[Federal Register Volume 61, Number 128 (Tuesday, July 2, 1996)]
[Notices]
[Pages 34454-34460]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 96-16878]
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NUCLEAR REGULATORY COMMISSION
[Docket Nos. 50-528, 50-529 and 50-530]
Arizona Public Service Company; Palo Verde Nuclear Generating
Station, Unit Nos. 1, 2, and 3; Issuance of Director's Decision Under
10 CFR Sec. 2.206
Notice is hereby given that the Director, Office of Nuclear Reactor
Regulation, has acted on a Petition for action under 10 CFR Sec. 2.206
received from Mr. Thomas J. Saporito, Jr., on behalf of Florida Energy
Consultants, Inc., dated May 27, 1994, as supplemented on July 8, 1994,
for the Palo Verde Nuclear Generating Station, Unit Nos. 1, 2, and 3.
In a letter dated May 27, 1994, the Petitioner requested that the
NRC (1) institute a show-cause proceeding pursuant to 10 CFR Sec. 2.202
to modify, suspend, or revoke the operating licenses for Palo Verde;
(2) issue a notice of violation against the licensee for continuing to
employ The Atlantic Group (TAG) as a labor contractor at Palo Verde;
(3) investigate alleged material false statements made by William F.
Conway, Executive Vice President at Palo Verde, during his testimony at
a Department of Labor hearing (ERA Case No. 92-ERA-030) and, in the
interim, require that he be relieved of any authority over operations
at Palo Verde; (4) investigate the licensee's statements in a letter of
August 10, 1993, from Mr. Conway to the former NRC regional
administrator, Mr. Bobby H. Faulkenberry, that Mr. Saporito gave
materially false, inaccurate, and incomplete information on his
application for unescorted access to Palo Verde and that, as a result,
he lacks trustworthiness and reliability for access to Palo Verde; (5)
investigate the circumstances surrounding the February 1994 termination
of licensee employee Joseph Straub, a former radiation protection
technician at Palo Verde, to determine if his employment was illegally
terminated by the licensee because he engaged in ``protected activity''
during the course of his employment; (6) require the licensee to
respond to a ``chilling effect'' letter regarding the circumstances
surrounding Mr. Straub's termination from Palo Verde and to specify
whether any measures were taken to ensure that his termination did not
have a chilling effect at Palo Verde; and (7) initiate appropriate
actions to require the licensee to immediately conduct eddy current
testing on all steam generators at Palo Verde because the steam
generator tubes were recently found to be subject to cracking.
In a letter dated July 8, 1994, the Petitioner raised six
additional issues. This supplemental Petition asked the NRC to (1)
institute a show-cause proceeding pursuant to 10 CFR Sec. 2.202 for the
modification, suspension, or revocation of the Palo Verde operating
licenses for Units 1, 2, and 3; (2) modify the Palo Verde operating
licenses to require operation at 86-percent power or less; (3) require
the licensee to submit a No Significant Hazards safety analysis
[[Page 34455]]
to justify operation of those units above 86-percent power; (4) take
immediate action (e.g., by confirmatory order) to make the licensee
reduce operation to 86-percent power or less; (5) require the licensee
to analyze a design-basis steam generator tube rupture (SGTR) event to
show that the offsite radiological consequences do not exceed a small
fraction of the limits of 10 CFR Part 100; and (6) require the licensee
to demonstrate that its emergency operating procedures for SGTR events
are adequate and that the plant operators are sufficiently trained in
emergency operating procedures.
The Director of the Office of Nuclear Reactor Regulation has
determined that requests 1, 2, 3, 5, and 6 of the July 8, 1994,
Petition supplement should be denied for the reasons stated in the
``Director's Decision Under 10 CFR Sec. 2.206'' (DD-96-08), the
complete text of which follows this notice and which is available for
public inspection at the Commission's Public Document Room, the Gelman
Building, 2120 L Street, N.W., Washington, D.C. 20555, and at the local
public document room located at the Phoenix Public Library, 1221 N.
Central Avenue, Phoenix, Arizona 85004. The Petitioners' two requests
for immediate action (Request 7 of the May 27, 1994 Petition and
Request 4 of the July 8, 1994, Petition supplement) were denied in a
letter dated July 26, 1994. The remaining requests are under
consideration and will be addressed in a separate decision. A
Director's Decision (DD-96-04) regarding Requests 1 through 6 in the
Petition of May 27, 1994, was issued under separate cover letter on
June 3, 1996.
A copy of this Decision will be filed with the Secretary for the
Commission's review in accordance with 10 CFR Sec. 2.206. As provided
by the regulation, the Decision will constitute the final action of the
Commission 25 days after the date of issuance of the Decision unless
the Commission on its own motion institutes a review of the Decision
within that time.
Dated at Rockville, Maryland, this 25th day of June 1996.
