects of tornado
missiles.
E.1.4.3 Conclusions
Calculation quality was mixed and many calculations were not being controlled in accordance
with the licensee's program. In contrast, instrument setpoint methodology and calculations were
consistent with commitments and calculation quality wasjudged to be good. Inconsistencies and
discrepancies between calculations and other design basis information was evident. There were
several instances in which the licensee had dimculty in retrieving design-basis information. This
problem directly contributed to the licensee's inappropriate "use-as-is" disposition of plant
hardware problems associated with the lack of overfrequency protection for the HPCS pump (50-
440/97-201-04) and inadequate protection of exposed equipment against the effects of tornado
missiles (50-440/97-201-08).
XI
Exit Meeting
After completing the on-site inspection, the team conducted an exit meeting with the licensee on
April 22,1997, that was open to public observation. During the exit meeting, the team leader
presented the results of the inspection. A partial list of persons who attended the exit meeting is
contained in Appendix B. Reference material used during the exit meeting is Attached to this
report.
48
-
.-,
.
.-
..
_ _ . _ .
_
__
.
-
Appendix A
,
List of Open Items
j
This report categorizes the inspection findings as unresolved items (URIs) and inspection
followup items (IFI)in accordance with Chapter 610 of the NRC Inspection Manual. A URI is a
.
matter about which the Commission requires more information to determine whether the issue in
question is acceptable or constitutes a deviation, nonconformance, or violation. The NRC may
issue enforcement action resulting from its review of the identified URIs. By contrast, an 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
Finding
Title
h'P3
50-440/97-201-01
HPCS Pump Vortex Calculation - 10 CFR Part 50,
Appendix B," Design Control" (El.2.2.2.d)
j
i
50-440/97-201-02
Untimely Resolution of Keep-Full Pumps Test
Results(El .2.2.2.f)
l
50-440/97-201-03
HPCS Secondary Modes Testing - Past Operability
Determination (E l .2.2.2.k)
,
50-440/97-201-04
HPCS Overfrequency Protection Relay Removal Calculation -
10 CFR Part 50, Appendix B," Design Control" and
j
" Corrective Action"(El.2.2.2.1)
50-440/97-201-05
Resolution of Emergency Diesel Generator Testable Rupture
Disk Failures - 10 CFR Part 50, Appendix B," Corrective
Action" (E 1.2.2.2.n)
I
50-440/97-201-06
Undocumented Modification to Droop Setting of Division III
>
EDG (El.2.3.3.a)
50-440/97-201-07
Treatment of Droop Bias with Respect to TS Acceptance
Criteria for Reduced Frequency at End User Mechanical
Equipment (El.2.3.3.a)
50-440/97-201-08
Protection Against External Missiles for HPCS and RCIC
Suction Not Consistent With the USAR (El.2.4.2.a)
A-1
.- -
- _ - . - - _ . _ _ . .
_ - - - - - . - . - - - - .
. . . . - . .
_
. _ -
.
.
.
I
'
\\
l
I
50-440/97-201-09
Normal Operation ofHPCS Aligned to Suppression Pool-
Inconsistent with the Description of Operation of the Facility as
}.
Described in the US AR (El.2.5.2.a)
50-440/97-201-10
Pipe Break (versus Pipe Crack) Criteria for Moderate-Energy,
!
Nonsafety, Non-Seismic Piping Outside Containment
(E l .2.5.2.a)
a
50-440/97-201-11
Potential Unanalyzed Condition Existing from the Initial
Licensing Period As a Result ofInsufficient Analysis and
i
Corrective Actions Regarding Deficiencies Identified in EDDR
l
10 (E 1.2.5.2.a)
50-440/97-201-12
Licensing Commitment Deviations Regarding Past Cleaning and
Subsequent Reporting that HPCS Room Cooler Commitments
4
i
Had Been Satisfied (El.2.5.2.b)
50-440/97-201-13
Licensing Commitment Deviations Regarding Current
Inspection Frequency of HPCS Room Cooler (El.2.5.2.b)
3
l
50-440/97-201-14
IFI
Unit I and 2 Division III Battery Missing Hold-Down Straps
j
(E l .2.6.2.a)
]
50-440/97-201-15
Maintenance of USAR and Consistency of USAR and Design
l
Calculations (El.2.7 and El.3.7)
,
i
l
50 ?40/97-201-16
IFI
USAR Clarity as to Definition of ECC Passive Failure Design
j
(E 1.3.2.2)
]
50-440/97-201-17
Surge Tank Emergency Makeup Design Basis - Reduction of
j
Capacity from 7 Days to 30 Minutes (El.3.2.2.a)
4
i
D-440/97-201-18
Non-Conservative Flooding Rate in Safety Evaluation 96-128 -
10 CFR Part 50, Appendix B, Criterion III," Design Control"
,
(E l .3.2.2.a)
c
3
5
50-440/97-201-19
Non-Conservative Analysis of Test Results for ECC/NCC
<
System Interface Leakage - 10 CFR Part 50, Appendix B,
,
]
Criterion XI, " Test Control"(El.3.2.2.b)
50-440/97-201-20
IFI
ECC Pump Minimum Flow Value Design Documentation and
Operating Procedures Inconsistencies (El.3.2.2.c)
A-2
_ _ _ _ _ . _
_ _._.___ _ _
_ _ _ _ _ _ _ . _ . . _ _ _ . _ _ . . . _ _ . . . _ . _ . _
,
.
.
j
i
t
<'
50-440/97-201-21
Application of ASME Section N111 Criteria to an ASME
Section III Component Without Documented Technical
Justification - 10 CFR Part 50, Appendix B, Criterion III,
" Design Control"(El.3.2.2.d)
-
50-440/97-201-22
Unconfirmed Calculations Assurnprions - 10 CFR Part 50,
l
Appendix B, Criterion III, " Design Control" (El 3.2.2.e)
!
50-440/97-201-23
Deviation from USAR Commitments, Stated in Appendix la
,
and Section 12.6, to Meet the Requirements of NUREG-0737,
Item II.B.2. (E1.3.5.2.b)
.,
'
50-440/97-201-24
Adherence to Procedure NEI-0341 - Calculations for
l;
Verification, Review, and Approval of Calculations - 10 CFR
!
Part 50, Appendix B, Criterion III, " Design Control" (El .4.2.a)
l
!
50-440/97-201-25
HPCS Overpressure Protection Analysis Methodology, and
i
Review / Approval - 10 rFR Part 50, Appendix B, Criterion III,
" Design Control" (El.4.2.c)
)
i
1
e
1
i
i
a
4
!
l
i
k
!
!
l
1
1
i
i
$
1
)
A-3
i
!
.
.
-.
.
.
-
_
-
- . - .
.
.
_-
.
.-
-
. - _ . . . . -
- - .
. - . . - . - . .
. - . . .
- - -
. - . _ . . - - . . . ~ . . - - . - . -
I - .
.
!
)
4
Appendix B
i
'
Exit Meeting Attendees
j
NAME
ORGANIZATION
R. Brandt
CEI, Plant General Manager
i
R. Collins
CEI, Manager, Quality Assurance
D. Dervay
CEI, Supervisor, Plant Engineering
j
J. Grabner
CEI, Supervisor, Projects Unit
'
D. Gudger
CEI, Regulatory Compliance
. H. Hegrat
CEI, Manager, Regulatory Affairs
j
J. Hopkins
NRC, Sr. Project Manager, NRR/DRPE
!
