ML20134N017
| ML20134N017 | |
| Person / Time | |
|---|---|
| Site: | LaSalle  |
| Issue date: | 11/15/1996 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20134M955 | List: |
| References | |
| 50-373-96-11, 50-374-96-11, NUDOCS 9611260127 | |
| Download: ML20134N017 (91) | |
See also: IR 05000373/1996011
Text
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U.S. NUCLEAR REGULATORY COMMISSION
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REGION lil
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5 Docket Nos: 50-373, 50-374
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i Report Nos: 50-373/96011(DRS); 50-374/96011(DRS)
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j Licensee: Commonwealth Edison Company
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j. Facility: LaSalle County Station, Units 1 and 2 ;
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Location: 2601 N. 21st Road
. Marseilles, IL 61341
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l Dates: September 3-24,1996 i
! inspectors: H. A. Walker, Lead Engineer
V. P. Lougheed, Lead Engineer
i K. Salehi, Engineering Inspector i
l R. A. Winter, Engineering Inspector l
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i Consultants: B. Gupta, Parameter
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R. Stakenborghs, Parameter
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Approved by: Mark A. Ring, Chief, Lead Engineers Branch
Division of Reactor Safety
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9611260127 961115 U
PDR ADOCK 05000373
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EXECUTIVE SUMMARY
LaSalle County Station, Units 1 and 2
NRC Inspection Report Nos. 50-373/96011(DRS); 50-374/96011(DRS)
During the period September 3 through 24,1996, a Region illinspection team conducted a
system operational performance inspection (SOPI) at the LaSalle County Nuclear Power
Station. The system chosen for this inspection was the service water system (SWS). This
encompassed the containment cooling service water (CCSW) (also known as the "VY"
coolers), the residual heat removal service water (RHRSW) and the diesel generator cooling
water (DGCW) systems. For these systems, the inspection included a detailed mechanical
and electrical design review; limited system walkdowns; review of system operation,
maintenance, and surveillance activities; and assessment of quality verification and
corrective actions. Additionally, operability evaluations and Technical Specification (TS)
clarifications were reviewed. The inspectors used Inspection Procedure 93801, " Safety
System Functional inspection," as well as Temporary Instruction 2515/118, " Service
Water System Operational Performance Inspection," as the basis for the inspection. The
inspectors also reviewed the licensee's implementation of commitments to Generic Letter
(GL) 89-13, " Service Water System Problems Affecting Safety Related Equipment."
Overall, the team concluded that the licensee's knowledge of the SWS's design basis was
lacking. This conclusion was based on the number of fundamental design control
weaknesses identified during the inspection. These weaknesses appeared to be reflected
in other functional areas as well, as evidenced by discovery of design changes being
performed as maintenance repairs, and operations failing to detect requirements not being
met.
Deficiencies were also identified in the actions taken in response to GL 89-13. Several
testing deficiencies were identified that indicated that the licensee did not understand the
basis for the testing being performed. Additionally, the actions taken to detect corrosion
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appeared to be less than adequate.
Maintenance
- Four apparent violations were identified and are described in Sections M2.1 through
M2.6. The apparent violations stem from a failure to use the design control process
when the impeller on the 2A RHRSW pump was changed to a larger size. The
resultant increased flow caused premature failure of a valve, and repetitive pegging
of a flow instrument during surveillance testing. These failures led to inadequate
testing, which in turn resulted in a TS surveillance not being met for over 11
months. Although multiple opportunities were present for the licensee to question
the acceptability of the change and resulting adverse affects, the licensee staff
failed to do so.
- Two fuel pool emergency makeup emergency pumps had the pump casings weld
overlaid with stainless steel under a maintenance work request rather than a design
change (see Section M1.1).
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- - GL 89-13 commitments did not appear to be well understood. The licensee did not
recognize that the surveillances did not include appropriate acceptance limits (see
Section M2.7). Furthermore, licensee staff were unaware that an adverse trend had
developed on the 2B RHR heat exchanger, although detection of such trends was a
major focus of GL 89-13 (see Section M2.9). Other aspects of GL 89-13 such as
, prevention of erosion or corrosion also appeared weak, in that the licensee had not
balanced the flows through safety related heat exchangers (see Section M2.10) and
had no SW corrosion detection program despite indication of corrosion within the
- system (see Section M2.11).
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- The licensee did not appear to understand the basis for TS surveillance requirements
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in the lake screen house. When sediment levels above those allowed by the TS
were discovered, the licensee first leveled the silt so that was under the TS
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requirement and then removed it without any governing procedure or instruction.
Furthermore, as identified by the licensee, an inappropriate mode change was made
while the plant was in a limiting condition of operation because of the sedimentation
levels. These issues are further described in Sections M3.1 and M8. Additionally,
j the licensee incorrectly interpreted the TS requirement, by requiring, in the
surveillance procedure, only portions of the lake screen house to be tested (see
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Sections M3.2 and M3.3).
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Enaineerino
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- A potential unanalyzed design condition was identified regarding a water hammer
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occurring in the RHR heat exchanger as a result of voiding due to tube elevation.
By the end of the inspection, the licensee had confirmed that a water hammer could
occur under certain post-accident conditions, but had not analyzed the extent of it
(see Section E1.4).
- The licensee did not appear to understand the design basis for the SWS based upon
the number of calculations using differing assumptions, the existence of calculations
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for non-installed equipment, and using out-dated information in calculations (see
Sections E1.1, E1.2, and E1.9).
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The licensee did not keep the updated final safety analysis report updated. Several
examples are identified in Section E1.3.
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Plant Operations
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- The licensee performed a thorough review of the TS clarifications, deleted severJ,
j identified a few cases where amendments were necessary (see Section 01).
} * The licensee had an extensive procedure revision program underway to improve
procedure clarity and detail. This was considered a positive initiative (see
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, Section 04.2).
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. e A concern was identified with licensee corrective actions to a potential fire in a
, turbine building corridor, which could affect all three divisions of emergency diesel
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generators. Although identified in 1987, it appeared that no alternate shutdown
path was credited until 1996 (see Section 07.1). j
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Table of Contents
M1 Conduct c.f Maintenance ..................................6
M2 Maintenance and Material Condition of Facilities and Equipment ...... 8
M3 Maintenance Procedures and Documentation . . . . . . . . . . . ....... 19
M8 Miscellaneous Maintenance issues ..........................24
El Conduct of Engineering ..................................25
E2 Engineering Support of Facilities and Equipment . . . . . . . . . . . . . . . . . 34
E4 Engineer Knowledge and Performance . . . . . . . . . . . . . . . . . . . . . . . . 34
Conduct of Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 5
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O2 Operational Status of Facilities and Equipment . . . . . . . . . . . . . . . . . . 36
03 Operations Procedures and Documentation .................... 36
04 Operator Knowledge and Performance . . . . . . . . . . . . . . . . . . . . . . . . 36
07 Quality Assurance in Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38
X1 Exit Meeting Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40
Attachments: A. Partial List of Persons Contacted
B. Items Opened, Closed, and Discussed
C. List of Acronyms Used
D. NRC Comments
E. Procedures Used and Documents Reviewed
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11. MAINTENANCE
M1 Conduct of Maintenance
M 1.1 Witness of Service Water System Maintenance: Fuel Pool Emeraency Makeuo
IFPEM) Pumos
a. Insoection Scope
The inspectors walked down portions of the service water system (SWS) in
accordance with Section c.3 of inspection Procedure (IP) 93801, " Safety System
Functional Inspection," and Section 03.03.b of Temporary Instruction (TI)
2515/118, " Service Water System Operational Program inspection." During the
walkdown, the inspectors noted that the 1 A and 2B FPEM pumps were removed for
repair. The inspectors reviewed actions taken on the repair of the pumps, including
review of work requests (WRs), and examined the repaired pump casings, located in
the plant warehouse.
b. Observations and Findinas
Work requests 950110761 (for Unit 1) and 9500194472 (for Unit 2) required that
corrosion be removed from the inside of the carbon steel casings of the 1 A and 28 -
FPEM pumps by grinding and that the walls be built up by welding with stainless
steel. The inside was then to be machined to the original design size. This work
was performed as normal routine maintenance.
The purpose of coating the pump casing internals with stainless steel was to reduce
casing corrosion. Licensee personnel stated that the stainless steel pump casing
would perform the same form, fit and function of the carbon steel pump casing and,
therefore, the work did not constitute a change to the pump's design.
However, the inspectors noted that the pumps no longer met the description in
Section 9.2.1.2 of the Updated Final Safety Analysis Report (UFSAR), which stated
"All pumps in the system are constructed with carbon steel casings and stainless
impellers and stuffing boxes." Because the pumps no longer met this description,
the inspectors asked licensee personnel for the safety evaluation performed in
accordance with 10 CFR 50.59. However, no safety evaluation was performed
because the license considered the coating process as a repair rather than a design
change. The inspectors reviewed design procedures NEP-04-00, "Roadmap-Design
Changes," and NEP-04-01, " Plant Modifications," which further supported the
conclusion that the coating process involved a change in design.
In addition to the above concern, the inspectors reviewed the repair process used
and determined that several problems were encountered during the modification
activity:
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- Removal of the corrosion required removal of more of the carbon steel
material than was originally thought to be necessary. Minimum wall
thickness of the carbon pump casing could not be maintained.
e Because of the part configuration, the planned welding process would not
work and an alternate welding process was used.
- Excessive heat during weiding resulted in some warping of the pump casing.
The FPEM pumps were classified as ASME Code Class Ill components, which
required that repairs be performed in accordance with Section XI of the ASME Boiler
and Pressure Vessel Code (the Code). The problems encountered during the coating
process required evaluation under the Code prior to their acceptance. The licensee
had not considered ASME Section XI requirements during the repair.
Following identification of the above concerns, the licensee took the following I
actions:
- Engineering performed a safety evaluation for the change. The inspectors i
reviewed the safety evaluation and had no concerns.
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- The licensee prepared a revision to Section 9.2.1.2 of the UFSAR to
correctly describe the pump. The UFSAR change was submitted to the
licensing organization to be included in the next UFSAR submittal prior to the
end of the inspection.
e Engineering evaluated the new configuration because the minimum wall
thickness was violated. This calculation was not completed by the end of
the inspection.
e As required by the ASME Code, a hydrostatic test was satisfactorily
conducted on each of the pumps prior to returning it to service.
Criterion Ill, " Design Control," of 10 CFR Part 50, Appendix B, requires that design
changes be subject to design controls commensurate with those applied to the
original design. The failure to perform a safety evaluation and to follow ASME
Section XI repair requirements is considered a violation of Criterion 111
(50-373/966011-01(DRS); 50-374/96011-01(DRS)). The inspectors also noted
that the failure to perform a safety evaluation was a violation of 10 CFR 50.59, and
the failure to follow Section XI requirements was a violation of 10 CFR 50,
Appendix B, Criterion IX, " Control of Special Processes." Because the inspectors
deemed that these omissions were caused by the licensee failing to recognize the
design change, these violations will not be separately cited.
c. Conclusions
Licensee personnel, including maintenance personnel, work planners and support
engineers, did not recognize that the proposed repair was actually a design change.
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The individuals involved were not aware that this equipment was discussed in the
UFSAR and did not question the work being performed as routine maintenance.
This work on the FPEM pumps was on-going at the time of the inspection and
current procedures and practices were used.
M1.2 Witnessina of Surveillances
The inspectors witnessed an SWS surveillance in accordance with Section d.10 of
IP 93801 and Section 03.04.g of Tl 2515/118. The only service water related
surveillance performed during the inspection was the monthly operability check of
the residual heat removal (RHR) system. This surveillance affected RHR service
i water (RHRSW) in two ways: it started the RHRSW pumps and verified that the
RHRSW discharge valve to the RHR heat exchanger was closed. This was all
accomplished from the control room. The inspectors locally observed operation of
the RHRSW pumps, inspected for leaks around pumps and valves, and verified
proper operation of permanently installed gauges. No problems were identified
dur!ng this surveillance walkdown.
M2 Maintenance and Materiel Condition of Facilities and Equipment
M2.1 Rebuild of "A" RHRSW Pumo
a. Insoection Scone
in accordance with Section c.4 of IP 93801 and Section 03.03.c of Tl 2515/118,
the inspectors reviewed several selected maintenance WR packages involving work
on the SWS.
b. Observations and Findinas
During review of WR LO6416, the inspectors noted that a complete rebuild of the
2A RHRSW pump was completed in March 1992. Maintenance records indicated
that the original impeller had a diameter of 13 7/8 inches, while the replacement
impeller had a diameter of 141/8 inches. Even though the replacement impeller
was larger than the original impeller, the change was made without going through
the design change process. As the result of the larger impeller, there was a
significant increase in pump discharge flow and pressure.
An estimated pump curve was developed for the pump from the existing curve for
the pump with the smaller impeller. No engineering review of the impact of the
change on the system was conducted, nor was a safety evaluation performed.
Since the design change control process was not used, complete engineering
reviews were not performed.
The WR for the pump repair only addressed mechanical aspects and the records did
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not indicate that the increase in pump capacity was reviewed for possible electrical
impact. In response to questions, licensee personnel stated that the motor and
breaker size and capacity were acceptable. However, this had not been formally
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reviewed. Although the inspectors noted that surveillance test results did not
mention any electrical problems, this was yet another aspect of the design control
process which was not followed.
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The lack of familiarity with the design control in this example is similar to that
demonstrated with regards to the FPEM pumps (see Section M1.1). The inspectors
were also concerned that other similar plant modifications may have been
improperly implemented as maintenance work without proper design reviews. The
inspectors relayed this concern to the licensee.
Criterion lil, " Design Control," of 10 CFR Part 50, Appendix B, requires that design
changes be subject to design controls commensurate with those applied to the
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original design. The failure to provide the required controls for design changes in
increasing the pump impeller size is an example of an apparent violation of
Criterion ill of 10 CFR Part 50, Appendix B, " Design Control"
(50-373/96011-02(DRS); 50-374/96011-02(DRS)).
M2.2 Post-Modification Testina
in accordance with Section d.5 of IP 93801 and Section 03.04.d of Tl 2515/118,
the inspectors reviewed the post-modification tests performed on the 2A RHRSW
pump impeller modification performed as a maintenance activity as discussed in
- Section M2.1.
The post maintenance test for the pump indicated high differential pressure in the
" required action" range. As required by ASME Boiler and Pressure Vessel
Section XI Code requirements, engineering performed an evaluation and determined
that the impeller change was the cause of the high differential pressure and that a
higher pressure was expected because of the larger impeller. The evaluation
concluded that the " pump is operating properly and is able to meet design function.
Increased flow is not a problem." The involved engineers failed to recognize the
affect of the change in impeller size on the design function and failed to develop a
new pump baseline curve.
10 CFR Part 50, Appendix B, Criterion XI, " Test Control," requires that tests results
be evaluated to assure that test requirements were met. The failure to recognize
and adequately evaluate the effects of the increased flow from the larger impeller is
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an apparent violation of Criterion XI (50-373/96011-03(DRS);
50-374/96011-03(DRS)).
M2.3 Technical Adeauacy of Technical Soecification Surveillance Procedures
a. Insoection Scooe
in accordance with Section d.2 of IP 93801 and Section 03.04.a of Tl 2515/118,
the inspectors reviewed surveillance procedures and inservice test procedures
performed over the past two operating cycles to ensure the technical adequacy of
the procedures. Specifically, the inspectors reviewed the surveillance procedure
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implementing technical specification (TS) surveillance requirements 4.0.5.a and
4.7.1.1.
b. Observations and Findinas
The inspectors determined that surveillance procedure LOS-RH-01, "RHR (LPCI) and
RHR Service Water Pump and Valve Inservice Test for Operational Conditions
1,2,3,4 and 5," did not meet the surveillance requirements. Specifically, TS 4.0.5.a
requires that testing of ASME Code Class components be performed in accordance
with Section XI of the Code.Section XI requires that individual pump performance
bo trended for degradation. However, the inspectors noted that the Unit 2,
Division 2 A and B RHRSW pumps were tested concurrently rather than individually.
The inspectors questioned whether the licensee had an approved relief request from
the ASME Code Section XI requirement to obtain individual pump data. The
inservice test coordinator determined that relief had neither been requested nor
received to allow dual pump testing. The surveillance coordinator reviewed the
surveillance records and determined that the pumps had not been individually tested
since October 1995, which exceeded the time requirements of TS surveillance
4.0.5.a. Therefore, the licensee declared the pumps inoperable, temporarily revised
the procedure to albw single pump testing, and tested both pumps. The system
engineer compareJ the results to those obtained during the last individual tests and
determined that ao pump degradation had occurred. The failure to perform pump
testing within the required interval in accordance with ASME Code requirements is
an apparent violation of TS 4.0.5.a (50-373/96011-04(DRS);
50-374/96011-04(DRS)).
The inspectors reviewed the circumstances surrounding the procedure revision
which allowed testing of the Unit 2 A and B RHRSW pumps differently than the four
Unit 1 pumps and the other division Unit 2 pumps. The licensee explained that the
manual isolation valve on the outlet of the 2A RHRSW pump had become damaged
to the point where it would no longer isolate. When the valve failed in October
1995, the licensee decided to eliminate single pump testing, which required closing
the valve. To this end, licensee engineers prepared, approved, and performed a
special test, LST-95-105, "RHR Service Water Pump and Valve Inservice Test,"
which did not gather individual pump data. The inspectors reviewed the Safety
Evaluation Characterization of Change attached to the test and noted that it clearly
stated that the reason for the change was that the valve had failed. Upon being
asked by the inspectors, the licensee confirmed that the valve had not been repaired
at the time of the inspection. Criterion XVI, " Corrective Actions," of
10 CFR Part 50, Appendix B, requires that conditions adverse to quality be promptly
identified and corrected. The failure to repair the pump discharge valve which
impacted the licensee's ability to perform an adequate surveillance test is
considered an example of an apparent violation of Criterion XVI
(50-373/96011-05(DRS); 50-374/96011-05(DRS)).
As discussed in Section M2.1, the inspectors discovered that the maintenance
department, with the cognizance of the system engineers, had replaced the 2A
RHRSW pump impeller with a larger one. This increased the flow by nearly 300
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gallons per minute (gpm). This increase in flow, along with an inadequate design
and surveillance practice of using a gate valve to throttle flow, caused increased
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wear on the valve disc until it failed prematurely. The inspectors established that !
the failure was premature, because only the 2A RHRSW pump discharge valve
failed. The inspectors noted that the discharge valves for the other seven pumps
had not failed, even though they continued to be throttled quarterly over an
additional year's time period.
M2.4 Testina of installed Components
a. Insoection Scoce
The inspectors verified installed SWS components were tested to ensure the
components would perform in accordance with their design bases in accordance
with Section d.3 of IP 93801 and Section 03.04.b of Tl 2515/118.
b. Observations and Findinas
During review of the 2A RHRSW heat exchanger re.sults, the inspectors noted that
the flow was documented as ">8000 gpm" for three of the last four dP tests
performed (in February and October of 1993, and in August 1995). As discussed
above, the inspectors determined that full flow through this heat exchanger
exceeded the capacity of the flow meter following replacement of the 2A RHRSW
pump impeller in 1992. The inspectors reviewed the completed surveillance
procedure for the most recent test, in October 1995, and noted that the flow rate
was not recorded. Because the licensee had not made any changes to the system
to reduce the flow to within the range of the instrument, the inspectors deduced
that the flow meter was likely pegged high during this test.
The inspectors determined that the licensee had not questioned the flow meter
being off scale high or the effect this had on the test being performed. This is
considered another example of an apparent violation of 10 CFR Part 50,
Appendix B, Criterion XVI, " Corrective Actions," which requires that conditions
adverse to quality be promptly identified and corrected (50-373/96011-06(DRS);
50-374/96011-06(DRS)).
M2.5 Test Acceptance Criteria
a. Insoection Scoce
in accordance with Section d.3 of IP 93801 and Section 03.04.b of Tl 2515/118,
the inspectors reviewed surveillance test procedures to determine the adequacy of
the acceptance criteria to demonstrate continued operability.
b. Observations and Findinas
l The inspectors determined that special test LST 95-105, discussed in
l Section M.2.3, did not contain appropriate test requirements to ensure that ASME
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Code requirements for pump testing were met. Further, the test overtly stated that
its purpose was to work around a failed component. Criterion XI, " Test Control," of
10 CFR Part 50, Appendix B, requires that test procedures incorporate requirernents
and acceptance limits contained in the design. The failure to incorporate the ASME I
Code requirement to test pumps individually is considered an example of an
apparent violation of Criterion XI (50-373/96011-07(DRS);
50-374/96011-07(DRS)). l
Following performance of the special test in December 1995, the system engineer
revised the routine surveillance, LOS-RH-Q1 "RHR (LPCI) and RHR Service Water l
Pump and Valve Inservice Test for Operational Conditions 1,2,3,4, and 5," to
reflect the special test and eliminate single pump testing. The Characterization of
Change for this revision noted that this was to " prevent from throttling a gate valve
and destroying the valve during testing." This is considered a second example of
an apparent viclation of 10 CFR Part 50, Appendix B, Criterion XI, " Test Control"
(50-373/96011-08(DRS); 50-374/96011-08(DRS)).
The inspectors also reviewed surveillance procedure LTS-200-3, "RHR Heat
Exchanger Tubeside DP Test." This surveillance was revised to provide an alternate
method of throttling flow to the RHR heat exchangers, according to the procedure
review and approval form. The reason for the change was given as "recent
problems with RHR WS pump discharge valve throttling." The revision paperwork
also noted that an increase in dose would be expected because the new valves to
be throttled were in a high dose area. The inspectors deemed that this procedure
, did not incorporate the requirements and acceptance limits of design documents in
that it was being used to work around a failed component, and the practice was not
in accordance with the station as-low-as-reasonably-achievable (ALARA) radiation
practices because it now required throttling of a valve located in a high radiation
area. This is considered a third example of an apparent violation of 10 CFR Part 50,
Appendix B, Criterion XI, " Test Control" (50-373/96011-09(DRS);
50-374/96011-09(DRS)).
M2.6 Conclusion on Effects of RHRSW Imoeller Chanae
The inspectors concluded that the licensee's failure to use the design control
process when the impeller was changed had significant consequences, including
premature failure of a valve, and repetitive pegging of a flow instrument during
surveillance testing. These failures led to inadequate testing, which in turn resulted
in a TS surveillance not being met for over 11 months. The licensee had
opportunities during the post-maintenance testing to question the acceptability of
the change as a maintenance rather than a design activity, but failed to do so.
The above scenario resulted in the following apparent violations being identified:
Criterion lil, Design Control
Criterion XVI, Corrective Actions (2 examples)
Criterion XI, Test Control (4 examples)
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l M2.7 Heat Exchanaer Testina
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[ a. Insoection Scooe
[ The inspectors reviewed the procedures for periodic testing of safety-related heat
L exchanger heat transfer capability and the trending of such results, in accordance
f- with Section d.6 of IP 93801 and Section 03.04.h of Tl 2515/116,
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i. At the time of the inspecticin, the licensee performed static head ! differential
!. pressure (dP)) testing on the, RHRSW heat exchangers, the emergency core cooling
system (ECCS) room coolers n'Y" coolers), and the. diesel generator cooling water
(DGCW) heat exchangers. The inspectors reviewed the cooler testing completed
surveillances.
b. Observations and Findinas
For the RHRSW heat exchangers, the inspectors observed that until the last test,
the dPs were taken at design as well as full flow conditions. However, on the last
test for all four heat exchangers, dP readings were measured at full flow only. The
reason for this test change is discussed in Section M2.3. The licensee then trended
the dP results directly, for both the design and full flow tests, without consideration
that the static head was a function of the square of the flow rate and that the
change in flow rates would affect the dP obtained. Therefore, the trending results
were meaningful only for the design flow tests.
The inspectors also noted that, although the' data sheet in the RHR heat exchanger
equipment specification, a design document, indicated the design dP was 9.0 psi,
this was not incorporated into the test acceptance limits. Additionally, no guidance -
was provided for comparing the dPs obtained at full flow to the design value. Nor
- were any acceptance criteria provided for the full flow condition.
10 CFR Part 50, Appendix B, Criterion XI, " Test Control," requires that tests results
be evaluated to assure that test requirements were met. The failure to provide
guidance on how to review the full flow dP results and to compare them to the
acceptance limit is a violation of Criterion XI (50-373/96011-10(DRS);
50-374/96011-10(DRS)).