For the Nuclear Regulatory Commission.
William T. Russell,
Director, Office of Nuclear Reactor Regulation.
I. Introduction
On May 27, 1994, Florida Energy Consultants, Inc. (FEC), by and
through Thomas J. Saporito, Jr. (Petitioners), submitted a Petition
pursuant to 10 CFR Sec. 2.206 to the U.S. Nuclear Regulatory Commission
(NRC). The Petition requested that the NRC (1) institute a show-cause
proceeding pursuant to 10 CFR Sec. 2.202 to modify, suspend, or revoke
the operating licenses of Arizona Public Service Company (licensee or
APS) for Palo Verde Nuclear Generating Station (PVNGS or Palo Verde);
(2) issue a notice of violation against the licensee for continuing to
employ The Atlantic Group (TAG) as a labor contractor at Palo Verde;
(3) investigate alleged material false statements made by William F.
Conway, Executive Vice President at Palo Verde, during his testimony at
a Department of Labor hearing (ERA Case No. 92-ERA-030) and, in the
interim, require that he be relieved of any authority over operations
at Palo Verde; (4) investigate the licensee's statements in a letter
dated August 10, 1993, from Mr. Conway to the former NRC regional
administrator, Mr. Bobby H. Faulkenberry, that Mr. Saporito gave
materially false, inaccurate, and incomplete information on his
application for unescorted access to Palo Verde and that, as a result,
Mr. Saporito lacks trustworthiness and reliability for access to Palo
Verde; (5) investigate the circumstances surrounding the February 1994
termination of licensee employee Joseph Straub, a former radiation
protection technician at Palo Verde, to determine if his employment was
illegally terminated by the licensee because he engaged in ``protected
activity'' during the course of his employment; (6) require the
licensee to respond to a ``chilling effect'' letter regarding the
circumstances surrounding Mr. Straub's termination from Palo Verde and
specify whether any measures were taken to ensure that his termination
did not have a chilling effect at Palo Verde; and (7) initiate
appropriate actions to require the licensee to immediately conduct eddy
current testing (ECT) on all steam generators (SGs) at Palo Verde
because the SG tubes were recently found to be subject to cracking.
As the bases for these requests, the Petitioners allege that (1) a
show-cause proceeding is necessary (a) because the public health and
safety concerns alleged are significant and (b) to permit public
participation to provide NRC with new and relevant information; (2)
past practices of TAG demonstrate that employees of TAG were retaliated
against for having raised safety concerns while employed at Palo Verde;
(3) citations to testimony from transcripts and newspaper articles
(appended as exhibits to the Petition) demonstrate that Mr. Conway's
testimony is not credible; (4) statements in the letter of August 10,
1993, are inaccurate and materially false and characterize Mr. Saporito
as an individual lacking trustworthiness and reliability for access to
Palo Verde, and that such negative characterizations have caused the
nuclear industry to blacklist him from continued employment, all in
retaliation for his raising safety concerns about operations at Palo
Verde; thus, the Petitioners ask that these statements be rescinded;
(5) an investigation into the termination of Mr. Straub is warranted in
view of the fact that the licensee has engaged in similar illegal
conduct in the past for which the NRC has required the licensee to pay
fines; (6) Mr. Straub is entitled to reinstatement with pay and
benefits pending the NRC's investigation into his termination to offset
the chilling effect his termination had on the Palo Verde workforce;
and (7) in addition to cooling tower problems, the stress-corrosion and
cracking in the SGs is a recurring problem of which the licensee is
aware and has failed to properly correct, so that the NRC should be
concerned about proper maintenance of safety systems and equipment at
Palo Verde.
On July 8, 1994, the Petitioners filed a supplemental Petition
(Petition supplement) raising six additional issues. The Petitioners
requested that the NRC (1) institute a show-cause proceeding pursuant
to 10 CFR Sec. 2.202 for the modification, suspension, or revocation of
the Palo Verde operating licenses for Units 1, 2, and 3; (2) modify the
Palo Verde operating licenses to require operation at 86-percent power
or less; (3) require the licensee to submit a No Significant Hazards
safety analysis 1 to justify operation of those units above 86-
percent power; (4) take immediate action (e.g., by confirmatory order)
to require the licensee to reduce operation to 86-percent power or
less; (5) require the licensee to analyze a design-basis steam
generator tube rupture (SGTR) event to show that the offsite
radiological consequences do not exceed a small fraction of the limits
of 10 CFR Part 100; and (6) require the licensee to demonstrate that
its emergency operating procedures (EOPs) for steam generator (SG) tube
rupture events are adequate and the plant operators are sufficiently
trained in EOPs.
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\1\ Section 50.91 of the Commission's regulations provides that
at the time a licensee requests an amendment it must provide the NRC
its analysis of the issue of no significant hazards consideration,
using the standards of Section 50.92.