J. Jacobson
NRC, Branch Chief, DRP/ Region III
S. Jaffe
Reporter, Plain Dealer
i
M. Kembic
CEI, Corporate Regulatory Affairs
i
,
M. Leach
NRC, Acting Deputy Director, DRS/ Region III
E. Listen
Member of the Public
j
,
L. McGuire
CEI, Supervisor, Electrical Unit
J. Milicia
Reponer, Lake County News Herald
'
D. Norkin
NRC, Section Chief, NRR/PSIB
H. Oats
CEI, Supervisor, Configuration Control
J. Powers
CEI, Manager, Design Engineering
A. Rabe
CEI, Independent Safety Evaluation Group
T. Rausch
CEI, Director, Nuclear Service Department
.
M. Ring
NRC, Branch Chief, DRS/ Region 11I
i
J. Sielicki
,
.
CEI, Corporate Communications
j
R. Twigg
NRC, Resident Inspector
,
4
,
J
i
i
B-1
.
.
._
.
.
-
-
_
.
.
Appendix C
List of Documents Reviewed
DDunnentho.
Egy
Qgg
Oncument TitlelDeictlDilon
CALCULATIONS
2.6.13
0
10/6/82
ESW/ECCW Cross-Connect
2.6.13.1
1
3/27/89
ESW/ECCW Cross-Connect Hydraulic Analysis
2.6.13.1.1
1
1/4/85
ESW/ECCW Cross Connect System With Standpipe-To-Swale
Hydraulic Analysis
22:08
12/14/78 Condensate Storage Tank Dike and Slab Load Combination
Summary
22:11
07/14/82 Missile Protection For Fuel Oil Day Tank Piping (Vent, Dipstick &
Refill) Unes
22:12
02/24/83 Condensate Storage Tank Instrument Miscila Shields
36:01.3.2.1.5
4
3/21/85
Control Complex El. 574-10 Nonsafety Sanitary Floor Drains Seismic
Support
4.05.1
0
10/6/81
Auxiliary Building - Pump Room Walls
B21-C06
Drywell Pressure
B21-C10
RPV Level 8
821-C11
RPV Level 2
CL-ECA-011
2
7/18/85
Environmental Conditions Analysis (AB-2-W)
CL-SBO-001
1
10/6/92
Steady State Temperature Within Unit 1 Division 2, High Pressure
Core Spray Switchgear Room During Station Blackout
E22-1
0
5/12/81
HPCS System, NPSH Calculations (with DCC 3)
E22-11
0
5/23/84
E22 Pump Suction Switchover
<
E22-19
1
7/23/92
Justification For Elimination Of HPCS Overfrequency Relay
'
E22-2
0
2/23/83
Overpressure Protection Analysis
E22-24
0
7/24/93
High Pressure Core Spray Waterleg Pump Surveillance Test
Acceptability
E22-26
1
3/20/95
Design Limiting U For Heat Exchanger
E22-28
0
10/4/95
Overall Heat Transfer Coefficient For Heat Exchanger
E22-29
3
2/1/96
SVI-E22-T2001 HPCS Pump Performance Acceptance Criteria
E22-29
4
2/28/97
SVl-E22-T2001, HPCS Pump Performance Acceptance Criteria
-
E22-32
0
10/14/95 HPCS EDG JW Heat Exchanger Test Results - 1995
E22-35
0
3/24/97
HPCS Pump - NPSH A With SPCU in Operation
E22-6
0
11/10/83 HPCS System Piping
E22-C01
Suppression Pool High Level
E22-C02
3
9/13/95
HPCS - CST Low Level Transfer Trip - 1E22-N654C(G)
E22-003
HPCS Minimum Flow
E22-C04
Diesel Air Crank Jog
E22-C05
HPCS Discharge Pressure Bypass Valve Interlock
E22-C06
Diesel Low Oil Pressure
E22-C07
Diesel Generator Tachometer
E22-C08
HPCS Diesel Generator Timing Relays
E22-C10
HPCS Discharge Flow ERIS Input
E22-C11
HPCS Discharge Flow Indication
E22-C12
HPCS Discharge Pressure Indication
E22-C133
Diesel Starting Air Pressure Regulator
C-1
_ _ .
. _ . _ .
___ _._ _______ _ _ __.
_
_
_ _ _ _ _ _ _ _ _ _ ,
-
.
.
.
E22-T01
2
6/26/96
Setpoint To erance Calculation For HPCS Diesel Square D
instrumentation Loops
E22-T03
0
9/24/91
E22 Waterleg Pump Low Pressure Alarm
.
ECPC-0001
2
8/25/92
Electrical Penetration 12T Verification
3
FSPC-0018
1
4/3/96
Div I MOV Fuse Sizing
FSPC-0019
1
4/1/96
Div 11 MOV Fuse Sizing
FSPC-0020
1
4/8/96
Div 111 MOV Fuse Sizing
JL-105
7
10/31/88 Containment and Drywell Break Exclusion Areas
JL-63
0
11/25/81 ECCS and Suppression Pool Level After ECCS Suction Break
-
M39-6
0
7/31/96
HPCS Room Cooler Performance Test Results - 1995
'
'
M43
2
5/9/91
Diesel Generator Building Vent System Ventilation Load
M43-1
0
8/28/86
Minimum Outside Air Temperature For Diesel HVAC Temporary
Conditions
MOVC-047
3
5/7/96
AC Voltage Drop Calculation For Butterfly MOVs (With DCCs 3,6,8)
i
P11-12
0
3/15/85
Level Setpoints in CST For Adequatti NPSH and No Vortexing
i
P11-12
1
3/25/97
P11 - Leve' Setpoints In CST For E22 and E51 Instruments
'
,
P42-11
2
5/25/89
P42 Syttem Operating Temperature (Note: This Calc. Has Been
Superseded By P42-28)
,
P42-12
0
12/24/84 P42 System - Heat Exchanger Thermal Relief Valve Analysis
1
)
P42-19
0
5/6/94
P42 System Heat Load Subsequent To A LOOP During RF04
t
P42-23
1
9/6/95
ECC Hx Performance Calculation
P42-24
1
4/28/95
Maximum Allowable Leakage From P42 System
P42-25
1
11/17/94 Determine The ESW Winter Bypass Une Flow To The ECC Heat
1
,
Exchanger, in Order To Maintain The C.C. Chiller Condenser Water
1
Temperature Between 55*F and 95*F.
!
!
P42-26
Composite Bias Uncertainty Of ECC 'A' ECC Flow
j
P42-27
Composite Bias Uncertainty Of ECC 'B' ECC Flow
.
P42-28,
0
6/1/95
ECC Thermal-Hydraulic Analysis
l
P42-30
0
4/29/95
Evaluation Of ECCHX Temperature Control Valve 1P42-F0665A/B
2
P42-31
0
9/15/95
ECC A Heat Exchanger Test Results - 1995
P42-32
0
9/29/95
ECC B Heat Exchanger Test Results - 1995
j
P42-33
0
5/1/96
Evaluation Of Heat Transfer Coefficient and Min. Required Wall
Thickness For ECC Heat Exchangers 1P42-80001 A/B
,
'
P42-4
3
5/24/89
ECCW Heat Exchanger Size and Outlet Temperature
P42-5
3
2/22/85
Emergency Closed Cooling Water System Surge Tank Sizing
P42-6
0
1/7/81
ECCW (P42) Calculation For System Design Pressure
{
P42-7
0
5/26/82
Atmospheric Surge Tank Vent (P42)
1
P42-8
0
7/30/84
Overpressure Protection Analysis
!
