ML20198N329
| ML20198N329 | |
| Person / Time | |
|---|---|
| Site: | Fermi  |
| Issue date: | 10/29/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20198N324 | List: |
| References | |
| 50-341-97-11, NUDOCS 9711040043 | |
| Download: ML20198N329 (42) | |
See also: IR 05000341/1997011
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U.S. NUCLEAR REGULATORY COMMISSION
REGION 111-
Docket No: 50-341
License No: NPF-43
Report No: 50-341/97011(DRS)
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Licensee: Detroit Edison Company (DECO)
Facility: Enrico Fermi, Unit 2
Location: 6400 N. Dixie Hwy
Newport, MI 48166
Dater: August 4 - October 10,1997
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Inspectors: V. P. Lougheed, Reactor Engineer, Rlli
H. A. Walker, Reactor Engineer, Rlli
R. A. Westberg, Reactor Engineer, Rlli
R. A. Winter, Reactor Engineer, Rlli
G. R. Golub, Reactor Engineer (Nuclear), NRR
E. D. Kendrick, Reactor Engineer (Nuclear), NRR
Approved by: Mark A. Ring, Chief, Lead Engineers Branch
Division of Reactor Safety
9711040043 971029
PDR ADOCK 05000341
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EXECUTIVE SUMMARY
Enrico Fermi, Unit 2
NRC Inspection Report 50-341/97011
This announced inspection was to review and assess engineering and technical support at the
Fermi 2 Nuclear Plant, as well as to review the licensee's self assessment program. The
inspection covered the period from August 4 through October 10,1997, with three weeks of
on-site inspection. Personnel from the Office of Nuclear Reactor Regulation participated for
one week to review rod block monitor operability requirements for Cycle 5, based upon the
results of a vendor inspection at General Electric (Inspection Report 99900003/97-01). This GE
inspection was conducted on March 10 - 14,1997.
Overail, the inspectors concluded that the engineering process at Fermi was reasonable.
Improvements were noted in support of other organizations and in resolution of long-standing
design problems. Some improvement in preparing safety evaluations was noted, although
continued problems were seen. Training for the new corrective action program was excellent;
however, the corrective action program, itself, was not in place long enough to be evaluated. A
strength was seen in control of engineering calculations.
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e Licensee engineers did not perform an adequate review of the Technical Specifications
l when revising the Updated Final Safety Analys!a Report response time limit tables and
technical requirements manuai to eliminate response time testing for the emergency
core cooling, reactor protection and isolation systems. This resulted in a required
Technical Specification amendment not being identified and led to response time testing
not being performed on sensors in the Emergency Core Cooling System (ECCS),
Reactor Protection System (RPS), and the isolation actuation systems within the
required eighteen month surveillance period,
o Per the core reload analysis during operating Cycle 5, which began in December 1994,
the rod block monitor system should have been required to be operable, until re-analysis
was completed in August 1995. The re analysis demonstrated that the mechanical
overpower criteria for the one percent plastic strain limit was met without the rod block
monitors operable,
e The eristing setpoint and calibration program fulfilled the requirements.
The Updated Final Safety Analysis Report and the Technical Specifications misreported
the amount of water available to the high pressure coolant injection and reactor core
isolation cooling (RCIC) systems by taking credit for water that was unavailable to be
used.
Valve operation requirements for the RCIC system were accurately translated into the
surveillance test procedures. The RCIC system appeared to be capable of delivering its
design flow within 50 seconds after actuation. Material condition of the RCIC system
was considered good. RCIC system engineers were doing an acceptable job of tracking
and trending system performance.
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Licensee engineering effectively identified and corrected a problem with engineering
. functional analyses,
o Although the frequency of the rod position indication problems had substantially !
decreased in the current cycle, the licensee continued to see a limited number of
. indication problems, apparently due in part to overly sensitive' reed switches,
e The design modification program was generally effective in improving plant design,
despite the minor problems found.' The licensee exercised good control of the
temporary modification program, based upon the limited number, non-safety
classification, and relatively short time the temporary modifications were left open.
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i e There was adequate net positive suction head available for the residual heat removal
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(RHR) and core spray pumps. Furthermore, the licensee's program to perform and
maintain design-basis calculations appeared satisfactory, based upon the three
calculations reviewed.
- The licensee failed to identify an apparent unreviewed safety questior, in that a
possibility of equipment ma! functions due to inadequate emergency equipment cooling
water flow was not previously analyzed in the Updated Final Safety Analysis Report
(UFSAR), despite the need for operator actions to rectify the situation.
- - The licensee addressed, in a timely manner, the issues raised by inaccuracies in the
vendor-supplied emergency operating procedure information.
- The training provided for the new corrective action program was very good. The new
corrective action program appeared promising, but was not yet fully implemented.
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Report Details
Engineering
E1 Conduct of Engineering
E1.1 Elimination of Selected Resoonse Time Testing Reouirements (AITS97-012)
a. Insoection Scoce
The inspectors reviewed licensing and regulatory documentation, applicable technical
specifications (TSs), Safety Evaluation (SE) 95-0053, Licensing Topical Report
NEDO-32291, Deviation Event Report (DER) 97-0452, and Licensee Event Report
(LER)97-006.
b. Findings and Observations
The inspectors established the following time line as to the sequence of events
regarding the licensee's elimination of response time testing (RTT) requirements:
l February 17,1994 The Boiling Water Reactor (BWR) Owner's Group issued
1.lcensing Topical Report NEDO-32291," System Analyses for
Elimination of Selected Response Time Testing Requirements."
April 26,1994 Licensee submitted request for a TS amendment " Relocation of
Response Time Limit Tables," under the guidance of Generic
Letter 93-08.
December 28,1994 NRC approved N5DO-32291 in a safety evaluation report, with a
supplement issued on May 31,1995.
June 29,1994 NRC issued Amendment 100 to the Fermi 2 Operating License,
consisting of a TS revision to relocate the response time limit
tables to the updated final safety analysis report (UFSAR).
August 22,1994 Licensee relocated response time tables for emergency core
cooling system (ECCS), reactor protection system (RPS), and
isolation actuation instrumentation from the TS to the UFSAR to
allow RTT limits to be controlled in accordance with provisions of
10 CFR 50.59. Reference: Licensing Change Request (LCR)
94-054-UFS.
January 26,1996 Licensee prepared SE 95-0053, Revision 0, to revise the UFSAR
and technical requirements manual to eliminate RTT for selected
instruments.
February 6,1996 The onsite review organization (OSRO) approved SE 95-0053.
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February 29,1996 Licensee issued LCR 95-113-UFS to eliminate selected RTT
requirements from the UFSAR.
June 26,1996 Licensee did not perform RTT procedures 44.010.009,010,023,
& 024; 44.020.011,014,045, & 046; and 44.030.261, & 262 prior
to their critical performance date.
June 28,1996 Licensee did not perform RTT procedure 44.030.308 prior to its
critical performance date
July 16,1996 Licensee did not perform RTT procedure 44.030.307 prior to its
critical performance date.
March 19,1997 NRC informed licensees that sensor RTT could not be eliminated
through the 50.59 process and that a TS amendment was
required because of the wording of the RTT definitions in Sections
1.11,1.16, and 1.33 of the TSs.
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March 19,1997 Licensee initiated DER 97-0432 to investigate how requirements
relating to RTT were implemented.
March 20,1997 Fermi 2 engineers identified that RTT of the ECCS, RPS, and
isolation actuation instrumentation had not been conducted in
accordance with TS requirements.
March 20,1997 Licensee initiated LER 97-006, " Response Time Testing Not in
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Conformance with Technical Specifications"; the LER was issued
April 21.1997.
March 26 - April 4, Licensee performed 44.030.261 and 44.030.262 RTT calibrations
1997- for Mode 4 (other surveillances not required in this Mode).
March 27,1997 Licensee submitted a request for a TS Amendment " Elimination of
Selected Response Time Testing Requirements." A supplement
was issued on April 4,1997.
April 18,1997 NRC issued TS Amendment 111.
The inspectors observed that the following requirements govemed the licensee's actions i
in regard to RTT and safety evaluations:
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- TS 1.11 defined the emergency core cooling response time as that time interval from
j when the monitored parametcr exceeded its ECCS actuation setpoint at the channel
L sensor until the ECCS equipment was capable of performing its safety function, i.e., the
j ' valves traveled to their required positions, pump discharge pressures reached their
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required values, etc. Times included diesel generator starting and sequence loading
delays, where applicable. The response time might be measured by any series of
sequential, overlapping or total steps such that the entire response is measured.
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TS 1.16 defined the isolation system responta time as that time interval from when the
monitored parameter exceeded its isolation ariuation setpoint at the channel sensor
until the isolation valves traveled to their regaired positions. Timec included diesel
generator starting and sequence loading delays, where applicable. The response time
might be measured by any series of sequential, overlapping or total steps such that the
entire response was measured.
TS 1.33 defined the reactor protection response time as that time interval from when the
monitored parameter exceeded its trip setpoint at the channel sensor until the
de-energization nf the scram pilot valve soienoids. The response time might be l
measured by any series of sequential, overlapping or total steps uch that the entire
response was measured.
TS 4.3.1.3 required that the reactor protection response time of each reactor trip
funcdonal unit be demonstrated to be within its limit at ' east once per 18 months.
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TS 4.3.2.3 required that the isolation actuation response time of each isolation trip
function be demonstrated to be within its limit at least once per 18 months.
TS 4.3.3.3 required that the ECCS trip function be demonstrated to be within its limit at
least once per 18 months.
Licensing / Safety Engineering Conduct Manual MLS07," Preliminary Evaluations and
10CFR50.59 Safety Evaluations, " Revision 1, Requirement 3.2.4, required that
licensing basis documents be reviewed when performing a PE or SE, as appropriate.
MLS07, Section 3.2.4.2.a. defined the operating license, license conditions, TS, and the
environmental protection plan as NRC-generated documents included in the " censing
basis.
10 CFR 50.59 permits a licensee to make changes to the facility or procedures, as
described in the USFAR, un'ess the propose change involves a change to the Technical
Specifications or an unreviewed safety questions.
c. Conclusions
While the above issues appear to involve violations of NRC requirements, no violations
are being issued due to similar concems at several other BWRs. Once the generic
aspects of this issue have been resolved, then the regulatory issue will be addressed for
Fermi. This is considered unresc!ved, pending NRC resolution of the generic concerns.
(50-341/97011-01(DRS)
This review closes NRC AITS item 97-012.
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E1.2 Evaluation of Vendor Rod Withdrawal Error (RWE) and Mechanical Overoower (MOP)
Analvses
a. insoection Scoce (37550)
The inspectors reviewed the RWE and MOP analyses performed by General Electric
(GE), the fuel vendor, and provided to the licensee for Fermi 2 operating Cycles 4,5A,
5B, SC, and 6. The review was performed by evaluating the correspondence between
licensee and vendor and the reports provided by GE to Fermi during this period.
Background information was obtained from a NRR vendor inspection at GE on March
10-14,1997 (Inspection Report 99000003/97-01),
b. Observatigos
Detroit Edison Company (DECO) performed a quality assurance (QA) inspection
including a design review of Reload 3 Cycle 4 for Fermi 2 in April 1992. The DECO QA
Surveillance Report 92-018, May 6,1992, included an observation that the Cycle 4 RWE
analysis revealed a potential for exceedin0 fuel thermal and MOP limits if the Rod Block
Monitor (RBM) was assumed to be inoperable with control rod patterns that deviated
from the normal Operation cycle patterns recommended by GE Nuclear Energy. Rod
pattems typically deviate from normal pattems while responding to a Xenon transient
during plant startup. The QA surveillance further noted that TS 3/4.1.4.3 did not prohibit
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this mode of operation. The licensee recommended that GE analyze both Fermi Cycle
l 3 and Cycle 4 cores to evaluate the validity of generic RWE analysis with respect to the
MOP criteria in intermediate control rod pattems.