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As bases for these requests, the Petitioners allege that (1) the
licensee experienced an SGTR in the free-span area on Unit 2 on March
14, 1993; (2) during a January 1994 inspection on
[[Page 34456]]
Unit 2, 85 axial indications were identified, the longest indication
being 7.5 inches; (3) as of May 1994, 28 axial indications were found
at Unit 2 and 9 axial indications were found at Unit 1 (more extensive
testing will confirm the existence of circumferential crack indications
in the expansion and transition areas); (4) in May 1994, SG sludge from
Units 1 and 2 indicated a lead content of 4,000 to 6,000 ppm, which is
unusually high, accelerates the crevice corrosion process, and is
believed to be caused by a feedwater source deficiency; (5) in eight
instances, the licensee failed to properly implement operational
procedures during the SGTR event on March 14, 1993; (6) the licensee's
failure to comply with approved procedures in the above-mentioned event
is indicative of a problem plant that warrants further NRC action; (7)
in four instances, the NRC is aware of additional licensee weaknesses
regarding the SGTR event; (8) the licensee cannot ensure that the
radiation dose limits are satisfied for applicable postulated
accidents; (9) the licensee is not maintaining an adequate level of
public protection in that the offsite dose limits will be exceeded
during an SGTR; (10) the licensee cannot demonstrate that a Palo Verde
unit can safely be shut down and depressurized to stop SG tube leakage
before a loss of reactor water storage tank inventory; (11) SG tubes
are an integral part of the reactor coolant boundary and tube failures
could lead to containment bypass and the escape of radioactive fission
products directly into the environment and, therefore, must be
carefully considered by NRC and the licensee; (12) the licensee cannot
demonstrate compliance with 10 CFR Part 50, Appendix A, which
establishes the fundamental requirements for SG tube integrity; (13)
the licensee has failed to comply with NRC recommendations under NUREG-
0800 to show that in the case of an SGTR event, ``the offsite
conditions and single failure do not exceed a small fraction of the
limits of 10 CFR Part 100''; and (14) the licensee has posed an
unacceptable risk to public health and safety by raising power on all
three Palo Verde units above 86 percent, considering the severe
degradation of the SG tubes.
In a letter dated July 26, 1994, I acknowledged receipt of the
Petition of May 27, 1994, and the Petition supplement of July 8, 1994,
and denied the Petitioners' two requests for immediate action. The
Petitioners requested the initiation of actions to require the licensee
to immediately conduct ECT on all SGs at Palo Verde (Request 7 of the
May 27, 1994, Petition) and immediate action to cause the licensee to
reduce operation to 86-percent power or less (Request 4 of the July 8,
1994, Petition supplement). Although these two requests for immediate
action were denied, the concerns raised by the Petitioners regarding
their requests for ECT and reduced power operation are addressed in
this Decision.
The staff informed the Petitioners that the remaining requests were
being evaluated under 10 CFR Sec. 2.206 of the Commission's regulations
and that a response would be forthcoming. This Decision addresses the
Petitioners' concerns about ECT (Request 7 of the May 27, 1994,
Petition), steam generator tube integrity, and emergency operating
procedures for SGTR events and the remaining requests (Requests 1, 2,
3, 5, and 6) of the July 8, 1994, supplement. The staff has completed
its review of the remaining issues in your supplemental Petition. A
Director's Decision (DD-96-04) regarding Requests 1 through 6 in the
Petition of May 27, 1994, was issued under separate cover letter on
June 3, 1996. A discussion of the Director's Decision follows.
II. Background
The Petitioners' concerns addressed in this Decision appear to be
based largely on the March 1993 SGTR event and the NRC staff findings
concerning that event set forth in the NRC Augmented Inspection Team
(AIT) 2 report. Palo Verde Unit 2 experienced an SGTR event in SG
No. 2 on March 14, 1993. At the time, the unit was at about 98-percent
power. The plant operators manually tripped the reactor, declared an
Unusual Event,3 which was subsequently upgraded to an Alert,4
and entered the PVNGS Functional Recovery Procedure 5 to mitigate
the event. The plant was cooled down and depressurized, and the event
was terminated when Mode 5 6 was achieved on March 15, 1993.
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\2\ An AIT is an NRC inspection team composed of experts from
the responsible NRC Regional Office augmented by personnel from NRC
Headquarters and others Regions with special technical
qualifications. The purpose of an AIT is to determine the causes,
conditions, and circumstances relevant to an event and to
communicate its findings, safety concerns, and recommendations to
NRC management.
\3\ The lowest level of emergency classification as delineated
in 10 C.F.R Part 50, Appendix E.
\4\ The second lowest level of emergency classification as
delineated in 10 C.F.R. Part 50, Appendix E.
\5\ PVNGS Procedures providing operators' actions for responding
to design basis events.
\6\ The operational mode defined as cold shutdown in plant
technical specifications.