P42-C01
ECC Flow Switches
l
P42-C02
Time Delay Setpoint Chiller MOV Opening
l
P42-T02
ECC Hx Outlet Temperature Bistables 1P42N051 A/B
j
P42-T04
ECC Surge Tank Level Switches P42-N131 A,8
j
P42-T05
ECC Surge Tank Level Switches P42-N130A,8
i
P42-T06
ECC Low Flow Alarm
P43-12
0
2/7/94
Seismic Event Inventory Loss Analysis
PNED-UOO8
2
11/4/96
Fuse Selection and Sizing Methodology
,
.
PRDC-0004
2
5/30/95
Class IE DC Control Circuit Coordination
!
PRDC-0005
3
5/23/96
Load Evaluation and Battery Sizing Of Div i & 11 Class IE DC System
l
PRDC-0006
0
4/8/91
Load Evaluation and Battery Sizing Of Div Ill Class IE DC System
!
PRDC-0007
3
4/3/96
Voltage Drop Control Circuit For Switchgear Fed Equipment
PRLV-0004
2
4/30/96
480v Breaker Coordination
.
PRLV-0059
Station Blackout: Div Ill To Div 11 Crosstie
PRMV-0001
2
11/22/88 Div I and H Diesel Generator, EH1102, EH1201,1R43S0001 A, B
<
!
3.
C-2
<
1
a
-_
- _ _
.
_
,
_ ____ _ _ . . _
.
. _ _ _ _ _
_
_ _ _ _ _ . _ _ .
. _ _ _ _ _ - _ . _ .
_ . . _ . _ . _ . _ _ _ _ _ _ _ _
.
-
<
!
l
4
PRMV-0014
2
11/22/88 Div Ill HPCS Diesel Generator EH1301,1 E22S001
PRMV-0015
0
3/11/85
EH13 Bus Supply Breakers EH1302, EH1303
,
PRMV-0017
0
3/11/85
EHF-1-E Transformer Breaker EH-1305
PRMV-0020
2
11/22/88 Degraded Voltage and Loss Off Power Undervoltage Relaying For
]
Div 1, ll, and 111
i
PRMV-0061
0
8/28/91
Div 1, ll and til Diesel Generator Voltage Controlled, Overcurrent and
i
Load Test Overload Protection
"
PRMV-0062
07/28/95 4.16kV Class 1E Switchgear Degraded Voltage Instrumentation Loop
Tolerance
PSTG-0001
2
8/24/95
PNPP Auxiliary System Voltage Study
,
PSTG-0003
2
6/29/95
480v Safety Related Motor Starting Voltage Drop
!
PSTG-0006
2
5/20/92
PNPP Short Circuit Study
l
PSTG-0014
3
10/21/96 Diesel Loading I,11 and 111
PSTG-0021
1
6/22/93
Voltage Drop in Control Circuit Of Safety Related Size 2,3 and 4
-
Starters
l
PSTG-0027
0
7/14/93
Voltage Drop in Control Circuit Of Safety Related Size 1 Starters
i
PY-CEl-96-001
0
10/31/96 Total Amount Of Fibrous Insulation Inside Containment
PY-CEl-96-002
0
10/30/96 Amount Of Fibrous insulation Produced By A Line Break inside
,
Containment
,
1
R44-6, Rev. 0
0
7/7/92
Correlation Of EDG Starting Air Properties At System Operating
Pressure Of 250 psig and At Atmospheric Pressure
i
R44-7
0
1/7/93
Starting Air Leakage Criteria For The Standby and HPCS Emergency
!
Diesel Generators Starting Air (R44) System
'
R45-10
2
4/28/91
Diesel Generator Fuel Oil Storage Tank Correlation
R45-11
0
11/25/92 Emergency Diesel Generator Fuel Oil Transfer Pump Performance
,
Requirements
-
R45-3
1
1/16/96
Diesel Fuel Oil Pumps (With DCC 2)
R45-C01
Diesel Fuel Oil Day Tank Level
R48-10
1
3/23/93
Standby and HPCS Diesel Generator intake Air
l
R48-11
2
6/29/95
Standby and HPCS DG Vent Valve
i
R48-13
1
12/9/96
EDG Exhaust Vent Valve Setpoint Calculation (With DCC 3)
R48-14
0
12/10/96 Diesel Generator Exhaust Vent Valve Testing (With DCC 2)
1
R48-17
0
11/13/92 Seizure Of EDG Exhaust Relief Valve Bearings
R48-8
1
3/3/93
EDG Exhaust Vent Va!ve Size
,
CORRECTIVE ACTION DOCUMENTATION
,
CR 89-0032
i
CR 92-016
CR 92-0215
CR 93-0114
CR 93-0245
CR 93-0276
'
CR 93-0486
CR 93-3022
CR 94-0095
CR 94-0428
CR 94-0507
CR 94-0686
CR 94-0889
CR 94-1462
CR 94-2104
CR 95-0132
C-3
. _ _ . . . _
_ _ _ _ .
. _ _ _ _ _ _ _ . _ _ _ . . _ . _ _ _ . _ _ _ _ - > _ . .
. _ .__ _ ._ ___.___. _ _ _
.
.
-
3
,
CR 95-OiS3
,
CR 95-0570
CR 95-1150
i
i
CR 95-1214
CR 95-1654
CR 95-2586
I
CR 96-0169
i
j
CR QQC-02345
1
NR 91-S-00091
4
i
NR 92-S-00252
'
NR 92-S-00289
'
'
NR 94-S-00615
.
NR MMQS-02965
PlF 94-2196
i
PlF 94-2247
PIF 95-0570
PIF 95-1150
'
PlF E0021
PIF 96-0164
PlF 96-0165
l
PIF 96-0325
i
PlF 96-0425
j
PlF 96-0656
PIF 96-0810
i
PlF 96-0900
P!F E1046
,
PIF 96-1078
5
PlF 96-1241
PlF E1265
PlF 96-1289
PlF 96-1291
PIF 96-1523
PIF 96-1554
PlF 96-1578
PlF E1866
PIF 96-1869.
PlF 96-2671
PlF 96-2699
PIF 96-2700
PlF 96-2846
PlF 96-2889
PIF 96-3035
PlF 96-3039
,
PlF 96-3642
PlF 97-0185
PlF 97-0325
PlF 97-0344
,
PlF 97-0345
PIF 97-0351
i
'
PIF 97-0379
PIF 97-0421
PlF 97-0431
PlF 97-0441
i
!
C-4
l
,
._
-
_
.
.