For the DGCW heat exchangers, the inspectors observed that the licensee had an
acceptance criteria of 25 percent of the baseline dP. Although the testing was-
done at full flow each time, this was'not a problem for the DGCW pumps, because,
as discussed in Section E1.10, the pumps were operating at nearly runout
conditions, so little variation in flows occurred. To verify that no errors were being
introduced, the inspectors recalculated the dPs, compensating for the change in
flow rates and observed that the dPs did not vary from each other by over two
percent. This was considered acceptable.
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c. Conclusions
The inspectors concluded that testing of the various SWS heat exchangers in
accordance with the licensee's commitment to GL 89-13 was being performed;
however, based on the observations in the above section, as well as those
documented in Sections M2.3, M2.4, and M2.9, the licensee did not appear to
understand the basis of the testing. The inspectors further concluded that the ;
licensee had not established sufficient acceptance criteria to determine when heat l
exchanger performance was affected. !
M2.8 Heat Exchanaer Insoections
The inspectors reviewed maintenance records for periodic inspection of SWS heat
exchangers to detect corrosion, erosion, protective coating failure, silting, and
biofouling in accordance with Section c.5 of IP 93801 and Sections 03.03.d and
03.03.i of Tl 2515.118. l
The licensee inspected the tube side of the emergency diesel generators (EDG) heat
exchangers as part of the routine EDG preventive maintenance and planned to
discontinue the static head testing. The inspectors confirmed that the heat
exchanger inspections were included in the EDG preventive maintenance procedure
and that the inspections had been performed during the last preventive maintenance
on all five EDGs. Additionally, small heat exchangers, such as the RHR pump seal
coolers, were inspected and cleaned in lieu of testing.
The inspectors reviewed selected preventive maintenance records for the RHR and
EDG heat exchangers. These records indicated that these heat exchangers were
inspected from the tube (service water) side during refueling outages. The records
indicated that few problems were found with the heat exchangers. The inspectors
also reviewed the schedule for the inspections and confirmed that inspections were
conducted within the frequency committed to in the licensee's response to
The inspectors had no concerns regarding the licensee's method of inspecting and
cleaning heat exchangers in lieu of heat exchanger testing.
M2.9 Comoonent History
a. Inspection Scooe
The inspectors reviewed the component history files,looking for indications of
adverse trends or recurrent test failures, in accordance with Sections c.8 and d.6 of
IP 93801 and Sections 03.03.f and 03.04.h of Tl 2515/118.
b. Optgervations and Findinas
The inspectors noted that, especially for the 1B and 2B RHR heat exchangers, the
full flow rates appeared to differ with every test. Since the dP was proportional to
14
- _ __ _ _ __ .__ _ ._ . . .
$
$
the square of the flow rate, changes in the flow rate affected the ability to trend
heat exchanger performance. For example, for the 18 heat exchanger, a dP of
9.9 psi at a flow rate of 7950 gpm was obtained in 1992, in 1995 a dP of 9.5 psi
was obtained at a flow rate of 7800 gpm. However, both dPs were basically
-
equivalent when correlated to a common flow rate. The inspectors were concerned
that the failure to equate all dPs to a common flow rate could mask a trend.
, in actuality, however, the inspectors observed that the licensee did not appear to be !
f
aware of adverse trends. For example, based on the recorded values over a three
- year period, the dP in the 2B heat exchaager increased by 2.2 psi, or 26 percent.
- When the inspectors equated the dPs back to the design flow rate, the increase was
'
j determined to be only 1.72 psi for a 22 percent actualincrease from 1992 to 1995.
Regardless of the extent of the trend, tFe licensee had not identified it. When
4
pointed out by the inspectors, the liceasee wrote a problem identification form (PIF)
to evaluate the effects of the trend. At the end of the inspection, the licensee was
determining whether to inspect the heat exchanger during the refueling outage.
,
Based on the information available at the time of the inspection, the inspectors
believed the heat exchanger was capable of performing its design fur ction. The
! failure to evaluate the test results to determine if adverse trends were developing is
considered another example of a violation of 10 CFR Part 50, Appendix B,
Criterion XI, " Test Control" (50-373/96011-11(DRS); 50-374/96011-11(DRS)).
1 c. Conclusion
.
The inspectors concluded that the licensee did not appear to be adequately
'
evaluating trends from heat exchanger performance test results. One example was
1 noted where the licensee failed to identify and evaluate an adverse trend.
] M2.10 Testino of Room Coolers
y a. Insoection Scoce
4
in accordance with Section 03.04.1 of Tl 2515/118, the inspectors reviewed testing
i of the air-to-water heat exchangers served by the SWS to ensure proper heat
transfer.
b. Observations and Findinos
'
The inspectors reviewed the results for the safety-related "VY" room coolers. The
,
inspectors observed that the flow rates through the coolers were considerably
above the design flow rate (the worst case, for the 4A coolers on Unit 1, was
2.4 times the design flow). As discussed in Section E1.10, the inspectors reviewed
the pump curves and determined that two of the pumps (the ODGCW and the high
pressure coolant system (HPCS) DGCW pumps) were operating at the end of the
pump curve (i.e., in a condition of high flow and low pressure). The test procedure
provided a method to equate the dPs obtained back to the design flowrate, and the
plotted dPs were compared to determine if any trends were developing.
15
l
!
l
The inspectors discussed with the system engineer a concern regarding maximum
i flow through the 1 A and 4A room coolers for both units. Because all four room
coolers receive cooling water from the ODGCW pump, the inspectors were
concerned that unbalanced flows could result in (1)less than design flow through
the 1 A coolers and (2) tube erosion in the 4A coolers. For the first concern, the
inspectors noted that the most recent surveillances demonstrated that flows
through both 1 A coolers were above design; therefore, this was not an immediate
concern. In response to the second concern, the licensee responded that the
manufacturer specified a flow velocity limit of 12 feet per second and calculation
VY-12 demonstrated that tube velocity was below that value. l
The inspectors reviewed calculation VY-12, " Evaluation of VY Cooler Tube Velocity I
Based on Test Data." As the name implied, this calculation evaluated the maximum
velocity in the tubes using the highest flow rates obtained as of September 1993.
The inspectors noted that higher flow rates were seen on at least one cooler during
its 1995 surveillance test. The inspectors asked the licensee if any bounding
calculation had been performed to determine the maximum flow through the coolers
which would not exceed the manufacturer's velocity limits. The licensee replied
that no bounding calculation had been performed.
Using the standard formula for determining flow (area times velocity), the inspectors
determined a maximum flow value at a velocity of 12 feet per second. The !
inspectors then confirmed that none of the coolers had exceeded this value. The j
inspectors confirmed the validity of the formula by calculating the velocity for the l
flows used in the licensee's calculation and comparing them with the results of the I
calculation. For coolers 1 A,2A, and 3A, the velocity calculated by the inspectors
agreed with the value obtained by the computer program used in the licensee's
calculation.
For the 4A coolers, the inspectors noted that the calculation treated them as two
i
separate coolers, with half the flow going to each "sub" cooler. The velocity
through each "sub" cooler was then calculated. Therefore, the inspectors
calculated the velocity for each 4A cooler using half the total flow. The inspectors'
calculated value, however, was exactly double what the licensee's calculation
determined. The system engineer, when questioned, could not explain why this
was the case. The engineer stated that one of the "sub" coolers was identical to
the 1 A coolers.
l
1
c. Conclusions
The inspectors concluded that the accuracy of the calculated velocities for the 4A i
coolers was questionable. The inspectors further questioned the calculation's !
conclusion that the maximum velocity would not be exceeded even if all the flow
went through one of the 4A "sub" coolers. The licensee was requested to provide
additional information about the 4A cooler and the formula used to calculate the
velocity to support the calculation's results. This is an unresolved item dependent
upon NRC review of the calculations' formula for the 4A cooler and determination
I
!
16
. . . _
l
l as to whether the maximum flows for the 4A cooler were acceptable
(50-373/96011-12(DRS); 50-374/96011-12(DRS)).
!
M2.11 Maintenance Proaram for Detection of Siltina and Corrosion
i
a. inspection Scope
in accordance with Section 03.03.d of Tl 2515/118, the inspectors reviewed the
Plant Corrosion Program and discussed the program with licensee personnel.
b. Observations and Findinas
l
.
'
1
The licensee had a flow-accelerated corrosion program for piping subjected to high I
temperature and pressure and low oxygen content. The service water systems, !
including the core standby cooling systems (CSCS), did not meet this criteria and I
therefore, no corrosion program was applied to these systems.
In response to GL 89-13, the licensee identified four areas where low flow
conditions existed in the service water system. These areas were inspected over
two refueling outages for evidence of corrosion. The inspections did not reveal any
evidence of corrosion, so no additional action was taken.
During the review of records, the inspectors noted documented corrosion in at least
two areas, inside the 54" core standby cooling system service water by-pass line
and inside the FPEM pumps in the auxiliary building. The inspectors questioned the
adequacy of the GL inspection effort, as it did not identify these spots as being
highly susceptible to corrosion. The inspectors further questioned the licensee
about what future plans they had, in regard to GL 89-13, since corrosion was
identified in these areas.
Licensee personnel stated that future plans included installation of a corrosion
system for service water. Proposals had been made to purchase and implement a
service water system corrosion program developed by EPRI. Support engineering
expected this program to be implemented before the end of 1997. There was no
assurance, however, that this program would be installed and, if so, how effective
it would be.
c. Conclusions
There was no corrosion program in place for the plant service water system even
though a corrosion program was recommended by Section lli of GL 89-13. Based
on records reviewed, the inspectors noted that some components in the system
showed evidence of corrosion.
17
!
l
M2.12 Inservice Test (IST) Proaram
l
The inspectors reviewed the IST program records for the pumps and valves in the
l RHRSW and the DGCW systems, in accordance with Section d.7 of IP 93801 and
l
03.04.e of Tl 2515/118.
l The inspectors reviewed the trends for the SWS and no recurrent failures were
identified. The inspectors reviewed the components in the IST program and noted
that the manual strainer backwash valves for the RHRSW were not included in the
program. However, similar valves for the DGCW system were included. The
inspectors questioned why this discrepancy existed. The licensee ascertained that
I a previous evaluation had determined that the RHRSW strainer backwash valves did
,
not serve a safety function. The licensee concluded that, in light of the grouting
l event (see Inspection Reports No. 50-373/96008; 50-374/96008 and
50-373/96009; 50-374/96009), this determination should be reexamined and wrote
a PlF.
A problem was identified with the licensee's implementation of the IST program, as
is discussed in Section M2.3.
M2.13 Instrument Calibration
in accordance with Section d.8 of IP 93801 and Section 03.04.f of Tl 2515/118,
the inspectors reviewed calibration of selected SWS instruments and verified the
installation locations of temporary test equipment. The inspectors also verified the
tolerance used for instrument accuracy.
The inspectors selected several temporary instruments used during surveillance
tests and reviewed their calibration frequency, along with the accuracy and
l repeatability ranges to which they were calibrated. The inspectors compared the
procedures to the design drawings, and ensured that the temporary instruments
were installed in an appropriate location for their use. The inspectors walked de,wn
the system (with the exception of the area around the RHR heat exchangers) and
noted that installed instrumentation appeared to be functioning properly. No
problems were identified during this review.
The inspectors noted that the RHRSW flow instruments normally operated at the
,
'
extreme upper end of their range. While appropriate calibrations appeared to be
performed, the inspectors considered it to be a poor practice because conditions,
such as the one described in Section M2.3, could cause the instruments to go off
scale and invalidate test results.
t
18
l
l
M2.14 System Walkdowns
a. insoection Scoce
The inspectors performed an in-depth walkdown of the CSCS in accordance with
Section c.2 of IP 93801 and Sections 03.02.a and 03.03.a of Tl 2515/118. The
walkdown included areas in the lake screen house and plant equipment rooms.
b. Observat'ons and Findinas
Only a few minor discrepancies were noted. Examples included pump sump covers j
not having bolts and scaffolding remaining long after projected removal date. Few !
packing leaks were present; however, some minor external corrosion was noted on
valve stems. The inspectors noted that some components had extra labels, such as
for the type of valve packing material and a construction quality control tag. Most
valve stems appeared lubricated and the inspectors were informed that balance of l
plant valves received periodic maintenance, including valve stem lubrication on a
54 month cycle for motor operated valves and a 10 year cycle for other valves.
System engineers appeared to be performing walkdowns and identifying deficient
conditions. Most areas had a number of action request tags denoting problems.
c. Conclusions
The inspectors determined that the materiel condition of equipment and areas for
CSCS was acceptable.
M3 Maintenance Procedures and Documentation
M3.1 Uncontrolled Removal of Silt from the Lake Screen House
a. Insoection Sconc
in accordance with Section c.4 of IP 93801 and 03.03.c of Tl 2515/118, the
inspectors determined whether maintenance procedures were sufficient to perform
the maintenance task and provided for identification and evaluation of equipment
deficiencies.
The inspectors reviewed surveillance records for verifying that silt levels in the lake
screen house were less than the TS required maximums. WRs for silt removal and
other lake screen house related activities were also reviewed.
b. Observations and Findinas
Surveillance procedure LTS-1000-4, completed February 9,1996, indicated that the
level of silt inside the lake screen house on the Unit 1 side exceeded the TS iimit of
12 inches maximum. A WR was written to remove the accumulated silt. Instead,
as documented in the surveillance, divers leveled the existing piles of silt to a
19
__ .- - . . . _ . . - .
maximum height of less than 11 inches. The silt levels in the lake screen house
were then below the TS maximum limit. The WR to remove the silt was canceled.
l
The inspectors questioned whether the silt levels in the lake screen house were still
below the TS limit, due to disturbances caused by operation of the circulating water
pumps. The system engineer stated that the sitt was removed. The licensee could
t
not locate a WR or other record which authorized or documented the removal of the
silt from the lake screen house. However, the licensee did provide the inspectors
with an August 26,1996, divers report, which indicated that the maximum level of
silting in the area was three inches. This report supported the licensee's assertion ,
! that the silt had been removed. !
l
The inspectors were subsequently provided a letter from Scott Diving Service, Inc.,
to Commonwealth Edison Company, dated September 6,1996, which stated,
"Between February 9 and 25,1996, our company performed the underwater
dredging of CIRC water bays 1 A,1B, and 1C at LaSalle station. The areas between
the traveling screens and the ramp areas were completely cleaned as per LaSalle
station directives." The inspector discussed this letter with the licensee and I
t
determined that the directives mentioned were verbal and that no written
j instructions were provided to the divers.
l Criterion V, " Instructions, Procedures, and Drawings," of 10 CFR Part 50, l
l Appendix B, requires, in part, that activities affecting quality be controlled by
approved procedures. The failure to provide the required controls of activities ;
affecting quality, i.e., removal of silt from the circulating water bays, is a violation I
of Criterion V (50-373/96011-13(DRS); 50-374/96011-13(DRS)).
c. Conclusions
The silt was removed without a controlling WR and the removal was not
documented on plant records.
M3.2 Review of Potential Common Mode Failures
a. Insoection Scope
l
l In accordance with Section 03.01.d of Tl 2515/115, the inspectors reviewed
! surveillance procedures, TS, and design features of the intake structure (lake screen
house) to determine if any common mode failures existed due to fouling or blocking
the intake,
b. Observations and Findinas
l- The inspectors determined that TS Surveillance 4.7.1.3.c required verification that
l " Sediment deposition anywhere within the lake screen house is not greater than one
foot in thickness" every 18 months.
20
t
!
,
- . . - .- - . . . - -
The inspectors reviewed completed surveillances and identified that the circulating
water bays on both units were only partially inspected between 1992 and 1996.
This was due to a proceduralized TS interpretation in LTS-1000-4, "CSCS Pond
Surveillance," that considered testing of the diagonal quadrants as fulfilling the TS
surveillance requirement. The failure to ensure that all portions of the lake screen
house were surveilled every 18 months is a violacion of TS 4.7.1.3.c j
'
(50-373/96011-14(DRS): 50-374/96011-14(DRS)).
l
l
The licensee performed a review of previous surveillances in response to the
inspectors concerns, and concluded that sediment level depositions in alternate
quadrants was representative of the adjacent quadrants. However, the inspectors
noted that this was not true for the March 1996 inspection discussed in
Section M3.1. At that time all four quadrants of all three bays on Unit 1 were
inspected. Only three (out of twelve) quadrants had levels in excess of the TS limit.
These were the southwest corner of the 1 A bay and the northwest corners for the
1B and 1C bays. The inspectors ascertained that there was a two- to four-inch
difference between the maximum sediment levels in the northwest and southwest- !
bays. Therefore, the inspectors deemed it possible that one quadrant could be
above the TS limit while the other was several inches below and that the licensee's l
surveillance method would not detect this. '
c. Conclusions
The inspecurs concluded that the licensee had proceduralized an interpretation,
l which resulted in the surveillance requirements of TS 4.7.1.3.c not being fulfilled.
l
l M3.3 Detection of Flow Blockaae
a. insoection Scooe
!
In accordance with Section 03.04.k, the inspectors reviewed the periodic inspection
l
'
program to detect flow blockage from biofouling in other systems, including the
surveillances used to detect biofouling and silt deposition in the service water tunnel
and the 54-inch bypass line.
b. Observations and Findinas
The inspectors noted during review of LTS 600-23, "CSCS Screen Bypass Line
Inspections," that it used an acceptance criteria of 20 percent. However, the actual
test data was taken in inches. The inspectors questioned the licensee whether the
l 20 percent was supposed to be a percentage of the diameter (10.8 inches) or of the
l~ area (458 square-inches) and, if it was the latter, whether sufficient information
l was given to calculate the area. The licensee stated that the 20 percent was
i intended to be percentage of the area and clarified the procedure to specify a
l maximum acceptable sedimentation height.
l
,
The inspectors also questioned the licensee as to why inspection of the service
, water tunnel and the bypass line was not considered necessary to meet TS
+
21
i
. _ . . ._ __ _ _ _ _ - _ _ _ . _ . _ _ _
l
surveillance requirement 4.7.1.3.c. This TS required verification that " Sediment
I deposition anywhere within the lake screen house is not greater than one foot in
thickness," and UFSAR Section 9.2.1.2 identified the service water tunnel as being
"in the basement of the lake screen house." The licensee noted that NRC had
previously reviewed and accepted exclusion of the service water tunnel in
Inspection Report No. 50-373/93007: 50-374/93007. The inspectors reviewed the
previous correspondence on this issue and noted that the licensee justified not
performing the surveillance on personnel safety reasons rather than technically
f justifying why the service water tunnel need not be inspected. Because the
licensee performed the LTS-600-19 and -23 inspections every 18 months, the
inspectors questioned the appropriateness of the licensee's justification.
The inspectors noted that the TS surveillance requirement was established by the
NRC because of a concern that the intakes to the CSCS system could be blocked or
clogged due to their location near the bottom of the service water tunnel. Since e
original concern was with the intakes to the CSCS equipment, and not the intakes
to the service water tunnel, the inspec: ors were concerned that the licensee's
justification was not adequately wpported and had been improperly accepted. The
inspectors expressed this concern to the licensee.
The inspectors further noted that UFSAR Section 9.2.1.3 stated that "it is not likely
the CSCS-ECWS intake pipe and intake bypass pipe will be blocked or clogged with
sand and/or other heavier-than-water debris over the lifetime of the plant." The
inspectors questioned the licensee about the accuracy of this statement, since the
bypass line was found to be approximately 75 percent blocked in 1992 and a
significant amount of debris was introduced into the service water tunnel, where it
could have affected the intakes of the CSCS intake pipes in July 1996.
After being presented this information by the inspectors, the licensee then reviewed
the TS surveillance, its basis, and the UFSAR, and concluded that their previous
interpretation, that the service water tunnel was not included in the TS surveillance,
was non-conservative. The licensee combined surveillances LTS-600-19 and 23
with LTS-1000-4, and applied the surveillance requirement to the entire lake screen
house, thereby including the service water tunnel and resolving the issue.
c. Conclusions
The inspectors concluded that the procedures the licensee used to ensure that no
flow blockage would occur had inadequacies, as discussed above. These concerns
were addressed during the inspection.
M3.4 Precoerational Testina
j a. Inspection Scope
l
l The inspectors reviewed results from preoperational testing to determine whether
j. the SWS capabilities and limitations were appropriately demonstrated, in accordance
with Section d.5 of IP 93801 and Section 03.04.c of Tl 2515. The inspectors
22
-
9
.._ _ _ _ __-_ _._ _ _ _ __ _. _ _ ._ _ _ . _ _._..- _ _ ._. _
l
,
!
! reviewed portions of the preoperational tests for the RHRSW, DGCW, and VY room
j coolers,
i
l' b. Observations and Findinas
The inspectors observed that the " integrated tests" performed during the
'
preoperational testing were tests of a single loop (i.e., pump and heat exchanger).
No true integrated testing was performed. This resulted in an untested system
interaction being identified in that the RHRSW shared a common discharge line with
, the DGCW. As the RHRSW pumps had a larger capacity than the DGCW pumps
! (8000+ gpm RHRSW per division versus 2000 gpm DGCW), the inspectors
l surmised that back pressure from RHRSW could adversely affect the flow through
i the VY coolers.
l
l The inspectors questioned the licensee whether this interaction was ever tested
(see Comments 8 and 14). In response, the licensee stated that the interaction was i
l
tested in July 1996. The inspectors reviewed the results of this testing and noted ;
L that RHRSW was not identified as being running during the testing. The licensee
formally responded that RHRSW was confirmed to have been running for Division 1 ,
by review of operating logs. For Division 2, the licensee noted that the effect of !
RHRSW on the coolers was determined analytically. The inspectors determined that
l the July testing was not intended to examine the system interaction and that the ,
L running of the RHRSW pumps during the Division 1 test was fortuitous. . The
!
inspectors independently reviewed the latest VY cooler testing and determined that
the cooler operability was not affected at the time of the inspection.
p c. Conclusions -
l
The inspectors concluded that the preoperational testing did not identify a
potentially significant interaction between the RHRSW and the DGCW While this
interaction did not appear to affect room cooler operability at the time of the
inspection, it had the potential to so do, if not properly taken into account,
'
( especially if flow balancing was done to resolve the cooler velocity concerns
expressed in Section M2.10. Determination of the effect of this interaction on the
VY coolers is considered part of unresolved item 50-373/96011-12(DRS);
50-374/96011-12(DRS).
I M3.5 Review of Maintenance Procedures and Vendor Manuals
a. Insoection Scope
in accordance with Section c.4 of IP 93801 and Section 03 03.c of Tl 2515/118,
.
the inspectors examined the licensee's handling of technical information provided by
the vendors of equipment and components. The inspection included examination of
the licensee's Vendor Equipment Technical Information Program (VETIP) procedure,
, compliance with the procedure, and selective examination of plant equipment
. records.
i
s
'
23
I
.-- . . . . - _ - - -. .- . . . . -.
. . . _ . _ _ _ _ _ _ _ _ _ _ _ _ _ . _ _ _ . _ _ _ . _ _ _ _
b.- Observations and Findinas
.
Although the procedural requirement stipulated a three-year cycle to update vendor
- manuals for all safety-related components, there was no stipulation to update
vendor manuals for those non-safety-related components important to safety, such
as fire protection equipment. For instance, the vendor for the diesel fire water
pump had not been contacted since 1991. The inspector's concern was that if
updated technical information existed for such a component, the licensee would ,
have not been informed. For safety-related motor operated valve MOV12 in the '
RHR system, the VETIP program contacted the vendor after five years and ,
determined there was no available updated information. j
1
c. - Conclusions
Although some minor programmatic deficiencies were identified, the inspectors did
,- not find any instances where vendor manuals were not updated when they needed
l to be.
M8 Miscellaneous Maintenance items
M8.1 '(Closed) LER 96-005-00, " Failure to Follow Procedures Results in Technical
Specification Violation of the Core Standby Cooling System Pond Surveillance." l
The LER contained some additional details about the issue described in
Section M3.1. - Specifically, the LER identified that during the period after
sedimentation levels above 12 inches were discovered in the lake screen house, but l
before the sedimentation was removed, a mode change was made on Unit 2 (from. 1
Mode 3 to Mode 2). This mode change was prohibited by TS 3.0.4 and occurred
because the involved personnel did not confirm that the reported sedimentation
levels were below the TS requirement. This licensee identified and corrected
violation is being treated as a Non-Cited Violation, consistent with Section Vll.B.1 i
of the NRC Enforcement Policy (50-373/96011-15(DRS); 50-374/96011-15(DRS)).