The inspectors reviewed records of the GE analysis for Fermi Cycle 4, which was the
first Fermi reload using the GE-11 fuel type. Results of the GE analysis were provided
in the Supplemental Reload Licensing Report (SRLR) 23A7075, April 1992, and did not
I include any reference to RBM operational requirements for MOP protection. The
licensee determined that the analysis showed that off-normal (or deviated) rod patterns
resulted in a seven percent increase in the linear heat generation rate compared to that
obtained using GE recommended rod pattems. These intermediate rod patterns
resulted in a slight (less than one percent) violation of the thermal MOP limits that GE
used as a screening criteria for confonnance to fuel-cladding plastic strain requirements.
The screening criteria were developed using bounding assumptions regarding core
operating conditions and the power history of the fuel thi: had been controlled by the
error rod of the RWE analysis. Generally, the screening criteria were considered to be
conservative with respect to the one percent plastic strain safety limit. However, as
discussed in the NRC Inspection Report 99900003/97-01, the GE prc.:edures did not
require analysis of these off-normal rod patterns and were not clear regarding actions to
be taken when the MOP screening criteria were exceeded.
After DECO questioned the need for a TS operability requirement because MOP limits
were exceeded, a further evaluation was performed. The Cycle 4 cladding strain was
evaluated in more detail for the conditions that exceeded MOP screening limits and GE
concluded that there was substantial margin to the one percent plastic strain limit. GE
also reported to DECO that a spot check of Fermi Cycle 3 RWE performance using
actual rod pattems showed no violation of the thermal mechanical limits. The inspectors
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confirmed this by review of the Fermi Cycle 3 analysis which was made available
following the GE Inspection. Sirc the cycle specific RWE analysis for Fermi 2 Cicle 3
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showed that actual MOP limits were not exceeded, the results of the previous generic 1
RWE analysis remained applicable to Fermi 2 and were reported in the November 1990
SRLR, Rev.1.
The Ferml 2 Cycle 5 SRLR was based on the original Cycle 5 core design and was
issued in December 1993. DECO performed a QA audit of the Cycle 5 core design in ,
December 1993. A Fermi turbine fire, also in December 1993, resulted in early I
termination of Cycle 4 and a redesign of the Cycle 5 core. Fewer fresh GE 11 type
bundles were required in the re design (58), and a re analysis of the RWE event
demonstrated that the original (SA) analysis was more limiting. Both Cycle SA and 5B
enalyses required the RBM to be operable to prevent the MOP criteria from being
exceeded. The Cycle SA analysis was competed on November 11,1993 (GE DRF
J11-02125, volumes. 6 & 7), while the Cycle 5B analysis was completed June 22,1994
(GE r~'} T11-02125, Vol.19). GE, in the original Cycle 5 SRLR, specified that RBM
shoule .a operable when moving control rods (to avoid exceeding of MOP limits for the
RWE event), in June 1994, GE repeated the recomm9ndation that at least one RBM
channel be operable when moving control rods for the redesigned core.
The inspectcrs determined, based on the Observations in the DECO Audit Report
93-032, and in later correspondence with GE regarding the Cycle 5 core redesign, that
DECO clearly understood the RBM operability requ;rements in 1993. Licensee
engineering personnel stated that they wrote a Deviation Event Report (DER) at the
beginning of Cycle 5 and began processing a TS change request, in addition to pursuing
additional vendor analyses to show that RBM operability was not required for Cycle 5.
However, in December 1994, when Fermi 2 retumed to power caeration, the licensee
did rot know whether R*1M operability was required during Cycle 5. Licensee engineers
stated that they made an assumption that RBM operability would not be necessary,
bated upon the core being less reactive than originally designed for Cyt,lo 5. However,
this operability assessment was not formally documented. In May of 1C95, in response
to a telephone request by the licensee, GE proposed a reanalys.ls of the operating Cycle
5 Fermi core, by performing a new PANACEA based analyses for the actual Cycle 5
core configuration and burnup history, that GE deemed would show RBM operability
was not required for MOP protection. The GE reanalysis was completed on August 22,
1995, and showed tha; MOP limits would not be exceeded during Cycle 5 operation.
Following recolpt of this analysis, the licensee canceled the TS change request, based,
according to the licensee, upon a commitment from GE to analyze future cores to
ensure dOP limits were not exceeded.
The Ci! PANACEA analyses for the Fermi-2 Cycle 6 core, which contained 176 new
GE-11 fuei assemblies and 452 previously burned GE 11 fuel assemblies, showed that
MOP limits would be exceeded within the control rod error cell for the RWE event,
without RBM operable. The SRLR for Cycle 6, issued 1996, stated: "At least one
RBM channel must be operable when moving rom der to protect for mechanical
overpower limits." At that time, instead of r ' o . S change, the licensee decided
to implement the requirement by a statement in r >re operating limih; report. NRC
issutd a violation on this issue, as documented c spection Repori Ls/34196013.
NRC permitted the licencee to start up using a: mstrative controls requirin; 'BM
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operability above thirty percent power while a TS change for the RBM operability
requirement was being processed by the NRC staff.
c. Conclusions
The GE 11 fuel design slightly exceeded the MOP screening limit established by GE.
Once the licensee became aware of this issue, further evaluation of both Cycles 3 and 4
was performed. Based on thlo evaluation, the licensee concluded that there was
substantial margin to tho one percent plastic strain design and licensing limit and that
the RBM operational requirements in TS 3/4.1.4.3 remained adequate during those
cycles. The inspectors concurred in this conclusion.
Both Cycle SA and SB analyses required the RBM to be operable to preverst the MOP
criteria from being exceeded. The analyses which demonstrated that the MOP criteria
for the one percent strain limit was met without the RBM operable was not completed
until August 1995, eight months after plant startup.
E1.3 Setoolnt Program
a. Insoection Scone
The inspectors evaluated the effectiveness of the licensee's setpoint process and
reviewed selected electrical or instrumentation and control (I & C) setpoint changes.
b. Observations and Findings
The inspectors noted that the licensee's existing setpoint and calibration program was
separated by whether or not an instrument was covered by the TS. The instruments
deemed "most important to safety" received the tightest controls by engineering in the
setpoint and calibration program. The inspectors determined that the setpoint design
calculations followed the guidelines of report NEDC 31336P A," General Electric
Instrument Setpoint Methodology" (1986). Although most surveillance and calibration
data sheets were available as computer records, some non technical specification
(generally, the less important balance-of plant (BOP)) calibration data tables were
maintained by the I & C shop in a master file cabinet. These sheets did follow guidance
provided by engineering on an instrument specification sheet, but the I & C shop had
some flexibility on the calibration points checked. The inspectors also found that some
BOP tolerances could be changed by system engineers who might use an angineering
analysis method that was not consistent with those used by th. specially trained
calibrat,on and setpoint engineers.
Tha engineering staff was conducting a multi-departmental review of the setpoint
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program and had requested information and procedures from other utilities to ascertain
the best methods available in industry and to benchmark their program against other
programs. From this review, engineering proposed a vrlidation program for the plant
data on instruments, manufacturer's specifications anu vendor manual guidelines. The
licensee believed that this would better utilize tolerances by supplying a range of
acceptable performance which would accommodate small, normal instrument drift for
non TS setpoints to minimize recalibration. The licensee also proposed converting to
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completely computerized records which would provide better engineering control and
oversight as well as provide case in grapNng and trending through updated software
capabilities. The inspectors considered the proposed improvements to the setpoint and
calibration program a good initiative toward the goals of increasing engineering control,
providing benefits in trending capability, and minimizing recalibration for less important
instrumentr' however, because the improvements were still in the planning stages, the
inspectors could not evaluate how effective the final p.ogram would be.
c. Concluslom
The inspectors concluded the existing setpoint and calibration program fulfilled the
requirements. Proposed improvements appeared to be good initiatives towards
providing more complete engineering control.
E1.4 Condensate Storage Tank Volume
a. insoection Scone
The inspectors reviewed an issue raised during the Fermi operational safety inspection
(FOSI), as documented on page 30 of Inspection Report 50-34196201, regarding the
available volume of the. condensate storage tank (CST). UFSAR section 6.3.2.6
contained a statement that the CST was designed to retain a minimum reserve of
150,000 gallons for use by the high pressure coolant injection (HPCI) or reactor core
isolation cooling (RCIC) system. However, the FOSI team had calculated the reserve
available for use to be only approximately 105,000 gallons, given the normallevel upon
switch-over to the suppression pool. UFSAR section 9.2.6.1 contained a similar
statement that the CST was designed to deliver its last 150,000 gallons only to the HPCI
or RCIC systems,
b. QDSprvations and Findings
The inspectors calculated the intemal volume, from the bottom of the tank to the
opening of the core spray standpipes, to be almost exactly 150,000 gallons, based
purely on the intemal tank diameter and the height of the standpipe. However, not all of
this water was available to provide a "miriimum reserve , , . for use by the HPCI or
RCIC systems," as stated in UFSAR Section 6.3.2.6, nor was the CST " designed to
deliver its last 150,000 gallons only to HPCI or RCIC" as stated in UFSAR Section
9.2.6.1. The inspectors determined that a certain volume of water, although physically
present in the tank, could not be used by the HPCI or RCIC systems. This was due to
the presence of a HPCl/RCIC standpipe and the height of the core spray and hotwell
standpipes. Additionally, vortex concerns, :ncluding instrument inaccuracies at
switch-over, required a minimum head of water to ensure operability of the HPCl/RCIC
pumps; this also reduct; the amount of water that, though physically present in the
tank, was available and deliverable for use by the HPCI or RCIC systems.
Specifically, the inspectors confirmed that the HPCl/ RCIC intake line had a short
standpipe (silt protector) that rose 5% inches above the tank bottom whiln the core spray
and hotwell supply and retum standpipes were located 8 feet,10% inches above the
tank bottom. The absoluie volume between these two standpipes was approximately
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143,000 gallons,7000 gallons less than stated in the UFSAR. Therefore, the inspectors
deemed that the absolute maximum amount of water " reserved for use" by the HPCI or
RCIC systems, under any circumstances, was 143,000 gallons.
The inspectors also noted that an additional volume of water would be lost due to the
need to switch HPCl/RCIC suction from the condensate storage tank to the suppression
pool prior to losing pump suction to prevent vortexing. This amount would vary,
dependent upon where the switch-over occurred. TS Table 3.3.3 2, entry 3.c required
the transfer setpoint to be set at or above 27 inches above tank bottom, with an
allowable value of 24 inches; the actual plant setpoint was 32 inches. Based on these
values, the amount of water "available" to the HPCI or RCIC systems would range from
116,000 gallons of water (at the TS allowable value) to a minimum of 105,000 gallons
(at the actual switch over setpoint).
The inspectors also observed that TS 3.5.3.b.3 required, in Operational Conditions 4
and 5, when the suppression peol level was less than 64,550 cubic feet, that the
condensate storage tank contalr *at least 300,000" available gallons of water,
equivalent to a level of 18 feet." The note stated: "The 300,000 gallons accounts for
150,000 gallons for CSS [ core spray system) and 150,000 gallons for HPCl/RCiC."
However, the inspectors observed that a level of 18 feet corresponded to an absolute
tank volume of 305,000 gallons. As discussed in the previous paragraph, at least 7000
gallons is physically unavailable for use. Therefore, a level of 18 feet did not provide
"300,000 available gallons."
The inspectors noted that other UFSAR and TS entries also referred to a specific CST
volume and might also need correcting.
