[Federal Register Volume 61, Number 235 (Thursday, December 5, 1996)]
[Notices]
[Pages 64541-64547]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 96-30949]
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NUCLEAR REGULATORY COMMISSION
[Docket Nos. 50-282, 50-306, and 72-10]
Northern States Power Company, Prairie Island Nuclear Generating
Plant, Units 1 and 2, License Nos. DPR-42, DPR-60 and SNM-2506,
Issuance of Director's Decision Under 10 CFR 2.206
Notice is hereby given that the Acting Director, Office of Nuclear
Reactor Regulation, has issued a Director's Decision concerning a
Petition dated June 5, 1995, filed by the Nuclear Information and
Resource Service and the Prairie Island Coalition Against Nuclear
Storage (Petitioners) under Sec. 2.206 of Title 10 of the Code of
Federal Regulations (10 CFR 2.206). The Petition requested that Prairie
Island Units 1 and 2 be immediately shut down and the operating
licenses be suspended until the issues raised in the Petition could be
resolved. The Petition was based on alleged problems with cracking of
the Prairie Island steam generator tubes and reactor vessel head
penetrations, use of the transfer channel between the reactor core and
the fuel pool during unloading and loading of dry cask storage units,
and use of the Prairie Island crane.
The Acting Director of the Office of Nuclear Reactor Regulation has
determined that the Petition should be denied for the reasons stated in
the ``Director's Decision Under 10 CFR 2.206'' (DD-96-21), the complete
text of which follows this notice. In reaching this decision, the
Acting Director considered the concerns expressed by the Petitioners in
letters to the NRC dated June 21, 1995, February 19, 1996 and March 13,
1996. The decision and the documents cited in the decision are
available for public inspection and copying in the Commission's Public
Document Room, the Gelman Building, 2120 L Street, NW, Washington, DC,
and at the local public document room located at the Minneapolis Public
Library, Technology and Science Department, 300 Nicollet Mall,
Minneapolis, MN 55401.
A copy of this decision has been filed with the Secretary of the
Commission for the Commission's review in accordance with 10 CFR
2.206(c). As provided therein, this decision will become the final
action of the Commission 25 days after issuance unless the Commission,
on its own motion, institutes review of the decision within that time.
Dated at Rockville, Maryland, this 27th day of November, 1996.
For the Nuclear Regulatory Commission,
Frank J. Miraglia,
Acting Director, Office of Nuclear Reactor Regulation.
DIRECTOR'S DECISION UNDER 10 CFR 2.206
I. Introduction
On June 5, 1995, the Nuclear Information and Resource Service and
the Prairie Island Coalition Against Nuclear Storage (PICANS), now
known as the Prairie Island Coalition (Petitioners), filed a Petition
pursuant to Section 2.206 of Title 10 of the Code of Federal
Regulations (10 CFR 2.206) requesting that the Nuclear Regulatory
Commission (NRC) immediately suspend the operating licenses for Prairie
Island Nuclear Generating Plant, Units 1 and 2, operated by Northern
States Power Company (NSP or Licensee).
II. Background
As a basis for their request, Petitioners presented four concerns
which are summarized as follows: (1) The Prairie Island steam
generators are suffering from tube degradation and may rupture unless
proper testing is conducted and corrective actions are taken; (2) the
Prairie Island reactor vessel head penetrations (VHPs) have stress-
corrosion cracks which, if not found and corrected, may result in a
catastrophic accident involving the reactor control rods; (3) plans for
loading and unloading of dry cask storage units in an emergency, which
include storage of irradiated components in the fuel transfer canal,
were not properly reviewed by NRC and do not satisfy NRC requirements;
and, (4) the physical integrity of the Prairie Island crane used to
lift the dry cask for Prairie Island's spent fuel requires physical
testing and a safety analysis before future crane use following its
handling of a heavy load for an extended period of time.
By a letter dated June 19, 1995, the Director of the Office of
Nuclear Reactor Regulation (NRR) denied the Petitioners' request for
immediate suspension of Prairie Island Units 1 and 2 licenses. The
Director stated that the NRC staff's review of the Petition did not
identify any safety issues warranting immediate action at the Prairie
Island Nuclear Generating Plant. The Director also stated that the NRC
staff would issue a Director's Decision addressing Petitioners'
concerns within a reasonable time.
PICANS submitted a letter to the Chairman of the NRC dated June 21,
1995, which reiterated the concerns raised in the Petition and
requested an evening public hearing within the vicinity of the Prairie
Island facility. In a July 12, 1995, response, the NRC staff informed
PICANS that an evening public hearing was not warranted at that time
but that the request would again be considered at the time of issuance
of the Director's Decision.1 PICANS was further informed that the
concerns raised in the June 21, 1995, letter would be addressed in the
Director's Decision.
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\1\ For the reasons set out in the cover letter transmitting
this Decision, the NRC staff has again determined that an evening
public hearing is not warranted.
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On February 19, 1996, Petitioners filed an addendum to their
Petition raising further concerns regarding steam generator tube
cracking and requested that Prairie Island, Unit 1 not be allowed to
return to operation until
[[Page 64542]]
certain inspections of steam generator tubes was conducted. In a March
1, 1996, response, the Director of NRR denied Petitioners' request for
action concluding that no safety issues warranting immediate action had
been identified.