PlF 97-0442
PIF 97-0463
PlF 97-0464
PIF 97-0471
PlF 97-0487
PlF 97-0499
PlF 97-0513
PIF 97-0526
PlF 97-0538
PIF 97-0544
PlF 97-0556
PIF 97-0560
PIF 97-0561
PIFRA 96-1609-001
DESIGN CHANGE PACKAGES fDCP)
86-0174
Replacement Of Orifice Plates OP42N0265A & B
86-0224
P45 Low Flow Bypass Around ECCs (P42) Heat Exchanger Outlet
Valve
'
86-0493
Addition Of High Point Vents To Transmitter 1P42N249
89-0117
Delay Control Complex Chiller Start Circuitry During A LOOP Or
90-0012
Replace Manual Valves P42-F550 and P42-F551 With MOV's
90-00181
Suppression Pool B Loop LevelInstrumentation
90-00235
Replace Agastat Time Delay Relays
90-0086
Rotate Spectacle Flanges On 2P42/1P45 Interface
90-0275
2
Diesel Generator Exhaust Testable Rupture Disc Modification
91-00104
MOVs in HPCS Starting Air Compressor - Voltage Spike
92-00042
Sliding Unks
92-00060
MOV To Manual Valve Change; Deactivate
92-0060
P42F315A B C Converted To Manually Operated Valves
53-00082 & 82 A
93-00092
Topaz inverters
93-00,133
No> Remote Shutdown MOV Power Fuse Sizing
93-00148
HVAC Fan Motor Fuse Operation
93-00179
Valve indication Wiring; Torque Switch Setting
94-00161
SIL 435; Stem / Disc Separation
94-0027
ECC Ternperature Control Valve and Bypass Line
96-04067
Relay Replacement - DCPs 68 - 72 Similar
SE 96-126
10/10/96 10CFR50.59 Safety Evaluation - ECC Surge Tank
DESIGN DOCUMENTATION
4
-
HPCS System Functional / Performance Design Bases
-
2/29/80
Target Rock Production Operational Test For Tag Number RNQ201
21 A9236 (GE)
4
Engine Generator For High Pressure Core Spray System
22A3131 (GE)
5
4/77
3
12/2/83
High Pressure Core Spray Design Specification Data Sheet
7964-W6
7/31/75
Struthers Wells Specification Sheet
DI-224
0
HPCS Pump Room Cooler Design input
C-5
.
.
DSP-E22-1-4549-00,
3
4/18/86
Design Specification High Pressure Core Spray and Pipe Supports
ASME Ill Division 1
FDDR KL1-3980
Overfrequency Protection Relay
08/00/79 High Pressure Core Spray System Power Supply Unit (Amendment 3)
PDB-B0002
1
Pump Performance Curves
SDM-E22A
6
2/28/96
High Pressure Core Spray System Description Manual
SDM-E228
8
7/25/95
HPCS Diesel Generator System Description Manual
SDM-P42
8
7/25/96
Emergency Closed Cooling (ECC) System Description Manual
Design Fabrication and Delivery Of Air Handling Units
DRAWINGS
04-4549-S-322-701
C
Pipe Support Mk-1E22-H1024
10776-7-2
4
Bishopric Drawing For Nozzle Details For HPCS Diesel Generator
Fuel Oil Storage Tanks
10776-7-5
7
Bishopric Drawing For HPCS Diesel Generator Fuel Oil Storage
Tanks Assembly
25131
C
Stewart and Stevenson Drawing
A
Byron Jackson Drawing
3/4 X 1 REH-5-4
G
Target Rock Drawing
39347
Bingham Willamette Drawing
Carrier Drawing HPCS Pump Room Cooling Air Handling Unit
F
Carrier Drawing
4549-22-140-1
0
Emergency Closed Cooling Heat Exchanger Loop "A" Tube Sheet
Drawing
4549-22-140-2
0
Emergency Closed Cooling Heat Exchanger Loop "B" Tube Sheet
Drawing
4549-40-198-3A
24"- 150# Gate Valve (MPL E22-015)
G
Target Rock Drawing
B-208-013 Sh H101
09/18/95 Nuclear Boiler Nuclear Steam Supply Shutoff System isolation Signal
B-208-013 Sh H104
01/10/92 Nuclear Boiler Nuclear Steam Supply Shutoff System Isolation Signal
B-208-013 Sh H105
01/11/92 Nuclear Boiler Nuclear Steam Supply Shutoff System Isolation Signal
B-208-040 Sh A014
08/01/95 Reactor Protection System Testability Card File Tabulations
B-208-040 Sh A015
08/18/86 Reactor Protection System Testability
B-208-040 Sh H100
09/06/95 Nuclear Boiler Nuclear Steam Supply Shutoff System Isolation Signal
B-208-055 Sh A008
07/26/94 Residual Heat Removal System Relay Logic Bus "B"
B-208-055 Sh A015
07/12/94 Residual Heat Removal System Testability (B)
B-208-055 Sh A036
07/26/94 Residual Heat Removal System RHR "B' Test Return MOV F0248
B-208-055 Sh A066
09/11/91 Residual Heat Removal System Suppression Pool Cooling Via RHR
Bypass Valve F609
B-208-055 Sh A067
09/11/91 Residual Heat Removal System Suppression Pool Cooling Via RHR
Bypass Valve F610
B-208-055 Sh A100
04/21/94 Residual Heat Removal System LOCA Signal
B-208-060 Sh A006
06/09/94 Low Pressure Core Spray System Testability Circuits
B-208-065, Sh.14
N
HPCS System Pump Injection Shutoff, MOV F004
B-208-066
Y
DIV lil Diesel Generator Control (1E22-S001)
B-208-066, Sh.1
Y
HPCS Power Supply System, Pump C001
B-208-094 Sh 000
10/13/86 Suppression Pool Drain and Cleanup Index
B-208-094 Sh 001
04/08/86 Suppress:on Pool Drain and Cleanup Pump C001
B-208-094 Sh 002
10/12/96 Suppression Pool Drain and Cleanup Pump Suction Valve F010
B-208-094 Sh 003
12/14/89 Suppression Pool Drain and Cleanup Pump Suction Valve F020
C-6
_-
._.
.
.
B-208-094 Sh 004
12/12/86 Suppression Pool Drain ano ueanup Fump Discharge Va ve F060
B-208-OS4 Sh 005
06/09/94 Suppression Pool Drain and Cleanup Demineralizer Alignment Valve
B-208-094 Sh 006
11/02/85 Suppression Pool Drain and Cleanup Demineralizer Effluent To RHR
Valve F080
B-208-094 Sh 200
04/17/86 Suppression Pool Drain and Cleanup Flow Process Instrumentation
B-814-842
E
Emergency Closed Cooling Surge Tank (1P42A001A) Level
Instrumentation
D-206-027
FFF
Electrical One Une Diagram, Class IE, 480v Bus EF1D
D-206-029
BB
Electrical One Une Diagram, Class IE, 480v Bus EF1D
D-206-051
WW
Electrical One Uno Diagram, Class IE DC System
D-206-052
UU
Electrical One Une Diagram, Non Class IE System Bus D1 A/D1B
D-214-004
T
Conduit and Tray Separation Criteria
D-215-004, Sh.601
S
Electrical Conduit Layout Detail
D-215-801
J
Cable Pulling Criteria, Bending and Training Radius
D-217-103 Sh 4
L
Electrical Heat Trace - Condensate Storage and Transfer
D-219-001
P
Grounding Details Drawing
D-301-801
A
No Title
D-302-212
KK
No Title
D-302-358
C
No Title
D-302-621 (Unit 1)
BB
Emergency Closed Cooling Water System (P&lD)
D-302-622 (Unit 1)
F
Emergency Closed Cooling Water System (P&!D)
D-302-623 (Unit 1)
H
Emergency Closed Cooling Operating Data
D-302-701
High Pressure Core Spray System
D-302-791
Z
No Title
D-302-792
No Title
D-303-016-101.2
11/29/79 Condensate Storage & Transfer
D-303-016-101.3
05/04/81 Condensate Storage & Transfer
D-303-016-101.4
07/06/82 Condensate Storage & Transfer
D-303-016-101.5
03/19/84 Condensato Storage & Transfer
D-304-313-103.2
05/19/80 Condensate Storage & Transfer
D-304-313-103.3
02/16/81 Condensate Storage & Transfer
D-304-313-103.4
12/21/82 Condensate Storage & Transfer
D-304-313-104.2
02/10/81 Condensate Sterage & Transfer
D-304-313-104.3
12/21/82 Condensate Storage & Transfer
D-304-313-104.4
08/30/83 Condensate Storage & Transfer
D-304-314-101.2
12/08/80 Condensate Storage & Transfer
D-304-314-101.3
04/03/81 Condensate Storage & Transfer
D-304-314-101.4
08/30/83 Condensate Storage & Transfer
D-304-701
M
High Pressure Core Spray Isometric Piping
D-352-621 (Untt 2)
S
Emergency Closed Cooling Water System (P&lD)
D-814-409 Sh 901
06/16/85 Condensate Storage Tank Level Instrumentation Pipe Routing
D-814-409 Sh 902
06/16/85 Condensate Storage Tank Level Instrumentation Hanger Orientation
D-814-409 Sh 903
06/16/85 Condensate Storage Tank Level Instrumentation Hanger Fabrication
& Tabulation
D-814-409 Sh 904
04/23/85 Condensate Storage Tank Level instrumentation (1E22-N054C) Rack
Details
D-814-409 Sh 905
04/24/85 Condensato Storage Tank LevelInstrumentation (iE22-N0540) Rack
Fabrication
D-814-409 Sh 906
04/23/85 Condensate Storage Tank Level Instrumentation (1E22-NO35A) Rack
Details
3
C-7
_
..-
. . - .