The inspectors discussed the wording la the UFSAR and TS with the licensee. The
licensee acknowledged that the 150,000 and 300,000 gallons were based strictly on
tank volume and did not result in those specified volumes of water being usable by the
HPCI or RCIC systems. The inspectors recognized that the UFSAR stated that the CST
volume was not credited in any accident analysis, and that there were no safety
consequences due to the discropancies. However, the inspectors considered the
UFSAR and TS to inaccurately desenbe the amount of water reserved for use by HPCI
or RCIC, and that this discrepancy had been identified to the licensee nearly a year
earlier. The failure to take actions to correct this inaccurate information is considered a
violation of 10 CFR Part 50.9. (50-341/9701102(DRS))
c. Conclusions
The inspectors concluded that the UFSAR and TS misreported the amount of water
available to the HPCI and RCIC systems.
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E2 Engineering Support of Facilities and Equipment
E2.1 Reactor Core Isolation Cooling System Design
a. Insoection Scoan r
The inspectors reviewed licensing and regulatory documentation including the UFSAR,
applicable TSs, Design Basis Document E51-00, " Reactor Core Isolation Cooling
(RCIC) System," surveillance test procedures, and DERs as documented at tr.e end of
this report.
b. Findings and Observations
The inspectors reviewed UFSAR Section 5.5.6, * Reactor Core isolation Cooling
System," to verify that valve operation requirements were accurately translated into the
surveillance test procedures. The inspectors identified one example during this review
where the surveillance stroke time for valve F045 was 10 seconds higher than the
UFSAR listed value; however, the inspectors determined that the stoke timing for that
valve had changed due to the original globe valve being replaced with a gate valve in
Engineering Design Package (EDP) 27431. The inspectors verified that the UFSAR
was scheduled to be corrected to reflect this change in the upcoming revision. In
another example, the inspectors found that the surveillance for valves F007 and F008
used inservice testing (IST) stroke times Instead of the UFSAR stroke times. However,
j these stroke times were more conservative than the UFSAR values The inspectors
reviewed the IST program guidelines for determin!ng stroke time acceptance criteria and
agreed that the IST stroke timing appeared to be more capable of detecting valve
degradation in this case.
The inspectors reviewed a sample c' completed surveillances, and verified that the
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valves were meeting the UFSAR stroke times and that the RCIC system was capable of
delivering its design flow within 50 seconds after actuation.
The inspectors walked-down the RCIC system with system engineering personnel and
verified the location and condition of major pieces of equipment. The inspectors
considered the material condition of the RCIC system, and the plant in general, to be
good.
The inspectors reviewed a sample of DERs written against the RCIC system in the past
year. The corrective actions and root cause analyses appeared to be effective. There
did not appear to be any common causes for deviations in this sample.
The inspectors also reviewed tracking and trending of the RCIC system performance
with the system engineers. The inspectors noted several good practices during this
review. For example, all BOP and nuclear steam supply system (NSSS) system
engineers had completed a three-day training course on tube oil analysis. With
implementation of the Maintenance Rule, RCIC system engineers had been maintaining
data on RCIC functional failures and system health. The critical performance
evaluation program (CPEP) was also available to all system engineers. Through CPEP,
the system engineers were connected to all databases maintained by the plant. In the
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f case of the RCIC system, critical system rsrameters such as valve stroke times were
tracked and trended,
c. Conclusions
Valve operation requirements had been accurately translated into the surveillance test
procedures. The RCIC system appeared to be capable of delivering its design flow
within 50 seconds after actuation. Material condition of the RCIC system was
considered good. RCIC system engineers were doing an acceptable job of tracking and
trending system performance.
E2.2 Qoerability Determinations
a. insoection Scoce
b The inspectors reviewed the procedures for control of limiting condition for operation
(LCO) and operability assessments and interviewed a shift supervisor and cognizant
engineering personnel,
b. Findings and Observations
During an NRC service water operational performance followup laspection in July 1996,
a question arose regarding open and current operability assessments. At that time,30
engineering functional analyses (EFAs) were found, including 26 classified as
permanent. After further review by engineering, it was determined that only 10 EFAs
were active; however, there was no formal prescribed method for closing EFAs. DER
96-0760, " Enhancement of EFA Closure Process, * was initiated on July 7,1996, to
investigate enhancements to the process including a controlled active life and a formal
closure process.
During the Inspection, the inspectors reviewed the old EFA procedure, MES 39,
' Engineering Functional Analyses," Revision 1, which had been canceled, and verified
that the enhancements to the process were included in tha procedures for control of
equipment and verification of system operability, procedures MOP 05, * Control of
Equipment," Revision 5, and MES 27, " Verification of System Operability," Revision 2,
respectively.
The inspectors interviewed operations and engineering personnel relative to operability
assessments and LCOs. The inspectors determined that the tracking document for
LCOs, also titled "LCO," was stored in a three-ring binder in the control room. Time-
sensitive LCOs were discussed daily and were included in the meeting handout. The
inspectors were informed that LCOs were not entered voluntarily if work was expected
to take more than half of the time clock.
For LCOs that involved an operability assessment, the licensee generated an LCO, in
accordance with MOP 05, and a DER was generated with a 24-hour turnaround
expected. For any DER where the shift supervisor requested an operability
assessment, an EFA was required. The inspectors determined that the EFAs required a
higher level of signature authority than an engineering calculation. The inspectors also
13
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.
'
observed th,.s a * duty * system engineer was available 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> a day to assist
operations with operability assessments. The LCO and related operability assessments
were reviewed by the operations superintendant and then cleared by the shift
supervisor.
The inspectors ascertained that fer LCOs w:th short time clocks, operations or
'
engineering could also call in an "LER Team * to support and advise the shift supervisor.
This team could be chosen frem a list of 20 or 30 highly qualified engineers. At the
conclusion of the inspection, the inspectors noted that no long term EFAs were in offect.
c, Conclusions
(. The Inspectors concluded that engineering had effectively identified and corrected a
l problem with EFAs.
E2.3 Rod Position Indication Svstem (RPIS)
laspe.ctlan Scone (37550)
The inspectors reviewed intemal documentation on the current status of RPIS problems,
and the documentation for the licensee's position indication probe (PIP) Improvement
plan. The PIP Improvement plan was conducted during the fifth refueling outage and
involved extensive upgrade to the RPIS, including reed switches within the PIPS.
Findings and ObservatiODE
The licensee conducted a PIP Improvement program during the 5th refueling outage
due to ongoing problems with the RPIS. The lnspectors noted that the frequency of
RPIS indication problems had decreased from the level in earlier operating cycles, but
that the licensee still observed a number of indication problems since startup from the
fifth refueling outage. The inspectors determined that most occurrences had been in the
form of a " double-flash." The double flash of a position reading occurred during rod
movements, and appeared to be due to overly sensitive reed switches. The inspectors
determined that problems involving a required repositioning of a rod had nearly been
eliminated, with only two indications involving superimposure of false readings onto the
valid indication since the fifth refueling outage.
Conclusignt
The frequency of position indication problems had decreased, but occasional indication
problems still occurred. ,
E2.4 Modifications
a, lasoection Scoce
The inspectors reviewed a number of EDPs installed either during the last refueling or
maintenance outage, or scheduled for the upcoming maintenance outage.
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.
b. Observations and Findings
The inspectors found that, overall, the modification packages provided design
improvements. The modifications had good tec'.nical analysis and sound engineering
was used in implementation. The inspectors verified, for a sample of modifications, that
procedure and drawing changes associated with each modification were completed. In
general, work requests to implement the modifications were acceptable. However, the
following two minor implementation issues were identified:
In implernenting EDP-28180 to provide freeze protection in the residual heat removal
(RHR) complex, a work request was prepared which used the standard Fermi 2 access
control log for ensuring foreign material did not remain in the system. The inspectors
found, during review of these logs, that the paperwork had not been meticulously kept.
This led the inspectors to question the method of control and whether all foreign material
had been properly removed. Further licensee investigation revealed that the licensee
had thoroughly searched the work areas, prior to closeout of the modification
.
' paperwork, to ensure that no foreign material remained in the RHR complex that could
have impacted the ultimate heat sink, The licensee generated a condition assessment
I
resolution document (CARD) to review possible enhancements to the method of keeping
access controllogs.
l
l
'
In reviewing EDP 27297, which replaced recorders with Westronics 2100 recorders and
required loop calibration, the inspectors discovered a non-safety related loop ca!ibration
data sheet which showed evidence (by an uninitiated line-out and a numerical value
change on the water column portion of the tolerance equation) that shop personnel
investigated the possibility of using a larger tolerance than the one specified on the
sheet after the as found reading was outside the specified tolerance. Fortunately, in this
instance, recalibration i djusted the as left reading to be within the original specified
tolerance. The inspectors were concerned that engineering oversight was not strong
enough to ensure that proper tolerance was used. The inspectors determined that the
licensee was in the process of performing a comprehensive review and upgrade of the
setpoint and calibration program with goals of greater control by engineering and
incorporating improved methods used within the industry. The inspectors deemed that
this program would aid in preventing problems with personnel not adhering to specified
tolerances.
c. Conclusions
The inspectors concluded that the design modification program was generally effective
in improving plant design, despite the minor problems found.
E2.5 Igmporary Modifications
a. Insoection Scoce
The inspectors selected and reviewed eight of the eleven listed open temporary
modifications and reviewed plant procedure MES12, ' Performing Temporary
Modifications," Revision 2.
15
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e
b. Observations and Findinas
The inspectors judged the number of open temporary modifications to be reasonable,
and did not identify any problems or concerns with the temporary modifications. None
of the temporary modifications were safety-related or had been open for an excessive
period of time. The inspectors noted that the oldest temporary modification had been
installed for approximately eighteen months. The inspectors did not identify any
undocumented temporary modifications during the inspection. Licensee personnel
appeared to be knowledgeable of the modifications and the background. No problems
or concerns were noted in this area,
c. Conc!usions
The inspectors concluded that the licensee exercised good control of the temporary
modification program, based upon the limited number, non-safety classification, and
relatively short time the temporary modifications were left open.
l
E2.6 Residual Heat Removal and Core Sorav Strainer Head Loss and Net Positive Suction
I
Head Reauirements
a. Insoection Scone
l Based upon recent problems with discovery of undersizea strainers at other nuclear
i plants, the inspectors reviewed the strainer head loss and net positive suction head
l calculstions supporting the RHR and core spray systems,
b. Observations and Findings
The inspectors noted that the design basis calculations were available and retrievable
from the licensee's document control system. The inspectors confirmed that the
calculations used standard methodology and were mathematically correct, including
confirmation of the core spray piping head losses by review of the isometric drawings.
The inspectors observed that major differences in the Fermi design involved individual
strainers to each suction line, large strainer size, and sufficient elevation differential
between the suppression pool and the pump centerline. The inspectors deemed that
the calculations provided sufficient justification to show adequate net positive suction
head available for the RHR and core spray pumps under ali modes of operation.
c. Conclusions
The inspectors concluded that there was adequate net positive suction head available
for the RHR and core spray pumps. Furthermore, the inspectors concluded that the
licensee's program to perform and maintain design basis calculations appeared
satisfactory, based upon the three calculations reviewed.
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s
E3 Engineering Procedures and Documentation
E3.1 Safety Evaluation (SE) Process
a. insoection Scoce
The b)pectors reviewed a number of SEs performed in accordance with 10 CFR 50.59
and associated with recently installed modifications. Additionally, several procedure
SEs were selected and reviewed. A list of the SEs reviewed can be found at the end of
this report.
b. Observations and Findinas
in general, the inspectors noted that the licensee performed safety evaluations on
modifications when needed and that the responses to the questions of 10 CFR 50.59
were answered appropriately. This was an improvement from the findings of the last
engineering and technical support inspection.
,
'
However, there were still some instances where further improvement was warranted.
One example was the failure to identify a required TS amendment for removal of the
l response time testing requirements, as discussed in Section E1.1. The NRC previously
l
' identified a similar problem (not obtaining a required TS amendment) In Inspection
Report 50-341/96013(DRP)).
