[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