. - - -
-
- - .
_
_
_ ~
- _ .
. - . . - . ~ . - .- - - . - . --__-
!
-
.
i
'
.
D-814-400 Sh 907
04/24/85 Condensare Storage Tank Level Instrumentation (1 E22-N035A) Rack
i
Fabncadon
D-814-409 Sh 908
04/23/85 Condensate Storage Tank Level Instrumentation (1E22-N054G) Rack
s
Details
D-814-409 Sh 909
04/24/85 Condensate Storage Tank Level Instrumentation (1E22-N054G) Rack
Fabrication
D-814-409 Sh 910
05/29/85 Condensate Storage Tank Level Instrumentation (1E22-NO35E) Rack
i
Details
'
D-814-409 Sh 911
05/29/85 Condensate Storage Tank Level Instrumentation (1E22-NO35E) Rack
j
Fabrication
D-814-409 906
C
No Title
D-814-409-908
C
Hu Title
D-814-728-907
8
No Title
D-814-842-901,
Emergency Closed Cooling Surge Tank (1P42A001 A) Level
-
'
instrumentation
D-814-842-903
Emergency Cicsed Cooling Surge Tank (1P42A001 A) Level
Instrumentation
l
D304-315
G
No Title
D304-316
J
No Title
D304-317
M
No Title
!
D76-95
S
No Title
E-303-016
K
No Title
i
E-303-002
H
No Title
l
FCD 308-311 Sh 1
0
HPCS Functional Control Diagrams
FCD 308-311 Sh 2
0
HPCS Functicnal Control Diagrams
FCD 308-311 Sh 3
0
HPCS Functional Control Diagrams
FCD 308-311 Sh 4
D
HPCS Diesel Generator Functional Control Diagram
T-37225
1
2Hi79
Byron Jackson Test Plot- HPCS Pump
LETTERS
-
07/18/95 General Electric Setpoint Methodology - Perry Nuclear Power Plant,
Unit No.1 (TAC No. M860233)
CEl- 04/26/82A
Response To Draft SER Containment Systems Branch
Gilbert /Commonwealt
12/5/77
Perry Nuclear Power Plant Control Complex Flooding
h to CEI
NRC to CEI
12/20/85 Fire Protection Inspections
PY-CEl/NRR-1121
1/26/90
Service Water System Problems Affecting Safety Related Equipment
PY-CEl/NRR-1328L
3/1/91
Supplemental Response To Generic Letter 89-13
PY-CEl/NRR-1706 L
10/15/93 Instrument Setpoint Methodology For Protection System
Instrumentation
PY-CEl/NRR-1734L
4/8/94
Service Water System Problems Affecting Safety Related Equipment
PY-CEl/NRR-2111L
11/4/96
Response To NRC Bulletin 96-03, Potential Plugging Of Emergency
Core Cooling Suction Strainers By Debris in Boiling-Water Reactors
PY-gal /CEl-12043
12/9/81
Minimum Suppression Pool Level Following ECCs Suction Lino Break
MEMOS
PY-STR-1091
06/1999 Perry Nuclear Power Plant FSAR Draft Sub-Section 3.5.1.4
PY-STR-1092
06/2599 Perry Nuclear Power Plant Tornado Missile Protection
PY-STR-1098
07/06/79 Tornado Missile Drawing Review
PY-STR-1102
07/13/79 Tornado Missile Drawing Review
C-8
9
1...,
,, .
_ . -
_ . . _ _ .
_ _ _ _ _ . . - . _ _
_ _ _ _ _ _ .
_ _ _ _ - .
,
.
.
l
RAS-94-0272
07/21/94
RHR (LPCl Opetability
'
f
OPERATING EXPERIENCE
'
10/25/89 Minutes of Public Meeting on Generic Letter 89-04
-
04/24/86 Implementation Of Fire Protection Requirements
,
03/25/94 Implementation Of Fire Protection Requirements
Supp1
04/03/89 Guidance on Developing Light Water Reactor Inservice Testing
Programs
,
Information Notice 83-
11/14/83 Air / Gas Entrainment Events Resulting In System Failures (Z00593)
77
Information Notice 87-
02/11/87 Information Notice Potential For Water Hammer During Restart Of
10
Residual Heat Removal Pumps
,
Information Notice 89-
10/19/89 Diversion Of The Residual Heat Removal Pump Seal cooling Water
71
Flow During Recalculation Operation Following Loss-Of Coolant
'
Accident (ZO2722)
{
information Notice 92-
3?/28/92 information Notice Potential For Loss Of Remote Shutdown Capability
'
18
During A Control Room Fire
,
LER 93-021
1
12/20/96 Improper Setting Of Motor-Operated Valve Results in Loss Of
'
Emergency Closed Cooling System Safety Function and Condition
Prohibited By Technical Specifications
LER 94-005
1
10/28/94 Loss Of Both Trains Of Control Room Emergency Recirculation Due
l
To Low Emergency Closed Cooling Temperature
,
PS 6136
RHR Pump Seal Cooler Shell Side Design Pressure
PROCEDURES. TESTS. INSTRUCTIONS
'
All-H13-P601-17
4
9/11/92
Alarm Response Procedure RHR B & C (Unit 1 )
ALl-H13-P601-20
11/28/94 Alarm Response Procedure RHR A (Unit 1)
ARI-H13-P601-16
4-
Alarm Response Procedure HPCS Water Leg Pump Discharge
Pressure Low
ONI-R61
0
10/2/96
Off-NormalInstruction Loss Of Control Room Annunciators (Unit 1),
l
through Plc No.1
gel-0007
1
Cable / Wire Termination Instruction
gel-0024
2
Cable Pulung instruction
GMI-180
0
Greer Hydraulic Actuator Maintenance
CMI-156
Operability Test and Maintenance Of Diesel Generator Testable
Rupture Disc
IMI-E3-23
06/12/91 Instrument Maintenance Instruction, Division Ill HPCS Diesel
Generator Woodward Governor
101-11
05/16/95 Integrated Operating Instruction, Shutdown From Outside The Control
P.com
ISTP
3
7/17/94
Pump and Valve Inservice Testing Program Plan (ISTP), through Plc
No. 6 Dated 1/31/97
ONI-D51
4
10/17/96 Off-Normal Instruction - Earthquake (Uniti), through Plc No. 5
ONI-R10
06/01/94 Off Normal Instruction - Loss Of AC Power
Pressure Relief Device Test Data Sheet 1E22-F014, W.O. Number
-
88-8670
4/12/94
Pressure Relief Device Test Data Sheet For 1E22-F0014
-
4/13/96
Pressure Relief Device Test Data Sheet For 1E22-F0533B
-
4/28/94
Pressure Relief Device Test Data Sheet For 1E-F0035
-
6/4/92
Pressure Relief Device Test Data Sheet For 1E22-F0533A
-
C-9
.