On March 13, 1996, Petitioners submitted another addendum to the
Petition raising additional concerns regarding steam generator tube
cracking at Prairie Island and again requesting that the NRC require
that Prairie Island, Units 1 and 2 be placed in mid-cycle outages for
the purpose of steam generator tube inspections. Petitioners further
requested an informal public hearing if the NRC determined that such
testing need not be conducted.
In an August 21, 1996, response, the Director of NRR concluded that
the addendum did not raise any safety issues warranting immediate
action and that an informal public hearing was not warranted at that
time.
Petitioners' concerns are addressed below. In addressing these
issues, I have considered the concerns expressed by the Petitioners in
the letters of June 21, 1995, February 19, 1996, and March 13, 1996.
III. Discussion
A. Steam Generator Tube Degradation
The steam generators used at pressurized water reactors (PWRs) are
large heat exchangers that use the heat from the primary reactor
coolant to make steam in the secondary side to drive turbine generators
which generate electricity. The primary reactor coolant flows through
tubes contained within the steam generator. As the coolant passes
through the steam generator tubes, it heats the water (i.e., secondary
coolant) on the outside of the tubes and converts it to steam which
drives the turbine generators. Steam generator tubes made from mill-
annealed alloy 600 have exhibited a wide variety of degradation
mechanisms. Such material has been used in a number of steam generators
at commercial nuclear facilities, including the steam generators at
Prairie Island Units 1 and 2. These degradation mechanisms include
mechanically induced (e.g., fretting wear, fatigue) and corrosion-
induced (e.g., pitting, wastage, and cracking) degradation.
Steam generator tubes constitute a significant portion of the
reactor coolant pressure boundary. As a result, the structural and
leakage integrity of the boundary is important in ensuring the safe
operation of the plant. A loss of steam generator tube integrity has
potential safety implications, as noted by the Petitioners, namely, (1)
the loss of primary coolant which is needed to cool the reactor core
and (2) the potential for leakage of radioactive fission products into
the secondary system where their isolation from the environment cannot
be ensured. As a result of the importance of this portion of the
reactor coolant pressure boundary, NRC has regulations on maintaining
the structural and leakage integrity of the steam generator tubes. The
overall regulatory approach to ensuring that steam generators can be
safely operated consists of the following:
(1) Technical specification requirements to ensure that the
likelihood of steam generator tube rupture events is minimized,
including
(a) Periodic inservice inspection of the tubing,
(b) Plugging or repair of tubing found by inspection to be
defective, and
(c) Operational limits on primary-to-secondary leakage beyond which
the plant must be shut down.
(2) Analysis of the design-basis steam generator tube rupture event
to demonstrate that the radiological consequences meet 10 CFR Part 100
guidelines.
(3) Emergency operating procedures for ensuring that steam
generator tube rupture events can be successfully mitigated.
Steam generator tube degradation can be detected through inservice
inspection of the steam generator tubes. These inspections are
generally required by a plant's Technical Specifications which specify
the frequency and scope of the examinations along with the tube repair
criteria. In the 1970s, wastage (i.e., general tube wall thinning) and
denting (mechanical deformation of the tube) were the dominant
degradation mechanisms being observed. These degradation mechanisms
were readily detectable with the bobbin coil inspection method and were
effectively controlled or eliminated, in part, by improvements in water
chemistry. Stress-corrosion cracking (SCC) emerged in the mid-1980s as
the dominant degradation mechanism affecting the steam generator tubes.
SCC can be oriented axially along the tube or circumferentially around
the tube, or can consist of a combination of axial and
circumferentially oriented cracks. SCC that has an axial orientation
can be detected with a bobbin coil probe. The capabilities of the
bobbin coil inspection method at detecting axially oriented cracks
depend on such factors as the location of the cracking, interfering
signals, and the data analysis procedures.
Circumferentially oriented SCC emerged as a significant problem
affecting the industry in the late 1980s. The bobbin coil probe is
generally insensitive to such cracking (i.e., circumferential SCC); as
a result, locations susceptible to circumferential SCC may need to be
examined with techniques other than the bobbin coil. Historically,
probes such as the motorized rotating pancake coil (MRPC) probe have
been used to detect circumferential SCC at locations susceptible to
such degradation. Recently, more advanced probes (e.g., Zetec Plus-
Point probe which contains a plus-point coil) have been used.
Deficiencies have been identified in certain utility inspection
programs for detecting SCC, particularly circumferentially oriented
SCC. Potential deficiencies include using inappropriate probes for
inspecting locations susceptible to circumferential cracking, not
optimizing the test methods to minimize electrical noise and signal
interference, and not being alert to plant-unique circumstances (e.g.,
dents, copper deposits) which may necessitate special test procedures
found unnecessary at other similarly designed steam generators or not
included as part of a generic technique qualification.
Even though deficiencies in eddy-current inspection programs have
been identified, operating experience indicates that steam generator
tube integrity can be maintained at a plant when appropriate eddy-
current data acquisition (including probe selection) and data analysis
procedures are used, when the data analysts have been properly trained,
when the intervals between inspections are determined based on the
inspection findings, and when the operating environment of the steam
generator tubes is controlled (e.g., water chemistry control). Adequate
tube integrity has historically been achieved at plants through
inservice inspections that involved the use of bobbin and MRPC probes.
In some instances, operating intervals were shortened between
inspections to ensure tube integrity.