Another example was use of Generic Letter 91 18, " Operability Determinations," to
l support the conclusions of SE 95-0036, Revision 1. The inspectors informed the
i
licensee that the generic letter provided guidance for licensee actions when a system
was degraded, and when corrective actions to resolve the degraded condition were
planned; however, it was not intended as guidance for permanent resolution of the
degraded condition. Upon further review, an additional, more significant concem was
identified with SE 95-0036. This is discussed seperately in Section E3.2.
c. Conclusions
Overall, the inspectors concluded that the safety evaluation program had improved.
However, some problems still existed.
E3.2 Potential introdstion of New Failure Mode for Safetv-Related Comoonents
a. insoection Scope
The inspectors reviewed SE 95-0036, Revisions 1 and 2, which discussed a change to
the UFSAR to describe a change in the operation of the emergency equipment cooling
water (EECW) system. This safety evaluation was reviewed to follow up on a concern
raised by the NRC during an earlier inspection as to whether the licensee had
considered accident scenarios outside containment during review of this change to the
facility.
17
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b, Observations and Findingli
The inspectors noted that the SE described the change to the facility to permit use of
one or both divisions of the EECW system to augment the reactor building closed
cooling water (RBCCW) system during normal operation. The inspectors ascertained
that the UFSAR had contained a statement, describing the operational philosophy of the
plant, which prohibited use,of EECW during normal power operation. Specifically, the
UFSAR, Revision 7, Saction 9.2.2.2, " System Description," fifth paragraph, had stated, in
part, *During normal plant operation, both EECW divisions are isolated from the RBCCWS
by motor-operated isolation valves. Upon loss of offsite power, high drywell pressure, or
failure of the RBCCWS, both divisions of the EECWS are automatically activated; that is,
pumps start, makeup tanks isolation valves open, and valves isolate the nonessential
portion of the RBCCWS. The makeup tanks isolation valves do not start to open until the
divisionalisolation valves are closed. Upon loss of RBCCWS differential pressure
between the supply and retum headers, either Division I and/or Division ll EECW loopc
will start automatically, depending on the portion of the RBCCWS affected. The EECWS
may also be manually initiated."
,, The inspectors also noted that an operating procedure and two alarm response
procedures required revision to describe new actions necessary as a result of this
change, and that these types of procedures were discussed in the UFSAR. Therefore,
the inspectors found that, although no hardware modifications occurred in the EECW
system, there was a " change to the facility" as described in UFSAR. Finally the
inspectors noted that TS 3.7.1.2.b described operability of EECW in terms of a flow path
" capable of removing heat from the associated essential equipment."
l
The inspectors determined that prior to this change, the licensee ran EECW, one
division at a time, for test purposes only. Fcilowing the change, the licensee had, on
occasion, run both divisions of EECW simultaneously. During periods when EECW was
augmenting RBCCW, operators were required to deliberately bypass the automatic
isolation of non essential loads (which occurred whether the EECW was automatically or
manually initiated)in order to provide cooling to these loads. This resulted in the
differential pressure sensors, which would detect an RBCCW failure, being disabled.
However, other automatic l solation signals, such as high drywell pressure or loss of
offsite power, would be unaffected and would still actuate.
! In October 1996, during review of Revision 0 of the SE, NRC questioned whether the
licensee had evaluated all accident scenarios where EECW might be cal!sd upon. In
response to these questions, the licensee identified a high energy line break (HELB) in
the RCIC system outside of containment, where operator action to isolate the
nonessentialloads would be necessary to ensure that the essentialloads continued to
receive adequate cooling. The particular scenario was a " maximum safeguards"
scenario where offsite power was not lost. Had offsite power been lost, then EECW
would have received an automatic initiation signal, which would have isolated the
non-essentialloads. Instead, during a maximum safeguards HELB, offsite power was
not lost, such that normal cooling systems were assumed available. Prior to the
change, or if EECW was not manually initiated, RBCCW would provide cooling to both
the essential and non-essential loads, if a single failure of RBCCW occurred, then
EECW would automatically start, and pick up the essentialloads, leaving the
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.
non essentialloads isolated. However, following this change, RBCCW would not
provide adequate cooling to the essential loads, EECW would not receive an automatic
start, and the non-essentialloads would not isolate. The licensee evaluated the effects
of leaving the non-essential loads unisolated and determined that some essential loads
would not receive their design basis cooling flows. The licensee performed a further
evaluation to determine the effects of the less than adequate cooling and the time
available to restore adequate cooling. The licensee determined that thanual operator
action was necessary to reinitiate EECW upon a high EECW supply temperature.
The inspectors reviewed the above scenario and were concemed that the use of EECW
to augment RBCCW had created the possibility of an equipment malfunction of a
different type than any evaluated previously in the safety analysis report. The inspector
determined that neither manual initiation of EECW nor inadequate cooling to essential
loads had been previously analyzed as part of the HELB scenarlo. The inspector
confirmed that no procedures had previously required EECW to be manually initiated to
respond to any event. The inspectors discussed the scenario with reviewers from the
Office of Nuclear Reactor Regulation, Human Factors Branch. The reviewers agreed
that the change to the facility had created the possibility of an equipment malfunction of
a different type than previously evaluated and that this change involved an unreviewed
safety question.
The inspectors noted the following deficiencies in the licensee's safety evaluation:
1) In response to several of the safety evaluation questions, the licensee wrote that
,
"ARPs 1D88 and 2D14 isolate the non-essentialloads." The inspectora
determined that ARPs 1D88 and 2014 were actually procedures, which were
revised during this change to provide inst'uctions to the operators to take manual
action to isolate the non essentialloads The safety evaluation did not address
that a new requirement was made upon tha operators or what the consequences
wore of the operators failing to take those manual actions.
2) The licensee responded to one safety evaluation question by stating "All
safety-related automatic controls for EECW and EESW (emergency equipment
service water) operation remain effective during a DBA (design basis accident).
Operator actions to support the EECW system during a HELB are not inhibited
or changed by EECW augmenting the RBCCW system. During a HELB, EECW
is manually initlated." The inspectors noted that these sentences gave the
incorrect impression that no safety related automatic signals were disabled by
this chanoe. The inspectors confirmed that the signals causing an automatic
start of EECW upon loss of RBCCW were isolated when EECW was manually
l initiated, eliminating this automatic start. The inspectors noted that the response
also gave the incorrect impression that operator actions were required during a
HELB prior to this change being implemented. The inspectors further confirmed
that, prior to this change, operator actions to initiate EECW were noi required
and that no procedure had previously directed the operators to manually initiate
3) The licensee responded to another safety evaluation question with "No changes
are made to the p: ant design or equipment as a result of this change to the
'
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. _ _ _ - - _ _ - _ _ _ _ - _ _ --
, a
UFSAR." The inspectors noted that this statement, while true in the sense that
no physical modification or design drawing changes needed to be made, was
inaccurate in that the plant was desioned for the EECW system to operate only
in response to off normal events. The licensee's response to this question went
on to state "No malfunction of equipment is anticipated since there are no
physical changes or functional changes being made to EECW or the plant as a
result of this SE." The inspectors disagreed that no functional changes were
made, as the change to allow EECW to augment RBCCW required a functional
change in the plant procedures to require operator action without which
equipment malfunctions, due to inadequate cooling, could occur.
4) The safety evaluation also contained the following statement:" Operation of the
EECW/EESW in support of RBCCW augmentation during power operation does
not differ significantly from operation of EECW/EESW in divisional outages
during a reiueling outage when RBCCW or GSW [ general service water) is out
of service." The inspectors noted severalImportant discrepancies in this
statement: First, the licensoe previously used EECW only one division at a time,
while this change allowed for both dMslons to be used. Second, there was a
major difference between the plant being shutdown for a refueling outage and
the plant being at power operation in terms of the equipment operating and the
heat loao on that equipment. Finally,10 CFR 50.59 requires that licensee's
ascertain only if the possibility of a different type of malfunction was created, not
to determine the significance of that malfunction,
c. Conclusions
Based on the above discrepancies, the inspectors concluded that the licensee failed to
recognize that the possibility of equipment malfunctions due to inadequato EECW flow
was not previcusly analyzed in the UFSAR an apparent unreviewed safety question.
This is considered an apparent violation of 10 CFR 50.59. (eel 50 3419701103)
E3.3 Revision to Tqrminal End Pine Break DefinitiDD
a. Insoection Secoe
The inspectors reviewed SE 97 001, in which the licensee evaluated a change to the
UFSAR wording to the term " terminal end." The licensee noted that the definition being
proposed did not match the one in NRC mechanical engineering branch technical
position MEB 3-1. Specifically the licensee took exceptien to a statement in MEB 3-1
that "In piping runs which are maintained pressurized during normalplant conditions for
only a portion of the run (i.e., up to the first normally closed valve) a terminal end of
such runs is the piping connection to this closed valve." Instead, the licensee proposed
to revise the UFSAR to include, in the terminal end definition, in lieu of the above ;
italicized sentence, the fo'!owing: "In-line littings, such as valves not assumed to be !
anchored in the piping code stress analysis, are not terminal ends."
20
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. *
b.' Qbservations and Findings
The licensee identified eight valves that would be affected by the MEB 31 definition. ,
However, the licensee contended that the eight valves were Doi termina! ends because: I
(1) the valves were not anchored either at or close to those locations, (2) the piping
code class did not change at the closed valves and (3) the pipe stresses in the vicinity of
the valves were low.
The inspectors determined that the rationale behind the MEB 3-1 statement was to
ensure that licensee's evaluated the increased stress that would occur due to
l differences in pipe schedule or material, discontinuities in stresses due to welds or
l Deometric differences, and restraints to pipe motion around the valves, due to supports ,
i or other partial anchors, The inspectors confirmed that the piping code class and '
material did not change at the eight valves under cortention, that the stresses due to the l
welds and geometric changes were low (under the valuet assumed for arbitrary !
intermediate pipe breaks) and that the piping was not anchored in the vicinity of the
valves. Therefore it appeared that the concems behind the MEB 31 sentence did not
,
apply to Fermi. The inspectors discussed this issue with pipe break experts within NRC, !
who agreed that the Fermi definition of terminal ends was acceptable and met the intent
of MEB 3-1.
c. Conclusions
The inspectors concluded that SE 97-0071 adequately defined the term " terminal end,"
although the term differed from the standard NRC branch technical position wording.
E3,4 Modifmations to Emergency Ooerating Procedures Due to inannuracies in Calculation
Methodoloav
lasoection Scone (37550)
The inspectors reviewed recent discrepancies in calculations for parameters used in the
plant Emergency Operating Procedures (EOPs). DER 97-0428," Fuel Design Specific
EOP Parameters" was reviewed.
Findinos and Observations
in supplement 1 of service information letter (SIL) 529, General Electric (GE) Informed
the BWR industry that another BWR/4 recently discovered that the fuel specific action
levels and limits used in the EOPs were not appropriate for that plant's current fuel load,
which consisted of GE 9x9 fuel. The existing EOP action levels and limits were based
on GE 8x8 fuel.
The purpose of Supplement 1 was to inform BWR owners that, in addition to the -
maximum suberitical banked withdrawal position noted in SIL-529, dated February 19,
1991, there were other parametars used as input to the calculations in Appendix C to
the BWR emergency procedure guidelines (EPG), revision 4, which were specific to
reload fuel design. Specifically, four steam cooling related parameters included in the
generic data of Appendix C to EPG revision 4 were applicable only to GE 8x8 fuel
21
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,
designs, in addition, Appendix C generic data included two shutdown boron weight
parameters which might be different for new fuel designs.
The licensee subsecuently reviewed Supplement 1 to determine whether any EOP input
data needed t > be revised. The licensee determined that in one instance, EPG
Appendix C Calculation Worksheet 10, *RPV Variablos Worksheet/' the generic data for
9x9 fuel resulted in a shorter * maximum core uncovery time limit * which made the Fermi
2 calculatioris less conservative. The licensee updated Worksheet 10 to reflect the
more conservative generic input data provided in the GE SIL 529 Supplement 1. The
inspectors verified that the corresponding Fermi EOPs were also updatad.