The inspectors reviewed the LER and noted that it described the inspection team as
being concerned that the same quadrants (i.e., northeast and southwest) of the i
Unit 2 A and B circulating water bays were inspected in 1993 and 1995. However,
as described in Section M3.2, the inspection team's concern was on the
proceduralized interpretation that inspecting only quadrants of the circulating water
bays met the requirement of "anywhere in the lake screenhouse."
The inspectors also disagreed with the licensee's assessment of safety
consequences, which concluded that the basis of the one foot maximum limit was
to ensure that any sediment would be below the seven service water tunnel inlets.
As discussed in Section M3.3, the inspectors determined that the inlets alluded to
p were the inlets to the CSCS equipment, from the service water tunnel to the
j auxiliary building, not the pipes from the circulating water bays to the service water
- tunnel. The inspectors did not understand why the licensee had renamed the
i service water tunnel "the CSCS tunnel" in the LER, as that name was not used in
j the UFSAR or any other design basis documents.
4
24
i
1
-- --. - -- .- .. --- -. - - -. -- - - . .
. . - - - .. -- .-. .- - - . . --
l
i Because these issues were discussed separately in Sections M3.2 and M3.3, this
! LER is closed.
l lli. ENGINEERING
E1 Conduct of Engineering
E1.1 Desian Basis Review
!
a. Insoection Scoce
l In accordance with Section 1.a of IP 93801 and Section 03.01.a of Tl 2515/115,
the inspectors reviewed various documents associated with the CSCS design bases.
The documents included the LaSalle UFSAR, calculations, and analyses which
documented the various operating conditions for CSCS to determine the functional ;
requirements for the system. '
!'
b. Observations and Findinas
The calculations provided for review seemed disjointed, as a whole. There were no I
overall governing calculations of the systems which made up CSCS, only individual
calculations which referenced other calculations. This made it very difficult to i
i
determine the effect of system interactions, particularly in the hydraulic response of l
the system during various modes of operation. As discussed in Section M.3.2, r.o i
j integrated system test was ever performed. Between the disjointed calculation and i
l lack of integrated testing, unanticipated pump interactions could occur during
l integrated operations. Additionally, the calculations did not always use the same
design assumptions, nor did they explain why differing assumptions were used. It
- appeared that each calculation was performed independently in response to a
specific issue and no attempt was made to reconcile them to the overall design
basis.
The licensee was not always certain of the design basis when questioned about
,
specific aspects of the system. For example, a calculation was performed in 1976
which sized an orifice to limit the flow rate through the RHR heat exchangers to
'
7,700 gpm. However, CSCS testing indicated that there was approximately 8,000
gpm flow rate through the heat exchangers. When questioned about this
! discrepancy, the licensee system engineer produced a 1974 calculation to support
this flow rate. However, the inspectors determined that this calculation did not
apply to any orifice plate installed at the station. After a review of the calculation,
the licensee agreed with this observation.
The inspectors then returned to the original question of why the RHR heat
exchangers had an 8000 gpm flow rate through them if the orifice was sized for
7700 gpm. The licensee replied (see Comment 23) that the 7700 gpm flow was
calculated at a lake elevation of 685 feet and this approximately equated to 8000
25
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,
_. . .. ._ . . . - _ . _ _ _ _ . - _ _ _ _ _ _ _.__-__ - _ _ _ . _ . _
l .. -
gpm at normal lake levels. The inspectors noted that surveillances did not measure
.
or otherwise account for lake level, which normally was around an elevation of 700
feet. This appeared to mean that an indicated value of 7400 gpm during
surveillances would actually be below the design basis requirement. ;The inspectors i
did not have an operability concern because the recorded measured flow rates have
consistently been above 7800 gpm. However the inspectors were concerned that !
surveillance tests, such as LTS 200-3, "RHR Tubeside DP Testing," which verified
the design flow of 7400 gpm, might be inadequate, because they did not account
for lake level. This is considered an unresolved item, awaiting the licensee
determining the effect of the lake level on the surveillance procedures
(50-373/96011-16(DRS); 50-374/96011-16(DRS)).
The licensee also could not produce evidence of the manufacturers' maximum
allowed flow rate allowed through the heat exchangers. Although the licensee
stated on several occasions that the maximum flow rate was 125 percent of the
normal flow, no documentation to support this was provided to the inspectors,
despite repeated requests. The inspectors were concerned because excessive flow
rates could result in erosion of the tubes. The inspectors noted that the RHR heat
exchangers baffle plates have already experienced cracking, which might be
l - attributed to excessive flow past the plates.
L At the beginning of the inspection, the inspectors specifically questioned the l
l- licensee regarding CSCS operation during design basis accidents. The response
was not provided until after the end of the inspection, indicating that the licensee ,
could not readily determine the CSCS design bases. Also, the licensee was l
!
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_ requested to provide the RHR heat exchanger design heat transfer duty. The
^
licensee's response stated that the appropriate measure of the heat exchanger
performance was effectiveness, rather than duty. The inspectors reviewed the heat
exchanger heat transfer surveillances and determined that the computed
i effectiveness' did exceed the 0.374 minimum UFSAR value. Therefore, the
( inspectors had no further concerns.
C. Conclusions
! The information provided and the licensees' responses to questions indicated a
l' general lack of knowledge of the CSCS design bases.
E1.2 Desian Assumotions
a. Insoection Scope
l
In accordance with Section 1.a of IP 93801 and Section 03.01.a of Tl 2515/115,
the inspectors reviewed the CSCS calculations and the UFSAR to determine the
appropriateness of the design assumptions, boundary conditions, and models.
i
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is 26
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. - .. ..~ _~ . , - . . - - . - . . - .- - .~ - - . - .. . - - . . - . . - - - .
1
b. Observations and Findinas -
l
l
The review indicated a number of areas where the assumptions and boundary
conditions for calculations were inconsistent with other documents associated with
the system.
For example,' calculation VY-13, " Unit 2 RH3 Service Water Pump Room C
Temperature on Loss of HVAC," established a room temperature of 119*F using
piping temperatures of 100*F. Another calculation, VY-5, "HVAC, RHR Service
Water Pumps (A&B) Room Ventilation System," established a room heat load using
piping temperatures of 182 F. The cause for the discrepancy was not resolved by
the licensee, who merely noted that the 182 F was " extremely conservative." The
inspectors were unable to determine any basis for the 182*F temperature, and
therefore, concluded that the results of the calculation using 100 F piping appeared
reasonable. 3
Also, a calculation was performed by the licensee to' determine the impact of
- strainer backwash activities on the system flow rates. The calculation was
performed based on a lake elevation of 700 feet. However, the minimum design
lake elevation is 690 feet. This discrepancy was noted by the inspectors and the
calculation was subsequently revised by the licensee. ;
A review of calculations VY-OO4, " Unit 1, Division i ECCS Equipment Cooling Water
System," Revision 0, ATD-0375, "ECCS Pump Room Temperature During Shutdown
With Area Coolers Inoperable," Revision 0, and 3C7-089-OO1, "ECCS Room
Temperature Transient _Following LOCA Concurrent With Loss of Area Cooler,"
Revision 1, indicated that the room heat load for the HPCS pump cubicle did not
include _any piping heat loads. Presumably this was due to the' fact that HPCS
originally took suction from the condensate storage tank, which was cool water.
. _
J
However, HPCS had been modified (under a temporary alteration in 1985 and as a 1
- permanent modification in 1993) to take suction only from the suppression pool,
which was a hot water source under post accident conditions. Therefore, these
calculations were determined to be invalid. This design discrepancy also impacted
an operability assessment performed on August 29,1996, concerning the VY cooler
performance, since it also did not account for suppression pool temperatures. This
is an example of a violation of 10 CFR Part 50, Appendix B, Criterion lli !
(50 373/96011-17(DRS); 50-374/96011-17(DRS)). I
c. Conclusions !
The information provided and the licensees's responses to questions indicated a
general lack of knowledge of the CSCS design bases. The inspectors determined
that in severalinstances, analyses were performed with assumptions and boundary
conditions which were not consistent with the LaSalle design basis. Also, several
- analyses were identified which appeared to use non-conservative assumptions.
i
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1-
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-- . . . _- _
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E1.3 Uodated Final Safety Analysis Review
a. Insoection Scoce ,
,
I
In accordance with Section 1.a of IP 93801 and Section 03.01.a of Tl 2515/115, l
the inspectors reviewed the LaSalle UFSAR, CSCS design calculations, and other
l
j. design information (i.e., design drawings and specifications, etc.) to determine if
{
CSCS was operated in accordance with its licensing commitments.
1 1
b. Observations and Findinas
The inspectors review indicated that, in general, it was difficult to determine the
licensing requirements for the system. This was evident in the number of
discrepancies between the system design and the UFSAR.
i
The first discrepancy was in the CSCS flow rate required to respond to various
accident and operational scenarios. UFSAR Section 9.2.6.3 contained a table of i
l
'
RHRSW flow rates which was determined by the licensee to be inconsistent with
actual system flows. As a result, the inspectors determined that UFSAR
- Section 9.2.1.3 contained an incorrect value for the maximum velocity of the 54
l inch by-pass line. The licensee calculated the correct value and performed an
operability assessment that determined that the error did not impact the operability
i
of the line. A PIF was generated to track the UFSAR change.
l Section 9.2 of the LaSalle UFSAR stated that the CSCS was designed to Seismic
Category I requirements. However, the 54 inch bypass as well as the 34 inch
normal suction lines were in fact not-safety-related and not seismically designed.
The licensee was upgrading this piping to be safety related and had performed
l calculations supporting the seismic acceptability of the piping. These calculations
'
are evaluated in Section E1.10.
The inspectors also noted that UFSAR Section 3.3.2.3 claimed that all non-seismic
structures (other than the turbine building) were separated from seismic Category I
structures by a distance greater than their height. However, this was not true for
the lake screen house. This non-seismic structure sat on top of the seismically
l qualified ultimate heat sink, including the service water tunnel. According to the
- licensee's response to an inspector question, the non-seismic lake screen house
i was designed to withstand the effects of a tornado to the extent that it would not
L collapse in such a way as to block the ultimate heat sink. Therefore, it appeared to
the inspectors that this UFSAR section also potentially needed revision.
!
LaSalle License Amendments 67 (Unit 1) and 49 (Unit 2), issued in July 1989,
increased the allowable suppression pool temperature from 100 F to 105 F. This
l change raised the maximum calculated post accident suppression pool temperature
l from 187 F to 192'F and impacted the starting point for several other analyses.
Although several UFSAR sections were affected by the amendment, the UFSAR
was not updated to reflect this change and remained inconsistent seven years later,
as follows:
28
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._ .. .. _ - _. __ .__ ___ ._ . _ _
. .. _ _ . _ ___.
1
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1
l
l * Section 6.2.2.3.2: listed a 187 F maximum final suppression pool
temperature
- Table 6.2 3: listed a maximum initial suppression pool temperature of 100 F
- Table 6.2-8: listed a maximum suppression pool temperature of 100 F
during the steam line break blowdown phase
l
- Table 6.2-22: listed a maximum initial suppression pool temperature of
100 F
10 CFR 50.71(e) requires that licensees update the UFSAR periodically to reflect
modifications to the plant. Subsection (4) requires such updates to be no more than
24 months apart and to reflect all changes made up to a maximum of six months
prior to the update. The failure to update the UFSAR for over six years after
issuance of this amendment is considerod a violation of 10 CFR 50.71(e)
l (50-373/96011-18(DRS); 50-374/96011-18(DRS)).
c. Conclusions
l
The CSCS licensirg basis was not well established in the UFSAR, nor was it
adhered to by the licensee. The inconsistencies noted in the UFSAR indicated that
the UFSAR has not been adequately updated.
E1.4 Sinale Active Failure Vulnerabilities
1
a. Insoection Scooe
i
The inspectors reviewed the UFSAR, design drawings, and calculations to determine
if any potential single failure vulnerabilities existed for the CSCS,in accordance with
Section 03.01.d of Tl 2515/115. l
l
b. Observations and Findinas I
The review indicated that generally, the CSCS contained adequate provisions to J
preclude multiple division failures resulting from a single source failure. However,
two instances were identified where this did not appear to be the case; one of 1
which was resolved prior to the end of the inspection. !
1
The first potential single failure was a possible water hammer event in the RHR heat
- exchangers which could result in tube damage. The heat exchangers were normally
lined up to allow water from RHR into the shell side of the heat exchanger. Because
RHRSW was manually initiated and did not normally run, the tube side would l
oepressurize below atmospheric pressure as a result of the relative elevations of the
tubes versus the ultimate heat sink elevation. If the lake was at the design basis
low level of 690 feet, voiding would be present in the tubes under normal operating
conditions. If the lake were at its normal level of 700 feet, boiling would occur in
the heat exchanger within seconds of RHR being initiated in its injection mode.
29
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. _ _ _ . _ __ . ._. . _ . . _ _ _ _ _ __
Once RHRSW was manually started, the steam voids would rapidly collapse as they
were condensed by the cold RHRSW, causing a water hammer which could break
'
tubes in both heat exchanger tubes in both RHR divisions. This could have rendered
both trains of RHR inoperable. The licensee responded that a water hammer would
occur as postulated by the inspectors. As of the end of the inspection, the licensee
l. had not determined the effect of the water hammer on the tubes. This is
l considered an unresolved item, pending completion of the licensee's determination
and associated operability analysis (50-373/96011-19(DRS);
l 50-374/96011-19(DRS)).
l The second potential single failure concerned the Unit 2 RHRSW pump A/B cubicle
! ventilation system. This system was supplied with air from a source which was
common to the Unit 2 HPCS diesel. Therefore, a single failure in this intake (such
as a clogged intake or filter) could potentially cause both RHRSW A/B and HPCS to
L be inoperable. This potentially violated the single failure criteria for the system.
!
The licensee responded to this concern by noting that passive failure of the filter
j due to clogging would be a long term event, and that there were sufficient
- operational controls to prevent its occurrence. The inspectors reviewed the
I licensee's response and had no further concerns.
c. Conclusions
l
!
! During the exit on September 24,1996, licensee management indicated that the
l RHR heat exchanger water hammer issue would be reviewed and corrected prior to
startup of either unit.
E1.5 Thermal and Hvdraulic Review
In accordance with Section 1.a of IP 93801 and Section 03.01.a of Tl 2515/115,
,
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the inspectors reviewed design calculations, surveillance procedures, equipment
specifications and vendor documents to determine if the system could meet its
j thermal and hydraulic requirements.
l
l- Based on a review of the CSCS design requirements and equipment specifications,
,
the inspectors determined that the CSCS components were adequately sized for
l ' their duty requirements. The equipment was, in fact, over sized in most instances,
i
such that there was adequata margin to allow for equipment degradation. The
l inspectors had no concerns regarding the ability of the CSCS to perform its design
l functions in the areas of heat removal and hydraulic capability.
!
- E1.6 Review of Confiauration Drawinas
!
a. Insoection Scope
.
In accordance with Section 1.b of IP 93801 and Section 03.01.b of Tl 2515/115,
l
the inspectors reviewed CSCS design calculations against equipment specifications,
system drawings, and vendor drawings to determine if they were consistent.
P
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30
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1
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The documentation reviewed indicated that the equipment specified and supplied
l was consistent with the requirements set forth in the original design calculations.
,
The equipment was over sized in severalinstances to allow for degradation due to
l wear. An observation was made that several of the calculations had not been
updated to reflect the equipment which was finally supplied. It appeared the results
- of the calculations would not have adversely affected had they been properly
updated. The inspectors determined that the equipment supplied for the CSCS was
consistent with the design calculations and specifications and therefore capable of )
performing its intended function.
E1.7 Effectiveness of Desian Features to Minimize Siltina and Biofoulina
t in accordance with Section 03.01.e of Tl 2515/115, the inspectors reviewed
l operation of the strainers in the RHRSW and DGCW systems, including the strainer
backwash circuits, in order to evaluate their effectiveness in minimizing silting and
biofouling of the piping and components.
f
The inspectors observed that the strainer backwash circuits were supplied with non-
l safety related power. This would result in automatic backwashing being unavailable
upon loss of offsite power. However, a manual backwash could be performed. For
the RHRSW, a safety related flow indicator was located in the main control room.
On low flow, the alarm response procedure directed dispatching personnel to
perfrvm a manual backwash. For the DGCW strainers, the only indication would be
r. high temperature alarm for the EDGs themselves. One of the alarm responses
was to locally verify that the strainers were not clogged, including performing a
l manual backwash, if necessary. Additionally, the in:; actors were provided
.
information from the strainer manufacturer that indicated that the strainers would
need to be over 80 percent clogged before any effect on the strainers would be
noticeable. Therefore, the inspectors concluded that sufficient information existed
to permit manual backwashing of the strainers upon loss of the normal power
supply.
E1.8 Flow Balancina and Runout Protection
a. Insoection Scooe
in accordance with Section 03.01.e, the inspectors reviewed system surveillance
procedures and piping and instrumentation diagrams (P&lDs) to determine how flow
balancing was achieved.
b. Observations and Findinas
The inspectors determined that adequate flow balancing provisions existed in the
CSCS in the form of throttle valves or orifices and flow indicators for individual
components. However, based on the procedure reviews and discussions with the
licensees' system engineers, these provisions were circumvented and the system
allowed to operate in a " valve wide open" mode. That is, all of the system throttle
valves were locked full open. This resulted in high flows to several of the
31
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components, namely the room coolers and the RHR heat exchangers. This situation
- resulted in the pumps operating away from _their design point' and, in two instances -
(ODG01P and the 1(2)E22-COO 2 pumps), the pumps operated either near or at their
. runout condition.
c. Conclusions
!
The inspectors concluded that the SWS design provided adequate provisions for
proper flow balancing; however, the provisions were not used, resulting in pumps
operating near their design limit. The effect of the system not being balanced is
considered an unresolved item as discussed in Section M2.10.
E1.9 Desian Features To Mitiaate Floodina
a. Insoection Scooe
The inspectors reviewed a number of calculations and operability assessments to
determine if flooding was properly accounted for in the CSCS design in accordance l
with Section 03.01.f of Tl 515/118. I
b. Observations and Findinas
The calculations indicated that flooding had been considered in the CSCS design, in
one instance the licensee determined that the watertight doors separating the-
different divisions of service water might not have been capable of performing 'their ;
intended function. An operability assessment was performed and a design 1
modification initiated to correct the situation. Also, the licensee determined in a
subsequent review that a ventilation duct which was below the maximum flood
elevation in one room might allow water to flow through it and flood an adjacent
room. An operability evaluation was performed and a modification initiated to
rectify the situation. These actions were determined to be appropriate for the
situations. ;
j Three of the calculations reviewed (S-OO8, S-OO9, and S-030) used inconsistent
'
assumptions and methodologies to determine flooding rates and maximum flood
elevations. The inconsistencies were different "K". factors for the break, different
assumptions for area reduction due to equipment, and the use of plant drains to
limit flooding heights. The licensees' response provided a logical explanation of
why the differences existed, but did not reconcile why different assumptions were
used.
c. Conclusions
The inspectors concluded that the !icensee had taken adequate measures to protect
L against internal flooding caused by the SWS. However, the inspectors deemed that
i use of a consistent methodology would enable the license to better maintain their
j design basis flooding analyses.
.
L 32
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E1.10 Seismic Qualification
in accordance with Section 03.01.g of Tl 2515/118, the inspectors reviewed
calculations which demonstrated seismic qualification of the 64-inch bypass line and
the six 36-inch intake lines. The inspectors questioned the licensee about the
assumptions used in the analyses and determined that the licensee's responses
were valid. Because these were the only non-seismic portions of the systern, the
inspectors had no further concerns.
E1.11 Modifications )
in accordance with Sections a.7 and a.8 of IP 93801 and Sections 03.01.g and
03.01.h of Tl 2515/118, the inspectors reviewed the design change packages listed l
in Attachment C. The modifications were determined to be adequate in detai! and !
technically correct. The safety evaluations or screenings performed to support the
modifications were acceptable. No problems were identified.
E1.12 Alarm Setooints
in accordance with Section 03.01.k of Tl 2515/118, the inspectors reviewed the
setpoints for alarms and actuations to ensure they were consistent with the design
basis and assumptions. The inspectors also reviewed CSCS compliance with
Regulatory Guide (RG) 1.97, Rev. 2, " Post Accident Monitoring."
Per RG 1.97, cooling water temperature and flow indications to essential
components should be available in the main control room. Temperature and flow
indications for the RHRSW were provided in the main control room, with the flow
instrumentation being supplied by safety related power. The temperature indication
was supplied by non-safety related power. While this was permitted by RG 1.97,
the temperature indication would not be c.vailable during any scenarios where loss
of offsite power occurred. The inspectors discussed this with the licensee, who
acknowledged the point. The inspectors considered this a minor issue because
RHRSW temperature was not used to respond to any accident condition.
E1.13 Electrical Calculations
in accordance with Section 1.a of IP 93801 and Section 03.01.a of Tl 2515/115,
the inspectors reviewed electrical calculations associated with engineered safety
l
feature (ESF) bus loading, hot shutdown, and isolation of safety and non-safety
loads.
The inspectors noted that calculation 19AK19 computed the loads on ESF Buses
141Y,142Y and 242Y without adding the RHRSW pumps 1E12-C300A and
1E12-C3008 pump load. As these pumps are assumed by the accident analysis to
be loaded within ten minutes to support suppression pool cooling, the pump loads
need to be included in the calculation. The inspectors and licensee independently
calculated the effects of adding these loads on the EDG load profile and concluded
that there was sufficient margin to include the loads. Additionally, the numbers in
33
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h
m
g6
'A the calculation for ESF Bus 242Y did not match with the UFSAR values. The
i
licensee provided a copy of a PIF which previously identified this problem and noted
9 that the UFSAR would be updated during its next revision to reflect the correct
'
values. The inspectors had no further concerns with the electrical calculations.
'
E2 Engineering Support of Facilities and Equipment
E2.1 involvement of Enaineerina in Surveillance Testina
in accordance with Section d.9 of IP 93801, the inspectors determined the
contribution of engineering and technical support personnel to surveillance test
procedures.
During the course of reviewing surveillances and completed tests, the inspectors
noted that the system engineers were heavily involved with the surveillance
program, ran many of the tests, and that they routinely reviewed test results.
However, this did not prevent significant problems from occurring as described in
Sections M2.1 - M2.6. The inspectors noted that the SWS components were
assigned to different system engineers, dependent upon who had the system which
SW was supporting (for example, the RHR system engineer had the RHRSW and the
EDG engineer had the DGCW). Furthermore, at the time of the inspection, no one
was assigned overall responsibility for GL 89-13 implementation.
E4 Engineering Knowledge and Performance
E4.1 Access to Generic Information
a. Insoection Scope
The inspectors examined the technical information available to a system engineer.
This included the system notebook, vendor manuals and other technical data. The
inspectors examined the access to GLs, Bulletins, and Information Notices (ins)
pertaining to equipment,
b. Observations and Findinas
Each system engineer had a system notebook as well as a notebook with all of the
GLs, ins, Bulletins and other technical documents pertaining to his/her system.
However, these books were only updated every two years. In order for the system
engineer to obtain more recent information, he would consult the computer. The
inspectors noted that one engineer could not access the necessary technical
information for his system from the personal computer. The engineer stated that a
new computer software program had been installed and he had not yet received
training on its use. This prevented the engineer's easy access to the various
technical information. The inspector examined the engineer's familiarity with the
past few PlFs on his system. The engineer was familiar with them.
34
_ _ _ _ _ . . . . . .
._ _ . -_. _
l
The inspectors also observed that the support engineering staff trended some data,
,
and if a parameter fell outside a designated band, the staff member would contact
l the system engineer.
C. Conclusions
The inspectors concluded that system engineers had access to generic information.
l
l
,
l 1. OPERATIONS
01 Conduct of Operations
.
01.1 Technical Soecification Clarifications (TSCs)
l
(
l
a. Inspection Scoce
i
j The inspectors examined LaSalle's TS clarification process, including a review of
I existing TS clarifications.
b. Observations and Findinas
!