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During the period March 17-25, 1993, an NRC AIT conducted an
inspection at PVNGS Unit 2. Overall, the AIT concluded that the
response to the SGTR succeeded in bringing the unit safely to a cold-
shutdown condition and limiting the release of radioactivity so that
there was no threat to public health and safety. However, the AIT
identified weaknesses in the licensee's implementation of emergency
plan actions, including event classification, activation of the
emergency response facilities, and prompt assignment of tasks to onsite
personnel. Weaknesses were also found in the procedures, equipment, and
training associated with responding to an SGTR event. The AIT
inspection was documented in NRC Inspection Report No. 50-529/93-14,
issued on April 16, 1993.
Enforcement action resulted from the AIT inspection in several
areas (e.g., emergency preparedness, chemistry and radiation
monitoring, and emergency operating procedures). All violations were
issued as Severity Level IV.7
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\7\ See EA 93-119 (issued July 1, 1993) and EA 93-039 (issued
April 27, 1993). At the time, violations were categorized in terms
of five levels of severity. Severity Level I and II violations were
of very significant regulatory concern. Severity III violations were
cause for significant regulatory concern. Severity Level IV
violations were less serious but were of more than minor concern.
Severity Level V were of minor safety or environmental concern.
General Statement of Policy and Procedure for NRC Enforcement
Actions, 10 CFR Part 2, Appendix C, Section IV. Effective June 30,
1995, the NRC's Enforcement Policy, as published in the Federal
Register (60 FR 34381), is set forth in NUREG-1600.
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The NRC issued a confirmatory action letter 8 (CAL) to the
licensee on June 4, 1993, for Unit 2. The NRC issued a safety
evaluation by letter dated August 19, 1993, concluding that Unit 2
could safely resume operation for 6 months, the interval between steam
generator tube inspections. This safety evaluation closed the CAL.
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\8\ This CAL set forth commitments made by the licensee to the
NRC staff on June 2, 1993, regarding the SGTR event on Unit 2. In
the CAL, the staff confirmed the licensee's commitment (1) to notify
the NRC prior to completion of ECT on the Unit 2 SGs; (2) to include
the proposed operating interval to the next SG tube inspection in
its safety analysis; and (3) not to restart Unit 2 until the NRC
concurs with the restart of the facility.
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The NRC issued a second CAL 9 on October 4, 1993, for Unit 3
(amended on
[[Page 34457]]
November 8 and 23, 1993), confirming the commitments made by the
licensee in its September 29, 1993, letter. By letter dated December 3,
1993, the licensee reported that it had completed the actions discussed
in the CAL. Satisfied that the licensee had completed the conditions of
the CAL, the staff closed the CAL by letter dated April 1, 1994.
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\9\ In this CAL, the staff confirmed the licensee's commitment
to (1) shut down Unit 3 for ECT inspection of both SGs; (2) continue
the review of Unit 3 ECT data to identify indications that were not
identified in refueling outage 3R3 by bobbin coil ECT and to provide
a written summary of the review; (3) continue to implement the Unit
1 SG inspection plan (SGIP); (4) implement changes to emergency
operating procedures (EOPs), operator training, and leakage
monitoring; and (5) continue to operate Unit 3 to take advantage of
some of the preventive measures that can be taken to reduce outside-
diameter stress corrosion cracking (ODSCC) rates.
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The licensee voluntarily reduced power to approximately 86-percent
power in the fall of 1993 to minimize steam generator degradation. The
licensee evaluated and implemented several improvements to the
operation of its steam generators, one of which was a reduction in the
reactor coolant system hot-leg temperature. The units were all returned
to 100-percent power by the fall of 1994.
Following a midcycle outage on Unit 2 and midcycle and refueling
outages on Unit 3, the NRC issued a safety evaluation on June 22, 1994,
which concluded that both Unit 2 and 3 could safely operate for 6
months between steam generator tube inspections. Since that time, there
have been additional midcycle outages on Units 2 and 3 and a refueling
outage on all three units. Eddy current inspection results and outage
planning for the Units currently support the following operating
intervals between inspections: Unit 1, 16 months; Unit 2, 12 months;
and Unit 3, 11 months.
III. Discussion
A. Eddy Current Testing on All Steam Generators at Palo Verde
Item 7 of the Petitioners' letter of May 27, 1994, requested the
NRC to require the licensee to conduct immediate ECT on all SGs at Palo
Verde to ascertain the integrity and life expectancy of the SG tubes.
Although, as indicated above, this request for immediate action has
been denied, the Petitioners' concerns regarding ECT are addressed
below.