.
. Conclusions
,
Yhe inspectors concluded that the licensee addressed, in a timely manner, the issues
raised by inaccuracles in the vendor supplied EOP information.
E4 Engineering Staff Knowledge and Performance
E4.1 Processes for Determining Recetitive Problems
a. losoection Scoon
The inspectors conducted a review of tracking systems available to licensee engineering
to detect generic / repetitive problems and rework.
b. Observatbns and Findings
The inspectors noted that the licensee work control group tret;ded a rework rate based
on conective maintenance and preventative ma!ntenance and published a list of
components that required rework monthly. Surveillances were numerically tabulated to
track those completed with as expected data or problems encountered which allowed
numerical tracking of surveillance rework. Additionally, the maintenance engineering
department had collateral dut es to investigate recurring problems. The inspectors did
not identify any programmatic concerns with these programs; however, the inspectors
noted that some rework as the result of poorly prepared procedures had been identified
by quality assurance audits or through self assessments.
c. Conclusions
The inspectors concluded that methods were in place to cover tracking and trending of
data which gives indication of trends in retvork.
E4.2 Control of Contractors
a. InsoectiqILScopa
C
The inspectors evaluated licensee controls of engineering contractor activities.
22
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O
b. Observations and Findings
The inspectors evaluated enhancements which were developed after Quality
Assurance,in DER 95-0434, identified that one of the significant causes of
recent design certification acceptance test failures and underlying EDP errors
was inadequate review and control of Architect / Engineer and vendor designs.
The licensee developed a strategy to identify high risk EDPs so there would be
heightened awareness among supervisors of the potential for problems when
design was done by an outside firm. AdditionalIlcensee actions included early
and regular review of Architect Engineer or vendor designs and feedback about
Fermi's expectations on the design work. Additionally, PEPS-0018, " Plant
Support Engineering Practice Standard Contractor Control," was developed to
proceduralize contractor control.
c. Conclusigns
The inspectors concluded that the licensee was acting to correct inadequate control of
contractors.
E5 Engineering Staff Training and Qualification
E5.1 Trainina on the New Corrective Action Process
a. Inspection Scoce
The inspectors attended training sessions conducted on the recently developed
corrective action program and discussed the training and training methods used with
licensee personnel.
b. Observations and Findings
During the review of the new corrective action program, the inspectors selected and
attended portions of the training on the new program and observed trainirg which was in
progress for engineers and other licensee personnel. The inspectors were briefed
thoroughly on the new corrective action program as well as the training methods used.
The training was approximately three hours in length and appeared to be thorough and
well organized. The instructors appeared to be knowledgeable and well versed in the
new program. The course consisted of a presentation on the new program with a
discussion of the existing corrective action program with its weaknesses. Several
training aids, such as fiow charts, were used to help in the training.
Personnel were organized in planned groups of approylmately six people from dFferent
functional areas with an assigned discussion leader. After the initial presentation, these
Individual groups discussed the new program with emphasis '. n the correction of the
weaknesses of the previous program. The groups then discussed and practiced
completion of the new corrective action form.
23
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Licensee personnel stated that more than a thousand people had been trained in the
new program and that additional training would be provided when the implementing
procedures were issued for use in the near future.
c. Conclusions
The inspectors concluded that the training provided for the new corrective action
program was very good.
E7 Quality Assurance in Engineering Activities
E7.1 Indeoendent Safetv Engineerino Grouo (ISEG)
The inspectors reviewed twelve ISEG reports completed in the past year. The quality of
the reports was good. Based on the reports reviewed, the inepectors concluded that
ISEG was adding value to the site organization by Improving nuclear safety and
contributing to the reduction of personnel errors.
E7.2 Engineering Self Assessments
a. Insoection Scoce
The inspectors reviewed the 1997 Annual Assessment Plan," System Engineering &
Plant Support Engineering," as well as eight engineering self assessments completed in
the past two years,
b. Findings and Observations
The inspectors determined that the engineering assessments were completed by
engineers in the Engineering improvement Group and were of acceptable quality. In
addition, audits or assessments of engineering we 3 completed by the Ouality
Assurance department and various other technical orgnizations. For example, Plant
Support Engineering issued a critique on replacement o1 the selector switch on
H11P085 and Nuclear Fuels and Reactor Engineering issued a report en fuel failure
response. However, the inspectors noted that there did not appear to be an overall site
plan for self assessment of engineering. The Engineering improvement Group was
attempting to track all self assessment in the engineering area, but it was an informal
system based mainly on personalinitiative.
c. Conclusions
The inspectors concluded that completed engineering self assessments were
acceptable; however, the program appeared to be fragmented or lacking in formality.
24
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E7.3 Engineerina involvement in the Corrective Action Proaram
a. Insoection Soope
The inspectors attended training sessions on the recently developed corrective action
process and discussed the new process with licensee personnel.
l b. Observations and Findinos
l
'
Both the NRC and the licensee have previously noted problems with the corrective I
action process at Ferml. As a result of these problems and concerns, licensee
personnel developed a new conective action program. This new program changed the
way conditions adverse to quality were documented and resolved; including changing i
the documentation form from a DER to a CARD.
The licensee performed extensive training on this new program during the inspection,
with training completed for more than 1000 plant personnel. The inspectors attended
selected portions of the training and were briefed thoroughly on the new program. This
training is discussed in Section E5.1 of this report,
f
! Licensee manaCement personnel stated that the new program would resolve most
corrective action concerns and would help create a new corrective action oriented
culture among licensee personnel. By the end of the inspection, the licensee had issued
the procedures and begun implementation of the new program.
Many of the program features appeared, to the Inspectors, to be effective ways to
onst'm that conditions adverse to quality were identified, documented, and corrected in
su* a manner as to prevent recurrence. However, the inspectors were unable to
set.- . the true effectiveness of the program, because the program was not fully
inpnented,
c. Conclusions
The inspectors concluded that, the new corrective action program appeared promising,
but was not yet fully implemented.-
E8. Miscellaneous Engineering losues
E8.1 (Closed) Unresolved item 50/34194019-02: Standby Feedwater Pipe Hanger
Deficiencies. This item involved inspector identification of possible pipe rnovement in
the standby feedwater system. To resolve this issue, the licecpe analyzed the pipe
and installed five new restraints to restrict pipe movement. The inspectors performed an
independent walkdown of the standby feedwater system, and concluded that the new
restraints would restrict the previously observed pipe movement. The inspectors
concluded that the issue was resolved. This item is closed.
E8.2 (Closed) Violation 50-341/95005-01: Failure to Perform 50.59 for DAS Hookup. Based
on a misconception that the DAS equipment was non-obtrusive because of its high
impedance, FIP-OP1-02, " Temporary Modifications," was not employed to hook up the
25
X
_ __ __ __ ________ _____ _- - - ___ _ ___ __ _
_ _ _ _ _ _ -
,
.
DAS equipment, which would have required a 50.59 safety evaluation. Because the
entire evolutlo.1 was viewed as short term trouble shooting, FIP-CT1-03, * Preparation
and Performance of Diagnostic Special Tests and Infrequently Performed Test', or
Evolutions,"was also not considered. Again this would have required a 50.59 SE had it
been employed.
The inspectors reviewed FIP-OP1-02, Revision 2, and FIP CT1-03, Revision 9, to verify
that they had been revised to cleaily differentiate between measuring and monitoring of
plant parameters. The inspectors reviewed SE 95-0015 which evaluated the shifting of
administrative controls for measurements from the temporary modification procedure to
the preparation and performance of a diagnostic special test procedure and reviewed
both of these procedures against the appropriate IEEE standards. The inspectors
reviewed records that indicated System Engineering had completed ad hoc training on l
'
the need for conservative decision making and the need to utilize the 50.59 process. In
addition, a trhining lesson plan was developed and provided to System Engineering,
Plant Engineering, Operations, Maintenance, and the planning staff. The subjects in
thic training included understanding the appropriate use of test equipment,
l understandnig the controls applied to test equipment, when the controls should be
l
!
applied, and how to apply these controls. The inspectors reviewed the content of the
training presented and considered it acceptable to prevent recurrence. This violation is
l considered closed.
E8.3 (Gupd) Violation 50-341/95005-02: DAS Hooked Up to Both Divisions of RPS. As
I
discussed in the violation above, the correct procedures were not employed during the
trouble shooting for the spurious RCIC level 8 sequence of events recorder point. Had
the correct procedures been employed, either FIP-OP102, or FIP CT103, the event
could have been prevented. FIP-OP102 specifically required review of a proposed
temporary modification for conformance with electrical separation criteria. Also, OSRO
approval would have been required. Further, step 5.5 of FIP-CT1-03 stated that special
16sts shall not include cimultaneous testing of both Division I and ll systems or
components in the same section of a test. Therefore, the inspectors considered the
corrective actions taken to be adequate. This violation is considered closed.
E8.4 (Closed) Violation 50 341/95005-03: Failure to Utiliza SOE or Temp Mod Procedure.
The inspectors considered the corrective actions taken in 95005-01 and 95005-02 to be
acceptable; therefore, this violation is considered closed.
E8.5 {Guqdi insoection Follow!io item 50/34195009-04: Review of RHR Water Hammer
Issues Associated with Information Notice 87-10. The issue involved occurrence of a
water hammer following a loss of coolant accident concurrent with a loss of offsite power
while in the shutdown cooling mode. To resolve this issue, the licenseo participated in a
BWR owner's group study; from which came several recommendations. The inspectors
verified that the owners group recommendations were implemented into plant
procedures. Additionally, the NRC had identified severai concerns in inspection repsrt
50/341-95009. The Inspectors reviewed the licensee's evaluation of those concerns and
concluded that they were adequately resolved. This item is closeo.
E8.6 (Closed) Violation 50/34190002-10: Inadequate Operating Procedurc Revision
Following Modification to the RHR Minimum Flow Valves. During a license examination,
26
. _ _ _ _ _ _ _ - _ - _ _ _ _ _ _ _ _ _ . .
.
-
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+
the NRO idenimed that training materials and operating procedures had not been
properly revised following a modification to the RHR minimum flow valves. To resolve
thu issue of outdated data present in different documents, the licensee revised the
training materials and operating procedures and conducted training on expectations and
responsibilitier for enauring the operating procedures would be identified and updated
when required by plant modificat!ons. The inspectors confirmed that the training
materials and operathy procedures were updated and training had been conducted.
The inspectors conc',uded that this lack of attention-to-detall issue was resolved and the
licornee had taken oppropriate actions. This item is closed.
E8.7 IClouMr2iEsAt1Lem_ 50/341 96DD2 13: UFSAR Discrepancies. Several
discrepancies W.src d$ covered between actw6 plant condOns or practices and the
Information presented in the UFSAR. The examples incluced confusion caused by
specifying the plant radioactive waste volume reduction and solidification system as
primary when in practice a vendor was used, by specifying a plant contaminated laundry
system when an outside vendor laundry facility was used, and by not explaining that
cable divislenal coloring occasionally had been used in BOP electrical distribution. In
response to this issue, the licensee corrected UFSAR discrepancies including items of
concern in Sections 8.3.1.5.1 and 11.5 of the UFSAR. The inspecars confirmed that
revision 8 of the UF', AR had been docketed May 5,1997. The inspectors concluded
that the licensee h6J taken reasonable action to resolve discrepancies identified. This
item is closed.