'
Since the mid-1980s, the licensee had included TS clarifications as an addendum in
a separate binder to their TS. The Administrative Procedura, LAP 1200-17,
" Operating License / Technical Specification Clarifications," provided requirements for
TSCs and included this guideline: "A license or Technical Specification clarification
is intended to provide guidance to the station operators concerning interpretation of
r specific license and technical specification requirements.... A clarification must not
change the intent of the bases for any license, design, or technical specification
requirement." The inspectors noted that over the years, a number of TSCs had
been initiated and deleted; for examples, in 1987 over 35 active previous TSCs were
l bundled in TSC 87-01 and reissued. At the time of the inspection, only pages 12,
, 13, and 35 remained for TSC 87-01. Additionally, at least 13 TSCs were initiated
l in 1989 and only TSC 13-89 still was active. Some of the deleted TSCs had been
proceduralized, creating a de-facto TSC in a procedure. Following an NRC
inspection at Zion, which raised questions about several TS Interpretations, LaSalle
operations staff conducted a review of their TSCs and determined 27 clarifications
could remain active and 16 TSCs should be deleted. Additionally, the licensee
identified 5 technical specifications requiring amendments. The inspectors
examined the licensee's TSC review and concluded that it was thorough and that
the re naining TSCs did not change the intent of the TS.
l The inspectors identified two minor concerns with the licensee's administrative
processes: (1) the method of controlling copies of TSCs did not appear effective
since the Quality Verification group's copy of the TSC binder was not controlled or
routinely updated; and (2) a cross referencing method of attaching orange dots on
the appropriate TS pages was not consistent; while most pages generally had dots
, indicating where a TSC applied, some did not.
35
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c. Conclusions
The inspectors concluded that the licensee's review of TSCs was thorough and that
the remaining TSCs did not change the intent of the TS.
O2 Operational Status of Facilities and Equipment
O 2.1 System Walkdown
The inspectors performed a detailed system walkdown in accordance with
Section 03.02.a of Tl 2515/118. The results are discussed in Section M2.15.
O3 Operations Procedures and Documentation
03.1 Review of RHRSW and DGCc/ Procedures
The inspectors reviewed the SWS alarm response procedures and operating
procedures for normal, abnormal, and emergency system operations to ensure that
the system was operated within the design envelope in accordance with Section b.2
of IP 93801 and Section 03.02.b of Tl 2515/118. This included review of the
adequacy of flow instrumentation relied upon during accident conditions.
The inspectors determined that local flow, pressure and temperature
instrumentation existed to determine normal operating conditions. There were
sufficient control room alarms to identify such conditions as strainers clogging (high
differential pressure), high temperatures, and pumps auto tripping. The inspectors
concluded that sufficient rnonitoring indication existed.
03.2 Imolementation of Service Water Operatina Procedures
The inspectors reviewed the operational valve lineups, valve throttling and flow
variations due to changing climate in accordance with Section 03.02.d of Tl
2515/118. The inspectors determined that the normal position of major system
valves was locked fully open, with no valve throttling. The only exceptions were
the DGCW valves which were positioned by engineering for correct heat dissipation
and locked in a slightly throttled position. Throughout the system there were no
requirements for any adjustment of flow for changing climate. The inspectors
concluded that no concerns existed regarding degradation of accident flows due to
normal system operation.
04 Operator Knowledge and Performance
04.1 Walk Throuah of Procedures
a. Inspection Scoce
The inspectors walked through the system operating procedures while relating
information obtained from the system process diagrams and system walkdowns in
36
accordance with Section b.4 of IP 93801 and Section 03.02.e of Tl 2515/118. The
review evaluated alarm response procedures, workability of procedures, and
accessibility of normally used and special equipment. The operators were
interviewed to determine their knowledge of system equipment and its operation.
b. Observations and Findinas
No concerns were developed during the walk through of system operating
procedures. The inspectors noted that an extensive procedure revision program
was in progress. The revision program was an attempt to write procedures in a
clearer format and to provide more details in steps. The inspectors noted that the
licensee recently took actions to clearly label and to attach to each strainer the
manual operator tool for strainer back flushing and to include more detailed
instructions in the operating procedures on how to manually back flush a strainer.
Failure of a DGCW strainer was a significant contributing element in one fault tree
for a severe accident scenario in the Individual Plant Examination. This was
considered a positive initiative.
c. Conclusions
The inspectors determined that the operational procedures were adequate to
operate the SWS and equipment was accessible.
04.3 Local Ooeration of Eauipment
in accordance with Section b.6 of IP 93801 and Section 03.02.g of Tl 2515/118,
the inspectors reviewed the licensee's procedures for local operation of equipment
and verified that equipment needed to perform the local operations was available.
The inspectors confirmed that equipment necessary to support installation of a
spool piece into the FPEM pumps was appropriately staged. The inspectors also
noted that a handle was attached to each strainer so that manual backwashes could
be performed. The inspectors verified that the environmental conditions, such as
the available emergency lighting, were adequate to support the remote operation of
the equipment. This inspection item was determined to be satisfactory.
04.4 Ooerational Controls for Travelina Screens
a. insoection Scooe
in accordance with Section 03.02.h of Tl 2515/118, the inspectors assessed the
operational controls for traveling screens and circulating water pumps to preclude
excessive draw down of the intake bay, with associated loss of SWS pump su': tion
head, as a result of clogging the traveling screens.
l
37
. ._ _ - . . .
b. Observations and Findinas
The inspectors noted that there was a 54-inch bypass line around the traveling
screens that was provided with a normally closed manual valve. The inspectors
verified that the control room had an annunciator which would alarm on high
differential pressure across the screens. The inspectors reviewed the alarm
response procedure, which identified operator actions to be taken, including
shutting down a circulating water pump and locally opening the manual valve in the
bypass line.
t
The inspectors noted that the differential pressure instruments and the annunciator
!
were non-safety related, which meant they could not be credited for operating
under design basis conditions.
The inspectors reviewed the design of the lake screen house with the licensee. The
design provided six connecting pipes between the circulating water pump bays and
the service water tunnel. Each circulating water bay had its own traveling screen,
l which lessened the probability that all the screens would be blocked. Furthermore, l
the licensee stated that under transient conditions where the CSCS equipment l
would be required, the circulating water pumps would be stopped. This would
decrease the screen discharge pressure, which would result in debris no longer
l clinging to the screens. Therefore, it would be very unlikely that all the screens
would be completely blocked.
l
The inspectors confirmed that only three of the six service water tunnel access lines
were necessary to maintain the level in the service water tunnel. Therefore, short-
l
term operator action did not appear to be necessary to prevent drawdown of the
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service water tunnel.
l C. Conclusions
The inspectors concluded that sufficient operational controls existed to ensure that
excessive drawdown of the service water tunnel would not occur if the traveling
screens were clogged.
07 Quality Assurance in Operations
l 07.1 Timeliness and Adeauacy of Issue Resolution
a. Inspection Scoce
in accordance with Section e.2 of IP 93801 and Section 03.05.d of Ti 2515/118,
!
the inspectors reviewed the timeliness and technical adequacy of licensee resolution
j of findings from its self-assessments. The inspectors examined handling of items in
j the licensee's nuclear tracking system as well as the effectiveness of completing
,
the assigned actions in due time.
38
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b. Observations and Findinas
The inspectors noted an issue open from 1987 to July 1996. The issue related to a
potential fire in a' corridor where control panels for all three EDGs were located. The
fire could render all three division EDGs inoperable. The action taken in 1987 was
initiation of an hourly fire watch and origination of a modification request to install
physical protective barriers. However, due to concerns with fire retardant materials,
the modification package was put on hold in 1991 and was canceled in September
of 1996.
The basis for canceling the modification was establishment of an alternative
shutdown path: core cooling by the reactor core isolation cooling system, which
did not require EDG operation. Other longer term actions, such as cooling the
suppression pool, would be handled by cross-tying the emergency busses to the ,
other unit. This assumption and the analysis was previously approved by the NRC '
for the Station Blackout issue.
The inspectors questioned the licensee on the adequacy of the compensatory l
actions in place from 1987 to 1996 and what guidance would have been available l
to the operators had a fire occurred during this nine-year period. The focus of the l
inspectors' concerns was on why the licensee required the EDGs to operate, as l
10 CFR Part 50, Appendix R, did not require a licensee to assume that offsite power
was lost, unless the fire caused it to be. The licensee stated that assuming loss of
offsite power was a conservative measure. However, neither the original (1987)
fire hazard analysis contained in Appendix H of the UFSAR, nor the revision
proposed in 1996, stated that a conservative assumption of loss of offsite power
had been applied. Therefore, the inspectors inquired whether the licensee had
confirmed that offsite power cables either would or would not be affected by a fire
in the zone.
c. Conclusions
The lack of compensatory actions for a nine-year period could be a significant failure
to take adequate corrective actions. The significance, however, depended on
whether offsite power would be affected for a fire in the EDG corridor. Although
the licensee claimed that loss of offsite power was a conservative assumption, this
was not reflected in either the original fire hazards analysis nor in the 1996 revision.
The inspectors requested that the licensee respond in writing providing evidence to
support the assertion that a fire in the EDG corridor would not result in loss of
normal power to the affected components. This is considered an unresolved item,
pending the licensee's response (50-373/96011-20(DRS); 50-374/96011-20(DRS)).
39
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X. Manaaement Meetinas
l
l X1 Exit Meeting Summary
l
The inspectors presented the results of these inspections to Comed management,
j as noted on the attached list of persons contacted, at an exit meeting on
September 24,1996. Comed acknowledged the findings presented. Additional
I
findings were discussed in a telephonic exit with Mr. D. Ray on October 30,1996.
The inspectors asked the licensee if any materials examined during the inspection
should be considered proprietary. No proprietary information was identified.
i
l Attachments: A. Partial List of Persons Contacted
,
B. Items Opened, Closed, and Discussed
I
C. List of Acronyms Used
D. NRC Comments
E. Procedures Used and Documents Reviewed
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ATTACHMENT A
PARTIAL LIST OF PERSONS CONTACTED
Comed
- W.' Subalusky, Site Vice President
"J. Brons. Vice President, Nuclear Support
"D. Ray, Station Manager
- L. Guthrie, Operations Manager
' A. Magnafici, Maintenance Superintendent
R. Fairbank, System Engineering Supervisor
- P. Antonopoulos, Site Engineering Manager i
"M. Rauckhorst, Site Quality Verification Director
"J. Burns, Regulatory Assurance Supervisor
D. Egan, Design Engineering Supervisor
fi&C
- *G. Grant, Director, Division of Reactor Safety (DRS)
"M. Ring, Chief, Lead Engineers Branch, DRS :
"M. Huber, Senior Resident inspector
K. Ihnen, Resident inspector
H. Simons, Resident inspector
!
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( * Present at exit meeting on August 7,1996.
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l ATTACHMENT B
' ITEMS OPENED, CLOSED, AND DISCUSSED
Onened
50-373/96011-01; VIO Failure to implement design control measures on
50-374/96011-01 modification to fuel pool emergency makeup pumps
50-373/96011-02: eel Apparent failure to implement design control measures
! 50-374/96011-02 on modification to 2A RHRSW pump impeller
50-373/96011-03: eel Apparent failure to adequately evaluate test results
50-374/96011-03 (effects of increased flow)
I
! 50-373/96011-04: eel Apparent failure to test 2A & 2B RHRSW pumps in -
50-374/96011-04 accordance with Section XI requirements
l
50-373/96011-05: eel Apparent failure to take adequate corrective actions to
'50-374/96011-05 repair the 2A RHRSW pump discharge valve
50-373/96011-06 eel Apparent failure to take adequate corrective actions to
50-374/96011-06 correct the off scale flow indicator for the 2A RHR heat
exchanger
Apparent failure to incorporate correct acceptance limits
~
50-373/96011-07; eel I
50-374/96011-07 into special test .)
50-373/96011-08; eel Apparent failure to incorporate correct acceptance limits
j 50-374/96011-08 into routine surveillance
L 50-373/96011-09; eel Apparent failure to incorporate correct acceptance limits
50-374/96011-09 into surveillance test !
50-373/96011-10;- VIO- Failure to provide acce~ptance limits for testing under full
,
50-374/96011-10 flow conditions
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-50-373/96011-11; VIO' Failure to evaluate effects of adverse trend on 2B RHR
50-374/96011-11- heat exchanger
! 50-373/96011-12; UNR Determinatior, ci maximum velocity through 4A room
l
50-374/96011-12 cooler and effect of RHRSW on cocier flows
50-373/96011-13; VIO Failure to provide documented instructions or procedures
50-374/96011-13 for removal of silt from lake screen house
50-373/96011-14; VIO Failure to meet requirements of TS 4.7.1.3.c to measure
50-374/96011-14 sediment levels in lake screen house
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-- . _ . _ _ - - . - . . . _ _ _ . _ . _ _ _ _ _ . . . ___ _ _ . . . _ _ . _ .
50-373/96011-01: VIO Failure to implement design control measures on
50-374/96011-01 modification to fuel pool emergency makeup pumps
50-373/96011-15; NCV Licensee identified that a mode change was performed
I
50-374/96011-15 while prohibited by TS
50-373/96011-16; UNR Determination of effect of lake level on RHRSW flow
50-374/96011-16 values in surveillance tests.
50-373/96011-17; VIO Failure to incorporate correct design assumptions l
50-374/96011-17 regarding HPCS pipe temperatures into calculations
l 50-373/96011-18; VIO Failure to update UFSAR following 1989 license
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50-374/96011-18 amendment
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50-373/96011-19; UNR Effects of water hammer on RHR heat exchangers i
50-374/96011-19 )
! 50-373/96011-20; UNR Determination of conservatism in assuming loss of
l 50-374/96011-20 offsite power concurrent with fire in EDG corridor
!
> Closed
L
96-005 LER Failure to Follow Procedures Results in TS Violation of the
Core Standby Cooling System Pond Surveillar.ce
! 50-373/96011-15; NCV Licensee identified that mode change was performed
50-374/96011-15 while prohibited by TS
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ATTACHMENT C
LIST OF ACRONYMS USED
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ALARA As Low As Reasonably Achievable
ASME American Society of Mechanical Engineers
l CCSW Containment Cooling Service Water
CFR Code of Federal Regulations
CSCS Core Standby Cooling System
dP Dif ferential Pressure
DGCW Diesel Generator Cooling Water
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DRS Division of Reactor Safety
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( EDG Emergency Diesel Generator
Escalated Enforcement item (apparent violation)
'
eel
ESF Engineered Safety Feature
FPEM Fuel Pool Emergency Makeup
,
GL Generic Letter
l GPM Gallons Per Minute
HPCS High Pressure Coolant System
IN Information Notice
IP Inspection Procedure
IST inservice Testing
LER Licensee Event Report
LPCI Low Pressure Coolant injection
LOCA Loss of Coolant Accident
LOS LaSalle Operating Surveillance
' LST LaSalle Special Test
LTS LaSalle Technical Surveillance
l NCV Non-cited Violation
l
NEP Nuclear Engineering Procedure
l NRC Nuclear Regulatory Commission
- PIF Problem Identification Form
PORC' Plant Operations Review Committee
PDR NRC Public Document Room
SSFl Safety System Functional Inspection
l SWS Service Water System
l SWSOPl Service Water System Operational Programs Inspection
TI Temporary Instruction
TS Technical Specification
TSC Technical Specification Clarification
UFSAR Updated Final Safety Analysis Report
- UNR Unresolved item
l VETIP Vendor Equipment Technical Information Program
VIO Violation
WR Work Request
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ATTACHMENT D )
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NRC COMMENTS
The following NRC comments were provided to the licensee in writing during the
inspection. Following each comment is the licensee's response to that item.
Comment 1: CSCS Flow at Strainer Alarm l
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Inspector: Bob Stakenborghs Date: September 4,1996 )
Calculation LOOO582 determined reduced flow rate due to increased strainer dP. The
calculation was not perforrned using minimum lake level as its basis. Also, the calculation
did not account for actuallake level present during the testing. These two factors could I
l make the flows calculated non-conservative.
Licensee Response (9/16/96): Calculation L-000582 was performed to determine the
ability of the CSCS pumps to provide the required design basis flow to the CSCS I
components at different system resistance levels, considering several operating conditions, l
including consideration for the system strainers when they are clean, when the strainers !
are at the backwash initiation .cetpoint, and when they are at the alarm setpoint.
The calculation assumes a nominallake level of 700' mean sea level and no specific
reference to a lower than normallake level was stated. However, the acceptance criteria
values listed in the calculation included considerations for the lower lake water level.
These acceptance criteria values were developed as part of LTS96-042, LTS96-043, and
LTS96-044 and were based on the lake level of 690', the design level of the CSCS pond.
As confirmation of the calculation's conclusion an independent verification, using a
methodology different than that used originally to account for lake levels, was performed.
,
This verification used the data obtained from the above referenced tests on the system
l operation. The effects resulting from strainer partial plugging were also included. This
separate verification confirmed the conclusions reached in Calculation L-000582.
Comment 2: Source of Water to Cool Safety Related Loads
Inspector: Patricia Lougheed Date: September 5,1996
Please describe the source of water for the CSCS pumps (RHRSW/DGCW/FPEM) following
(1) a LOCA with loss of offsite power, (2) an earthquake, and (3) a tornado. If credit is
taken for any non-safety or non-seismic component or structure, provide the supporting
! documentation as to why this component or structure will continue to be available. If
credit is taken for any operator action, provide the procedure outlining that action as well
as the supporting human factor analysis demonstrating that sufficient time is available to
. 1
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take those actions. Documentation needs to include justification as to how GDC
requirements are met.
Licensee Response (9/18/96): The normal path for water flow for the system is through
the bar grill and traveling screens of the service water system located in the lake screen
house, into the six circulating water pump suction bays, each of which includes a 36-inch
pipe with a locked open rnanual gate valve that directs the flow through the building into
l the service water tunnel. From there it then passes to the inlets of the suction lines and
l then to the CSCS pumps. A 54-inch bypass pipe with a manual normally closed valve
provides an alternate flow path around the traveling screen, in the unlikely event that the
screens plug. The 36-inch and 54-inch bypass pipes empty into the seismically designed
l service water tunnel. From there the cooling water flows into the headers which supply
l CSCS piping and equipment beyond the service water tunnel are safety related and
seismic.
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The bar grill and traveling screens are non-safety-related, non-seismic components. If
either of these collapsed during a seismic event, water would simply pass through and
around them into the circulating water pump bay in the lake screen house. If there were a
high pressure drop across the traveling water screens, several protective measures are
! available. A high delta-P across the screens will alarm in the control room. A high-high
! delta-P will trip the circulating water pumps. Once these pumps stop, the water velocity
l across the screens will be very low (= 0.1 ft/sec) and the pressure drop across the
! screens will drop substantially. There is no recognized failure mechanism that would
l prevent the safety function of water passing from the ultimate heat sink to the inlet of the
36-inch pipes.
The 36-inch pipes and the manual gate valve were both recently qualified by analysis to
Seismic Category I but have always been classified as non-safety-related. The pipes and
valves are passive components and are partially encased in a Seismic Category I concrete
! structure. The manual valves in the 36-inch pipes are locked open and administratively
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controlled. If a crack were to develop in one of the six 36-inch pipes, the water level
would rise in the area of the pipe until it rose in the lake screen house to the level of the
i lake, at which time it would then continue to flow through the pipe to the service water
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tunnel. That would also not affect the ability of the other five 36-inch pipes to deliver
flow. LaSalle has begun the process of upgrading the safety classification of these pipes
and valves.
The 54-inch bypass line and manual valve are currently classified as non-safety-related and
were recently qualified by analysis to Seismic Category 1. The pipe is a design feature that
would provide flow if the traveling water screens became blocked through some
unspecified event. Use of this feature is unlikely to be needed because of action that could
i be taken to stop the circulating water pumps in the event of high pressure drop across the
screens and thereby ensure continued flow as discussed above. The pipe inlet is located
10 feet below the minimum pond surface elevation and 1 foot,6-inches above the intake
structure floor to prevent ingestion of floating or heavier than water debris. The pipe is
completely underground and tornado protected. The in-line manual valve can be opened in
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l response to a high pressure drop across the screens. LaSalle has begun the process of
upgrading the safety classification of the 54-inch pipe and valve.
,
(1) For a LOCA with loss of offsite power: In this case, water would pass through the 36-
! inch pipes in the circulating water pump bays to the service water tunnel and on to the
supply pipes and system pumps. While the traveling water screens are not supplied with
emergency power and would have stopped, the circulating water pumps and (non-safety-
relatedl service water pumps are also not supplied with emergency power and would also
l stop, and flow would then only be a fraction of the flow before the LOOP, and not credible
to cause blockage. Once the circulating water pumps and service water pumps are
stopped, the pressure drop across the screens would drop substantially, and there would
l be a reduction in transport of foreign materialinto the traveling screens. This design meets
l the requirements of the GDCs. Though not required to respond to the event, the 54-inch
l bypass line isolation valve can be opened and the bypass line utilized in response to a high
i delta-P across the screens.
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(2) Earthquake response: In the case of an earthquake, flow would pass through the 36-
inch, Seismic Category I pipes in the lake screen house to the Seismic Category I designed
service water tunnel, both of which are housed within the below grade seismic designed
portion of the building. Collapse of the bar grill, screens, or structure above the seismic
portion of the building above grade would not prevent flow of water into the lake screen
j
house,36-inch piping and service water tunnel. The configuration of the structure will
- prevent the effects of the earthquake on the portion of the building above the concrete
!
from affecting the inlets to the 36-inch pipes. The 36-inch pipe has a long, sloped opening
on top that follows the slope of the intake bay, the farther part of which is well away from
the traveling screen. The seismic concrete structure has a forward shelf at grade level that
will tend to capture any collapse onto the 36-inch piping. The building structure and piping
design of the 36-inch pipes and service water tunnel meet the GDC requirements. l
l (b; Tornado response: The below grade portion of the lake screen house structure in the
area of the 36-inch pipes is designed for the effects of a tornado. Failure of a bar grill and
traveling water screen from a tornado missile would not prevent water from reaching the
36-inch lines. Although not required to respond to the event, the 54-inch bypass line is l
also tornado designed and available.
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l Comment 3: CSCS Technical Specification Surveillance, Lake House Sedimentation
Inspector: Bob Stakenborghs Date: September 5,1996
Technical specification surveillance 4.7.1.3.c requires verification that " sediment
- deposition anywhere within the lake screen house is not greater that one foot in thickness"
l every 18 months. A review of completed station surveillances (LTS-1000-4) indicates that ,
! this inspection occurred in 3/5/92, and not again until 2/9/96. This appears to violate the l
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18 month requirement. Please provide documentation indicating that this surveillance was
i performed during the period in question.
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Licensee response (9/6/96): Copies were provided of completed LTS-1000-4 surveillances
i for both units between March 1992 and February 1996.
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Comment 4: Design Basis for CSCS
'
inspector: Bob Stakenborghs/ Babu Gupta Date: September 5,1996
Please provide documentation to support the design basis accidents for which CSCS is
required to support unit shutdown / accident recovery. Specifically, what accident
combination makes up LaSalle's design basis (i.e., single unit LOOP /LOCA, dual unit
LOOP /LOCA, seismic, etc.). Also, please provide CSCS flow requirements under each
accident condition identified as a valid scenario.
Licensee response (9/23/96): The accident combinations composing the design basis
CSCS-ECWS flow rates for LaSalle are as follows:
e Safe Shutdown Earthquake - This event requirement conforms to the LaSalle
commitment to Appendix A of 10 CFR Part 50, General Design Criteria (GDC) 2,
detailed in UFSAR Section 3.1.2.1.2 " Evaluation Against Criteria 2 - Design Basis
for Protection Against Natural Phenomenon," and further detailed in UFSAR
Section 3.7, " Seismic Design."
e LOCA - These accident scenarios are detailed in UFSAR Section 15.6.5 entitled
"' oss-of-Coolant Accidents Resulting from Spectrum of Postulate Piping Breaks
Within the Reactor Coolant Pressure Boundary."
l 'e Loss of Offsite Power- This accident scenario is detailed under UFSAR
l Section 15.2.6, " Loss of A-C Power."
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e ATWS - This accident scenario is detailed in UFSAR Section 15.8 entitled
" Anticipated Transient Without Scram."