Nevertheless, inspection findings at the Maine Yankee Atomic Power
Station in 1994 and 1995 raised concerns that large circumferential
cracks could develop over the course of an operating interval or that a
large number of circumferential cracks may be present if a facility was
not using appropriate inspection techniques. As a result of these
inspection findings, the NRC staff issued Generic Letter (GL) 95-03,
``Circumferential Cracking of Steam Generator Tubes,'' on April 28,
1995,
[[Page 64543]]
which: (1) Requested affected licensees to evaluate recent experience
(including the Maine Yankee experience) concerning the detection and
sizing of circumferential cracks and the potential applicability of
this experience to their plants; (2) on the basis of the results of
this evaluation, including past inspections and the results thereof,
and other relevant factors, requested affected licensees to develop a
safety assessment justifying continued operation until the next
scheduled steam generator tube inspections were performed at their
plants; and (3) requested that licensees develop and submit their plans
for the next steam generator tube inspection as they pertain to the
detection of circumferential cracks.
Subsequent to the issuance of GL 95-03, the Petitioners made the
following requests with respect to steam generator tubes at Prairie
Island Units 1 and 2: Request (a)--``That all steam generator tubes in
Prairie Island Unit 2 be given a full length inspection utilizing the
more comprehensive and proactive battery of tests employed at Maine
Yankee during NSP's 1995 outage. Petitioners specifically demand that
the Zetec Plus Point Probe and any state of the art, eddy current probe
for corrosive cracking be employed at Prairie Island 2 during Outage 17
scheduled to end June 15, 1995.'' Request (b)--``That if the Zetec Plus
Point Probe and any state of the art probe are not employed during the
mid-June 1995 outage, then reactor Unit 2 be taken immediately off-line
until such time these specific Zetec Plus Point Probe and any state of
the art, eddy current probe for corrosion cracking are completed.''
Request (c)-- ``That Prairie Island Unit 1 immediately be placed into a
mid-cycle outage to perform the NRC requested actions outlined in
Generic Letter 95-03. In addition, all Unit 1 steam generator tubes be
inspected through the use of the Zetec Plus Point Probe and any state
of the art, eddy current probe for corrosion cracking.''
NSP submitted its response to the generic letter for Prairie Island
Units 1 and 2 by letter dated June 27, 1995. As discussed below, the
information submitted provides no indication of an active
circumferential crack mechanism at the Prairie Island units, nor does
it suggest any significant concern regarding the potential for large,
undetected circumferential cracks at these units.
The Prairie Island Unit 2 steam generators were last inspected in
June 1995. This inspection included a 100-percent, full-length
inspection with the bobbin probe. In addition, a 100-percent inspection
was performed with a combined MRPC/Plus-Point probe from the hot-leg
tube end to 3 inches above the tubesheet. Most row 1 and 2 U-bends were
also inspected with the MRPC/Plus-Point coil. The bobbin probe is
appropriate for performing the general-purpose, full-length inspection
of the tubing because of its capability to detect flaw geometries
exhibiting an axial component (e.g., corrosion thinning and wastage,
mechanically induced wear, pitting, and axial cracks). The bobbin
inspection was supplemented by inspections with a combined MRPC/Plus-
Point probe to provide enhanced sensitivity to detecting cracks. These
inspections encompassed the areas of axial crack activity with the
bobbin coil probe and, in addition, the locations most vulnerable to
circumferential cracking with the MRPC/Plus-Point coil.
NSP reports that the Prairie Island Unit 1 steam generators were
last inspected in January 1996. This inspection included a 100-percent
full-length inspection with the bobbin probe, except for rows 1 and 2
U-bends. Rows 1 and 2 U-bends were examined with MRPC/Plus-Point. All
hot-leg tubes were examined with rotating probe technology (including
Plus-Point) from the tube end to 6 inches above the top of the
tubesheet. All sleeves were examined full length with the Plus-Point
rotating coil.
In addition, NSP's response to the generic letter addressed, in
part, each of five locations at which circumferentially oriented
degradation has historically occurred in Westinghouse steam generators.
These locations are places where there is significant axial stress
associated with variations in tube geometry and include (1) tube
expansion transition areas, (2) dented top-of-tubesheet locations in
partial roll-expanded tubes (described below), (3) dented tube-to-tube
support plate intersections, (4) small-radius U-bends, and (5) sleeve
joints. Significant axial stress would contribute to the development of
circumferential cracking.
Regarding the first and second categories, the tubes at Prairie
Island are roll expanded over only the lower portion of the tubesheet
depth (i.e., partial roll expansion). NSP reports that the incidence of
circumferential cracks at expansion transitions where the tubes have
received a partial-depth expansion has been negligible industry-wide.
For Prairie Island Unit 1, the 100-percent MRPC/Plus-Point inspection
in the tubesheet regions in January 1996 did not find any
circumferential indications in the in-service tubes. Similarly, for
Prairie Island Unit 2, the MRPC/Plus-Point inspections in the tubesheet
regions did not identify circumferential indications.
With regard to the third category, circumferential SCC at dented
tube support plate intersections has only been reported at a limited
number of plants. In addition, dented regions have exhibited both axial
and circumferential SCC with axial SCC typically being the more
frequently observed degradation mechanism. Axial SCC at dented
locations can be detected with the bobbin probe. Although NSP has not
reported performing MRPC or Plus-Point examination at the support
plates, it has examined 100 percent of these locations using a bobbin
probe and has not reported any axial cracking. Not detecting any axial
cracking gives confidence that widespread circumferential SCC is not
occurring.