E8.8 (Closed) Violation 50/341-96004-06: Inadequate Investigation of RHR Service Water
(RHRSW) Flow Reduction. Fifteen months after an unexpected reduction in service
water recirculetion flow when a mechanical draft cooling tower bypass valve was closed,
the licensee had not determined the cause of the event. Following issuance of the
violatior' the Ilcensee acknowledged that a root cause for the event was not adequately
pursueo. The licensee held a " lessons learned" training session to stress the
irmportance of determining the root cause of events. The licensee was also in the
process of revamping its corrective action process, as discussed in Section E7.3. The
licensee acknowledged that it could r,ot eliminate blockage of the line due to Ice
formation as a possible root cause. The inspectors reviewed the lessons teamed
tralning and concluded that the licensee took adequate corrective actions for the
previously inadequate investigation. This item is closed.
E8.0 (Closed. Insoection Followuo item 50/34196004-09: Active Seismic Monitoring
System. The !icensee discovered that the active seismic monitoring system surveillance
did not n,eet all Technical Specification requirements. To remedy this issue, the
licensee revised surveillance procedures to ensure compliance with technical
specifications. The inspectors ccnfirmed the calibration was now covered and the
accelerometeg and the omnitrigger setpoint were now verified against a standard in an
offsite bench test. Additional!y, the licensee replaced the seismic monitoring system
recorder with a newer technology model to aid in reliability, because repair parts for the
older model were no longer available. The inspectors concluded that these actions
effectively addressed the issue. This item is closed.
E8.10 [CJosed)Insoection Followuo item 50/34196005-04: Spent Fuel Pool Review. The
licensee discovered several issues as cocumented in DERs 95-1021,96-0235, and
27
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_ _ _ _ _ _ _ - _ _ _ _ - _ _ _ _ _ _
,
96-0306, The inspectors reviewed the packages that closed-out the above DERs and i
concluded the licensee's corrective actians were appropriate. The inspectors had no
further concerns. This item is considered closed.
E8.11 (Closed) Violation 50/341-96006-01: Not All RHR:sW Valves included in System
Operating Proceduro (SOP). The !!censee reviewed the drawings and identified a
second valve not incorporated in the valve lineups. The licensee revised the SOP to
incorporate these valves. The inspectors confirmed that the SOP was revised. This
, item is closed.
E8.12 (Coen)Insoection Followuo item 50/341-96006-04: No Provision to Stroke Time Tust
Valve included in Inservice Testing Program. The licensee had prepared a relief
request to refrain from stroke time testing tha valves and had submitted it to NRC
l (Office of Nuclear Reactor Regulation). NRC was reviewing the relief request at the
time of the inspection. This item will remain open, pending NRC approval of the relief
l request.
E8.13 (Closed)Insoection Followuo item 50/34196006-09: Failure to Identify Thermal Aging
Components identified in Vendor Service Information Letter. The original action by plant
personnel, to replace the GE CR120A relays in response to the SIL, did not identify
relays located in " black box" or skid supplied equipment. During a subsequent review of
this type equipment, licensee personnelidentified 48 additional GE CR120A type relays
which had not been previously identified. Replacement coils were ordered for the relays
with the installation to be scheduled as soon as practical after the coils were received.
l During discussions, licensee personnel stated that steps had been taken to ensure that
" black box" type equipment would be included in searches for other generic component
problems. This item is closed.
E8.14 (Closed) Insogtlon Followuo item 50/341-96007-04: Emergency Diesel Generator
(EDG) 12 Tripped Due to Failed Circuit Cards. The EDG tripped during post
maintenance testing due to a generator ficid failure. Following the trip, licensee
personnel determined that the failure of a card in the EDG automatic voltage regulator
circuit caused the failure. The defective card was replaced and retumed to the supplier
for cause determination. The cause was determined to be a defective integrated circuit
>
chip on the card. The chip was replacad and the card was successfully tested No
generic type problems were identified. The inspectors concluded that the action taken
was adequate. This item is closed.
E8.15 (Closed) Violation 50/341-96010-04: Failure to Follow Test Termination Criteria After
Loss of Core instrumentation. A test engineer failed to rmynize that loss of indication
on the portable test monitoring instrumentation wie: a test termination criteria and
communications about the loss of ind;0& tion with the senior line manager did not get
passed on to the test director. After a review of the performance of the test, the
licensee determined that the test engineer was not trained specifically to operate the
portable instrumentation and that responsibilities for the senior line manager and the
test director were not clearly delineated such that concurrent duties could distract them
( from performing their primary function relating to conducting the test. The inspectors
confirmed MES 31, revision 3, now included clearer instructions for conducting tests.
The inspectors concluded that appropriate actions had been taken. This item is closed.
28
1
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p _ _
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1 1
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. = <
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i E8.16 (Closed) Unresolved item 50/34196013 08: Incomplete Safety Evaluation on EECW.
- -
Safety evaluation 95-0036 did not fully evaluate the consequences of operating the
i
EECW system to supplement the RBCCW system. This issue is discussed in Section
2
E3.2. '
- !
E8.17 (Closed) Insoection Followao item 50/34196201-01: Inadequate Guidance for ,
- . Classification of DERs. As discussed in Section E7.3, the licensee changed from the -
DER system to the CARD system. The new system appeared to significantly change
the licensee's method for identifying, documenting and resolving conditions adverse to !
quality. This item is closed.
E8.18 (Closed) Insoection Followun item 50/34196201-02: Lack of Guldance for Classifying '
'
i Trend DERs._ As discussed in Section E7.3, the licensee changed from the DER
! system to the CARD system. The new system appeared to significantly change the ,
licensee's method for identifying, documenting and resolving conditions adverse to
,
quality. This item is closed.
- E8.19 ~ (Closed) Insoection Followun item 50/34196201-03: Failure to identify and Train Root !
l Cause Evaluators. As discussed in Section E7.3, the licensee changed from the DER
system to the CARD system. The new system appeared to significantly change the
licensee's method for identifying, documenting and resolving conditions adverse to
quality. This item is cloaed.
s
E8.20 (Closed) Deficiencv 50/341-96201-01: High Piessure Coolant injection System UFSAR
. Errors [ Tracked as Inspection Followup System item URI 96201-10.] The Ferm! ,
L Operational Safety Inspection identified a number of discrepancies in various sections of
j the UFSAR relating to the HPCI system. The inspectors evaluated the discrepancies .
- and found that some of the examples were due to the differing purposes of the differing
UFSAR sections. For example, Table 6.3-6 provided a summary of accident analysis '
input variables. These variables are lower than those used in the TS or the actual plant,
- to provide a margin of safety within the design. Therefore, a numerical discrepancy is
- necessary. In other cases, the licensee corrected the UFSAR or restored the system
- function to match the UFSAR. One discrepancy which did not get resolved was the
- CST volume; this is discussed in Section E1.4.
t
i E8.20 (Closed) Unresolved item 50/341-97002-Q5: EECW System Deficiencies. This item was ;
'
discussed in Inspection Report 50/34197003 and an inspection followup item was
opened (See section E8.21). The inspectors also reviewed the associated safety '
evaluations, as discussed in sections E2.4 and E3.1. The inspectors concluded that the
,
licensee's actions were appropriate and had no further concerns, This item is closed.
,
E8.21 (Closed)Insoection Followuo item 50/341-97003-10: NRR Heview of EECW Design
icsues.- This item is discussed in section E3.1.'. This item is closed. ,
,
- E8.22 (Closed) Unresolved item 50/341-9700311'
- Reactor Protection System Response Time
L Testing TS Compliance. This item is discussed in section E1.1. This item is clowi
',
i
i E8.23 (GQ&pd) Licensee Event Reoort (LER) 50/34195001-00: Reactor Water Level
Indication Transient. This LER is associated with violations 95005-01 through A" Nee
l 29
!
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_ _ _ _
. o
f
Sections E8.2 - E8.4). Based on the review done in those sections, the inspectors
concluded that the LER corrective actions were satisfactorily completed. The LER is
closed.
E8.24 (Closed) LER 50/341-95008-00& -01: One Megawatt Nonconservative Bias Found in
Core Thermal Power Calculation. LER 95-008 pertained to an omission of the control
rod drivo flow directed to the reactos recirculation pumps for seal flow. This flow of
approximately four gallons per minute to the primary system resulted in an
approximately one megawatt nonconservative error in the heat balance. Corrective
actions included accounting for the effects of the control rod drive purge flow into the
reactor heat balance calculations by a modification to the process computer and manual
heat balance calculation methodologies via a change to the Radiative Heat Loss
Constant. The inspectors verified that this action has been completed.
E8.25 (Closed) LER 50/341-96005-00: Emergency Equipment Cooling Water Makeup Tank
Inoperable Due to Design issue. This issue is discussed in Inspection Report
50/341-96003. This item is closed.
E8.26 (Closed) LER 50/34196007-00: Plant Shutdown Due to Technical Specification 3.0.3
Entry. This issue is discussed in inspection Report 50/341-96003. This item is closed.
E8.27 (Closed) LER 50/34196013-00: Heat Balance Impact Due to Reactor Recirculation
Pump Power Computer Error. LER 96-013 pertained to an error in the core heat
balance due to a discrepancy in the calibration as-found data between a recirculation
l pump motor power wattmeter and the associated process computer point. The impact
l on the heat balance calculation was that the calculated core thermal power could be up
(
'
to approximately three megawatts thermallower than actual power. Corrective actions
included adding the reactor recirculation pump motor puwer instrument loop to the Fermi
configuration management system and revising the associated calibration instruction.
The licensee also committed to evaluating inputs to the process computor relating to
heat balance for similar problems. The inspectors verified that these actions were
completed prior to cycle 6 startup.
E8.28 (Closed) LER 50/341-96019-00: Inoperable Standby Feedwater System Flow Path for
10 CFR Part 50, Appendix R Applications. The licensee identified that TS 3.7.11
requirements for Appendix R attemative shutdown requirements were not always being
met. Specifically, the minimum CST level to ensure standby feedwater operability was
not being maintained. The licensee performed a calculation and determined the
minimum CST level for safe shutdown use. The licensee revised procedures to require
a minimum tank level of 22 feet. This licensee identified and corrected violation is of
minor safety significe.tce and will not be cited in accordance with Section Vll.B.1 of the
NRC Enforcement Policy (NCV 50-341/97011-04a). This item is closed.
E8.29 (Closed) LER 50/341-97001-QQ: Error in Mass Flov. Conversion Algorithm in Heat
Balance Method. LER 97-001 pertained to an error in the mass flow conversion
algorithm in the heat balance methodology for calculating core thermal power. Due to
this error, the possibility existed for Fermi 2 to exceed its licensed power lim lt on one or
more occasions by 0.6 megawatts. In the LER, the licensee committed to evaluating the
software and instrumentation interface in the Process Computer for similar problems.
30
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i
This action is scheduled for completion December 17,1997. At t'ie . 'Jme of the
inspection, the licensee was reviewing alllevels of the process computer heat balance
process diagram, including working with the vendor to review the accuracy of vendor
application softNare that provided inputs to the heat balance model and the vendor -
,
software functions that comprised the model. The licensee also committed in LER
97-001 to correct the mass flow conversion algorithm, revise the procedure for the
! manual heat balance calculation and correct the software specification to include the
,
1
appropriate algorithm. The inspectors verified that these actions were completed.
E8.30 (Closed) LER 50/34197003-00 & 97003-01: Emergency Equipment Cooling Water
System Containment Isolation Function Outside Design Basis. This LER is associated
with unresolved items 97002-05 and 9700310 (see Sections E8.20 and E8.21). Both
revisions of the LER are closed.
E8.31 iClosed) LER 50/34197005-00: Emergency Equipment Cooling Water (EECW)
Makeup Tank Isolation Valve Interlocks Potentially Preventing Operation of EECW from
Dedicated Shutdown Panel. The licensee idsntified that the EECW could not be started
from the dedicated shutdown panel because of an RBCCW to EECW valve interlock
which could not be verified at the shutdown panel, contrary to the requirements of TS 3.7.11. The licensee modified the shutdown panel design to ensure that the EECW
system could be operated from the panel. Additionally the licensee expanded the
review to other systems required to operate from the dedicated shutdown panel and
submitted a revision to the LER to describe additional circuits identified. Finally, the
license revised appropriate procedures. The inspectors reviewed the modification and
associated safety evaluation and had no conceins. This second example of a licensee
identified and corrected violation is of minor safety significance and will not be cited in
accordance vith Section Vll.B.1 of the NRC Enforcement Policy (NCV
50-341/97011-04b). This item is closed.