The Petitioners assert as a basis (Petition Basis 7) for their
request concerning ECT that the licensee's SGs have recently developed
cracks in the free-span portion of their internal structure, that tube
stress corrosion and cracking is a recurring problem in SGs, and that
there is a risk the emergency cooling system will be unable to prevent
the melting of the fuel because of tube ruptures.10
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\10\ The Petitioner also mentioned cooling tower problems in
this basis, stating that ``the NRC should be concerned about proper
maintenance of safety systems and equipment there.'' The cooling
towers at Palo Verde are not safety-related systems. If the cooling
towers of a unit were incapacitated, the unit might operate less
efficiently, but that would be an economic penalty, rather than a
safety problem. The Petitioners did not provide any specific
examples of problems with the cooling towers, though the staff is
aware of the general maintenance problems the licensee has had with
the cooling towers. This issue was the subject of a previous
Director's Decision, Arizona Public Service Company, (Palo Verde
Nuclear Generating Station, Units 1, 2, and 3, DD-92-1, 35 NRC 133,
137 (1992), which found no substantial nuclear safety concern with
the condition of the cooling towers.
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The licensee has completed at least two eddy current inspections on
each of the Palo Verde units since the SGTR event in March 1993. The
staff issued safety evaluations (SEs) that addressed Unit 2 and 3
operating intervals by letters dated August 19, 1993, and June 22,
1994.11 These SEs were based on the results of the licensee's eddy
current inspections of Unit 1 in October 1993, of Unit 2 in May 1993
and January 1994, and of Unit 3 in December 1993 and May 1994. In
summary, the staff concluded that Units 2 and 3 could be safely
operated for up to 6 months between SG eddy current inspections. The
licensee conducted five of these ``minicycles'' 12 (three on Unit
2 and two on Unit 3), thereby obtaining extensive SG eddy current data,
which it used to validate models used for analysis. In May 1995, the
licensee submitted a report supporting a cycle length of up to 11
months on Unit 3. Unit 1 completed a 16-month operating cycle in June
1995. After meeting with the licensee, the staff approved a Unit 3
cycle length of 11 months in a meeting summary dated August 22, 1995.
During a September 20, 1995, meeting with the staff, the licensee
presented its submittal and arguments to support a 12-month cycle for
Unit 2. The staff incorporated data from the most recent Unit 3 steam
generator inspection in its evaluation of the licensee's conclusion
regarding a 12-month operating cycle on Unit 2. The staff approved the
12-month operating cycle by letter dated March 5, 1996.
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\11\ Unit 1 was not directly addressed in the SEs because no
free span axial indications were identified on Unit 1 at the time.
\12\ The Palo Verde operating cycle is normally 16-18 months.
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In summary, the licensee performed the necessary eddy current
inspections, and the staff extensively reviewed and approved Palo Verde
SG eddy current inspection results and continues to review additional
information regarding the integrity of the SG tubes. On the basis of
its review of ECT, the staff has concluded that the Petitioners'
concerns regarding the need for ECT have been satisfactorily addressed
by the licensee and that no further action by the NRC staff is
warranted.
B. Operation Above 86-Percent Power
Requests 1, 2, 3, and 4 of the Petition supplement, in essence,
request actions requiring the Palo Verde licenses to be modified to
require operation at 86-percent power or less.13
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\13\ The specific request for immediate action to make the
licensee reduce operation to 86-percent power or less (Request 4)
was denied by letter of July 26, 1994. With regard to the request
(Request 3) to require the licensee to submit a No Significant
Hazards safety analysis to justify operation of the units above 86-
percent power, the licensee is not required by the NRC regulations
to submit a no significant hazards analysis, since a TS change was
not required to resume operation above 86-percent power. The staff
did, however, review a no significant hazards analysis related to
operation of the Units at 100-percent power with a reduced hot-leg
temperature. These TS changes were submitted by the licensee on
February 18, 1994, for Units 1 and 3; and on July 1, 1994, for Unit
2. The NRC staff review of these TS changes and support for
operation at a power level of 100 percent is discussed at page 17,
infra.
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As bases for these requests, the Petitioners assert that on March
14, 1993, Palo Verde Unit 2 had an SGTR in the free-span section
between the tube supports and that in January 1994, an inspection of
Palo Verde's Unit 2 SGs found 85 axial indications (longest indication,
7.5 inches) (Petition supplement, Basis 2); and that as of May 1994, 28
axial indications were found at Unit 2 and 9 axial indications found at
Unit 1. The Petitioners believe that more extensive testing will
confirm the existence of circumferential crack indications in the
expansion-transition area (Petition supplement, Basis 3). The
Petitioners also assert that in May 1994, Units 1 and 2 SG sludge
indicated a lead content of 4,000-6,000 ppm, which would accelerate the
crevice corrosion cracking process (Petition supplement, Basis 4). The
Petitioners also stated that the operation of Palo Verde units at above
86-percent power is unacceptable due to severe degradation of the SG
tubes (Petition supplement, Basis 14).