Regarding the fourth category, SCC in the small-radius (row 1 and
some row 2) U-bends has been extensive in Westinghouse steam
generators. This cracking has been predominantly axial, with only
isolated instances of non-axial cracks. NSP reports that the small-
radius U-bends are routinely inspected with the MRPC. In January 1996,
the licensee inspected 100 percent of rows 1 and 2 U-bends on Prairie
Island Unit 1 with the MRPC/Plus-Point and found no indications. The
June 1995 inspections at Prairie Island Unit 2 with the MRPC/Plus-Point
probe looked at the majority of small-radius U-bends, and found one
axial and no circumferential indications.
Regarding the fifth category, during the January 1996 inspection in
Unit 1, all in-service and new sleeves were examined full length with
Plus-Point. Indications were found in the upper sleeve weld region of
61 ABB Combustion Engineering welded tubesheet sleeves. These
indications were characterized as single or multiple circumferential
indications or volumetric indications. All of these sleeved tubes with
circumferential indications were removed from service by sample removal
and/or plugging. The volumetric indications were evaluated and
indications located within the pressure boundary were plugged. No
sleeves are installed in Unit 2. Sleeves were installed in Unit 1 to
address forms of tube degradation (e.g., axial cracking and
intergranular attack) other than circumferential cracking.
In response to the large number of indications identified in the
upper sleeve welds of ABB Combustion Engineering welded tubesheet
sleeves during the January 1996 Unit 1 outage, the NRC staff held
discussions and meetings with the Licensee to determine
[[Page 64544]]
the root cause of the indications. NSP pulled five sleeve/tube samples
during the outage to perform metallurgical analysis on and determine
the root cause of the indications. Four of the removed tubes contained
circumferential indications and one contained a volumetric indication.
NSP started up Unit 1 on March 3, 1996, and committed to perform a mid-
cycle outage to perform additional inspections unless the results of
the metallurgical analyses from the pulled sleeves indicated that
additional inspections would not be warranted.
ABB Combustion Engineering performed the metallurgical
examinations, with third-party review by the Electric Power Research
Institute. The results showed that the sleeve weld indications were not
service induced. Instead, they were original fabrication flaws that
were the result of faulty cleaning of tube surfaces prior to welding.
The examinations of the tube samples revealed the sizes of the flaws
were such that the structural integrity of the welds was not
compromised. None of the flaws showed any indication of having
propagated in service. Since the indications were not service induced,
the NRC staff agreed that a mid-cycle outage to perform further
inspections was not necessary.
ABB Combustion Engineering is currently revising its topical report
on sleeving to incorporate improved cleaning techniques prior to
installation of sleeves, in order to prevent such flaws in the future.
NSP plans to submit an amendment to the NRC for review to adopt the
revised ABB Combustion Engineering topical report prior to installation
of CE sleeves.
After GL 95-03 was issued, additional information from inspections
performed at Maine Yankee and the destructive examination of several
tubes removed from Maine Yankee became available. This additional
information appears in NRC Information Notice 95-40, ``Supplemental
Information Pertaining to Generic Letter 95-03, `Circumferential
Cracking of Steam Generator Tubes'.'' This information led to the
conclusion that the tubes with the largest indications at Maine Yankee
continued to exhibit adequate structural integrity at the time they
were found. This was attributable, in part, to the crack morphology as
discussed in the Information Notice. As a result, adequate tube
structural integrity was ensured for the operating interval between
inspections, even though the MRPC probe, rather than the Plus-Point
probe, was used during the earlier inspections.
As mentioned above, the safe operation of the steam generators is
ensured by performing inspections and repairing defective tubes,
limiting the operational leakage through the steam generators,
analyzing a design-basis steam generator tube rupture event to
demonstrate acceptable radiological consequences, and having
appropriate emergency operating procedures in place. As discussed
above, the staff believes that the inspection probes used during the
May 1994 and June 1995 outages at Prairie Island Units 1 and 2,
respectively, were adequate to provide reasonable assurance of tube
integrity. In addition, NRC requires an operational leak rate limit to
provide reasonable assurance that, should a leak occur during service,
it will be detected and the plant will be shut down in a timely manner
before rupture occurs and with no undue risk to public health or
safety.
Therefore, on the basis of (1) the fact that appropriate steam
generator tube inspections have been performed, (2) monitoring of
primary-to-secondary leakage is being conducted, and (3) the fact that
appropriate emergency operating procedures are in place, the NRC staff
has concluded that the Petitioners' request for the shutdown of Prairie
Island Units 1 and 2 until full-length tube inspections are completed
using the Zetec Plus-Point probe and any state-of-the-art eddy-current
probe should be denied.
B. Vessel Head Penetration (VHP) Cracking
The Petitioners contend that the VHP's at Prairie Island Units 1
and 2 are likely to have stress-corrosion cracks which, if not found
and corrected, may result in a catastrophic accident involving reactor
control rods. The Petitioners also contend that VHPs in PWRs in France,
Belgium, Switzerland, and Sweden are cracking and that French data
indicate that the cracking mechanism will not necessarily produce a
detectable leak prior to a break that would initiate a serious
accident. The Petitioners further contend that failure of a VHP could
cause the ejection of a control rod drive mechanism (CRDM), resulting
in a loss of control of the reactor and/or a serious leak that could
not be isolated and thereby could induce a loss-of-coolant accident.