V. Management Meetings
X1 Exit Meeting Summary .
The inspectors presented the inspection results to licerisee representatives during an exit
meeting on September 22,1997, and during a telephonic exit on October 10,1997, to convey
the NRC's conclusion regarding an apparent violation involving an unreviewed safety question.
The licensee acknowledged the findings and d.'d not indicate that any materials examined
during the inspection should be considered proprietary.
31
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PARTIAL LIST OF PERSONS CONTACTED
Licensee
P. Borer, Vice President, Nuclear Operations i
R. Delong, Superintendent, System Engineering I
P. Fessler, Plant Manager
D. Gipson, Senior Vice President, Nuclear Generation
K. Howard, Superintendent, Plant Support Engineering
J, Moyers, Director, Nuclear Quality Assurance
! N. Peterson, Supervisor, Compliance
J. Plona, Technical Director
i
Nf1G
!
G. Harris, Senior Resident inspector, Fermi 2
C. O'Keefe, Resident inspector, Fermi 2
INSPECTION PROCEDURES USED
IP 37001: Safety Evaluations
IP 37550: Engineering
IP 92701: Followup
IP 92702: Followup on Corrective Actions for Violations and Deviations
IP 40500: Effectiveness of Llcensee Controls in identifying, Resolving, and Preventing
Problems
32
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ITEMS OPENED, CLOSED, AND DISCUSSED
Ooened
97011-01 VIO Failure to Meet TS Requirements for Response Time Testing
97011-02 VIO Inadequate 50.59 for Response Time Testing
l 97011-03 VIO UFSAR and TS Inaccurate on Condensate Storage Tank Volume
97011-04 eel Potential Unreviewed Safety Question on New Failure Mode for
Safety Related Equipment Cooled by EECW
l 97011-05 NCV Failure to Meet TS 3.7.11 Roquirements Two Examples
!
'
Go. Sad
94019-02 UNR Standby Feedwater Pipe Hanger Deficiencies
95005-01 VIO DAS Installed on Both Divisions of RPS
95005-02 VIO DAS Hooked Up to Both Divisions of RPS
95005-03 VIO Failure to Utilize SOE or Temp Mod Procedure.
95009-04 IFl Review of RHR Water Hammer issues Associated with IN 87-10.
96002-10 VIO Inadequate Operating Procedure Revision Following Modification
96002-13 URI UFSAR Discrepancies
96004-06 VIO Inadequate investigation of RHRSW Flow Reduction
'
96004-09 IFl Active Seismic Monitoring System
96005-04 IFl Spent Fuel Pool Review
% 006-01 VIO Not All RHRSW Valves included in System Operating Procedure 1
96006-09- IFl Failure to identify Thermal Aging Components identified in Vendor SIL
96007 04 IFl Emergerney Diesel Generator 12 Tripped Due to Failed Circuit Cards
96010-04 VIO Failure to Folkw Test Termination Criteria After Loss of Core
Instrumentation.
96013-08 URI Incomplete Safety Evaluation on EECW
96201-01 IFl Inadequate Guidance for Classification of DERs
96201-02 IFl Lack of Guidance for Classifying Trend DERs
96201-03 IFl Failure to identify and Train Root Cause Evaluators
96201-10 URI High Pressure Coolant Injection System UFSAR Errors
97002-05 URI EECW System Deficiencies
97003 10 IFl NRR Review of EECW Design issues
97003-11 URI Reactor Protection System Response Time Testing TS Compliance
95001-00 LER Reactor Water Level Indication Transient.
95008-00 LER One Megawatt Nonconservative Blas Found in Core Thermal Power
, Calculation
96008-01 LER One Megawatt Nonconservative Blas Found in Core Thermal Power
Calculation
96005 00 LER Emergency Equipment Cooling Water Makeup Tank Inoperable Due to
Design Issue
96007-00 LER Plant Shutdown Due to Technical Specification 3.0.3 Entry
96013-00 LER Heat Balance Impact Due to Reactor Recirculation Pup Power Computer
Error
96019-00 LER Inoperable Standby Feedwater System Flow Path for 10 CFR Part 50,
Appendix R Applications
33
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L ITEMS OPENED, CLOSED, AND DISCUSSED, cont.
.97001-00 LER Error in Mass Flow Conversion Algorithm in Heat Balance Method
97003-00 LER EECW System Containment Isolation Function Outside Design Basis
l 97003-01 LER EECW System Containment Isolation Function Outside Design Basis
97005 00 LER EECW Makeup Tank isolation Velve Interlocks Potentially Preventing
Operation of EECW form D6dicated Shutdown Panel
l
Discussed
!.
l 96006-04 IFl No Provision to Stroke Time Test Valve included in Inservice Testing -
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Program
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LIST OF ACRONYMS USED
BOP Balance-of-Plant
BWR= Boiling Water Reactor
CARD Condition Assessment Resolution Document
CPEP Critical Performance Evaluat;on Program
CSS Core Spray System
CST Condensate Storage Tank
DBA Design Basis Accident
DECO Detroit Edison Company
DER Deviation Event Report
ECCS Emergency Core Cooling System
EDG Emergency Diesel Generator
EDP Engineering Design Package
EECW Emergency Equipment Cooling Water
EESW Emergency Equipment Service Water
EFA Engineering Functional Analysis
EOP Emergency Operating Procedures
EPG Emergency Procedure Guidelines
FOSI Fermi Operational Safety inspection
GE General Electric
GSW General Service Water
HELB High Energy Line Break
HPCI High Pressure Coolant injection
l&C instrumentation and Control
ISEG Independent Safety Engineering Group
IST In Service Testing
LCO Limiting Condition for Operation
LCR Licensing Change Request
LER Licensee Event Report
NRC Nuclear Regulatory Commission
NSSS Nuclear Steam Supply System
OSRO On-Site Review Organization
PDR Public Document Room
PIP Position Indicating Probe
RBCCW Reactor Building Closed Cooling Water
RCIC Reactor Core Isolation Cooling
RPIS Rod Position Indication System
RTT Response Time Testing
SE Safety Evaluation -
S!L Service Information Letter
SOP System Operating Procedure
TS Technical Specification
,
UFSAR Updated Final Safety Analysis Report
.
35
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.: .
,
LIST OF DOCUMENTS REVEWED
The following is a list of I;censee documents reviewed during the inspecuun, ;rauding
documents prepared by others for the licensee. Inclusion on this list does not imply that NRC
inspectors reviewed the documents in their entirety, but, rather that selected sections or
portions of the documents were evaluated as part of the overallinspection effort. Inclusion of a
. document in this list does not imply NRC acceptance of the document, unless specifically stated
in the body of the inspection report.
.
Desian Basis Document
E51-00 Reactor Core Isolation Cooling System, Revision A, April 16,1994
Qgsign Calculations (DC)
, 0367 Residual Heat Removal System Calculations, Rev L, Hydraulic Analysis A-1
l through A-3
l 0388 Core Spray Hydraulic Analysis, Rev A (part of the Core Spray System
<
Calculations, DC-230, Rev F)
5888 EECW Operation with Non Essential Loads Open, Rev 0
Deviation Event Reoorts (DER)
! 93-0512 IE Notice 87-10 Potential for Water Hammer During Restart of RHR Pumps
95-0434 EDP Weaknesses or Errors Found During DCATs
95-1021 Clarification of Assumptions and Calculations Related to the Design of the
Spent Fuel System
96-0235 Time to Boiling in the Spent Fuel Pool on a Loss of Cooling and Associated
issues
96-0306 Values for Flow Limits for the RHR System When Used to Cool the Spent Fuel
Pool
96-0365 RHR Service Water Cooling Tower Drain Lines
96-0754 Notics of Violation: Inadequate Root Cause
96-0760 Enhancement of EFA Closure Process
96 1654 RCIC System Logic Functional Test Failure Due to incorrect Wiring
Configuration
96-1836 Safety Evaluation 95-0036 Failed to Review All Accident Scenarios
97-0318 Loss of EECW Associated with Drywe9 Pipe Breaks
'97-0323 EECW Containment isolation Outside Design Basis
97-0355 E5150F054, RCIC Turbine Drain Pot to Water Trap Bypass Valve Failed to
Close
37-0428 Fuel Design-Specific EOP Parameters
97-0550 Failure of E55150F007 to Open
97-0600 E5150F007 Valve Stayed Open W/O lsolat6 ion Signal Present
97-0715 D'screpancy With the E51-F045 Valve During Surveillance 24.206.004
97-0973 E5150F010 Failure to Automat ally Close
36
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- *
.,
DERs, cont.
-97-0941 Unusual Noise from MOV Motor on E5150F059 '
97-1261 Inappropriate Reference to GL 91-18 in SE 95-036, Rev.1
Drawings -
D1270-1 - 600,000 Gallon _ Condensate Storage Tank Plan & Elevation View, Rev 3
D1270-4 600,000 Gallon Condensate Storage Tank, Nozzle Details, Rev 7
6M7212044 - Reactor Core Isolation Cooling System, Revision AN
6M721-2045 RCIC System Barometric Condenser, Revision AF
6M721-3149-1 Core Spray System Isometric, Suppression Pool to Pump Suction, Rev R
6M721-5709-1 RCIC System Sketch, Revision X
6M721-5709-'2 RCIC Turbine Lube Oll/ Control Oil Functional Operating Sketch, Revision D
6M7215859 - Reactor Core Isolation Cooling System, Revision B
6M721-Y 2000 Valve Pit and Piping - Condensaie Storage Tank In Yard, Rev Q
61721-2235-1 RCIC System Logic Circuit, Revision Q
- 61721-2235-2 RCIC _ System Logic Circuit, Revision Q
61721-2235-3 RCIC System Logic Circuit. Revision V
761E277 Core Spray Process Diagram, Rev 3
Engineering Design Packages EDP)
12744 Replacement of Existing RWCU Filter Demineralizer Control Panel G33P001
with a Microprocessor Based Programmable Logic, Revision 0
, 27130 Wiring Mod;iication to 480v Load Shed String to Add Second Contact Off
Agastat Relay to Break Inductive Current, Revision 0 -
27422 _
Pressure Locking Mitigation Modification, Revision 0 '
27423(TSR) Adjust Spring and Air Regulator Set Pressures'on (Roswell) Edward Valves
with Fisher Actuators, Revision 0
27431 E5150F045 Replacement, Revision 0
27509. Improvements to Barton D/P Switches P44N425A, PA4N425B, P44N426A,
P44N4268, Revision 0
28180 RHR Complex Pumps Freeze Protection _ Revision 0
4
28456- EECW Makeup Surge Tank Tie-In, Revision 0
28479 Removal of 14 Small Bore Manual Valves from the Reactor Feedwater System,
Revision 0
28556- Modification of Mechanical Draft Cooling Tower Freeze Protection Drain Lines,
'
Revision 0
28786(TSR) Provide Full Range Accuracy for Square Root Converters P61K818 and
P61K819 and accuracy for Rosemount Transmitter P61N422, Revision 0
- 28827 Replacement Thrust Bearing for RHR Reservoir Cross-tie Valves, Stem
' Extension Shaft, Revision 0
28844 EDG Heat Exchangers Zinc Anode Replacement with plugs, Revision 0
29056 Motor Replacement for Motor Operated Valves N6200F617 and N6200F618;
from 10 Ft-Ib to 15 Ft-Ib, Revision 0
37
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,Irvianandant Rafetv Evaluatlan Grouo Rarwis
~
96-020 . RF-05 Refueling Outage Plan Safety Review,iAugusi 23,1996
- 96-021._ Employee Concems and Questions Regarding Installation of the Posulon
_ indication Probe Modification Planned for RF05, September 16,1996
96-023- SRV Pilot Setpoint Drift,' December 10,1996 : _
97-001 ISEG Review of Previous Equipment Problems, Revision 1 January 2,199_7 -
> 97-004 L lSEG Plan, May 5,1997
y' 97-005- Independent Root Cause Analysis of CM Output _ Breaker Failure on January 7,
'
,
i 1997 February 27,1997:
- 97-006 ISEG Review of Production Related Work Requests Greater Than Six Months '
Old,' March 14,'1997
'97-008' - Potential Common Mode Equipment issue review, May 30,1997
'97-009- Motor Control Center Replacement /Refurtaishment, June 5,-1997
l
-
- 97-010 Review of Seismic Qualification of 480V & 4160V Breakers, June 12,1997-
L 97-011 Evaluation of the Fuel Reliability Action Plan, June 17,1997
[ - 97-012 - _ Review of the Operator Work Around List and the Collection of Concerns / Issues
impacting Plant Startup or Continued Operation, July 11,1997
LillRCE
NRC-96-0071 ~ Reply to Notices cf Violation (96004-06 and 004-05), July 15,1996
, L[qesino Chance Raouests
96-156-UFS . Replacement of E5150F045 with a Gate Valve per EDP-27431, Revision 0
96-160-UFS Update UFSAR to include Reference to the RHRSW Drain Lines for Freeze ,
1 - Protection, 12/23/96-
Procedures
Alarm Response Frocedures
a-
.1D88 EECW Heat Exchanger Outlet Temperature, Division 1
-2D14 EECW Heat Exchanger Outlet Temperature, Division 11
Channel Calibration Procedures
-44.010.006- RPS'- Reactor Steam Dome Pressure, Trip System B, Channel B1/B
- Calibration, Revision 27
-44.010.007 RPS - Reactor Steam Dome Pressure, Trip System A, Channel A2/C
Calibration, Revision 27 - ,
44.010.008- - RPS - Reactor Steam Dome i , essure, Trip System B, Channel 82/D '
Calibration, Revision 27 H
-44.010.017- RPS and NSSS - Reactor Vessel Low Water Level (Level 3) Trip System A.