.
.
.-
- . - . . - .
-
-
.__.
.
\\
.
.
PTI-M39-P0002
Surveillance Task Number S95-000032
PTI-P42-P0008
1
9/1/95
Periodic Test Procedure P42 Leak Rate Determins. tion
E22A
01/06/89 HPCS Pump and Valve Operability Test
E22A
05/15/96 High Pressure Core Spray System (Unit 1)
E22A Change
01/20/94 HPCS Pump and Valve Operability Test
SOI-G41
8
7/31/95
Fuel Pool Cooling and Cleanup System
sol-P42
7
3/16/96
System Operating Instruction Emergency Closed Cooling System
(Unit 1)
'
sol-P45/P49
2
9/19/95
System Operating Instruction Emergency Service Water and Screen
i
Wash Systems, through PIC No. 8 dated 3/16/96
sol-P47
5
4/7/92
System Operating Instruction Control Complex Chilled Water System,
through Plc No.10 dated 2/21/97
E22-T1329
Division 3 HPCS Diesel Generator 18 Month Functional Test
E22-T1339
02/05/96 Division 3 HPCS Diesel Generator 18 Month Loss Of Off-Site Power
Test
E22-T2001
02/03/97 HPCS Pump and Valve Operability Test
E22-T2001
12/05/95 HPCS Pump and Valve Operability Test
E22-T2001 C-1
01/08/96 HPCS Pump and Valve Operability Test
E22-T2001 C-2
05/09/96 HPCS Pump and Valve Operability Test
E22-T2001 C-3
08/28/96 HPCS Pump and Valve Operability Test
j
E22-T2001 S85-9278
02/20/97 HPCS Pump and Valve Operability Test Data Sheets
E22-T5397
HPCS Initiation and Loss Of EH13 Response Time Test
SVI-E22-T0194-G
3
HPCS CST Low Level Channel G Calibration For 1E22-N054G
SVI-E22-T0194-G
3
HPCS CST Low Level Channel G Calibration For 1E22-N054G
SVl-E22-T0196
3
HPCS Suppression Pool High Level Channel C Calibration For 1E22-
N055C
SVI-E22-T1192
3
HPCS Logic System Functional Test
SVI-E22-T1319
Surveillance Task Number S85-8474
SVI-E22-T1339
Div 111 Diesel Generator 18 Month LOOP /LOCA Test
SVI-E22-T2001
Surve!llance Task Number S85-9278
SVI-E22-T5217
6
5/24/96
Performance Test of Battery Capacity-Division lli (Unit 1)
SVI-E22-T9409
Type C Local Leak Rate Test Of 1E22 Penetration P409
SVI-GEN-T2000
2
ASME Code Check Valve Disassembly Testing
1
SVI-P42-T2002
4
7/11/95
Surveillance Instruction Emergency Closed Cooling System Valve
Operability Test
SVI-P42-T5326
4
10/13/86 Surveillance Instruction Emergency Closed Cooling System Valve
Position Check, including Temporary Change Nos. 2 Through 7 and
Blanket Change Dated 2/17/95
SVI-R42-T5202
5
6/6/91
Weekly 125V Battery Voltage and Category A Limits Check (Uniti)
SVI-R42-T5211
4
11/15/91 Service Test of Battery Capacity (Unit 1, Division I)
SVI-R42-T5219
1
8/5/91
125V Battery Cat. B Limits, Terminal Corrosion and Electrolyte
Temperature Check (Unit 1, Division I)
SVI-R45-T1323
0
Surveillance Task Number S85-8528
TXI-0148
0
Temporary instruction - Division 3 Diesel Generator Timed Starts
Using One Bank Of Starters
VLI-P42
6
9/29/95
Valve Lineup Instruction Emergency Closed Cooling System, through
Plc No. 3 dated 10/16/96
SELF-ASSE5dMENT REPORTS
ISEG Report 91-005
10/27/92 HPCS and EGD SSFl Assessment Results
PA 95-23
03/20/95 System Based instrumentation and Controlinspection (SBICl)
C-10
, _ _ _ _ _ _ _ _ . _ _ _ . _ . .
_ _ _ _ _ _ . _ . . _ . _ _ . _ _ . . _ _
_ _ _ . _ _ _ _ . _ _ _ _ - - . . _ _ _ . _ _
,
.
.
!
5/1/95
System Operation and Review (SO TR) Reports, System Operation
-
and Test Review Program HPCS System Report
SAFETY ANALYSIS REPORT
10/02/89 Appendix R Evaluation: Safe Shutdown Capability Report
l
-
l
Secdon 1.8
NRC Regulatory Guide Assessment
I
Sec6on 12.6
Design Review of Plant Shielding for Spaces / Systems Which May Be
Used in Postaccident Operations Outside Containment
Sec6on 15
Accident Analyses
Section 3.1
Conformance With NRC General Design Criteria (GDC 5,44,45,46)
Section 3.5
Missile Protection
Section 3.6
Protection Against Dynamic Effects Associated with the Postulated
Rupture of Piping
Section 6.2.4.2.2.2
Justification With Respect To General Design Criteria 56
Section 6.2.7
Suppression Pool Makeup System
Section 6.3
Section 7.3.1.1.6
Emergency Water System (EWS) Instrumentation and Controls
Section 8.3
Onsite Power Systems
Section 9.2.2
Emergency Closed Cooling System
Section 9.3.3
Equipment and Floor Drainage System
Section 9.4.5
Engineered Safety Features Ventilation System
Section 9.4.9
Chilled Water Systems
Table 3.9-30
Summary Of Active Valves (Non-NSSS)
Table 0.3-1
Connected, Automatic and Manual Loading and Unloading Of Safety
System Switchgear
OTHER LICENSING DOCUMENTS
GESSAR 113.5.1.3
Missiles Generated By Natural Phenomena
GESSAR 113.5.2
Structures, Systems and Components To Be Protected Frcm
Externally Generated Missiles
1.RG 11 Response
1/25/82
Control Of Post-LOCA Leakage To Protect ECCS and Preserve
Paper
Suppression Pool Level
LRG ll Working Paper
10/26/81 Control Of Post-LOCA Leakage To Protect ECCS and Preserve
Suppression Pool Level
5/82
Safety Evaluation Report Related To The Operation Of Perry Nuclear
,
>
Power Plant, Units 1 and 2, including Supplements 1 Through 10
TECHNICAL SPECIFICATIOBS
Section 3.3.5.1
Emergency Core Cooling System (ECCS) Instrumentation
Section 3.5
Emergency Core Cooling Systems (ECCS) and Reactor Core
isolation Cooling (RCIC) System
Section 3.7.10
Emergency Closed Cooling Water (ECCW) System
Section 3.8
Electrical Power Systems
CODES. STANDARDS. GUIDES
IEEE Trial-Use Standard Criteria for Separation of Class IE
Equipment and Circuits
09/09/76 IEEE Standard Criteria For Diesel-Generator Units Applied As
Standby Power Supplies For Nuclear Power Generating Stations
!
l
C-Il
l
l
t
l
t
_ . . .