The Petitioners request immediate, full inspection of all VHPs in Units
1 and 2 for cracking using state-of-the-art eddy-current testing. The
Petitioners also request that NRC immediately suspend the operating
licenses of both units until the VHPs are inspected.
This same issue has been the subject of a recent Director's
Decision under 10 CFR 2.206 issued by the Director of NRR. See All
Pressurized Water Reactors, DD-95-2, 41 NRC 55 (1995). There, the NRC
staff concluded, after reviewing the information referred to by that
Petitioner, that the likelihood of the formation of circumferential
cracks is small, the likelihood of forming small axial cracks is
higher, and that leaks would develop before catastrophic failure of a
VHP would occur. This would result in the deposition of boric acid
crystals on the vessel head and surrounding area that would be detected
during surveillance walkdowns. The Petitioners contend that this
conclusion is not supportable as French data indicate that the cracking
mechanism will not necessarily produce a detectable leak prior to a
break that would initiate a serious accident.
The NRC staff's review of the French data does not support the
Petitioners' contention that a crack would not be detected due to
leakage prior to catastrophic failure. Topical reports submitted to and
reviewed by the NRC staff indicate that cracks in the CRDM VHP's would
need to grow well above the reactor vessel head before reaching a
critical size that would lead to the catastrophic failure of a CRDM
VHP. The portion of the crack above the head would leak well before the
critical size is reached.
The circumferential crack at the French reactor was very small
relative to the size flaw that would jeopardize structural integrity.
Furthermore, the circumferential crack initiated from the exterior of
the VHP which is more susceptible to circumferential cracking. This
situation occurred after a small axial throughwall crack leaked. Thus,
it is expected that leakage would be detected long before significant
circumferential cracking could occur. Of the numerous VHP inspections
in Europe, Japan, and the United States, no additional cases of
circumferential cracking have been observed. The members of the
Westinghouse, Babcock & Wilcox and Combustion Engineering Owners Groups
through Nuclear Energy Institute submitted acceptance criteria for both
axial and circumferential cracking to the NRC for review and approval.
The acceptance criteria were partially accepted by the NRC staff. The
criteria for axial cracking were accepted as proposed. The criteria for
circumferential cracking were rejected. Any circumferential cracks
found must be reported to the NRC staff for disposition. If VHP
cracking violated the above acceptance criteria, the NRC staff would
review the Licensee's plan for monitoring or repair of the crack.
[[Page 64545]]
Finally, a foreign reactor developed extensive circumferential
cracking in VHPs as a result of two major demineralizer resin ingress
events in the early 1980s. The NRC staff issued a request for
additional information to NSP on September 25, 1995, to determine if
any similar resin ingress events had occurred at Prairie Island. The
Licensee responded to the NRC staff on October 24, 1995, that there
have been no resin ingress events at Prairie Island.
The NRC staff has closely monitored VHP cracking experience in the
U.S. and abroad and has reviewed extensive evaluations of VHP cracking.
The evaluations and operating experience indicate that it is highly
unlikely that significant circumferential cracks could develop and that
there is significant margin between the flaw sizes that would result in
detectable leakage and the flaw sizes that would jeopardize structural
integrity. Thus, the staff has concluded that VHP cracking is not a
safety concern at this time. To assure that VHP cracking continues to
be properly monitored and controlled, the NRC is in the process of
preparing a Generic Letter requesting addressees to describe their
program for ensuring the timely inspection of PWR CRDM VHPs and other
VHPs. This letter was issued for public comment on August 1, 1996.
Accordingly, the requests made by the Petitioners for the shutdown
of the Prairie Island units and inspection of the VHPs with enhanced
inspection techniques is denied. As explained above, the NRC staff has
concluded that no substantial health and safety issues have been raised
by the Petitioners.
C. Unloading of Dry Cask Storage Units
Spent fuel discharged from a reactor core is stored on site in a
spent fuel pool prior to transfer to the U.S. Department of Energy
(DOE) for final deposition. Typically, one-third of a reactor core is
discharged every refueling outage (approximately every 18 months in the
case of each of the Prairie Island units). The Licensee concluded
several years ago that it would reach maximum capacity in its spent
fuel pool in 1994, prior to availability of a DOE repository for
storage of spent fuel. To support the need for continued storage of
spent fuel at the reactor site, the Licensee applied to NRC for a
license to store spent fuel in an onsite independent spent fuel storage
installation (ISFSI). NRC issued Materials License No. SNM-2506 to NSP
on October 19, 1993, for receipt and storage of spent fuel at the ISFSI
on the site of the Prairie Island Nuclear Generating Plant. Materials
License No. SNM-2506 allows NSP to use the TN-40-type casks for storage
at its ISFSI. The TN-40, a metal cask system, is designed to store 40
PWR spent fuel assemblies in each cask. Dimensions of the cask (with
protective cover) are 202 inches high with an outside diameter of 103.5
inches. A loaded TN-40 storage cask weighs 109.3 metric tons.
On April 28, 1995, a public meeting was held in Red Wing,
Minnesota, to present NRC inspection findings related to dry cask
storage activities at the Prairie Island plant. Questions were raised
by members of the public as to how the Licensee would unload the spent
fuel in a dry storage cask, if it became necessary, i.e., would there
be enough empty fuel racks in the spent fuel pool to accommodate
unloading of the cask.