Axial and Circumferential Steam Generator Tube Indications
With regard to the Petitioners' concern about identifiable axial
indications (Petition supplement Basis 2), it is correct that 85 axial
indications in the free-span area (longest indication, 7.5 inches) were
discovered on SG tubes at Palo Verde Unit 2 during the January 1994
inspection. However, this number was apparently based on preliminary
information from the licensee's eddy current inspection during the
January 1994 eddy current inspection. The licensee's report of March 8,
1994, stated that actually 330 free-span axial indications were
discovered during the Unit 2 first midcycle outage: 22 in SG 1 of Unit
2 (SG 21) and 308 in SG 2 of
[[Page 34458]]
Unit 2 (SG 22). Although a number of axial indications were detected by
the licensee, it is not the number of indications that is of a safety
concern but rather the severity of the indications (i.e., severity in
terms of whether the tube indication had adequate structural and
leakage integrity). As noted in the Petition supplement, the longest
indication was 7.5 inches long. The safety significance of this
indication, as with any eddy current indication, depends not only on
the length of the indication but also on the depth of the indication.
To assess the safety significance and/or severity of an indication,
licensees size the indications in terms of length, depth, and/or
voltage.14 However, eddy current testing methods have not been
qualified for determining the depth of stress corrosion cracks. Where
qualified eddy current methods do not exist, licensees may pursue
alternative methods such as in situ pressure testing 15 to further
confirm or assess the condition of the tube (i.e., to confirm that the
tube indication could withstand the required pressure loadings; thereby
demonstrating that the tube had adequate structural integrity). The
licensee did select nine tubes for in situ pressure testing during the
outage. The 7.5 inch long indication did not meet the licensee's
screening criteria for selecting the more severe indications. The
screening criteria, discussed in the NRC staff's SE of June 22, 1994,
considered the length, depth, and/or voltage of the indication. All
nine tubes satisfactorily passed the in situ pressure test thereby
providing reasonable assurance that the tube indications had adequate
structural integrity. Furthermore, all tubes with axial free span
indications were plugged before Unit 2 was returned to operation.
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\14\ Voltage is electrical force or potential difference.
Voltage measurements can be used to estimate the severity of an
indication.
\15\ In situ pressure tests were conducted to determine whether
the tubes could withstand the pressure loading specified in NRC
Regulatory Guide 1.121 (i.e., whether the SG tubes have adequate
structural integrity).
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The Petitioners also assert as of May 1994, 28 axial indications
were found on Unit 2 and 9 axial indications found at Unit 1 and that
more extensive testing would confirm the existence of circumferential
crack indications in the expansion transition areas (Petition
supplement, Basis 3). These numbers are incorrect. Neither Unit 1 nor
Unit 2 was in an outage conducting eddy current examinations in May
1994. Unit 1 had no axial indications identified as of this date. The
Unit 2 data is described above. Unit 3 was in an outage at this time
and identified a total of 20 axial indications. Regarding the
performance of more extensive testing to confirm the existence of
circumferential crack indications at the expansion transition area, the
licensee has performed inspections in this region. In general, the
licensee's steam generator tube inspection program consists of an
initial inspection sample which is expanded, if necessary, based on the
initial inspection sample results. The licensee has been examining the
expansion transition locations with a motorized rotating pancake coil
(MRPC) probe since, at least, 1993. These examinations permit the
licensee to detect circumferential crack indications. In its SEs and
meeting summaries, the NRC staff has reviewed the licensee's results
from its MRPC inspections and found them acceptable.16 To date,
Palo Verde Units 2 and 3 have each exhibited a small number of
circumferential crack indications per Unit. Unit 1 has exhibited the
most extensive circumferential cracking both in terms of number of
indications and the severity of the indications when compared to Units
2 and 3. Nonetheless, the staff concluded in a meeting summary dated
October 19, 1994, that operating Unit 1 to the end of the operating
cycle (April 1995) did not pose an undue risk to public health and
safety in view of (1) the absence of detectable axial free-span cracks
during the previous refueling outage inspection; (2) the improved
secondary water chemistry performance at Palo Verde; (3) the reduced
hot-leg temperature, which is expected to reduce crack growth rates;
and (4) the implementation of enhanced MRPC inspection techniques at
the expansion transition locations. The licensee will continue to
perform extensive SG inspections at the end of each operating cycle to
ensure continued safe operation of SGs.
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\16\ The Staff's reviews are documented in SEs dated August 19,
1993, and June 22, 1994, and also in meeting summaries dated August
22, 1995, March 22, 1994, October 19, 1994, August 22, 1995, and
September 20, 1995.