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e Plant Fire - This event scenario conforms to the LaSalle commitment to
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Appendix A of 10 CFR Part 50, GDC 3, detailed in UFSAR Section 3.1.2.1.3,
" Evaluation Against Criteria 3 - Fire Protection," and further detailed in UFSAR '
Section 9.5.1 and Appendix H, " Fire Hazards Analysis."
e Flood - This event requirement conforms to the LaSalle commitment to Appendix A
of 10 CFR Part 50, GDC 2, detailed in UFSAR Section 3.1.2.1.2 and further detailed
in UFSAR Section 3.4 entitled " Water Level (Flood) Design."
i e Tornado - This event requirement conforms to the LaSalle commitment to
l Appendix A of 10 CFR Part 50, GDC 2, detailed in UFSAR Section 3.1.2.1.2 and
further detailed in UFSAR Section 3.3 entitled " Wind and Tornado Loadings."
The flow values, listed below for each of the scenarios, were obtained by evaluating the
component requirements for the scenario, utilizing, as necessary, the UFSAR and design
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and operational considerations. Specific values for flows through the individual
components were obtained from design basis information listed in the UFSAR and other
design documents such as component specifications. Since the common diesel generator
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is typically included in the Unit 1 portion of the CSCS system, the configuration that is
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most limiting in terms of CSCS/ECWS flow is that configuration which considers Unit 1
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experiencing the accident or event scenario and Unit 2 achieving shutdown. The flow
l rates postulated in the scenarios listed in the table are within the design capability of the
pumping systems.
Based on the flow requirements to the CSCS-ECWS components, the limiting scenario with
respect to CSCS-ECWS flows is the steady state operation of the CSCS-ECWS when the
station (both Units) is experiencing a Safe Shutdown Earthquake (SSE) with a postulated
Loss of Offsite power. This scenario results in the greatest required CSCS-ECWS flows,
in those scenarios where one unit is experiencing a design basis scenario and the other
- urut is experiencing an orderly shutdown, the required CSCS-ECWS flow rates will be less
l than for those scenarios where both units are affected.
SCENARIO UNIT STATUS CSCS FLOW RATE (GPM)
Safe Shutdown Earthquake Both Units Affected Unit 1 - 18,194
Considering a Loss of Offsite Unit 2 - 17,394
Power Total - 35,588
DBA - LOCA One Unit LOCA - Other Unit Unit 1 - 18,244
Achieving Shutdown Unit 2 - 8,774
Total - 27,018
Loss of Offsite Power Both Units Affected Unit 1 - 17,944
Unit 2 - 17,144
Total - 35,088
ATWS One Unit ATWS - Other Unit 1 - 17,944
Unit Achieving Shutdown Unit 2 - 8,774
Total - 26,718 l
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Plant Fire One Unit Plant Fire - Other Unit 1 - 17,944 l
Unit Achieving Shutdown Unit 2 - 8,774
Total - 26,718
Flood Both Units Affected Unit 1 - 17,944
Unit 2 - 17,144
Total - 35,088
Tornado- Loss of Offsite Both Units Affected Unit 1 - 17,944
Power Unit 2 - 17,144
Total - 35,088
Comment 5: CSCS Diesel Generator Cooling Water Pumps l
Inspector: Babu Gupta Date: September 5,1996
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UFSAR Section 9.2.1.5 states "the diesel generator cooling water pumps are started I
automatically at the same time the corresponding diesel generator is started." This
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statement needs clarification, since the DG cooling water pumps cannot be started until
the bus is energized by the corresponding DG in case of loss of offsite power.
Licensee response (9/16/96): The above statement relating to the autostart of the DG
cooling water pumps is meant to be a description of the normal operation of the system.
Normal operation at LaSalle station consists of both offsite power sources connected and
utilized by the station. In this condition, the DG cooling water pumps will receive a start
signal when the DG reaches 150 rpm, the actual engine starting speed.
In the event of a loss of offsite poviar, the DG cooling water pumps would not start for ,
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approximately 13 seconds. This delay is a result of the time required for the DG to reach
its rated speed (900 rpm) and for the DG output breaker to close onto the bus and
reenergize the autoconnected loadt fed from the bus. System engineering, in conjunction
with the diesel vendor, has determined that the 13 second period of time has no effect on
the engine's operation.
In order to clarify the description within UFSAR section 9.2.1.5, AIR #373-160-00107has
been initiated to include a brief description of the system's operation in the event of a loss
of offsite power as part of the next scheduled UFSAR amendment.
Comment 6: Surveillance LOS-RH-Q1 (RHRSW Portion only)
Inspector: Patricia Lougheed Date: September 5,1996
The following discrepancies were noted during review of this procedure:
1. For the U1 RHRSW pumps and the U2 C/D RHRSW pumps, the pump seal cooler
isolation valves are closed during the individual pump tests, but open for the
combined test; for the U2 A/B RHRSW pumps, the pump seal cooler isolation valves
are closed. (a) Why the difference? (b) What is the flow rate through the seal
cooler? (c) Calculation CS-2 did not evaluate the impact of installing an orifice on ,
the coolers (plus the calculation used incorrect values). This could result in much
higher flow rates through the cooler than originally designed. (d) The UFSAR says
the flow rate through these coolers is 20 gpm --is this confirmed anywhere?
(e) The valves are shown as locked open on P&lD M-87; however, the procedure
does not require them to be locked open (except for step 24u, which is contradicted
by Attachment 2A). (f) Are the valves currently locked? (g) If the valves are not
locked, please provide the surveillance to comply with TS 4.7.1.1.
2. (a) Start of the cubicle cooler is checked for pumps 1 A-D and pumps 2C&D, but
not for 2A&B- why? (b) Why is the cubicle cooler start not recorded in the
Attachments?
3. In step 24j, where does the 8000 gpm flow rate come from (design value of 7400
is used for the other combined pump tests)?
l 4. Numerous numbering errors were identified. Eight specific examples provided ;
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l where attachment referenced wrong procedure section.
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S. Please provide the 50.59 for procedure revision which changed the test method for
RHRSW pumps 2A&B.
Licensee response (9/4/96): ]
1. (a) The intent of valving out the seal coolers is to ensure that the total RHRSW l
flow is through the flow element for pump testing; however, the seal cooler flow l
rate is negligible compared to the RHR heat exchanger flow. This had applied to all J
four RHRSW subsystems until the procedure was revised for the Unit 2 A and B l
pumps due to a failure of the 2A RHRSW pump discharge valve. There is no j
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specific reason why the difference exists. The only consideration is to reopen the
seal cooler isolation valves which are previously closed at the conclusion of the
testing for the A and B loops. The next revision of the test procedure will restore all
four loops to the same test methodology. l
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(b) UFSAR Section 9.2.1.1.1.a specifies that the system is designed to provide a
minimum seal cooler flow rate of 20 gpm. The original vendor design requirements 1
are 18 gpm at an inlet service water temperature of 105 F. Recent evaluations
have shown the design flow is 12.5 gpm, considering the design basis 100 Finlet
service water temperature, j
(c) The calculation was reviewed and a new calculation performed to determine the
_ system flow characteristics using correct values. This new calculation took into l
account the impact of the orifice (E12-D304A/B)on the seat cooler flow rate. The I
resultant calculated flow to the seal coolers was 18 to 21 gpm. !
(d) The RHR seal cooler line is not instrumented to measure flow. LST 87-73 was
developed to collect baseline [datal for the RHR seal coolers. As discussed in the
test evaluation, an attempt was made to determine actual RHR seal cooler flow.
Due to the testing methodology, significant data uncertainty occurred related to the
actual cooler differential pressure vs. flow during the flow testing. Due to the data
uncertainty, the test evaluation never concluded what the flow was through the
coolers. A recent review of the data was made and, when considering conservative
assumptions regarding the frictional data for this test rig, flow can be estimated at
15-20 gpm. A PIF was generated and an operability detnrmination was completed
based on an initial review of the seal cooling requirements. An Operability
Evaluation is currently being performed to further assure system operability.
(e) The P&lDs do not control the use of locks. Procedure LAP-240-1, "Uso of
Locks on Valves," is the administrative procedure which controls the locking of
valves. The procedure states in E.1 that " Locks on valves are not design
l information. The designation LC or LO on the P&lDs are not to be used to
! determine if a lock is required or what the locked position is." The valves at the
l inlet and outlet of the RHR seal coolers do not meet the criteria for being locked per
l LAP-240-1.
'
(f) The seal cooler inlet and outlet valves are not currently locked.
4
. _ . . . . _ _
(g) Tech Spec 4.7.1.1 is met by verifying all valves in the flowpath described in
LCO 3.7.1.1.b are either locked open or, in the case of the 1(2)E12-F068A/B
valves, closed and power available in the control room. Valves which are locked
open are 1(2)E12-F330A/B/C/D,1(2)E12-F332A/B/C/D, and 1(2)E12-F014A/B.
Procedure LOS-RH-M1 verifies that valve 1(2)E12-F068A/ Bis in its correct position
(closed) at least once per 31 days. The valves which isolate the seal coolers are
not locked. While these coolers support the operability of the RHR A and B pumps
for shutdown cooling, there is no requirement to lock valves to support this mode of
operation (either in the TS or per procedure.)
2. (a&b) The verification of the autostart of the VY cubicle coolers is done at LaSalle
as a Good Operating Practice to verify the fans are autostarting as designed. There
are no requirements to test this logic. Until recent revisions to LOS-RH-01, the
cubicle cooler fan associated with the 2A and 2B RHR service water pumps starting
signal were tested in the same fashion. During this revision, a change was made to
modify the required IST testing of the service water pumps. The revision became
necessary when the manualisolation gate valve on the outlet of the 2A RHRSW
pump was found damaged to the point that it could not be used to throttle flow
from the pump. This revision was required to allow IST testing of the pumps with
both pumps running. During this revision, the step verifying the operation of the VY
i cubicle coolers was inadvertently removed from the surveillance. This step will be
added to the next revision of the surveillance.
3. This flow rate was also changed during the revision to LOS-RH-01 described above.
During initial testing of the proposed IST testing process, the data was collected
within LST 95-105. This LST contained the statement regarding the 8000 gpm and
was mistakenly copied directly to the LOS-RH-01 instead of the correct value of
7400 gpm. This step will be corrected during the next revision to the surveillance.
I 4. (to all eight items) LOS RH-01 is currently in revision. The correct step number will
i be referenced in Revision 36 of the surveillance.
i
l 5. A copy of the 50.59 screening has been supplied.
Comment 7: Seismic Requirements for Common Suction
Inspector: Bob Stakenborghs Date: September 6,1996
i Per the LaSalle SER (Section 9.2) the originallicense was granted based on the CSCS
being " designed to Seismic Category I requirements." Contrary to this requirement, the
common suction line ORH01 AA-54"is listed as non-seismic in the piping line list. What is
the justification for this discrepancy?
Licensee response (9/18/96): The LaSalle FSAR states that all CSCS piping is designed to
Seismic Category I requirements. This inconsistency was identified as a result of recent
intake structure design reviews. As a result of these reviews, line ORH01 AA-54is in the
process of being upgraded to safety related. This upgrade was supported by analyzing the
,
8
!
l
r
. _ - _ -.
I
i
components, and did not require any modification to the piping. A safety evaluation was
completed to review this change. Documentation changes are stillin progress.
Comment 8: Preop Tests PT-VY-101 and PT-VY-102
Inspector: Patricia Lougheed Date: September 6,1996
l
1. The RHRSW and DGSW have a common return line. This could impact the flow to
the room coolers (because of the higher RHRSW flow rate). This interaction was
not tested during the preop. Was it ever tested? (Please provide test if it was).
2. The acceptance criteria for all the pumps were revised on the test data sheet.
Please provide the justification for these changes.
3. Was the FSAR value of 5 ft/sec in the 54" bypass line ever verified? If so, where?
4. Was manual valve E12-F300 ever tested? If so, where?
5. Please provide copies of the preop-verified pump curves.
License response (9/16/96): :
1. The potential back pressure effect of the RHRSW flow on the room cooler flow was
never tested in the Preops. However the flow data that was obtained in the special
tests referred to in A5 below was gathered with the RHRSW in operation.
Additionally, analyses have been recently performed using room cooler flow data
that was gathered during LSTs96-042,96-043 and 96-044 (July 1996) which
address, among other factors, the impact on cooler flows as a result of having
RHRSW in operation. The conclusion of this analysis was that acceptable flows are
being provided to the room coolers.
2. The acceptance data in the Preop originally did not include allowance for the I
backwash flow of the strainers. The revision to the data sheets was made to l
account for this backwash flow. The test evaluation write-up for the pump tests :
did include an explanation of this revision.
3. The 5 ft/sec value was not verified in the Preop. This line is a parallel path to the
normal water supply path and is not instrumented for flow. The 5 ft/sec value is
the approximate calculated velocity in the bypass line in the unlikely event of total
blockage of the traveling screens, thus preventing any flow through the normal flow
path, combined with a demand for only the maximum CSCS flow.
4. The valve is tested each Unit 1 refuel cycle under LTS-600-23,"CSCS Cooling
Water Screen Bypass Supply Line Inspection."
l S. The flow rates to the room coolers were verifieo in a one time special test on both
l units following the Preop. Unit 1 was performed under LST-81-74 and Unit 2 under
I LST-83-128. Copies of the special tests are available. Additionally, as discussed
l
l 9
. - - ._.____._______.____..___.-.___.___.~._m __
r .;
L
I- above, testing and calculations have been performed recently where the flows to
the room coolers were shown to be acceptable.
t
6. New pump curves were not generated during the Preop test on this system. The
. Preop test collected pump data that was used to verify the pumps were operating 1
on the vendor curves, which was included in engineering review of the test report.
The certified vendor pump curves were in the information previously provided to the
.
,
L NRC (Item #2). i
. Comment 9: RHR Heat Exchanger Duty Requirements .
Inspector: Bob Staker;borghs Date: September 6,1996 -
Please resolve the following discrepancies:
1 Per the UFSAR, Figure 5.4-5, the maximum RHR heat transfer requirement is
155 x 10' BTU /hr. Contrary to this, the heat exchanger test acceptance criteria is
122 x 108 BTU /hr.
2. Per Figure 5.4-5, the 1.55 x 108 BUT/hr requirement was based on 7450 gpm RHR
flow. The heat exchanger data sheet design condition of 170 x 108 BTU /hr was
based on 8400 gpm.
3. Per Figure 6.2-7, the maximum pool temperature is 187 F. This temperature is
used in several cales associated with the heat exchanger testing. Per Tables 6.2-5 - j
and 6.2-4, the peak pool temperature is 200oF. Which temperature should be used
'
for the RHR heat exchanger?
! Licensee response (9/18/96): 4
1. In surveillance procedure LTS-200-17,"RHR Heat Exchanger Capacity Test," the )
effectiveness of the heat exchanger is determined from the test data. This ;
effectiveness is then utilized in conjunction with a suppression pool temperature of
~
j
187oF, and a maximum service water temperature of 100 F to determine the heat
removal capability under these conditions. An effectiveness of 0.379 is required to
~
- meet the acceptance criteria of 122E6 BTU /HR. An effectiveness of 0.374 is
required to meet the conditions in UFSAR Figure 5.4-5, Mode B. It should be noted
that the peak suppression pool temperature of 212 Fin this table is not the peak
temperature calculated for LaSalle (see NRC Comment #10), in GE Report
EAS-083-1188, dated Novamber 1988, GE utilized an RHR heat exchanger K of
385 BTU /sec- F, which corresponds to an effectiveness of 0.372 and an RHR flow
of 3,725,000lbm/hr (7400 gpm). Therefore, the effectiveness of 0.379 required to
meet the' acceptance criteria in LTS-200-17 exceeds the effectiveness required to
meet the values in the analysis of record.
p
! 2. The heat exchanger data sheet that uses 8400 gpm of RHR flow and results in
i 170E6 BTU /hr heat removal describes a hypothetical design case for the
! containment cooling mode of operation with a 212 F suppression pool temperature
!
- 10
i
i, !
I
. . _ - . . ._~_ . . , . _,. ,-. -- # - ,, . ,, , - . - , _ _m _
, _ . _ _ _ . ~. .-- _ _ . . . _ _ . _ _ . - . _ _ . . . _ _ _ . . _ _ _ > _ . _ _ . _
h
and no allowance for tube plugging. The design case for the RHR heat exchangers
was shutdown cooling with a 5% allowance for tube plugging and an RHR mass
, flow rate of 3,725,000lbm/hr (7400 gpm), which results in a 0.374 effectiveness. !
l As discussed above, a RHR flow of 3,725,000lbm/hr and a 0.372 effectiveness
were used in the GE analysis. ;
3. In discussion with the reviewer, it was concluded that the response to j
Comment #10 would address this issue. :
r
Comment 10: Suppression Pool Maximum Temperature i
inspector: Bob Stakenborghs Date: September 6,1996 ,
P
Calculation 3C7-0181-003apparently either established or confirmed the maximum i
suppression pool temperature to be 187 F. The UFSAR states that this temperature is *
i based on a number of initial conditions, one of which is " Technical specification maximum
! pool temperature." Contrary to this, calc. 3C7-0181-003 was performed at an initial pool
-
!
temperature of 100 F versus the allowed 105 F (Tech Spec limit). In fact, a revision to -
the calculation was performed in 1992 which corrected a number of non-conservative
initial conditions, including pool initial temperature, and calculated a maximum temperature
!
of 199 F. Also, calc 3C7-0181-003does not appear to use as-built RHR heat exchanger !
data for effectiveness. Provide an operability assessment as well as a no-unreviewed ]
safety question determination for this issue.
l
Licensee response (9/20/96):
Calculation 3C7-0181-003,Rev. O, was prepared by S&L in parallel with GE calculations
during the original plant licensing effort in 1981. Both calculations were based on a 100 F
initial pool temperature, which was the Tech Spec limit at the time. The GE calculations
l were ultimately used as the design basis calculations.
In July 1989, LaSalle requested and received Tech Spec changes (Amendment Nos. 67
and 49 to Facility Operating License Nos. NPF-11 and NPF-18, respectively) increasing the
maximum pool temperature to 105 F. GE Report No. EAS-49-0888 was submitted with
j the Tech Spec change request and provided the technical support for the proposed change.
!- This report was reviewed by the NRC as documented in the SER supporting the
g aforementioned Amendments to the Facility Operating Licenses. GE later provided
l additional supporting analysis to LaSalle in Report EAS-083-1188, dated November 1988. ,
it was concluded by GE in EAS-083-1188 and clarified in their letter EBO-90-102 that the 1'
! post-accident maximum suppression pool bulk temperature would be less that 192oF with
l~ an initial maximum pool temperature to 105 F (an increase above 187 F for the initial pool
L temperature of 100 F) for the Design Basis Accident. It was observed in this review that
the UFSAR was not updated to reflect tho increase in the maximum pool temperature to
105 F. The UFSAR will be updated to mflect this change.
Bechtel issued Problem Investigation Report (PIR) No. SF-N-88-01 Rev. O, dated December
j ' 1988, for an issue that was discovered at Limerick Unit No. 2 concerning the effect of
'
water holdup during a LOCA on suppression pool temperature. According to this PIR,
i
1 11
- __ _ .- .- - .- - .-
. - . . - . - -. . - - --
Philadelphia Electric Company sent a message on this concern over the INPO Nuclear
Network. Also, Bechtel later issued PIR No. G-89-03-NO, Rev. O, in April 1989 to alert
other BWR projects that there may be a potential concern if lower than design water level
in the suppression poolis discovered following an analyzed accident.
Action was initiated by LaSalle after receipt of the previously mentioned PIRs in 1989 and
this action to address the issues identified in the PIRs continued into early 1993.
Specifically in May of 1992, Calculation 3C7-0181-003,R1, was prepared to address the
effects of water holdup during a LOCA on suppression pool temperature. This calculation
was not prepared to support any changes in the licensing basis of the LaSalle Station. This
calculation revision was performed with updated design input data, including the increased
initial pool temperature. The calculated maximum pool temperatures are provided on page
C3 of this calculation for all analyzed transient cases. However, for cases 3 and 3A which
show post-accident maximum pool bulk temperatures above 192oF, the results should
have been noted as not applicable, since cases 3 and 3A involve an MSIV closure (non-
LOCA) that would not lead to a water holdup issue. Thus the post-accident maximum I
suppression pool bulk temperatures provided in Calculation 3C7-0181-003 R1 were
consistent (i.e., less than 192 F) with the results provided in the GE analyses previously
mentioned.
In response to the observation that Calculation 3C7-0181-003 R1 did not appear to use as- l
built RHR heat exchanger design data for the effectiveness, it is noted that RHR heat l
l exchanger data from GE's " Finalized LaSalle Lorig Term Pool Temperature Assessments- i
I
Mark 11 Task C.11" was utilized. Our review of this data indicates that it is consistent with
the as-built heat exchanger design data per the vendor data sheets.
As the change in the maximum allowable initial suppression pool temperature was
,
previously evaluated as part of a formally submitted and approved Tech Spec change, no
l operability assessment is required at this time.
Comment 11: Suppression Pool Initial Temperature
Inspector: Bob Stakenborghs Date: September 16,1996
UFSAR Table 6.2-22 states that the initial suppression pool temperature is 100 F.
Contrary to this, the Technical Specification suppression poolis allowed to go to 105 F.
What is the effect of the increased pool temperature on the hydrogen concentration
analysis (the subject of Table 6.2-22)?
Licensee response (9/23/96): As was discussed in response to Comment #10,in the
1988/89 time frame, LaSalle requested and received Tech Spec changes increasing the
maximum initial suppression pool temperature from 100 to 105 F. The UFSAR was not
updated to totally reflect this change. Table 6.2-2 of the UFSAR should have been
updated to reflect the change to 105 F.
! To address the specific impact of the change in initial suppression pool temperature on the
UFSAR (Section 6.2.5.3) hydrogen concentration analysis, the following is provided.
12
l
l
.. - . . . . .. .
l
l
l
Short Term Hvdroaen Generation: For the short term, hydrogen generation is due to the
metal-water reaction. The LaSalle analysis assumed a 0.77% metal-water reaction, which
corresponds to the maximum allowable value based on ECCS-LOCA acceptance criteria.
This value is assumed to be five times greater than the amount calculated in accordance l
with 10 CFR 50.46, as discussed in the UFSAR. As such, the short term hydrogen l
generation with a 105 Finitial pool temperature is bounded by the values provided in the
UFSAR. 1
Lona Term Hvdroaen Generation: For the long term, hydrogen generation comes from i
radiolysis of the pool water. The impact of long-term hydrogen generation is negligible, as !
long as there is no boiling. As was discussed in the response to Comment #10, the
maximum calculated suppression pool temperature was 192 F, considering an initial
suppression pool temperature of 105 F. Therefore, no boiling will occur and the long-term
hydrogen generation values in the UFSAR are applicable for an initial pool temperature of
105*F.
Therefore, the increase in the maximum initial suppression pool temperature to 105oF did
not cause a change in the hydrogen concentration analysis provided in the UFSAR. UFSAR
Table 6.2-22 will be revised to correctly show the initial suppression pool temperature as
105 F.
Comment 12: Non-conservative Assumptions in Calculation
Inspector: Bob Stakenborghs Date: September 16,1996
l
Calculation VY-13 established a room temperature of 119oF assuming a loss of the cooling
i fan. This calculation used heat loads which appear non-conservative when compared to
the calculation that established the cooling load (VY-5). Specifically, the piping
temperature is assumed to be 100 F in VY-13 las compared tol 182 F in VY-5. Also,
what equipment is instalied in the Unit 2 RHRSW "C" pump room? i
l
Licensee response (9/19/96h There is no high temperature piping in the RHR Service l
Water Pump 1 A and 1B Room or the RHR Service Water Pump 2A and 2B Room which l
were evaluated in calculation VY-5. These rooms contain the pump suction and discharge l
piping and the strainers. The RHR heat exchangers are in different rooms. The piping
temperature of 182 F used is extremely conservative compared to the maximum UHS
temperature of 100 F.