In a letter to the NRC dated May 3, 1995, the Licensee submitted a
plan for unloading the TN-40 cask in response to the questions raised
at the April 28, 1995, meeting. In that letter, the Licensee stated
that some of the fuel racks in the spent fuel pool contain nonfuel-
bearing components, which could be relocated to a temporary location in
the fuel transfer canal. Alternatively, it may be possible for the
components to be stored temporarily in the TN-40 cask, should it become
necessary to unload a cask. In the latter case, even though the TN-40
cask being returned to the spent fuel pool may no longer be qualified
to hold spent fuel, it quite possibly could still safely hold
irradiated nonfuel-bearing components.
The Petitioners raised issues concerning compliance with 10 CFR
50.59 and the need to make changes to Technical Specifications in order
to use the fuel transfer canal for nonfuel-bearing components under the
Licensee's plan. Petitioners also stated that 10 CFR 50.59 requires a
safety analysis and amendment to the operating license with a public
hearing whenever a change occurs in Technical Specifications for spent
fuel pool and reactor transfer canal use. Petitioners further stated
that a safety analysis is essential when a Technical Specification
change occurs.
The need for a change to the Technical Specifications and the
process to be followed under 10 CFR 50.59 are two separate, but
related, issues. With regard to the Prairie Island Technical
Specifications, the plan proposed by the Licensee in its letter of May
3, 1995, for dealing with the need to unload a cask, would not involve
a change to Technical Specifications because Technical Specifications
do not address use of the fuel transfer canal nor do they address
movement of nonfuel-bearing components within the spent fuel pool.
Prairie Island's Technical Specification 3.8 specifies operating
limitations associated with fuel-handling operations and core
alterations only. Further, the fuel transfer canal is not classified as
a reactor safety system. The fuel transfer canal provides no protection
for the reactor, nor does it mitigate the consequences of a postulated
accident to the reactor. The fuel transfer canal is a component of the
fuel storage and fuel handling systems, which is considered a plant
auxiliary system rather than a reactor safety system. As use of the
fuel transfer canal in the Licensee's plan does not involve a change to
the Technical Specifications, an amendment for this reason would not be
required and the opportunity to request a public hearing with regard to
a Technical Specification change would, therefore, not arise.
With regard to Sec. 50.59 of Title 10 of the Code of Federal
Regulations, that provision allows a Licensee to make changes to its
facility and procedures as described in the Final Safety Analysis
Report (FSAR) without prior approval from NRC, provided a change in
Technical Specifications is not involved (which, as described above, is
met in this instance) and an unreviewed safety question does not exist.
Before moving the nonfuel-bearing components to temporary storage racks
in its fuel transfer canal, NSP would need to determine if this use of
the transfer canal changes the facility or procedures as described in
the FSAR. If NSP determines that a change has been made to the facility
or procedures as described in the FSAR, then a safety evaluation
pursuant to 10 CFR 50.59 is required to be performed by the Licensee.
If a Technical Specification change were needed (not the case as
discussed above), or an unreviewed safety question existed, NRC review
and approval would be required. Otherwise, the Licensee could make the
modifications without prior NRC approval. Licensees submit a list of
modifications that were performed under 10 CFR 50.59 without NRC
approval to NRC annually.
The Licensee did not fail to comply with the requirements of 10 CFR
50.59 by presenting a plan for retrieval of fuel from a cask, which
included an option to place nonfuel-bearing components in the fuel
transfer canal. At the time a cask unloading is deemed necessary, the
Licensee can evaluate the specific modifications needed to implement
the plan and determine whether 10 CFR 50.59 is applicable.
When applying for the license, NSP performed an accident analysis,
in its Safety Analysis Report, as required by
[[Page 64546]]
NRC regulations.2 In its Safety Evaluation Report dated July 1993,
the NRC staff reviewed the Licensee's accident analysis and determined
that ``Dose equivalent consequences, from a single cask, to any
individual, from direct and indirect radiation and gaseous activity
release after postulated accident events, are less than the 50 mSv (5
rem) limit established in 10 CFR 72.106(b).'' Additionally, in its
Environmental Assessment, dated July 28, 1992, the NRC staff assessed
the accident dose at the Prairie Island site boundary as: ``a small
fraction * * * of the criteria specified.* * * '', and found that:
``These doses are also much less than the Protective Action Guides
established by the Environmental Protection Agency (EPA) for
individuals exposed to radiation as a result of accidents;* * *''
Because it has been shown that the dose equivalent from a single cask
to any individual from postulated accident events is not in excess of
the levels required for taking protective actions to protect public
health, the NRC staff considers that a time-urgent unloading of the TN-
40 cask is not a likely event.
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\2\ The Licensee analyzed accidents classified as Design Events
III and IV, as described in ANSI/ANS 57.9, ``Design Criteria for an
Independent Spent Fuel Storage Installation (Dry Storage Type).''
Design Event III consists of that set of infrequent events that
could reasonably be expected to occur during the lifetime of the
ISFSI. Design Event IV consists of the events that are postulated
because their consequences may result in the maximum potential
impact on the immediate environs. Included among the scenarios
considered under Design Event IV was a loss of confinement barrier
leading to an immediate release of radioactivity.
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Even if such an unlikely accident occurred and the Licensee
determines that corrective actions may need to be taken to maintain
safe storage conditions, options are available. This may include
returning the cask to the auxiliary building and/or the spent fuel pool
for repairs. Once the cask is in the spent fuel pool, it does not
necessarily have to be unloaded to maintain safe storage conditions. In
addition, the Licensee may have other options available to cover this
unlikely contingency including temporary storage of spent fuel in a
spare storage cask or use of an existing certified transportation cask.