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Lead Content in Steam Generator Tube Sludge
The Petitioners assert without providing any supporting basis that
the SG sludge of Units 1 and 2 has a lead content of 4,000-6,000 ppm
(Petition supplement, Basis 4). The licensee performed sludge analyses
during two consecutive Unit 1 outages. The data, which were reported in
a letter from the licensee dated November 2, 1993, indicate a lead
content of 78 ppm (from Unit 1, Refueling 3) and 98 ppm (Unit 1,
Refueling 4).17 Sludge samples were obtained from both Unit 2 SGs
after the March 1993 SGTR event. The data were documented in the
licensee's report, ``Equipment Root Cause of Failure.'' Both the
licensee and outside contractors analyzed the samples; all analyses
indicated a lead content of 100 ppm or less.
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\17\ During the Unit 2 midcycle outage in early 1994, the SGs
were chemically cleaned before sludge lancing; therefore, the
composition of the sludge was not tested.
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The NRC staff conducted two Palo Verde chemistry inspections
(Inspection Reports 94-15 and 94-27 on Units 50-528/50-529/50-530). The
staff reviewed films and sludge for their lead content, and the data
were consistent with the licensee's reports. Inspection Report 50-528/
50-529/50-530/94-15 specifically referred to the inspector's
determination to note ``whether lead was detected, because of recent
work which indicated it may have a deleterious effect.'' In referring
to examinations of the burst region 18 of pulled tubes, the report
stated that insignificant levels of lead were found in the sludge and
in the films examined.
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\18\ Burst region refers to the section of the crack in a pulled
tube that is exposed as the result of a burst or rupture due to an
applied pressure either during plant operation or laboratory
testing.
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Inspection Report 50-528/50-529/50-530/94-15 also reviewed the
licensee's secondary water chemistry control program.19 The NRC
inspection team found that the program requirements had fully conformed
to the EPRI guidelines throughout Palo Verde's operating history with
respect to chemical parameters, analytical frequency, limits for
critical parameters, and required actions when critical parameters were
exceeded. In summary, the Petitioners' assertions regarding lead
content have not been substantiated and do not agree with available
data. The licensee has verified 20 that lead content in both Units
1 and 2 SGs is 100 ppm or less, not 4,000-6,000 ppm as asserted by the
Petitioners. Additionally, NRC Inspection Reports 94-15 and 94-27 on
Units 50-528/50-529/50-530 have not
[[Page 34459]]
revealed any information about elevated lead content.
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\19\ The NRC inspection team compared Electric Power Research
Institue (EPRI) NP-6239, ``PWR Secondary Water Chemistry
Guidelines,'' Revisions 1 through 2, and EPRI TR-101230, ``Interim
PWR Secondary Water Chemistry Recommendations for IGA/IGSCC
Control,'' with the licensee's secondary water chemistry control
program for PVNGS.
\20\ PVNGS performed its own inspections and also utilized
contractors, ABB-Combustion Engineering (ABB-CE) and Babcock and
Wilcox Nuclear Technologies (BWNT), to perform metallurgical
examinations. The inspections revealed minor quantities of lead in
surface deposits and films. See NRC Inspection Report 50-528/50-529/
50-530/94-15, dated June 23, 1994.
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Steam Generator Tube Degradation and Operation at a Reduced Power Level
The Petitioners also assert that the operation of Palo Verde units
at above 86-percent power is unacceptable due to severe degradation of
SG tubes (Petition supplement, Basis 14). In December 1993, the
licensee volunteered to reduce power in all three units to
approximately 86 percent as an interim measure to curtail steam
generator degradation. The primary purpose of this administrative power
limit was to operate with a lower reactor coolant system hot-leg
temperature in order to reduce tube degradation. This specific power
level had been selected because it provided for a Thot that
approximated the value that would be implemented if the licensee's
proposed TS changes for operating at 100% power with a reduced
Thot were approved by the NRC. Additionally, the licensee's
thermal-hydraulic analysis indicated that, at this reduced power level,
the potential for freespan tube degradation from corrosion is reduced.
The licensee took this action voluntarily to minimize further
degradation of the SGs until corrective, mitigative, and preventive
actions could be implemented to reduce steam generator tube
degradation.
On June 7, 1994, the NRC issued a TS change for Units 1 and 3 that
permitted the licensee to operate at full power with a lower Thot
temperature.21 The Unit 2 TS change was reviewed separately
because the licensee was continuing to perform analyses arising from
the SG tube plugging in Unit 2. The staff issued this TS change on
August 12, 1994.22 These TS changes permitted operation at a power
level of 100 percent as did the staff's post-March 1993 SGTR SEs dated
August 19, 1993, and June 22, 1994, regarding the length of operating
cycles of the Palo Verde units. Furthermore, as stated above, the staff
did not impose any power restrictions or limits on the licensee.
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\21\ Noticed in the Federal Register on June 22, 1994 (59 Fed.
Reg. 32240).
\22\ Noticed in the Federal Register on August 31, 1994 (59 Fed.
Reg. 45038).