.
-
-_
._-
_. -
..
_
.
.
Regulatory Guide
0
11/00H5 Thermal Overload Protection For Eiectric Motors on Motor-Operated
1,106
Valves
Regulatory Guide
1
03/00/77 Thermal Overload Protection For Electric Motors On Motor-Operated
1.106
Valves
Regulatory Gu'de
04/0098 Tornado Design Classification
1.117
Regulatory Guide
05/00/83 Bypassed and Inoperable Status Indication For Nuclear Power Plant
1.47
Safety Systems
Regulatory Guide
04/00/74 Design Basis Tornado For Nuclear Power Plants
1.76
0
03/00/71 Selection, Design and Qualification Of Diesel-Generator Units Used
As Standby (Onsite) Electric Power Systems At Nuclear Power Plants
2
12/00/79 Selection, Design and Qualification Of Diesel-Generator Units Used
As Standby (Onsite) Electric Power Systems At Nuclear Power Pfar>ts
l
4
%
C-12
_
-
.
.
Appendix D
List of Acronyms
,
Alternating Current
AE
Architect-Engineer
ANS American Nuclear Society
ANSI American National Standards Institute
I
Action Request
Alarm Response Instruction
American Society of Mechanical Engineers
Anticipated Transient Without Scram
B&PV Boiler and Pressure Vessel
BWR Boiling-Water Reactor
Cleveland Electric Illuminating
CFR
Code ofFederalRegidations
CR
Condition Report
Condensate Storage Tank
DBA Design-Basis Accident
'
Direct Current
DCP Design Change Package
Diesel Generator
DSP
Design Specification
ECC Emergency Closed Cooling
ECCS Emergency Core Cooling System
EDDR Engineering Design Deficiency Report
EDG Emergency Diesel Generator
EPRI Electric Power Research Institute
ESW Emergency Service Water
,
FCD Functional Control Diagram
FDDR Field Deviatior Disposition Request
FLA
Full Load Amperage
FPCC Fuel Pool Cooling and Cleanup
FSAR Final Safety Analysis Report
GDC Gcneral Design Criterion / Criteria
General Electric Co.
GL
Generic Letter
D1
__ .
_
_ _ _
_ _ _ _ ____
. _ . _
_
__
_
_
, ,
,
I
l
I
HPCS High-Pressure Core Spray
Instrumentation and Control
Inspection and Enforcement
IEEE Institute of Electrical and Electronics Engineers
IFI
Inspection Followup Item
IMI
Instrument Maintenance Instruction
IP
Inspection Plan (or Inspection Procedure)
Inservice Inspection
ISMG Instrument Setpoint Methodology Group
Inservice Testing
ISTP Inservice Testing Program
LER Licensee Event Report
LOCA Loss-of-Coolant Accident
LOOP Loss ofOffsite Power
LPCS Low-Pressure Core Spray
MCC Motor Control Center
MOV Motor-Operated Valve
NCC Nuclear Closed Cooling
NEI
Nuclear Engineering Instruction
NPSH Net Positive Suction Head
NR
Nonconformance Report
NRC
U.S. Nuclear Regulatory Commission
NRR Nuclear Reactor Regulation, Office of(NRC)
NSSS Nuclear Steam Supply System
OER Operating Experience Review
ONI
Off-Normal Instruction
P&ID Piping and Instrumentation Diagram
Potential Issue Form
PNPP Perry Nuclear Power Plant
RCIC Reactor Core Isolation Cooling
Regulatory Guide
SBICI System-Based Instrumentation and Control Inspection
SBO Station Blackout
!
SDM System Description Manual
!
.
D-2
- . _
- . -
- . - - -
-
-
. -. _ . -
- - . - .. - . ..--- - .. - _ . .-. - .
-
. . .
.
.
.
SER Safety Evaluation Report
SOI
System Operating Instruction
'
SPCU Suppression Pool Cleanup
Standard Review Plan
>
SSFI Safety System Functional Inspection
'
SVI
Surveillance Test Procedure
,
SWEC Stone & Webster Engineering Corporation
l
TCV Temperature Control Valve
TDH Total Discharge Ilead
TRD Testable Rupture Disc
l
TS
Technical Specification (s)
Unresolved Item
!
USAR Updated Safety Analysis Report
WG _ Water Gage
I
l
i
l
i
t
l
I
,
l
?
l
t
l
'
D-3
_-
-
. -
. .
.
_-
. - . _ _ _. _
. _ _ _ . _ - . . . _ . .
. . - . _ - . __ _ . - . . _ _ . _
. _ _ _ _
_ . - - _ _ _ _ . _ _ . _ . . _ _ _
_ _ .
.
.
Attachment 1
-
,
Slides Used During Public Exit
t
l
l
\\
I
i
-
,
\\
i
Attachment 1-1
l
l
.
- --.-
- --- --_ -_.
_ -
. . . - - -
.
.
t
t
i
1
a
h
PERRY NL CLEAR PLANT, UNIT 1
i
.
.
DESIGN INSPECTION
,
!
EXIT MEETING
,
i
!
APRIL 22,1997
l
.
P
I
l
-
,
Attachment 1-2
i
.
- - - - - - --- - - - - - - - -
- - ---
- - - - -
- - - - - - - - - - - -
-
-_ --
- ----
--- ---
1
I
OUTLISE OF PRESE: STATION
!
!
INTRODUCTIONS
i
-
l
OBJECTIVES, SCOPE ASD SCHEDULE
1
INSPECTION RESULTS - GENERAL ASSESSENT
INSPECTION RESULTS - SPECIFIC FISDINGS
(
CONCLUDING REMARKS
>
1
i
!
1
,
Attachment 1-3
1
4
b
e
,-
-n,
-w
,
-w--,-m-r-e-.
-r-w
r-w - r m += w - v e
t dev
tN
- '-
- - -
.
-
. -
-_
-
- - - - _ - --- _ -- ----- - --- ---- -
-
.
'
i
,
INTRODUCTIONS
-
'
i
i
INSPECTION REPORT NO. 50-440/97-201
I
.
REPORT WILL BE ISSUED IN APPROXIMATELY 45 DAYS
1
!
FOLLOWUP ACTIONS WILL BE BASED ON THE FINDINGS
i
AND MAYBE ACCOMPLISHED BY BOTH REGIONAL AND
HEADQUARTERS PERSONNEL
ENFORCEMENT ACTION WILL BE ISSUED BY THE REGION
Attachment 1-4
.
en
.
. _
- -
--- - --_ _ --- __
_ - _ - - _ _ .
_ - - .
.
._
i
!
l
OBJECTIVES
i
!
DETERMINE IF PERRY MEETS ORIGINAL DESIGN BASES & TO VERIFY
!
DESIGN BASES HAS BEEN MAINTAINED
!
SCOPE
I
EMERGENCY CLOSED COOLING SYSTEM
HIGH PRESSURE CORE SPRAY, INCLUDING THE DEDICATED DIESEL
GENERATOR
!
l
SCHEDULE
STARTED FEBRUARY 17 COMPLETED MARCH 27
,
1
Attachment 1-5
-
i
e
-vw
.a
-
a
- - -- -
- - - - -
- - - - -
- - - - - - .
- -
. -
- -
-
- -
. -
. .