The Licensee would have time to consider these, and other available
options, in such an unlikely event.
Petitioners also raise an issue concerning the necessity to offload
both the entire reactor core and a TN-40 cask simultaneously. NRC has
no requirement for licensees to maintain the spent fuel capacity to
offload the entire core at once. Prairie Island normally offloads only
one-third of the core during refueling outages. If NSP determines the
need to offload the entire core during a refueling outage, NSP can
install temporary fuel racks in the cask laydown area in the spent fuel
pool. Therefore, a cask could not be unloaded for the short time that
temporary racks are installed in the cask laydown area. The staff does
not view this as a problem for two reasons. First, the probability that
a cask would require unloading at the same time a full-core offload is
in process is extremely small. Second, in the event it became necessary
to unload a cask, fuel could be placed back into the reactor vessel and
the temporary fuel storage racks could be removed. As discussed above,
time-urgent unloading of a TN-40 cask is extremely unlikely. The cask
could then be unloaded after the cask laydown area was cleared of the
temporary fuel storage racks.
In addition to assuring that a TN-40 cask could be unloaded if
necessary, the Licensee's plan also provides assurance with regard to
spent fuel retrievability. Subpart F of 10 CFR part 72 provides general
design criteria for ISFSIs and monitored retrievable storage
installations. Section 72.122 sets overall requirements and 10 CFR
72.122(l) provides for retrievability of the fuel and states: ``Storage
systems must be designed to allow ready retrieval of spent fuel or
high-level radioactive waste for further processing or disposal.'' The
NRC staff concluded in a May 5, 1995, letter to the Licensee that the
ability to unload a TN-40 cask if necessary in accordance with the
Licensee's plan would satisfy this fuel retrievability provision.
Finally, Petitioners state that the wrong NRC department reviewed
and approved NSP's plan for retrievability of irradiated fuel. The
Office of Nuclear Material Safety and Safeguards (NMSS) is responsible
for licensing and regulating all issues under 10 CFR part 72, including
issues related to the design requirements for ISFSIs. Therefore, NMSS
is the correct NRC office to review whether the licensee's plan met 10
CFR 72.122(l). As discussed above, the Licensee's plan does not involve
a Technical Specification change. Accordingly, NRR review of such a
change would not be required. If, upon implementing its plan, the
Licensee determined that a safety evaluation pursuant to Sec. 50.59 was
required, NRR review and approval would be required only if an
unreviewed safety question existed.
With regard to the requests made by the Petitioners, there is no
basis for suspending NSP's operating licenses for the Prairie Island
units until a safety analysis is completed, reviewed, and approved by
NRC, and until NSP's licenses are amended and public hearings have been
held. If NSP plans to implement a specific plan to utilize the fuel-
transfer canal which changes the facility or procedures as described in
the FSAR, then an evaluation pursuant to 10 CFR 50.59 would be required
at that time, which would not require prior NRC approval unless an
unreviewed safety question exists or a change to Technical
Specifications is required.
D. Auxiliary Building Crane
Petitioners contend that a recent incident at Prairie Island on May
13, 1995, involving the crane used to lift the dry cask for Prairie
Island's ISFSI, requires physical testing and safety analysis before
future crane use. The incident resulted in the crane holding the
123.75-ton cask above the surface of the reactor pool for 16 hours. The
Petitioners assert that the incident could have caused metal fatigue
within the crane's structure and the cables attached to the crane.
Also, Petitioner Prairie Island Coalition asserts in its June 21, 1995,
letter to the Chairman of the NRC that the crane, its cable, and its
cable mechanisms were not designed to withstand holding nearly a
maximum load for 16 hours.
The Prairie Island auxiliary building crane was upgraded in 1992 in
accordance with the provisions of Topical Report EDR-1(P), ``Ederer
Nuclear Safety-Related Extra Safety and Monitoring (X-SAM) Cranes.''
The crane is designed and tested in accordance with the NRC staff's
guidance as outlined in NUREG-0554, ``Single-Failure-Proof Cranes for
Nuclear Power Plants,'' and NUREG-0612, ``Control of Heavy Loads at
Nuclear Power Plants.''
The staff evaluated the design of the auxiliary building crane and
the lifting device for the cask as part of its review of the dry cask
ISFSI. This crane system is designed so that a single failure will not
result in the loss of the capability of the system to safely retain the
load (this design is known as single-failure proof). The crane is
designed to handle a rated load of 125 tons and is capable of raising,
lowering, and transporting occasional loads, for testing purposes, of
25-percent higher than the rated load without damage or distortion to
any crane part. All parts of the crane that are subjected to dynamic
strains, such as gears, shafts, drums, blocks, and other integral
parts, have a safety factor of 5 (i.e., they are designed to lift 5
times the design rated load). The hook has a
[[Page 64547]]
design safety factor of 10 and was subjected to a 200-percent overload
test followed by magnetic particle inspection prior to initial
operation. Protection against wire rope wear and fatigue damage are
ensured by scheduled inspection and maintenance. The special lifting
device used for cask movement is designed to support 6 times the weight
of the fully loaded cask and was subjected to a 300-percent overload
test by the manufacturer. The lifting device undergoes dimensional
testing, visual inspection, and nondestructive testing every 12 months
(plus or minus 25 percent).