Calculation VY-13 verified that the temperature in the RHR Service Water 2A and 2B Room
would not exceed the design temperature of 122 F, assuming that supply and exhaust
fans 2VYOSC and 2VYO7C were not operating. The use of a 100oF piping fluid
temperature in this calculation was appropriate because it the maximum UHS temperature, ,
even though it is less conservative than the 182 F value used in calculation VY-5. I
The room referred to as the Unit 2 RHR Service Water Pump Room "C" in calculation
VY-13 is the room that contains the RHR Service Water 2A and 2B Pumps and Fuel Pool
,
Make-Up Pump 2A. The nomenclature "RHR Service Water Pump Room C" is reflected on
HVAC flow diagram M-1465.
13
. __ _ _ ._ ._ _ .- . _ _. . . _.
Comment 13: Seismic Evaluation of 54" Buried Bypass Piping
'
inspector: Bob Stakenborghs Date: September 17,1996
Calculation L-000556 was performed to qualify the 54-inch bypass for seismic
! considerations. Based on a review of the methodology in the UFSAR for buried piping, the
! following questions arise:
l 1. The calculation did not consider Rayleigh waves. Why?
i
l 2. The calculation did not consider any bend stresses or penetration stresses. _ This 1
omission was based on an assumption that may not be conservative or acceptable i
l in the UFSAR methodology.
l
3. The calculation did not account for corrosion thickness in the pipe wall. Also, is l
l there any verification of the actual material properties or existing piping wall I
thickness (other than that provided in piping design table 0021S?)
Licensee response (9/23/96):
1. The strains and stresses in a buried structure due to traveling wave effects are
!
directly related to the ground acceleration and velocity caused by the particular
j wave type. Because the ground accelerations associated with Rayleigh type of l
! surface waves are quite small as compared to ground acceleration caused by shear l
l and compression waves, the strains and stresses in the buried pipeline due to the
! shear waves are much larger than those caused by the Rayleigh waves. Hence,
Rayleigh waves are not considered in the solution. The calculation shows that the
seismic induced strains and stresses due to soil overburden are very small as
compared to the allowable stress.
l 2. The buried bypass pipe is very close (6'-3") to the screen house structure. Also,
the valve pit is rigidly attached to the lake screen house. Due to this closeness and
rigidity of the structure, the soil around the structure and the pipe buried in it will
l move with the structure during the earthquake and there will be very little or no
l relative motion between the elements. Therefore, there will be no significant effect
i on the bending stresses or the penetration stresses due to traveling seismic wave
, effect.
!
l 3. The corrosion allowance is typically applied to calculate the minimum wall thickness
for pressure loading per ASME Section Ill, Subsection NC/ND-3640. After this
l
minimum wall has been established, all other evaluations per NC/ND-3650 are
'
based on nominal wall thickness. Even if a reduction of nominal wallis included,
the resultant stresses are well below allowable. In this specific case of buried pipe
subjected to earthquake induced shear waves, the pipe stresses are strain induced
and are independent of wall thickness.
I
14
. . ._ _ . ~ . _ _ _ . _ _ - - . - _ _ _ . . _ __ _
Comment 14: Potential Unreviewed System Interaction
Inspector: Bob Stakenborghs Date: September 17,1996
Per P&lD M-87, the cubicle coolers are fed from the diesel generator cooling pumps and
return to a common discharge with RHRSW. No integrated testing or calculations were
performed to verify the cubicle cooler flow is maintained when the RHRSW pumps are
running, since the pumps are basically of identical size. This interaction was not preop
tested either. What is the basis for concluding that this interaction will not result in
degraded flow to the cubicle coolers?
l Licensee response (9/27/96): There are a total of three discharge lines from the station for
the CSCS piping, one line per Division which is common for Units 1 and 2. For each
Division, the RHR SW pump flows combine with the Diesel Generator Cooling Water pump
flows. Therefore, the operation of the RHRSW pumps will reduce the flow through the
individual cubicle coolers, associated with the same Division, due to the increase in the
backpressure in the discharge line.
The effect of the added backpressure due to the operation of the RHR pumps,Ns been
determined to be acceptable for all of the affected cubicle coolers. For the Division 1
cubicle coolers 1VYO1 A,1VYO4A,2VYO1 A, and 2VYO4A and the Unit 1 and 2 LPCS
,
pump motor coolers, the acceptability was demonstrated through testing performed during
July 1996 in a configuration where all of the Division 1 RHRSW pumps were operating.
'
This testing and analysis confirmed the flows through the individual cubicle coolers to be ;
acceptable. The operation of the Division 1 RHRSW pumps was confirmed by the station !
logs as well as through discussion with personnel who witnessed the test.
1
With respect to Division 2 and 3, testing was performed during July 1996 and analysis I
concluded the flows through the affected coolers to be acceptable. It should be noted for l
Division 2, the operation of the RHRSW pumps were accounted for analytically.
Comment 15: Flooding Calculation inconsistencies
Inspector: Bob Stakenborghs Date: September 17,1996
Calculations S-8, S-9, and S-30 establish flood levels in RHRSW pump rooms due to line
breaks. The calculations are inconsistent as follows: Calc S-8 uses a K of 1.5 to calculate
break flow and reduces the room area by 15% to account for equipment. Calcs S-9 and i
S-30 use a K of 1.0 to calculate break flow. They use a 10% area reduction. In either l
! case, the area reduction didn't seem to be related to the size of the room or the amount of
equipment in the room. Also, S-30 credits floor drains to limit flood height, is there a
standard methodology for flooding analysis? Are the floor drains safety-related so that
they can be credited in the analysis?
Licensee response (9/3/96): In early 1995, concerns were raised regarding certain flood
protection features for internal gravity-fed flooding from the cooling lake. These issues
included the flood doors between the CSCS pump rooms not being adequate in both
directions and various service water and circulating water piping not being contained
15
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. . _ _
-. -. -- _._ . . - .
within flood protected barriers. Calculations S-8, S-9, and S-30 were prepared to address
portions of the corrective actions associated with these flooding related issues.
Calculation S-8 was performed to determine the fill rate for the Unit 1 Division 1 and 3
CSCS pump rooms and to determine if sufficient time was available for operators to
l respond to a pipe leak so that operators need not be posted in these rooms until the
temporary door fixes (adding dogs) were installed. For conservatism, it was later decided
to continuously post operators in these rooms until the temporary door fixes were installed.
Calculations S-9 and S-30 were prepared to determined the time available for station
actions to occur if pipe cracks were to occur in various service water and circulating water
piping that is not contained in flood protected barriers. Other calculations and analyses
were performed that concluded that either the crack exclusion criteria has ';een met
(therefore, ro pipe cracks need be postulated) or the piping is small (3" t@S or smaller)
and is isolable from the source of flood water. In an attempt to quantify the postulated
event, even though pipe cracks need not be postulated, an assessment of the time
available to allow station actions to occur was performed.
The methodology used in calculations S-8, S-9 and S-30 to determine the area and K
values is acceptable based upon the following:
1. For the cases cited in calculations S-8, S-9 and S-30, floor areas were based upon
design drawings with direct reduction for blocked areas. To account for smallitems
such as piping and transient items within the room, a percentage was subtracted.
There is no " standard" percentage for this accounting, but it has generally been
found that once identifiable blockage is removed from the floodable floor area,10%
- is sufficient to account for other small and transient items. The 15% value was
used for calculation S-8, since the CSCS pump room was more congested than the
turbine building basement (calculations S-9 and S-30), which has large walkways ,
with minor equipment.
2. A loss coefficient, K, is required to determine the break flow rate for a moderate ,
energy crack of % diameter in length and % wall thickness in width. As a l
! minimum, the loss is 1.0 for the exit from a crack. Considerirg the crack as a I
rough edged pipe crack rather than a smooth edged ncz:!c inl6t provides l
l justification for an inlet loss of 0.5, giving a total K of 1.5. Thus, while a K of 1.0 l
is conservative, in light of the subjective nature of the specification of the crack, an I
overallioss coefficient of 1.5 is considered to be justified.
1
Treatment of floor drains in flooding analyses is addressed in ANSI-ANS-56.11-1988, l
" Design Criteria for Protection Against the Effects of Flooding in Light Water Reactor
Plants." The floor drain piping is classified as non-safety-related, but they are considered
available paths for water removal. The ANSI document provides guidance as to the )
availability of the floor drains, and notes that the drains can be assumed to be open if l
design provisions, engineering evaluations, and appropriate tests and inspections document
that the drain would not plug. This guidance, combined with the fact that the intent of
calculation S-30 was only to quantify a postulated event and was not intended to provide
,
,
16
i
design basis flood protection information, allowed the conclusion that the availability of the
floor drains was appropriate.
Comment 16: Effect of Suppression Pool Temperature on RHR Flow
inspector: Bob Stakenborghs Date: September 18,1996
Additional review of calc 3C7-0181-003 and response to previous Comment #9 indicates
that the max suppression pool temperature was calculated assuming a constant RHR flow
of 1036 lbm/sec which is based on 7,450 gpm @ 62.4 lbm/ft. However, the actual
volumetric flow of 74,50 gpm is constant but the density changes as RHR temperature
goes up. This density change decreases the mass flow by 4%, which results in a 4%
increase in pool temperature for the same heat removal (~4oF).
Licensee response (9/23/96): Calculation 3C7-0181-003 assumed a constant value for the
mass flow to calculate the heat exchanger performance. The comment suggests that the
volumetric flow rate will be constant, and that as the temperature goes up, the density will
go down, resulting in reduced mass flow, and thus reduced heat transfer.
The constant mass flow assumption is a simplifying assumption that is common in heat
exchanger performance analyses. Because heat exchanger performance is not particularly
sensitive to minor flow changes, this assumption does not introduce significant
inaccuracies to the analyses. The calculation states the heat exchanger flow in terms of
mass flow only. The volumetric flow (in gpm)is not identified in the calcuiation, but the
numbers are consistent with the design flow rate of 7450 gpm converted to mass flow
using standard water density (i.e., [62.4 lom/ft at a water temperature of) 60 F). This
conversion is consistent with the methodology used in the heat exchanger manufacturer
data sheets. Although it would have been more conservative to base the mass flow
conversion on the lowest density within the temperature range, it should be noted that
using the lower density introduces conservatisms which were not considered in the
calculation. These are explained below.
Although pumps are considered constant volume devices, this does not mean that the flow
rate will remain constant as the density changes. There are numerous factors that affect
how a pump will perform in response to system parameter changes. As the temperature
goes up, the density goes down, the viscosity goes down, and the effect of piping friction
goes down, all of which make it easier for the pump to move fluid through the system. A
review of the viscosity and friction coefficient variations associated with the temperature l
range in question (60 to 192 F) shows that, for the expected fluid velocities, these 1
l factors will more than offset the density change, so that the mass flow will actually show
l
a slight increase as the fluid temperature increases. In this particular case, the fluid i
viscosity at 60 F is 1.12 centistokes, and at 192 F,it is 0.33 centistokes, which causes I
the Reynolds number to increase by 240%. For smooth pipes, this 1sults in the piping
friction factor reducing from 0.0113 to 0.0093 (for 18" pipe) and . 4119 to 0.0096 (for :
24" pipe), which will reduce overall system resistance by approximately 18%. When this l
reduced system resistance is applied to the RHR pump performance curve, the flow rate is l
estimated to increase by approximately 3.9%. Since the density decreases by 3.4% (from I
<
17
!
l
62.4 lbm/ft at 60 F to 60.34 lbm/ft at 192 F), the increase in volumetric flow rate will
slightly increase the mass flow rate through the RHR heat exchanger.
In response to the comments suggestion that a 4% decrease in mass flow rate will result
in a 4% increase in pool temperature, it should be noted that the relationship between
mass flow rate and heat exchanger performance is usually not linear. Based on typical
heat exchanger performance characteristics, a given change in the mass flow rate will
result in a smaller change (typically less than half) in the heat transfer performance of the
heat exchanger.
Based on the above assessment, the use of the mass flow rate at 60oF does not introduce
overall nonconservatisms in the calculated results.
Comment 17: HPCS Room Tempefature
Inspector: Bob Stakenborghs Date: September 18,1996
A review of calcs VY-4 and 3C7-089-001 indicates that neither calculation included piping
heat loads. Presumably, this was due to the fact that HPCS is aligned to the CST.
However, there are modes of operation where HPCS can be aligned to the suppression
pool. Should these calculations include a heat load to account for this possibility?
Licensee response (9/23/96): Calculation VY-4 was the original design calculation that
was used for system design and equipment procurement. VY-4 concluded that the room
would experience a heat gain of approximately 530,000 BTU /hr. This value was
developed utilizing somewhat conservative assumptions regarding such things as pump
motor efficiencies, it, however, did not explicitly include heat loads from hot piping.
Performance testing and verification of the actual expected cubicle heat loads was
performed in 1983. This testing concluded that the VY-4 calculated values were quite
conservative. The actual expected heat input would be =289,000 BTU /hr, compared to
the design value calculated in VY-4 of 530,000 BTU /hr. It is recognized that the test did
not include heat input from the piping, which was difficult to simulate.
The potential heat rejection from a 200oF piping surface temperature from the 24" inlet
and 16" outlet piping into a room at 150 F (post accident maximum temperature) is less
than 50,000 BTU /hr, based on 32 feet of inlet and 24 feet of outlet piping. This load is
only a small portion of the margin that exists between the VY-4 calculated design loads
and the measured test ioads.
Calculation 3C7-089-001 used a maximum heat load of 521,000 BTU /hr. This value was l
based on the VY-4 calculated design values and excluding the room cooler fan heat. Thus '
the heat loads used in this calculation may be considered quite conservative.
Based on the above, it is concluded that even though Calculations VY-4 and 3C7-089-001
did not explicitly include piping heat losses, the calculations included substantial heat load
margins. This margin was more than sufficient to account for any piping losses that would
exist, and thus, the results of these calculations remain appropriately conservative.
18
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l Comment 18: ESF Bus Loading
i
l Inspector: Babu R. Gupta Date: September 18,1996
L
Clarification is needed as follows:
1. Calculation 19AK19, Rev. 2, has not included RHRSW pumps 1E12-C003A and B in
kW,n load for Unit 1 ESS-1.
l 2. FSAR Table 8.3-1 (Sheet 2 of 3), Rev. 9, has the following conflicts with Calc
19AK19-
i (a) Unit 2, ESS-2 load as per calc (page 14)is 2726kW, while FSAR shows it as
l 2652kW.
1 (b) FSAR identifies kW as " Total motor input kW," even though kW,, includes
'
non-motor loads.
Licensee response (9/27/96):
l 1. The RHR Service Water Pump loads (i.e., kW,n) are not included in the tabulation for
i the D/G loading in calculation 4266/19AK19, Rev. 2, for the following reason: The
RHR Service Water Pumps are manually added loads. These loads are not required
immediately after a LOCA. Service water pumps 1E12-C300A and B are manually
i connected to the bus / Diesel Generator (DG) when they are needed. The "O" DG
has sufficient margin within its continuous rating (i.e.,2600 kW) to support the
,
total kW,n identified in Calculation 19AK19, Rev. 2, plus the RHR Service Water
l Pumps (Estimated total = 2304 + 280 = 2584 kW).
Note: Nuclear Tracking System (NTS) Item No. 373-160-96-00025previously
identified a discrepancy in the UFSAR concerning the automatic start versus manual
start of the RHR Service Water Pumps. The investigation of this item willinclude a 4
review of UFSAR Table 8.3-1 and Calculation 4266/19AK19.
2. (a) As indicated above, a review of the discrepancy between Calculation !
,
4266/19AK19 and UFSAR Table 8.3-1 was previously identified and is l
l underway. Manually added loads, which are added under administrative l
control (Reference Station Procedures LOA-AP-101/201), are included in 1
both of the totals (i.e.,2726kW and 2652kW). Both totals are well within
the 2000 hour0.0231 days <br />0.556 hours <br />0.00331 weeks <br />7.61e-4 months <br /> rating (i.e.,2860) of the EDG.
l
(b) UFSAR Table 8.31 [does) identify the input kW as " Total Motor input kW;" l
however, it does include both non-motor and motor loads. l
l
19 l
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_ _ mm _m_. . - . _ . - _ - _ _ . , . _ _ _ . _ _ _ _ _ _ _ _ _ _ _ _ _______
Comment 19: Hot Shutdown of Units 1 and 2
Inspector: Babu R. Gupta Date: September 18,1996
Calculation 19Al3, Rev. O, shows the following details: EXH 1 A shows shutdown of
Units 1 and 2 by ESS-1; EXH 1B shows shutdown of Units 1 and 2 by ESS-2: EXH 1C
shows shutdown of Units 1 and 2 by ESS-2 HVAC (additional to EXH 18). While loads are
very much similar in EXH 1 A and EXH 1B, HVAC loads are shown only for ESS-2 and not
for ESS-1. Clarification is requested.
!
Licensee response (9/3/96): Calculation 4266/19Al3 was prepared as part of a study for
the "NUMARC Station Blackout Initiatives Survey" to verify the hot shutdown loading of
the Diesel Generators. The Station Blackout (SBO) submittal does not postulate shutting
down with just the Division 1 Diesel Generator (DG-0) being available. The SBO analysis .;
t does show that the Units can be safely shutdown with the Division 1 and 2 diesel l
. generators unavailable with the loss of the ventilation system for the Main Control Room
(MCR) and Auxiliary Electric Equipment Room (AEER).
The HVAC system loads for the MCR and the AEER are supplied from the Unit 1 and
Unit 2 Division 2 ESF buses (i.e., the redundant trains are fed from different units) and
these systems will not be available if the Division 1 Diesel Generator (DG-0) is the only
source of AC power. Hence, Exhibit 1 A of calculation 4266/19Al3 does not list the MCR
Comment 20: Potential for RHRSW Water Hammer
Inspector: Bob Stakenborghs Date: September 18,1996
Since the RHR heat exchanger is located in the vertical orientation, the tops of the tubes -
would be greater than 32 ft above the low lake level of 690 ft. Thus, the possibility exists
for voiding the tubes in this condition. (Top of tubes at approximately el 730', based on
quick review of drawings.) Also, the RHR heat exchanger is normally aligned in the LPCI
flow path. This means that the fluid in the tubes would be exposed to " hot" suppression
pool fluid with the tubeside at a very low pressure or voided condition. This will result in
- tubeside steam condition due to the low saturation temperature of RHRSW in this
condition. (Approx. the entire length of tubes could be steam filled at a temperature of
. 140 with the lake at normal 700' level.) Either of these conditions could lead to a
damaging water hammer event when RHRSW is manually started following a DBA. This
event is similar to the Containment Air Cooler scenario for PWRs.
,
Licensee response (9/27/96): The physical configuration of the RHR heat exchangers is
. such that the top of the U-tube bundle represents a high point in the system located
approximately 31 feet above the normallake level. During RHRSW operation, the pumps
,
pressurize the piping and heat exchanger tubes against backpressure created by an orifice
L located in the discharge piping. The backpressure keeps the tubes completely filled with
j water while the pumps are running. When the system is to be shut down, the operating
1' procedure requires that the motor-operated heat exchanger discharge valve (the "68
i valve") is started closed first, and the pumps are shutdown one at a time, the first at 4000
i
i 20
I
o
I . ._. . ~
l
I
!
[ gpm and the second after the 68 valve is completely closed. This methodology ensures
l that the siphon is not broken, and the heat exchanger tubes remain completely filled with
water. Station personnel have observed that the system remains pressurized for a period
of time after the pumps are shut down, indicating that the pump discharge check valves
and the 68 valve in each train form a substantially tight pressure boundary. I
The top of the heat exchanger tube bundle is located approximately 31 feet above normal
l lake level on the inlet side, and approximately 30 feet above the outf all level on the
.
I
discharge side. This results in a equilibrium pressure of approximately 1.3 psia at the top !
of the highest tubes of the bundle. The tops of the lowest tubes in the bundle are
approximately 3.5 feet lower, with a corresponding pressure of approximately 2.8 psia.
l
The above tube-side pressures correspond to a saturated temperature range of
approximately 110 F to 139 F. When the system is in this standby mode, the tubes will
remain " solid" as long as the fluid temperature remains below these values. Since the j
normal ambient conditions in the areas where the RHRSW pipes are located are below l
l these temperatures, the tubes remain solid. If the lake level drops to 690', voids would I
l form at any temperature. The size of these voids would depend on the amount of valve l
'
leakage.
When the RHR system is started normally for shutdown cooling or pool cooling, the
operating procedures require that the RHRSW system be started first to ensure that cooling 1
water is available when the hot fluid first begins flowing in the RHR heat exchanger shell.
I Since the RHRSW system is started first, the temperature in the tubes always remains
below saturation, the tubes remain solid, and the system pressurizes without incident.
l l
The procedure for starting the RHRSW pumps calls for the 68 valve to be started open l
first. The operator then waits 5 to 6 seconds after dualindication is received on the i
l position indicating lights before starting the first RHRSW pump. Typical dP test trace data !
shows that dual indication occurs almost immediately (0.5 seconds) after the valve switch
is operated. An additional 2.5 seconds is required before the disc begins to move due the
geometry of the stem / disc connection, and at least 3 more seconds elapses before there is i
any increase in vibration, indicating the presence of flow. The rnotor-operator on the 68 l
valve typically takes about 115 seconds to fully open this 20" gate valve, making the disc
travel rate slightly more than %" per second. As the valve continues to open, the system
flow increases. When the flow reaches 4000 gpm, the operator may start the second
RHRSW pump.
A potential concern has been identified when the RHR system operates in response to a l
LOCA. In this case, the RHR system automatically starts in the injection mode, and the
,
suppression pool water passes through the open heat exchanger shell-side isolation valves
!
as well as the heat exchanger bypass valve. The suppression pool temperature is initially
l below the maximum allowable normal temperature of 105 F, but it immediately begins to
l rise in response to RCPB blowdown. The RHRSW pumps do not start automatically, but
'
rather the emergency operating procedures require that these pumps be started manually
within the first 10 minutes of the accident. During that time the temperature of the pool
water flowing in the shell could go as high as 170 F, which is well above the saturation
temperatures for the equilibrium pressures, causing the stationary RHRSW in the tubes to
21
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l
" boil" and form voids. These voids would collapse as soon as the RHR pumps started and
increased the pressure in the tubes above the saturation point. The collapsing of these
voids would form pressure waves in the tubes that could result in water hammer as they
propagate through the system.
Action Plan: Based upon our preliminary assessments, the postulated event, although
unlikely, could potentially occur under certain scenarios. As a conservative measure, the
units have been shut down. We are currently investigating the issue to ensure operability
prior to restart for each unit.
Comment 21: Velocity Through Tubes in VY Coolers
Inspector: Patricia Lougheed Date: September 19,1996
Results from dP flow tests for the VY coolers are showing flow rates considerably above
their design flow. This is especially true for the 4A coolers on both units, which are seeing
flow rates almost double the design (actually over double for Unit 1). What is the vendor's
recommended maximum velocity for the tubes? Have you evaluated the effect of these
greater-than-design flows on maximum tube life?
Licensee response (9/23/96): The vendor recommends that the tube velocities not exceed
12 feet per second (fps). A calculation was performed specifically to address the higher
flow rates that were measured during surveillance testing in 1993. The calculation
concludes that the maximum tube velocity in any of the tested coolers was 9.9 fps.
Specifically, the 1/2VYO4A coolers with a measured maximum flow of 482 gpm had a
tube velocity of 4.4 feet per second, well below the vendors recommended 12 fps.
Comment 22: U2 RHRSW and HPCS Interaction
Inspector: Bob Stakenborghs Date: September 19,1996
The Unit 2 RHRSW Pump A/B Cubicle Ventilation system is supplied with outside air from
a common intake with the HPCS diesel. Does this violate the separation criteria for
divisions since a single failure (such as blockage) could inop both HPCS and RHR A/B?
Licensee response (9/27/96): The design configuration for the Unit 2 Diesel Generator
Building does include a single missile protected air supply structure for both the Division 1
(RHR A/B) and 3 (HPCS) engineered safety feature ventilation systems (ESFVS). This ;
single inlet has an air filter to provide airborne particulate material control, and a differential '
pressure switch to monitor loading of the filter media over time. An alarm is initiated prior
to filter plugging reaching the point that would impair proper operation of the diesel or its
associated ventilation systems and CSCS pumps. Supply and return fans for each division
ESFVS are located in separate equipment rooms in the HPCS ventilation penthouse. Based
on Division 1 system design, there are no automatically initiated components installed in
Unit 2 (single common diesel is installed in Unit 1 Diesel Generator Building).