.
.
--.
.
.
-
.
.
.
l
INSPECTION RESULTS - GENERAL ASSESSMENT
i
l
THE TEAM DETERMINED THAT THE SYSTEMS ARE CAPABLE OF
e
PERFORMING THEIR INTENDED SAFETY FUNCTIONS.
l
e
CONTINUOUS OPERATION OF THE SUPPRESSION POOL CLEANUP
l
SYSTEM RESULTS IN THE HIGH PRESSURE CORE SPRAY SYSTEM BEING
i
OPERATED IN AN ALIGNMENT DIFFERENT THEN DESCRIBED IN THE
i
FSAR.
e
ALTHOUGH THE LICENSEE'S SAFETY SYSTEM SELF-ASSESSMENTS DID
j
NOT IDENTIFY AND CORRECT MANY OF THE ISSUES RAISED BY THE
TEAM, MANY GOOD ISSUES WERE IDENTIFIED AND CORRECTED. THE
,
SYSTEM BASED INSTRUMENT AND CONTROL SYSTEM INSPECTION
,
ALSO RESULTED IN THE IDENTIFICATION AND CORRECTION OF MANY
i
ISSUES AS WELL.
'
I
Attachment 1-6
- ,
.
- .
- -
-
-
-
-
- -
-
--- -
--- --
- - - - - - - - - - -
--
- - - -
. -
- - - - - -
- - - - -
_-
- - - - - - _ _ -
-
_
_
i
Il
DESIGN OF THE EMERGENCY CLOSED COOLING SYSTEM WAS
e
. GENERALLY GOOD, WITH MORE THAN ADEQUATE MARGIN IN THE
DELIVERY SYSTEM. HOWEVER, WEAKNESS IN THE ORIGINAL DESIGN
OF THE SURGE TANK COMBINED WITH BOUNDARY VALVE SEAT
i
l
LEAKAGE HAS RESULTED IN EARLY MANUAL OPERATOR ACTION
'
THAT MAY CONSTITUTE AN UNREVIEWED SAFETY ISSUE.
THE HIGH PRESSURE CORE SPRAY SYSTEM IS CAPABLE OF
e
PERFORMING ITS REQUIRED SAFETY FUNCTION. HOWEVER, THE
1
SYSTEM HAS LITTLE MARGIN AS TO REQUIRED FLOWS AND TIME
i
RESPONSE. CURRENT OPERATING PRACTICES (SPEED DROOP AND
l
OPERATION OF SPCU) ALSO IMPACT SYSTEM MARGIN.
j
THE QUALITY OF CALCULATIONS WAS MIXED. NEWER ONES WERE
e
BETTER THAN OLDER ONES. ELECTRICAL CALCULATIONS WERE NOT
,
j
BEING UPDATED AS REQUIRED. DESIGN CHANGES REVIEWED WERE
GENERALLY GOOD.
!
i
Attachment 1-7
>
.
.
.
.
.
.
. . -
.
.
.
. -
.
.
- . .
.
-
_
_
_
_ _ _ _ _ _ - - - _.
e
CORRECTIVE ACTION FOR DIVISION III DIESEL EXHAUST TESTABLE
,
RUPTURE DISK FAILURES HAS BEEN SLOW. ADDITIONALLY, YOUR
STAFF IDENTIFIED THAT THE OVERFREQUENCY RELAY FOR HIGH
PRESSURE CORE SPRAY PUMP DISCHARGE PIPING OVERPRESSURE
l
PROTECTION WAS NOT INSTALLED. HOWEVER, THE TECHNICAL
j
REVIEW FAILED TO ADEQUATELY CORRECT THIS CODE ISSUE.
e
AFTER REMEDIAL ACTIONS BY PERRY THE TEAM DID NOT HAVE ANY
UNRESOLVED OPERABILITY CONCERNS. PERRY IS ADDRESSING LONG
TERM ISSUES THROUGH THE CORRECTIVE ACTION PROCESS
Attachment 1-8
,
9
__
- _ - _ _ _ _ _ _ _ _ _
_ _ _ _ - - _
..
INSPECTION RESULTS - SPECIFIC FINDINGS
10CFR 50.59 EVALUATIONS
SAFETY EVALUATION TO SUPPORT MANUAL OPERATOR
INTERVENTION TO REFILL ECC SYSTEM SURGE TANK APPEARED
INADEQUATE.
THERE WAS NO ENGINEERING OR SAFETY EVALUATION PERFORMED
WHEN EDG SPEED DROOP WAS CHANGED FROM WHATTHE VENDOR
RECOMMENDS AND FROM HOW THE EDG WAS ORIGINALLY TESTED
FOR QUALIFICATION. .
CONTINUOUS OPERATION OF THE SPCU SYSTEM IMPACTS HOW THE
HPCS SYSTEM IS ALIGNED AND THE NORMAL POSITION OF
CONTAINMENT VALVES. THIS DIFFERS FROM THE FSAR DESCRIPTION
AND THERE WAS NO SAFETY EVALUATION PERFORMED.
Attachment 1-9
L
e
-_ __ -_ . _ _ _ - - - - - -
- _ - - - - - - - - - - - - - - - _ - -
_
3
PORTIONS OF THE HIGH PRESSURE LORE SPRAY SUCTION PIPING
e
FROM THE CONDENSATE STORAGE TANK (CST) AND CST INSTRUMENT
LINES WERE NOT PROTECTED AS DESCRIBED IN THE FSAR.
!
,
TESTING ISSUES
,
.
l
!
e
PREVIOUS AND CURRENT TESTING OF HPCS ROOM COOLERS APPEAR
'
TO DEVIATE FRO-M COMMITMENTS
i
METHOD OF TESTING EDG TRD DOES NOT ALWAYS ENSURE
e
.
!
REPEATABLE RESULTS
,
!
e
TESTING OF ECC/NCC SYSTEM INTERFACE VALVES DOES NOT PREDICT
ACTUAL VALVE LEAKAGE
j
LEAK TESTING OF SUPPRESSION POOL CLEANUP SYSTEM. INLET
e
!
VALVES IS NOT BEING PERFORMED
,
i
Attachment 1-10
t
4
1
-,
, , . , , - , .
,_.....,v.,_,.,
._.
,
.w. r.
,. - .. . - . . , , , . . . . . ..
_ _ - . , , ...
_ _ , , .. , , , , _ . ,,,
..
y . .
,,m.
. , _ , , , . _ , -
. , , _ , , ,- . . , - - ,
-e
- . - .
,
3
__ - . _-_ ,
._
. _ _ _ _ _ _ - - - -
_
_ - - _ _ _ _ _
_ _ _ - -
- - - _ _ _ -
- - - _ _ - .
- _ -
. - - - - - - - - _
-
4
!
!
l
DESIGN CONTROL ISSUES
!
CONTROL OF CALCULATIONS
!
1
QUALITY AND ACCURACY OF CALCULATIONS
j
DOCUMENTATION ISSUES
l
l
FSAR DISCREPANCIES
i
,
'
SER AND FSAR INCONSISTENCY (HPCS ROOM DESIGN, PASSIVE
j
FAILURE, NON-SEISMIC PIPING DESIGN)
'
!
MAINTENANCE ISSUES
!
!
CLOGGED FLOOR DRAINS, MISSING HANGER, AND BATTERY
1
j
HOLDDOWN BRACKETS NOT PER DRAWING
.
(
i
,
Attachment 1-11
.
1
. _ _ ,
,
.
. .
.
. . . - - - .