A single-failure-proof crane, such as the crane at Prairie Island,
that has become immobilized by failure of components while holding a
load, is able to hold the load or set the load down while adjustments
or repairs are made. Safety features and emergency devices permit
manual operation to accomplish this task. Two separate magnetic brakes
are provided as well as an emergency drum band brake. Each magnetic
brake provides a braking force of at least 150 percent of rated load.
The emergency drum brake assures that the load can be safely lowered
even if power is lost to the crane. Because of the large design margins
and the ability to withstand a failure of any single component, the NRC
staff does not postulate a load drop from a single-failure-proof crane.
After the incident on May 13, 1995, the Licensee temporarily
removed the crane from service for testing. The Licensee and the crane
vendor performed testing on the crane to analyze the event and assure
the crane was operable. The Licensee's analysis of the May 13, 1995,
incident found the problem to be an improperly calibrated load cell (a
load cell is a device that measures the load being lifted by the crane
and provides input to an overload-sensing device). It was determined
that the actual load was less than what was being sensed by the
overload-sensing device. The function of the overload-sensing device is
to stop the operation of the crane when the load reaches a
predetermined value. This prevents loading the crane beyond its rated
load by maintaining loads within the design working limit, thereby
maintaining safety and the physical integrity of the crane system.
Since the design-rated load of the crane was not exceeded during
the incident, there is no reason to assume that the crane cannot
continue to operate safely. Even if the rated load had been exceeded,
an analysis would be needed to determine how much the rated load was
exceeded and if that amount is significant. When cranes are built,
manufacturers conduct proof tests at a load above rated load. The proof
test for this crane was 25 percent higher than the 125-ton design-rated
load for the main hoist (i.e., the proof test was 156.25 tons).
With regard to the Petitioners' comment about metal fatigue, metal
fatigue is a condition that results from cyclic stress. Cyclic stress
is produced by repeated loading and unloading. The crane is designed to
handle all loading and unloading cycles during the life of the plant,
including construction and operating periods. A single static
(constant) load such as the load in question, does not produce the
cyclic stress that causes metal fatigue. The Petitioners' contention
that it was never contemplated that the Prairie Island polar crane hold
a load of 123.75 tons inches above the surface of the reactor pool for
16 hours is incorrect. The contemplated failure mechanism of a single-
failure proof crane is to hold the load safely at any location until
the load can be safely moved. Because of the large design margins, the
length of time that a design-rated load (or a load less than design
rated) is on the hook of a single-failure-proof crane is
inconsequential.
With regard to cable and cable mechanisms (also known as the
reeving system and lifting devices), the crane is provided with a
balanced dual reeving system with each wire rope capable of supporting
the maximum critical load (if a load being held by a crane can be a
direct or indirect cause of release of radioactivity, the load is
called a critical load). The hydraulic load equalizing system allows
transfer of the load to the remaining rope, without overstressing it,
in the event of a failure of one rope. Protection against wire rope
wear and fatigue damage are ensured by scheduled inspection and
maintenance.
In conclusion, NRC agrees with the Licensee in its determination
that the cause of the incident was an incorrectly calibrated load cell.
This cause was documented in NRC Inspection Report 95-006, issued June
27, 1995. NRC has determined that the Licensee met the design and
testing requirements established in industry standards for the control
of heavy loads such as a dry storage cask, that the overload-sensing
device worked as designed, and that no safety issue was involved in the
Licensee's use of the auxiliary building crane and associated cask
handling equipment to move the cask. Therefore, the Petitioners'
requests for suspension of NSP's licenses for the Prairie Island units
until physical testing and safety analyses can be performed on the
crane are denied.
IV. Conclusion
Petitioners requested an immediate suspension of NSP's licenses for
Prairie Island Units 1 and 2 until corrective actions of potentially
hazardous conditions would be taken by NSP and NRC with regard to
issues identified in the Petition. The institution of a proceeding in
response to a request for action under 10 CFR 2.206 is appropriate only
when substantial health and safety issues have been raised. See
Consolidated Edison Co. of New York, (Indian Point, Units 1, 2, and 3),
CLI-75-8, 2 NRC 173, 176 (1975), and Washington Public Power Supply
System (WPPSS Nuclear Project No. 2), DD-84-7, 19 NRC 899, 923 (1984).
I have applied this standard to determine if any action is warranted in
response to the matters raised by the Petitioners. Each of the claims
by the Petitioners has been reviewed. The available information is
sufficient to conclude that no substantial safety issue has been raised
regarding the operation of Prairie Island Units 1 and 2. Therefore, I
conclude that, for the reasons discussed above, no adequate basis
exists for granting Petitioners' requests for immediate suspension of
NSP's licenses for Prairie Island Units 1 and 2.
A copy of this decision will be filed with the Secretary of the
Commission for the Commission to review in accordance with 10 CFR
2.206(c).
As provided by this regulation, this decision will constitute the
final action of the Commission 25 days after issuance, unless the
Commission, on its own motion, institutes a review of the decision with
that time.
Dated at Rockville, Maryland, this 27th day of November, 1996.
For the Nuclear Regulatory Commission.
Frank J. Miraglia,
Acting Director, Office of Nuclear Reactor Regulation.
[FR Doc. 96-30949 Filed 12-04-96; 8:45 am]
BILLING CODE 7590-01-P