Channel A1/A Calibration, Revision 30 '
38
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Channel Calibration Procedures, cont.
44.010.018 RPS and NSSS - Reactor Vessel Low Water Leve.! (Level 3) Trip System B,
Channel B1/B Cslibration, Revision 33
44.010.019 RPS and NSSS - Reactor Vessel Low Water Level (Level 3) Trip System A,
Channel A2/C Calibration, Revision 31
44.010.020 RPS and NSSS - Reactur Vessel Low Water Level (Level 3) Trip System B,
Channel B2/D Calibration, Revision 31
44.020.007 NSSS - Reactor Vessel Low Water Level (Levels 1 and 2), Trip System A,
Channel A Calibration, Revisions 30,32, and 33
44.020.008 NSSS - Reactor Vessel Low Water Level (Levels 1 and 2), Trip System B,
Channel t3 Calibration, Revision 32
44.020.039 NSSS - Main Steam Flow Division I, Channel A Calibration / Functional,
Revision 33
44.020.040 NSSS - Main Steam Flow Division 11, Channel B Calibration / Functional,
Revision 32
44.020.041 NSSS - Main Steam Flow Division I, Channel C Calibration / Functional,
Revision 34
44.020.042 NSSS - Main Steam Flow Division 11, Channel D Calibration / Functional,
Revision 32
44.030.255 ECCS - Reactor Vessel Water Level (Levels 1,2, and 8), Division I, Channel A
Calibration, Revision 38
44.030.256 ECCS - Reactor Vessel Water Level (Levels 1, 2, and 8), Division ll, Channel B
Calibration, Revision 35
44.030.257 ECCS - Reactor Vessel Water Level tLevels 1,2, and 8), Division I, Channel C
Calibration, Revision 37
44.030.258 ECCS - Reactor Vessel Water Level (Levels 1, 2, and 8), Division ll, Channel D
Calibration, Revision 38
44.030.303 ECCS - Drywell Pressure - RHR, CSS and HPCI Actuation, Division I,
Channel A Calibration, Revision 30
44.030.304 ECCS - Drywell Pressure - RHR, CSS and HPCI Actuation, Division ll,
Channel B Celibration, Revision 29
44.030.305 ECCS - Drywell Pressure - RHR, CSS and HPCI Actuation, Division I,
Channel C Calibration, Revision 31
44.030.306 ECCS - Drywell Pressure - RHR, CSS and HPCI Actuation, Division ll,
Channel D Calibration, Revision 30
Conduct ManualProcedures
MES11 Technical Service Request, Revision 6
MES 12 Performing Temporary Mcdifications, Revision 2
MES 27 Verification of System Operability, Revision 2
MES 31 Diagnostic, Special and Infrequently Performed Tests or Evolutions, Revision 3
MES 39 Engineering Functional Analyses, Revision 1 (Canceled)
MLS 07 Preliminary Evaluations and 10CFR50.59 Safety Evaluations, Revision 1
MOP 05 Control of Equipment, Revision 5
MWCO2 Work Control, Revision 8
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Conduct ManualProcedures, cont.
MWC03 Surveillance / Performance Package Control, Revision 5
Fermiimplementing Procedures
4
FIP-OP1-02 Temporary Modifications, Revision 2
FIP-CT103 Preparation and Performance of Diagnostic Special Tests and Infrequently
Performed Tests or Evolutions, Revision 9
Maintenance Procedures
35.808.002 Safety Relief Valve Removal and Installation, Rev 25
Plant Support Engineering Practice Standards
PEPS-0018 Contractor Control, Revision 2
-
Response Time Testing Procedures
"
44.010.009 RPS - Reactor Vessel Steam Dome Pressure, Trip System A, Channel A1/A,
Response Time Test, Revision 28
44.010.010 RPS - Reactor Vessel Steam Dome Pressure, Trip System A, Channel B1/B,
Response Time Test, Revision 28
44.010.023 RPS - Reactor Vessel Low Water Level (Level 3), Trip System A, Channel
A2/C, Response Time Test, Revision 28
44.010.024 RPS - Reactor Vessel Low Water Level (Level 3), Trip System A, Channel
B2/D, Response Time Test, Revision 28
44.020.011 NSSSS - Reactor Vessel Low Water Level (Level 1), Trip System A, Channel A,
Response Time Test, Revision 33
44.020.014 NSSSS - Reactor Vessel Low Water Level (Level 1), Trip System B, Chan' el D,
Response Time Test, Revision 33
44.020.045 NSSSS - Main Steam Line Flow, Division I, Channel C, Response Time Test,
Revision 31
44.020.046 NSSSS - Main Steam Line Flow, Division 11, Channel D, Response Time Test,
Revision 30
44.030.261 Response Time Test of B21-N091C, Revision 31
44.030.262 Response Time Test of B21-N091D, Revision 31
44.030.307 ECCS - Drywell Pressure - RHR and CSS Actuation, Division I, Channel A,
Response Time Test, Revision 27
44.030.308 ECCS - Drywell Pressure - RHR and CSS Actuation, Division 11, Channel D,
Response Time Test, Revision 27
' System Operating Procedures
23.127 RBCCW/EECW System, Rev 57
-23.425.01 Primary Containment Procedures, Rev 29
40
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Surveillance Procedures
23.104 Condensate Storage and Transfer System, Revision 23
24,137.11 Safety Relief Valve (SRV) Operability Test, Rev 25
24.206.01 RCIC System Pump and Valve Operability Test, Revision 35
24.206.02 RCIC Valve Operability Test, Revision 29
24.206.03 RCIC Discharge Piping Venting and Valve Verification Test. Revision 28
24.206.04 RCIC System Automatic Actuation and Flow Test, Revision 30
27.000.04 Freeze Protection Lineup Verification, Revision 13
43.137.001 Main Steam Safety / Relief Valve Setpoint Testing, Rev 26
Quality Assurance Audits92-018 DECO QA Surveillance Report, May 6,1992
93-032 DECO QA Audit Report, JarJary 10,1994
Correspondence Related to Audit 93-032
GE to DECO Responses to Audit 93-032, February 10,1994
GE to DECO Additional Information Regarding DECO QA Audit Report, February 23,1994
DECO to GE Evaluation of Responses to Detroit Edison's Quality Observations Numbers 1 &
3 of the Fuel Design Audit,93-032, (Follow-po verification, performed at
Wilmington NC,8/15-17/94)
DECO Internal Cancellation of Temporary Rod Block Monitor Out of Service Actions,
November 1,1995, (D. Powell to J.M. Thorson)
Reload Analyses
23A7075 Supplemental Reload Licensing Report (SRLR), Rev. O
J11-02125 initial Cycle 5 Analysis, Volume s 6 & 7, (GE DRF), November 11,1993
J11-02125 Revised Cycle 5 Analysis, Volume 19, (GE DRF), June 22,1994
J11-02144 Final Cycle 5 Analysis, Volume 6, (GE DRF), August 22,1995
Safety Evaluations
95-0036 Change to UFSAR Description of RBCCW/EECY; Operation, Revisions 0,1 & 2
96-0082 E5150F045 Replacement, Revision 0
96-0083 Add Text to UFSAR to Describe RHR Complex Freeze Protection, Revision 0
97-0048 Evaluation of Change of Divisional Power to Containment isolation Valves,
Revision 0
97-0031 Revise UFSAR Criteria for Postulating Pipe Rupture Locations, Revision 0
97-0064 Change UFSAR to include New Bypass Leakage Paths, Revision 0
97-0068 Addition of Check Valve in Division i of EECW, Revision 0
97-0069 Replace Containment isolation Valve Motor with Larger One, Revision 0
97-0071 Clarification to Criteria for Postulating Pipe Rupture Locations As to the
Definition of Terminal End, Revision 0
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SelfAssessments
TM-95-0008 RF04 EDP Review,' July 14,- 1995
- TM-95-0016 - Good Plant Modifications Characteristics -
TM 95-0034 - Client Survey Sumn.ary, November 29,1995'
TMFR-95-0054 Re-engineering the Fuel Reliability Action plan, December 12,1995
TM 96-0049 Progress Review of GSW Modification Prrject, June 14,1996
--TM 96-0063 : Common Threads from DERs, July 19,1996
TM 96-0074 EDP 26849 Station Air Compressor Self Assessment, September 11,1996
TM-97-0025 _ System Engineering Assessment Plan, May 19,1997
- TM 97-0043 RF05 Engineering Design Change Snap Shot Reviews, November 41996
-Technical Chance Reauests
- 28559- Update RHRSW Design Basis Documentation to include As-built Information
Regarding RHR Complex Freeze Protection, Revision 0
l 29098. . Condenser Pump Seal Water High Flow Switch Evaluation, Revision 0
I-
Technical Soecification Clarifications
96-004: - Rod Block Monitor Applicability
-
= Temocrary Modification Pack =aas -
96-0001 Temporary Thermocouple Cable Installed from Manhole # 16953 to the
Circulating Water Pump House,
96-0002 Installed Temporary Instrumentation to Collect Data for Turbine Power Up-Rate.
'96-0006 Installed Temporary Thermocouple Cable from Manhole #.16953 to the
_
_ Circulating Water Pump House.
96-0013 - Added Diode to Timer Circuit in Fire Protection Panel P82P430A.-
96-0014 Relocated Master Reflash Card for Annunciator System Alarm -
96-0019 Installed EDG 14 Inboard Bearing Temperature Indication
96-0020 Added LAN Circuits in Control Room
97-0006 Installed EDG 11 Inboard Bearing Temperature Indication
--97-0009 Substitute the HI HI Level Switch N62N414B to Control the Drain Valve N62,
Revision 0
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