The common filter configuration is evaluated for acceptability in the following two ways:
I
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_ _ _ . _ _ _ .. - . . _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . _ _ _ _ _ _ _ _ _ . _ _ _
l
1
1
1. Division 2 (RHR C/D) provides the redundant safety functions of the Division 1
equipment. The Division 3 equipment does not specifically provide redundant ;
functions for either the Division 1'or 2 RHR trains, due to its primary design purpose J
of providing core cooling at high pressure, nor does either RHR division provide 1
redundant high pressure operating modes for Division 3 functions. Therefore, I
failure of the Division 1 ESFVS due to plugging of the inlet filters would not impact
any redundant station equipment.
The designed divisional separation' can also be demonstrated from a safe shutdown l
perspective. Both the Division 1 and 3 components are utilized for the basic safe ;
shutdown method, as indicated in safe shutdown report (UFSAR, Appendix H) Table !
,
H.4-90, which correctly identifies the presence of both the Division 1 and 3 ESFVS l
l supply and return fans in the same fire zone (8A1). Division 2 components are !
l. utilized for the alternate shutdown method. ,
l
1
2. The air intake filter is a passive component, and there are no active components -
contained in the common air path to the Division 1 and 3 ESFVS. Passive
I _ component failure is not specifically discussed in Standard Review Plan 9.4.5,
" Engineered Safety Feature Ventilation Systems." However, the licensing basis for -
LaSalle (UFSAR Table 9.4-16) does consider the gradual increase in the inlet filter
differential pressure to a point above the alarm setpoint as a potential failure mode
for this HVAC system. This is consistent with guidance in ANS 58.9-1981 that
passive failure of the ESFVS can be assumed to occur 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> following an
- initiating event (long term failure.)
l
Detection of filter fouling from the local alarm initiates a WR for filter
removal / replacement, which could be performed with the ESFVS in operation, if
necessary (separate downstream filter is in place for diesel combustion air and long
term dust control for rooms would not be essential during any accident scenario).
This is consistent with the Comed response to FSAR question 040.38, which
credited monitoring of the differential pressure across the intake filter during
regularly scheduled operational tests to determine the need for replacement of a
marginal filter. There is no procedural guidance to turn off any ESFVS upon high
pressure differential across the inlet filter or to shut down the associated divisional
L
ECCS equipment.
!
Separate alarms are provided to identify high temperatures in the rooms, which l
would indicate if filter fouling was preventing proper operation of the respective i
ventilation system, and to monitor the Division 3 EDG operation. Even if sufficient I
filter fouling is postulated to require shutdown of the Division 3 ESFVS, there would )
be no impact on the Division 1 equipment. The reduced air flow requirement for
- operation of only the Division 1 equipment (10,000 cfm versus 90,500 cfm) would !
'
result in a significantly lower filter pressure loss, and thus restore any potential
degraded air flow to the Division 3 equipment.
I
l -Therefore, the designed configuration for the Unit 2 Division 1 and 3 ESFVS air intake
' plenum does not provide a common failure mode for redundant ECCS components.
,
J 23
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I~ Comment 23: RHR Heat Exchanger Flow
Inspector: Bob Stakenborghs Date: September 20,1996
Calculation CS 2 appeared to establish a limit of 7700 gpm through the RHR heat
exchanger. Contrary to this, testing indicates that 8000 gpm flows through the heat
exchanger.
1. What is the allowable maximum flow through the heat exchanger as established by
the heat exchanger manufacturer and is 8000 gpm acceptable?
j 2. If the calculation was performed to establish 7700 gpm, why does the system
j perform at 8000 gpm?
Licensee response (9/26/96): The following information provides a response to the above
l
questions:
l 1. In response to question 1, the maximum allowable flow rate through the RHR heat
- exchangers is 9,250 gpm. This flow value was calculated from guidance supplied
, by GE which stated that, for the tube side of the heat exchanger, the maximum
!
allowable flow is 125% of the rated flow. Thus, for a rated flow of 7,400 gpm, the
maximum allowable flow is 9,250 gpm.
The operation of the pump under normal operating conditions, with the lake level at
a nominal elevation of 700', based on preoperational test data, determined that
maximum possible flow for any of the RHRSW pumps when they are aligned as
would be the case for normal operation, is approximately 4,100 gpm. Realizing that l
l
each RHR heat exchanger requires operation of two RHR[SW] pumps operating in -
parallel to provide the design flow rate, even if it is assumed that the total pump
flow would be twice that determined during the preoperational testing for each
pump, the maximum flow would still be substantially lower than the maximum .
allowable flow of 9,250;that is, the flow in this conservative analysis would be on
l the order of 8,200 gpm. ,
l l
, A modification was performed on the 2A RHRSW pump which increased the size of
! the impeller. This modification resulted in an estimated increase in flow of less than
4%, or assuming conservatively that the flow was 8,200 gpm before the
modification, this modification would result in a flow of approximately 8,500 gpm,
which is still well below the maximum allowable limit of 9,250 gpm. Therefore, the l
RHR heat exchangers are experiencing a maximum flow rate lower than that
maximum allowable flow rate.
!
2. The referenced calculation was based on 7,700 gpm at a lake level of 685' for the
sizing of the orifice plate. This value ensures that adequate flow to the RHR heat
exchangers is provided for design considerations such as lake level changes.
l
!
In the calculation, the water level was assumed to be at elevation 685' which is
conservative since the level of the CSCS pond, assuming failure of the lake, is
24
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l-
elevation 690'. The assumed value level is approximately 15' lower than the lake
l nominal operating level of 700' elevation. Extrapolating the system head curve
!
provided in the calculation (which is based on a lake level of 685') to the normal
_
operating level of 700', a parallel curve to the system head curve can be drawn.
The point at which this "new" curve crosses the pump curve is approximately
8,000 gpm or reasonably close to the nominal operating value for the RHR heat
exchangers. As stated above, the design flow rate through the RHR heat exchanger
is approximately 7,400 gpm at a lake /CSCS pond level of 690'. Thus 8000 gpm
provides sufficient margin to account for changes in lake level.
l
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ATTACHMENT E
l PROCEDURES USED AND DOCUMENTS REVIEWED
i
NRC Insoection Procedures Used Durino the insoection
IP 93801 Safety System Functional Inspection
Tl 2515/118 Service Water System Operational Performance Inspection j
i
Licensee Documents Reviewed Durino the insoection !
The following is a list of licensee documents reviewed during the inspection. Inclusion in
this list does not imply that the NRC completely reviewed and accepted these documents,
L but, rather that they were evaluated as part of the overallinspection effort.
i
l CALCULATIONS -
1, Rev.1, LaSalle County Station Service Water Flow Velocities, Stone & Webster
l Calculation
i
11Al3, Rev. O,2/9/87, Hot Shutdown of LaSalle Units 1 and 2 By One Diesel Generator
19Al34, Rev. O,1/9/92, Isolation of Non-Safety Related Loads Supply From Safety-Related
l Source
19AK15, Rev.1,1/23/92, KWin Loading on 4160V SWGR 143 and 243
l
19AK19, Rev. 2,1/23/92, input KW Loading on 4160V SWGR 141Y,142Y and 242Y )
19AN49, Rev. O,1/22/92, Breaker Settings for Bus 235X Main Breaker & for RHR SWP
l 2A,2B & Cont. Vent Supply Fan 2A Breakers
3C7-0890-001,Rev.1,11/90, ECCS Room Temperature Transient Following LOCA
Concurrent With Loss of Area Cooler
l
3C7-1086-001,Rev. O, Evaluation of Reduced Service Water Flow Through the RHR Heat
l Exchanger
ATD-0340,(no title supplied)
l
l
ATD-0375, Rev. O, 3/91. ECCS Pump Room Temperature During Shutdown With Area
Coolers inoperable
! CS-1, Rev. O, CSCS Cooling Water Piping Wall Thickness
.
CS-2, Rev. O, CSCS-EWCS Orifices
).
1
_ -. .
!
l CS-3, Rev. O, CSCS ECWS Discharge Piping Design Pressure
!
DG 11, Rev. O, Calculation of Flow Velocity Through DG Heat Exchangers
!
EMD-023757,0, Piping Stress Report Subsystem 1WS20, Addendum A
EO-01, Rev.1, HVAC, Temperature and Humidity Profile for the ECCS Pump Cubicles
EQ-07, Rev. O, HVAC, Temperature and Humidity Profile for the DG Rooms and HPCS
l Rooms
l LAS-NPD-95-0015, Rev.1, Moderate Energy Pipe Break Evaluation in Diesel and
l Turbine / Auxiliary Buildings
l
'
LOOO556, Rev.1, Evaluation of 54 Steel By-Pass Line - Lake Screen House
LOOO558, Rev. O, Supplemental Calcs for Lake Screen House
!
L000561, Rev. O, Evaluation of 36-125 lb Crane Ferrosteel Wedge Gate Valve for Seismic
Loads
L000562, Rev. O, Lake Screen House: Design Margin Against Overturning and Floatation
L000563, Rev. O, Lake Screen House Evaluation of Tunnel Basemat and Exterior Wall for
Irregularities Found During Underwater Examination
i LOOO566, Rev. O, Evaluation of Henry Pratt 54-Triton XL Butterfly Valve with a H3BC
l Operator for Seismic Loads
i
L000568, Rev. O, Lake Screen House Review of Shear Walls for Revised Vertical Seismic
Loads l
l
LOOO570, Rev. O, Structural design of HVAC Duct Dams Between Division 1 and Division
3 CSCS Pump Rooms
LOOO579, Rev.1, Evaluation of HPCS Diesel Generator Operation During HPCS Diesel l
l Generator Cooling use Evaluation of Tunnel Basemat and Exterior Wall for Irregularities l
!
Found During Underwater Examination l
l
l
LOOO566, Rev. O, Evaluation of Henry Pratt 54-Triton XL Butterf!y Valve with a H3BC
Operator for Seismic Loads
L000568, Rev. O, Lake Screen House Review of Shear Walls for Revised Vertical Seismic
Loads j
LOOO570, Rev. O, Structural design of HVAC Duct Dams Between Division 1 and Division
3 CSCS Pump Rooms
,
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l
l
___ _
_ _ _ .__ _.
4
-
LOOO579, Rev.1, Evaluation of HPCS Diesel Generator Operation During HPCS Diesel
,
Generator Cooling use Evaluation of Tunnel Basemat and Exterior Wall for Irregularities
Found During Underwater Examination
LOOO566, Rev. O, Evaluation of Henry Pratt 54-Triton XL Butterfly Valve with a HSBC
Operator for Seismic Loads
4
L000568, Rev. O, Lake Screen House Review of Shear Walls for Revised Vertical Seismic
4
Loads
L000570, Rev. O, Structural design of HVAC Duct Dams Between Division 1 and Division
. 3 CSCS Pump Rooms
LOOO579, Rev.1, Evaluation of HPCS Diesel Generator Operation During HPCS Diesel
Generator Cooling LPCI-A Keep Filled Alarm Setpoint and Associated Technical
Specification Allowable Value
,
NED-I-EIC-0154, Rev.1,5/31/94, Determination of optimal RHR LPCI-B Keep Filled Alarm
Setpoint and Associated Technical Specification Allowable Value
NED-I-EIC-0155, Rev.1,5/31/94, Determination of Optimal RHR LPCI-C Pumps Keep Filled
- Alarm Setpoint and Associated Technical Specification Allowable Value
i'
NED-l-EIC-0156, Rev.1, 5/31/94, Determination of Optimal Low Pressure Core (LPCS)
Keep Filled Alarm Setpoint and Associated Technical Specification Allowable Value
S-008, Rev. O, Unit 1 CSCS Pump Room Div i / Div Ill Flood Rate
a
S-009, Rev. O, Flood Rates Due to Cracks in Gravity Fed CW Pipe Outside Condenser Pit
i
,
S-030, Rev. O, HPCS Switchgear Room Flooding Due to Postulated Crack in 36 CW
j Manway
'
S-036, Rev. O, Replacement Watertight Doors D13, D15, D16 and D17
S-039, Rev. O, Computation of Allowable and Ultimate Flood Depths for Door Nos. D16
and D17 (Unit 2) and Estimate of Flood Depth When Leakage May Occur
i
Unnumbered SLL,1971, Core Spray Cooling System Cooling Water (CSCS)
Unnumbered S&L,1972, CSCS Pump Sizing
Unnumbered S&L, Service Water System Sizing - Normal Operating Mode
VD-1 A, Rev. O, HVAC, Standby Diesel Generator Room Ventilation System (1DG01 K)
VD-2A, Rev. O, HVAC, Standby Diesel Generator Room Ventilation System (0DG01K)
3
_ . _
1
VD-3A, Rev. O, HVAC, HPCS Diesel Generator Room Ventilation System
VD-3C, Rev. 3, HVAC, HPCS DG Cooling Water Pump, Switchgear and Battery Room I
Ventilation System
VD-3E, Rev. O, HVAC, Temperature and Relative Humidity Profile for HPCS DG Room
VY-01, Rev. O, Material for CSCS Supply and Return Headers
VY-02, Rev. O, Backflow Into Bldg in Event of Failure of 1/2E12-F068A RHR HX Outlet)
VY-03, Rev. O, CSCS Orifice Plate
,
VY-04, Rev. O, 6/76, Unit 1, Division i ECCS Equipment Cooling Water System
VY-05, Rev. O, Intake Fiume Velocity Under Condition Described
VY-06, Rev. O, ECCS Pump Operating Time for Cubicle Cooling (VY)
VY-1, Rev.1, HVAC, RHR Pumps (B & C) Cubicle Cooler Vent System 1
1
VY-2, Rev. O, HVAC, RHR Pump (A) Cubicle Cooler Ventilation System
VY-3, Rev. O, HVAC, LPCS Pump Cubicle Cooler Ventilation System j
VY-4, Rev. O, HVAC, HPCS Pump Cubicle Cooler Ventilation System
l
l
VY-5, Rev.1, HVAC, RHR Service Water Pumps (A & B) Room Ventilation System l
1
VY-6, Rev. 2, HVAC, RHR Service Water Pumps (C & D) Room Ventilation System
VY-7, Rev.1, HVAC, ECCS Equipment Area Duct Pressure Drops
VY-9, Rev. O, HVAC, Capacity Verification for the VY System - Unit 2
VY-10, Rev. O, HVAC, Cubicle Cooler Temperature Switch Qualification Test Anamoly
VY-11, Rev. 2, HVAC, ECCS Projected Cubicle Heat Load, Heat Exchanger Parameters and
Airflow Communication Paths
! VY-12, Rev. O, HVAC, Evaluation of VY Cooler Tube Velocity Based on Test Data
VY-13, Rev. O, HVAC, Unit 2 RHR Service Water Pump Room C Temperature on Loss of
l HVAC
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DESIGN CHANGE PACKAGES
8300137 Replace Current Transmitters
8700063 Add Local Remote Transfer Switch to DG "0" Cooling Water Pump
9100266 Repair 18 RHR Heat Exchanger Partition Plate
9200182 Replace 120V AC Contactor Coils for HPCS Diesel Cooling Water Pump
9300358 Replace Unit "0" DG Strainer Sackwash Piping
9400227 Replace SW Temp Control Vaive Bypass
9500302 Replace Watertight Doors
DRAWINGS i
l
1E-0-3722, Rev. AP, Lighting Cabinets * to 14 Detail & Loading Sheets l
1E-0-4412AC, Rev. W, Schematic Diagram Diesel Generator System DG Pt. 3
l
i l
1E-13754, Rev. T, Lighting - Auxiliary Building & Control Room, EL 768' COL.13-15:J-N
1E-1-4000A, Rev. L, Generator, Transformer & 6900V Buses l
1E-1-4000B, Rev. L, Standby Generators and 4160V Buses
l
1E-1-4000D, Rev. A,480V Substations on Switchgear 141X & 141Y
1E-1-4000E, Rev. A,480V Substations on Switchgear 142X,142Y & 143
l
l 1E-1-4000M, Rev. E, Station Key Diagram 6900V and 4160V Switchgear
,
1E-1-4000N, Rev. H, Station Key Diagram 480V Switchgear Pt.1
l
1E-1-4000P, Rev. K, Station Key Diagram 480V Switchgear Pt. 2
1E-1-4000U, Rev. T, Station Key Diagram 480VAC MCC's Pt. 5
I 1 E-2-4000M, Rev. E, 6900V and 4160V Switchgear
i 1E-2-4000N, Rev. K, Station Key Diagram 480V Switchgear Pt.1
1E 2-4000P, Rev. H, Station Key Diagram 480V Switchgear Pt. 2
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.
1E-2-4000U, Rev. O, Station Key Diagram 480V AC MCC's - Pt. 5
1E-1-4000AL, Rev. C, Key Diagram 4160V Switchgear 142X
1E-1-4000BD, Rev. D, Key Diagram 480V Switchgear 132X
1E-1-4000BN, Rev. C, Key Diagram 480V Switchgear 135X
1E-1-4000BP, Rev. E, Key Diagram 480V Switchgear 135Y
1E-1-4000BO, Rev. E, Key Diagram 480V Switchgear 130X
1E-1-4000BR, Rev. G, Key Diagram 480V Switchgear 136Y
1E-1-4000CJ, Rev. K, Key Diagram 480V PP'S 132B-4,132B-5 & MCC 132X-1
1E-1-4000CM, Rev. K, Key Diagram Reactor Bldg 480V AC MCC 133-2
1E-1-4000CR, Rev. R, Key Diagram 480V MCC's 134X-2 & 134Y-1
1E-1-4000DA, Rev. O, Key Diagram 480V AC MCC 1431
1E-1-4000DW, Rev. J, Key Diagram 480V MCC 136X-3
1E-1-4000KT, Rev. G, Key Diagram 120/208VAC Dist. Pnl. at 480V. MCC 133-2
1 E-1-4000LA, Rev. H, Key Diagram 120/208VAC Distribution Panel AT 480V MCC 134X-
2
1E-1-4001 AE, Rev. C, Auxiliary Power Sys AP Pt.16
1E-1-4001 AS, Rev. C, Auxiliary Power Sys AP Pt. 23
1E-1-4001 AT, Rev. D, Auxiliary Power Sys AP Pt. 24
1E-1-4005BB, Rev. E,4160V Switchgear 142Y Feed to Trans.134X & 134Y System AP
Pt. 26
1E-1-4005CJ, Hev. B, Auxiliary Power System AP Pt. 57
l
1E-1-4009AB, Rev. K, Schematic Diagram Diesel Generator System DG Pt. 2
j 1E-1-4009AC, Rev. H, Schematic Diagram Diesel Cooling Water Strainer 1DG01F System
l DG Pt. 3
l !
1E-1-4009AO, Rev. J, Schematic Diagram Diesel Generator Sys (DG)
4
1E-1-4032AB, Rev. D, Schematic Diagram Fuel Pool Cooling & Clean-Up Sys FC Pt. 2
6
i
i
1E-1-4081 AA, Rev. G, Primary Containment Water Chiller 1 A System VP Pt.1
1 E-1-4081 AC, Rev. K, Primary Containment Vent. System VP Pt. 3
1E-1-4089AA, Rev. E, Core Standby C1E-1-4009AB, Rev. K, Sr 4
sc Diagram Diesel
Generator System DG Pt. 2
l
l 1E-1-4009AC, Rev. H, Schematic Diagram Diesel Cooling Water Strainer 1DG01F Sys. DG
'
Pt. 3
1E-1-4009AQ, Rev. J, Schematic Diagram Diesel Generator Sys (DG)
1E-1-4032AB, Rev. D, Schematic Diagram Fuel Pool Cooling & Clean-Up Sys FC Pt. 2
1E-1-4081 AA, Rev. G, Primary Containment Water Chiller 1 A System VP Pt.1
,
1 E-1-4081 AC, Rev. K, Primary Containment Vent. System VP Pt. 3
1E-1-4089AA, Rev. E, Core Standby C Removal System RH (E12) Pt. 5
l
1E-1-4220AF, Rev. N, Schematic Diagram Residual Heat Removal System RH (E12) Pt. 6
1E-1-4220AG, Rev. H, Schematic Diagram RHR Service Water Strainer 1 A System RH
(E12) Pt. 7
1E-1-4220AN, Rev. AA, Residual Heat Removal System RH (E12) Pt.13
1E-1-4220AO, Rev. O, Residual Heat Removal Sys RH (E12) Pt.15
1E-1-4220AU, Rev. E, Schematic Diagram RHR Service Water Strainer 1B System RH j
(E12) Pt.19 l
1E-2-4220AU, Rev. K, RHR Service Water Strainer 28 Sys RH (E12) Pt.19
1E-1-4220AX, Rev. V, Schematic Diagram Residual Heat Removal System RH (E12) Pt. 22 l
l
1E-1-4220BS, Rev. L, Residual Heat Removal System RH (E12) Pt. 41
1E-1-4220CJ, Rev. P, Schematic Diagram Residual Heat Removal Sys RH (E12) Pt. 57
1E-1-4223AR, Rev. O, Schematic Diagram HPCS DG-1B Gen /Eng Control Sys HP (E228)
Pt.16
1E-1-4223AT, Rev. H HPCS Diesel Cooling Water Strainer Sys HP (E22B) Pt.18
i
1E-1-4"_23AV, Rav. E, HPCS DG-1B Gen /Eng Control Sys. HP(E22B) Air Compressor
"B10," Pt. 20
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7
4:'4m J 6 L = ,bo.- 4a--2 sn A + -, + --, a b S,- 4----* -_-e- .--s, ,-+ _ar ---4- .A-M---+ k - ,A-,mL.---
1E-1-4414AD, Rev. O, INT / EXT Wiring Diagram Aux Bldg. 480V MCC 136X-3 Pt. 4
1E-1-4658AE, Rev. R, INT./ EXT. Wiring Diagram Part 3 Remote Shutdown Panel 1C61-
P001
1E-1-4658AJ, Rev. L, INT./ EXT. Wiring Diagram Part 7 Remote Shutdown Panel 1C61-
P001
731E966AA, Rev. 5, Process Diagram - Residual Heat Removal System
731E999AA, Rev. 7, Residual Heat Removal System (3 sheets)
828E156AA, Rev.1, High Pressure Core Spray Power Supply (3 sheets)
LG A-01, Rev.15, RPV Control (Unit 1)
LGA-03, Rev.18, Primary Containment Control
'
M-19, Rev. D, General Arrangement, Lake Screen House
M-87, Rev. AC, Unit 1 P&lD CSCS Equipment Cooling Water System (3 Sheets)
M-94, Rev. AD, Low Pressure Core Spray (;.PCS) - Unit 1
M-134, Rev. AB, Unit 2 P&lD CSCS Equipm9nt Cooling Water System (3 Sheets)
M-140, Rev. AG, Low Pressure Core Spray (LPCS)- Unit 2
M-153, Rev. N, Process Radiation Monitoring - Units 1 & 2
M-1464, Rev. B, CSCS Equipment Cooling System - Unit 1
M-1465, Rev. B, CSCS Equipment Cooling System - Unit 2
M-2096, Rev. B, C & I Details RHR System - RH - Unit 1
M-2142, Rev. D, C & I Details RHR System - RH - Unit 2
M-5087, Rev. D, Logic Block Diagram Core Spray Equip. Cooling Wtr. Sys.(DG) (FC) (HP)
,
(RH) (2 sheets)
M-5134, Rev. B, Logic Block Diagram Core Spray Equip. Cooling Wtr. Sys.(DG) (FC) (HP)
(RH) (2 sheets)
M-5464, Rev. D, CSCS Equipment Cooling System (VY)
l S-60, Rev. C, lotake Fiume Plan & Profile
< 8
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EQUIPMENT DRAWINGS
I
)
231164#1, Rev. 2, Spec J-2535, Service Water Pumps i
231165#1, Rev.1, Spec J-2535, Service Wr>ter Jockey Pump
37654, Rev. 7, Spec J-2946, RHR Service Watar Strainers
37656, Rev. 6, Spec J-2946, DG Cooling Water Strainers
5-046-15-156-001,Rev. 2, Spec J-2544, Diesel Generator Coolers
BBC-100-9, Rev. 4, Spec J-2582, CSCS Area Cooler 1VYO1 A ,
l
BBC-100-10, Rev. 2, Spec J-2582, CSCS Area Cooler 1VYO2A
BBC-100-11, Rev. 4, Spec J-2582, CSCS Area Cooler 2VYO1 A
BBC-100-12, Rev. 2, Gpec J-2582, CSCS Area Cooler 2VYO2A ;
BBC-100-13, Rev. 2, Spec J-2582, CSCS Area Cooler 1VYO3A
BBC-100-14, Rev. 2, Spec J-2582, CSCS Area Cooler 2VYO3A
'
BBC-100-15, Rev. 3, Spec J 2582, CSCS Area Cooler 1VYO4A
I
BBC-100-16, Rev. 3, Spec J 2582, CSCS Area Cooler 2VYO4A
C-01977, Rev. 3, Spec J-2599,CSCS Cooling Water Screen Bypass Line Isolation Valve
OE12 F300 l
l 1
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DP-14450-2, Rev. B, Spec J-2944, RHR Service Water Pumps
DP-14450-6, Rev. O, Spec J 2944, Fuel Pool Emergency Make-Up Pumps
i
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DP-14450-4, Rev. O, Spec J-2944, Diesel Generator Cooling Water Pump, ODG01P
DP-14450-3, Rev. O, Spec J-2944, Diesel Generator Cooling Water Pump,1/2DG01P
E22-4010, Rev. 2,04/74, Design Specification Data Sheet
VPF-3161-001, Rev.11, Spec J-2500, RHR Heat Exchangers ;
I
VPF-3411-080(1)-11,Rev.1, Spec J-2500, HPCS Diesel Generator Coolers
!
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EQUIPMENT SPECIFICATIONS
l
J-2500, Addendum 1, Nuclear Steam Supply System
J-2530, Amendment 12, Erection of Piping Systems
l J-2544, Conformed, Diesel Generators
'
l J 2563, Addendum 2, Traveling Screens for Lake and River Screen Houses
! J-2582, Addendum 1, Heat Exchanger Coils and Cabinets
J-2938, Addendum 1, Gate, Globe & Check Valves (Section Ill)
! J-2944, Amendment 2, Miscellaneous Horizontal Centrifugal Pumps (Section lil)
J-2945, Conformed, Fuel Pool Heat Exchangers (Section Ill)
J-2946, Conformed, Service Water Strainers (Section Ill)
GENERIC LETTER 89-13 CORRESPONDENCE
Letter from CECO (MNRichter) to NRC (Document Control Desk), dated 1/29/90 -
. Letter from CECO (DLTaylor) to NRC (Document Control Desk), dated 11/14/90
Letter from CECO (DLTaylor) to NRC (Document Control Desk), dated 6/7/91
Letter from CECO (MAJackson) to NRC (Document Control Desk), dated 5/14/92 )
i
Letter from CECO (MBDepuydt) to NRC (Document Control Desk), dated 3/18/93 .
~ Letter from CECO (JLockwood) to NRC (Document Control Desk), dated 5/18/94
- Stone & Webster Service Water Design Review Report,04/26/91,in Response to NRC
l
l Comed Service Water System Evaluation 89-13 Checklist
HEAT EXCHANGER INSPECTION RECORDS
RHR Heat Exchanaer Tubeside
1 A RHR Heat Exchanger (Water Side),03/94
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1 A RHR Heat Exchanger (Water Side),02/96
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er -- < ~ - . . , . - . , - - . - ,---
!
1B RHR Heat Exchanger (Water Side),10/92 l
2B RHR Heat Exchanger (Water Side),10/93
RHR Area Cooler Heat Exchanaers Shellside l
l
Unit 2 ECCS Area Cooler Cubicles, 12/18/91 ,
1
A RHR Corner Room Area Cooler (Air Side),09/92
A RHR Corner Room Area Cooler (Air Side),10/93
B/C RHR Corner Room Area Cooler (Air Side),09/92
Diesel Generator Heat Exchanaer Tubeside
1 A DG Heat Exchanger (Water Side),11/92
1 A DG Heat Exchanger (Water Side),03/94
1B DG Heat Exchanger (Water Side),11/92
1B DG Heat Exchanger (Water Side),03/94
2A DG Heat Exchanger (Water Side),09/93
RHR Pumo Seal Coolers
Unit 2A RHR Pump Seal Cooler,03/95
Unit 2B RHR Pump Seal Cooler,08/96
LPCS Motor Coolers
Unit 2 LPCS Motor Cooler,03/95
PREOPERATION AL TESTS
( PT-VY-101 CSCS Equipment Cooling Water Section 10.5, Pages 123- 146, and
associated data sheets (1/82)
j PT-VY-102 CSCS Equipment Ventilation Section 10.5, Pages 59 - 71, and associated data
sheets
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PROCEDURES
Abnormal Procedures
,
LOA-FP-101, Rev. O,08/96, Unit 1 Fire Protection System Abnormal
LOA-FP-201, Rev. O,08/96, Unit 2 Fire Protection System Abnormal
LOA-RH-03, Rev. 7,03/94, Loss of RHR Service Water
LOA-WS-01, Rev. 9,07/96, Loss of Service Water
LOA-ZZ-03, Rev. 5,02/94, Failure of the Cooling Lake Dike
Administrative Procedures
LAP-100-29, Rev. 6,06/94, Conduct and Review of Station Surveillances
LAP-1200-17, Rev. 3, 09/96, Operating License / Technical Specifications
LAP-1300-1, Rev. 56, Action / Work Request Processing
<
Alarm Resoonse Procedures
!- LOA-1(2)H13-P601-A104,Rev. 4,09/89, Diesel Generator 1(2)B Cooling Water Pump l
Trouble / Strainer
LOA-1(2)H13-P601-A407,Rev. 4,09/89, HPCS Diesel Cooling Water Pump Room Sump )
Level Hi-Hi
LOA-1(2)H13-P601-A408,Rev. 5,05/93, HPCS Pump Cubicle Temperature High
l
l LOA-1(2)H13-P601-A501, Rev. 3, 09/93, Diesel Generator 1B(28) Engine Trouble
l
LOA-1(2)H13-P601-B103,Rev. 3,10/89, RHR Pump 18/1C(28/2C) Cubicle Cooler fan
Auto Trip
LOA-1(2)H13-P601-B104,Rev. 5,10/89, RHR Service Water Pump 1(2)C Auto trip
l LOA-1(2)H13-P601-B105,Rev. 6, C9/89, RHR Service Water Pump 1(2)D Auto trip
l
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LOA-1(2)H13-P601-B112,Rev. 8,04/94,1(2)A RHR Service Water Radiation High
. LOA-1(2)H13-P601-8204,Rev. 4,09/89, RHR Service Water Strainer 1(2) E12-D3008
Differential Pressure High
i LOA-1(2)H13-P601-B212,Rev. 7,04/94,1(2)B RHR Service Water Radiation High
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LOA-1(2)H13-P601-B301,Rev. 9,04/94, Service Water Effluent Radiation High
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LOA-1(2)H13-P601-8403,Rev. 4,09/89, RHR Service Water Pump 1C/1D(2C/2D) Cubicle !
Fan Auto Trip High
LOA-1(2)H13-P601-8404,Rev. 4,09/89, RHR Service Water Pump 1C/1D(2C/2D) Cubicle :'
Temperature High
LOA-1(2)H13-P601-B503, Rev. 3,09/89, RHR Service Water Pump 1C/1D(2C/2D) Room
Sump Level High High
LOA 1(2)H13-P601-C101,Rev. 5,09/89, RHR Service Water Pump 1(2)A Auto trip
LOA-1(2)H13-P601-C102,Rev. 6,10/89, RHR Service Water Pump 1(2)B Auto trip
LOA-2H13-P601-C106, Rev. 2,10/89, RHR Service Water Pump 2A/2B Cubicle Return
Fan Auto Trip
LOA-1(2)H13-P601-C202,Rev. 5,10/89, RHR Service Water Strainer 1(2)A Differential
Pressure High
l LOA-1(2)H13-P601-C205,Rev. 5,12/91, RHR Pump 1(2)A Cubicle Temperature High
l
l LOA-1(2)H13-P601-C301,Rev. 6,10/92, RHR Heat Exchanger 1 A/1B(2A/28) Discharge
i Cooling Water Temperature High
!
l LOA-1(2)H13-P601-C302,Rev. 3,10/89, RHR Heat Exchanger 1 A/1B(2A/28)lnlet Water
l
Temperature High
LOA-1(2)H13-P601-C401,Rev. 4,10/89, RHR Service Water Pump 1 A/1B(2A/28) Cubicle
Temperature High
! LOA-1(2)H13-P601-C408,Rev. 5,11/91, LPCS/RCIC Pump Cubicle Temperature High
l
LOA-1(2)H13-P601-C501,Rev. 3,09/89, RHR Service Water 1 A/1B(2A/28) Room Sump
l Level Hi-Hi
LOA-1(2)H13-P601-C502,Rev. 3,09/89, RHR Service Water 1 A/1B(2A/28) Cubicle Cooler
Fan Auto Trip
LOA-1(2)PM03J-8509, Rev. 5,03/93, Lake Screen House Traveling Screen Panel Trouble
LOA-1(2)PM10J-A401, Rev. 4, 9/89, Service Water Strainer 1(2)WS01F Differential
Pressure High
LOA-1(2)PM10J-A402, Rev. 4, 9/89, Service System Transfer Switch in Emergency
i Position
,
4
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LOA-1(2)PM10J-A403, Rev. 4,9/89, Service Water Jockey Pump OWS02PA(B) Automatic 4
l
Trip
LOA-1(2)PM10J-A501, Rev. 4,9/89, Service Water Pump Automatic Trip
LOA-1(2)PM10J-A502, Rev. 6, 2/90, Service Water Header Pressure Lo
LOA-1PM10J-A503, Rev. 3,9/89, Service Water Strainer OWS01F Differential Pressure
High I
Chemistrv Procedures
LCP-310-17, Rev. 4,4/95, Sampling of Lake Screen House influent, Condenser Discharge .
Structure Effluent, and River I
l
LCP-830-21, Rev.1,4/94, Service Water Corrosion Monitoring Program
Qqsien Proced_urg3
NEP-04-00, Rev.1, Roadmap - Design Changes
NEP-04-01, Rev. 2, Plant Modifications
Maintenance Procedures
LMP-GM-25, Rev. 2, ECCS Service Water Strainer Maintenance
LMP-RH-05, Rev. 2, Residual Heat Removal (RHR) Pump Mechanical Seal Replacement
Ooeratina Procedures
LOP-CF-01, Rev. 3,9/95, Chemical Feed System Startup and Shutdown
LOP-CF-02, Rev. 2,4/93, Chemical Feed System Receipt and Offloading
LOP-CF-03, Rev. O, 3/92, Chemical Feed System Polyacrylate injection System Flush
LOP-CF-01E, Rev.1,9/95, Unit 1 Chemical Feed System Electrical Checklist
LOP-CF-02E, Rev.1, 9/95, Unit 2 Chemical Feed System Electrical Checklist
LOP-CF-01M, Rev.1,12/95, Unit 1 Chemical Feed System Mechanical Checklist
LOP-CF-02M, Rev.1,12/95, Unit 2 Chemical Feed System Mechanical Checklist
l
LOP-CW-05, Rev. 8,5/93, Startup of Circulating Water (CW) Traveling Screens
LOP-CW-08, Rev. 5,9/90, Shutdown of Traveling Water Screens (CW)
14
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LOP-CF-03M, Rev. 5,11/91, Unit 1 CW Traveling Screen Startup Mechanical Checklist
LOP-CF-04M, Rev. 5,11/91, Unit 2 CW Traveling Screen Startup Mechanical Checklist
LOP-DG-04, Rev.18,5/96, Preparation for Standby Operation of 1B(2B) Diesel Generator
1(2)E22-S001
l
l LOP-RH-04, Rev. 6, 3/91, Filling, Venting of the RHR Service Water System
l
l LOP-RH-05, Rev.13,12/93, Operation of the RHR Service Water System
i
l LOP-RH-14, Rev. 4, 9/90, Backwash of the RHR Service Water Strainers
l
l- LOP-RH-01E, Rev. 3,2/82, Unit 1 RHR Service Water System Electrical Checklist
!~
LOP-RH-03E, Rev. 3,2/82, Unit 2 RHR Service Water System Electrical Checklist
LOP-RH-01M, Rev. 7,2/96, Unit 1 RHR Service Water System Lineup Mechanical Checklist
!
LOP-RH-03M, Rev. 6, 3/95, Unit 2 RHR Service Water System Lineup Mechanical Checklist
i
LOP-RH-22, Rev. 2,4/95,' Draining the RHR Heat Exchanger Tubeside During a Service Air ,
-Test
i l
LOP-WS-01, Rev. 7,4/91, Service Water System Startup !
LOP-WS-02, Rev. 6,4/91, Service Water Pump and Service Water Jockey Pump Startup
LOP WS-03, Rev. 5,4/91, Service Water Pump Shutdown
LOP-WS-04, Rev. 6,4/91, Draining Components Served by the Service Water System
LOP-WS-05, Rev. 3,1092, Service Water Strainer Operations
LOP-WS-06, Rev.1,4/91, Service Water Operation with the Unit Circulating Water
Discharge Unavailable
LOP-WS-01E, Rev. 3,1/92, Unit 1 Service Water System Electrical Checklist
LOP-WS-02E, Rev. 2,1/92, Unit 2 Service Water System Electrical Checklist l
LOP-WS-01M, Rev.12,5/94, Unit 1 Service Water System Lineup Mechanical Checklist
LOP-WS-03M, Rev.11,10/94, Unit 2 Service Water System Lineup
!
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._ ___._ . _ _ . _ . _ _ _ _ . . . . . _ , _ . . _ . . _ _ _ _ _ . _ _ _ _ _ _ _ . _ . _ _ _ _ _ ,
I- Technical' Procedures
LTP-100-5, Rev.1,11/92, Heat Exchanger Program
LTP 500-11, Rev.1,10/91, Determining Chemical Feed System Flow Rates
.
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' PUMP CURVES
T-5695, RHRSW Pump 1 A,10/20/76
! T-5706, RHRSW Pump 1B,10/23/76
!
T-5707, RHRSW Pump 1C,10/25/76
T-5708, RHRSW Pump 1 D,10/20/76
.
A~
T-5669, RHRSW Pump 2A,09/29/76
T-5670, RHRSW Pump 28,09/28/76
T-5671, RHRSW Pump 2C,09/22/76
- T 5672, RHRSW Pump 2D,09/20/76
T-5611, FPEM Pump 1 A,07/31/76 .l
T-5609, FPEM Pump 18,07/28/76
T-5658, FPEM Pump 2A,09/01/76
T-5608, FPEM Pump 2B,07/29/76
T-5771, DGCW Pump 0,12/28/76
T-5731, DGCW Pump 1,11/11/76
T-5752, DGCW Pump 2,11/20/76
QUAllTY VERIFICATION SURVEILLANCES
CAR 1-93-87 Parts A (Severity Level 1) and B (S.L. II), 12/22/93
Fire Protection Program Assessment Report,09/01/95
i
- . PORC Minutes #
- 96-39,40,41,42,43,45,46, and 48.
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SPECIAL TESTS
i
l LST-87-73, Rev. O,05/87, RHR Pump Seal Cooler Flowrate Test
LST-90-105, Rev. O,10/90, RHR Service Water Pressure Transient Monitoring During
! System Startup
l LST-95-105, Rev. O,10/95, RHR Service Water Pumps and Valve Inservice Test
l
SURVEILLANCE PROCEDURES
Instrument Surveillances
LIS-RH-105, Rev. 3,03/94, Unit 1 RHR Service Water Effluent Radiation Monitor
i Calibration -
LIS-RH-205, Rev. 2,09/93, Unit 2 RHR Service Water Effluent Radiation Monitor
Calibration
LIS-RH-107, Rev. 5,07/93, Unit 1 RHR B Service Water Flow Indication Refuel Calibration
LIS-RH-207, Rev. 5,07/93, Unit 2 RHR B Service Water Flow Indication Refuel Calibration ,
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LIS-RH-305, Rev. 5,03/94, Unit 1 RHR Service Water Effluent Radiation Monitor
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Functional Test
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LIS-RH-405, Rev. 5,09/93, Unit 2 RHR Service Water Effluent Radiation Monitor
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Functional Test
l Maintenance Surveillances
LMS-DG-01, Rev.16,11/95, Main Emergency Diesel Unit Surveillances (pages 1-8 & 55-
56)
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Operatina Surveillances
! LOS-RH-M1, Rev.13,04/96, RHR System and RHR WS System Operability Test for
Conditions 1,2, 3,4 and 5
LOS RH-01, Rev. 35,05/96, RHR (LPCI) and RHR Service Water Pump and Valve Inservice
! Test for Operational Conditions 1,2,3,4 and 5
LOS-ZZ-MS, Cathodic Protection and Safety Shower / Eyewash Monthly Surveillance
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Technical Surveillances
LTS-200-3, Rev. 3,10/95, RHR Heat Exchanger Tubeside DP Test
LTS-200-9, Rev. 4, 08/91, RHR Pump Seal Cooler Flowrate Test
LTS-20010, Rev.1,03/91, LPCS Pump Motor Cooler Flowrate Test -l
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LTS-200-11, Rev. 3,07/92, Diesel Generator Heat Exchanger Performance Test l
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l LTS-200-12, Rev. 3,04/94, Northeast and Northwest Cubicle Cooler 1(2)VYO1 A and
1(2)VYO4A Flowrate Test
LTS-200-13, Rev. 2,03/91, Southwest Cubicle Area Cooler Flowrate Test
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LTS-200-14, Rev. 2,05/93, Southeast Cubicle Area Cooler Flowrate Test i
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LTS 200-16, Rev. 2,10/90, Fuel Pool Cooling Heat Exchanger Performance Monitoring
LTS-200-17, Rev. 2,03/91, RHR Heat Exchanger Capacity Test
LTS 200-19, Rev. 3,06/94, ECCS Cubicle Area Cooler Air Flowrate Test
LTS-600-19, Rev. 3,09/93, Corbicula and Zebra Mussel Inspections
~LTS-600-20, Rev. 4,01/96, LaSalle Station Flow Accelerated Corrosion Program 1
LTS-600-23, Rev.1,09/93, CSCS Cooling Water Screen Bypass Supply Line Inspection ,
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LTS-600-28, Rev. 3, ASME Section XI Manual Pressure Testing l
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' LTS-1000-4, Rev. 5, 01/95, CSCS Pond Surveillance j
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LTS-1000-5, Rev. 7,08/94, LaSalle Cooling Pond Minor Dike inspection j
LTS-1000-17, Rev. 4,12/91, Lake Screen House and Main Plant Settlement Monument
Surveillance
LTS-1000-18, Rev. 3,08/94, Cooling Lake Dike Settlement Monument Surveillance
LTS-1000-32, Rev. 4,09/92, LaSalle Cooling Pond Major Dike Inspection
SURVEILL ANCES (COMPLETED) -
LOS-ZZ-M5, Completed 09/96
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.LOS-ZZ-MS, Completed 08/96
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LOS-ZZ-M5, Completed 07/96
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! LOS-ZZ-M5, Completed 06/96
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-LOS-ZZ-M5, Completed 05/96
LOS-ZZ-M5, Completed 04/96
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LOS ZZ-M5, Completed 03/96
l- LOS-ZZ-MS, Completed 02/96
LOS-ZZ-M5, Completed 02/96
LOS-ZZ-MS, Completed 12/95
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LTS-200-3, Completed 12/95 (Heat Exchanger 28) j
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! LTS-200-3, Completed 11/95 (Heat Exchanger 18)
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LTS-200-3, Completed 10/95 (Heat Exchanger 2A) .
LTS-200-11, Completed 12/95 (Heat Exchanger 1DG01 A)
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LTS-200-11,Comoteted 12/95 (Heat Exchanger ODG01 A)
l LTS-200-11, Completed 01/96 (HPCS Heat Exchanger) !
LTS-200-12, Completed 09/95 (Unit 2, Cubicle Cooler 1 A)
I LTS 200-12, Completed 09/93 (Unit 2, Cubicle Coolers 1 A & 4A)
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LTS-200-12, Completed 08/93 (Unit 1, Cubicle Coolers 1 A & 4A)
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LTS-200-13, Completed 02/94
LTS-200-13, Completed 03/94 '
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L LTS-200-13, Completed 09/95 (Unit 2)
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LTS-200-13, Completed 06/96 (Unit 1) ,
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, LTS 200-14, Completed 12/94, Unit 1)
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- LTS-200-14, Completed 06/96 (Unit 1)
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- LTS-200-14, Completed 10/95 (Unit 2)
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LTS-200-17, Completed 01/90 (1 A and 1B Heat Exchangers)
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LTS-200-17, Completed 04/91 (2B Heat Exchanger)
LTS-200-17, Completed 05/91 (2A Heat Exchanger)
LTS-200-17, Completed 10/91 (1 A Heat Exchanger)
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j LTS-200-17, Completed 10/91 (1 B Heat Exchanger)
l LTS-600-19, Completed 12/87
LTS-600-19, Completed 01/88
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LTS-600-19, Completed 11/90
LTS-600-19, Completed 01/92
LTS-600-19, Completed 11/92
LTS-600-19, Completed 09/93
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l LTS-600-19, Completed 11/95
LTS-600-19, Completed 02/96
LTS-600-20, Completed 03/94
LTS-600-20, Completed 02/95
( LTS-600-20, Completed 01/96
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LTS-600-23, Completed 03/91
LTS-600-23, Completed 11/92
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LTS-600-23, Completed 04/94
I LTS-600-23, Completed 02/96
LTS-1000-4, Completed 1/90 (Unit 2, all bays)
LTS-1000-4, Completed 12/91 (Unit 2, bay B)
LTS-1000-4, Completed 12/91 (Unit 2, bay A)
LTS 1000-4, Completed 12/91 (Unit 2, bay C)
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LTS-1000-4, Completed 08/92 (Lake only)
LTS-1000-4, Completed 11/92 (Unit 1, all bays)
LTS-1000-4, Completed 08/93, (Lake only)
LTS 1000-4, Completed 09/93 (Unit 2, partial: A&B - NE/SW corners, C - NW/SE corners) i
LTS-1000-4, Completed 03/94 (Unit 1, partial: NE/SW corners only)
LTS-1000-4, Completed 03/95 (Unit 2, partial: NE/SW corners only)
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LTS 1000-4, Completed 02/96 (Unit 1, all bays) l
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LTS-1000-4, Completed 02/96 (Unit 2, all bays) i
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LTS-1000-17, Completed 05/96
l TRAINING MATERIAL (LESSON PLANS)
Service Water (WS), Chapter 55, Rev. 5,01/94
RHR System (RHR), Chapter 39, Rev. 7,02/96
- RCIC System (RCIC) Chapter 41, Rev. 8,10/95
Fire Protection System, Chapter 70, Rev. 6,02/96
- TRAINING MATERIAL (COURSE ATTENDEES)
' Plant Staff Attending Service Water training between 01/92 and 09/96
Plant Staff Authorized Preparer / Approver for Safety Evaluations 09/96
Job Assignment Matrix for Maintenance Staff as of 09/96
WORK REQUESTS
LO6416, Completed 03/92, Pump refurbishment for 2A RHR Service Water Pump
' 95000714201, Completed 03/96, Clean and inspect RHR PP Seal Cooler
! 95000714401, Completed 02/96, Clean and inspect RHR PP Seal Cooler
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a- -, --a -- aw-,- s------ sm--. ,-# . -- , rh s--wee - y +m--
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95000879001, Completed 03/96, inspect RHR heat exchanger 1 A service water baffle
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plate
95008140301, Completed 03/96, inspect RHR heat exchanger 2A service water baffle
plate
950107612, Ongoing at time of inspection, Repair of Unit 2 Fuel Pool Emergency Makeup
pumps
950194472, Ongoing at time of inspection, Repair of Unit 1 Fuel Pool Emergency Make\up
pumps
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95008140301, Completed 03/96, inspect RHR heat exchanger 2A service water baffle !
plate !
960006606 01 & 02, Completed 09/96, Replace valve actuator assembly for the DG j
cooling water strainer valve !
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96006279901 Completed 07/96, Perform inspection of LPCS Motor Cooler .
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96006905401, Completed 07/96, inspect valve disc /T-head connection for degradation
on DG "O" cooler backwash outlet stop
960083338 01, Completed 09/96, Replace the DG cooling water strainer valve due valve
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stem and disc separation
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