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In summary, the Petitioners' concerns regarding operation of the
Palo Verde units above 86-percent power (including bases relating to
the March 1993 SGTR event, identification of axial and circumferential
steam generator tube indications, alleged elevated lead contents in
steam generator sludge) have been satisfactorily addressed, and do not
warrant any further action by the NRC staff.
C. Need To Reanalyze the Design-Basis SGTR Event
Request 5 (of the Petition supplement) is that the NRC require the
licensee to analyze a design-basis SGTR event to show that the offsite
radiological consequences do not exceed a small fraction of the limits
of 10 CFR Part 100. The staff requires an analysis such as this to be
completed for all pressurized-water reactors (PWRs) and documented in a
final safety analysis report (FSAR) before plant operation. The
licensee complied with this requirement.23
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\23\ Updated Final Safety Analysis Report (UFSAR) Section
15.6.3.1.3.2 describes the radiological consequences of an SGTR, and
the results are shown in UFSAR Table 15.6.3-5. The staff initially
reviewed PVNGS's UFSAR in November 1981.
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The Petitioners assert in the basis (Petition supplement, Bases 8,
9, 10, 11 and 13) that the licensee cannot ensure the dose limits are
satisfied for applicable postulated SGTR events; the offsite dose
limits would be exceeded during an SGTR event and adequate protection
to the public would not be maintained; the licensee cannot demonstrate
that the plant can be safely shut down and depressurized to stop SG
tube leakage before reactor water storage tank inventory is lost; the
NRC and the licensee must carefully consider SGTR; and ``the licensee
has failed to comply with NRC requirements under NUREG-0800 insofar as
the licensee is required to analyze the consequences of a design basis
SGTR event to show that the offsite conditions and single failure do
not exceed a small fraction of limits of 10 CFR Part 100.''
The AIT report documents findings regarding the Unit 2 SGTR event
of March 1993. The report stated that the plant was safely brought to
cold shutdown and no radioactivity was released off site. Additionally,
the staff's SE, dated August 19, 1993, assessed a single SGTR event and
single and multiple tube ruptures induced by a major secondary-side
rapid depressurization and concluded that the radiological consequences
were within applicable limits.24 Finally, in a memorandum dated
January 26, 1996, the staff performed a confirmatory review of the
licensee's updated SGTR event analysis, submitted with Revision 6 to
the FSAR (March 10, 1994), and concluded that the results are
acceptable. The Petitioners also assert in the basis (Petition
supplement, Basis 12) that the licensee cannot demonstrate compliance
with certain criteria of Appendix A to 10 CFR Part 50,25 which
establishes the fundamental requirements for steam generator tube
integrity. However, the Petitioners have failed to provide any details
or support for this assertion.
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\24\ In 10 CFR Part 100, acceptance criteria are specified for
the dose analyzed during initial plant licensing at the exclusion
area boundary (EAB) and low population zone (LPZ) for design-basis
accidents. The dose in 2 hours at the EAB is not to exceed 25 rem to
the whole body or 300 rem to the thyroid. The dose in 30 days at the
boundary of the LPZ is not to exceed 25 rem to the whole body or 300
rem to the thyroid. The staff reviewed the licensee's Unit 2 steam
generator tube rupture analysis, submitted by letter dated July 18,
1993, and concluded that the methods used by the licensee were
acceptable. See the NRC staff's safety evaluation dated August 19,
1993.
The Petitioners assert that the licensee has failed to comply
with NUREG-0800 requirements regarding consequences of a design
basis SGTR event. However, NUREG-0800 does not set forth
requirements; rather it sets forth acceptable approaches to
satisfying NRC requirements.
\25\ The Petitioners reference portions of General Design
Criteria (GDC) 14, 15, 30, and 31 of Appendix A to 10 CFR Part 50.
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In summary, on the basis of the NRC staff's review of the
licensee's design-basis SGTR event and more recent confirmatory review,
the staff has concluded that the Petitioners have not presented a basis
for further NRC action.
D. Adequacy of Training and Procedures for an SGTR Event
Regarding Request 6 of the Petition supplement, that the NRC
require the licensee to demonstrate that its emergency operating
procedures (EOPs) for SGTR events are adequate and the plant operators
are sufficiently trained in EOPs, the staff has already taken
sufficient action. The Petitioners allege (Petition supplement, Bases
5, 6, and 7, respectively) that the licensee failed to properly
implement operational procedures regarding the SGTR event of March 14,
1993, citing eight instances in Basis 5 26; that the licensee's
failure to comply with approved procedures in this event is indicative
of a problem plant that warrants further NRC attention (Basis 6); and
that the NRC is aware of additional licensee weaknesses regarding the
SGTR event, citing four instances in Basis 7.27 These bases
[[Page 34460]]
largely concern areas the staff reviewed after the SGTR event on March
14, 1993. Specifically, the Petitioners repeated several of the
procedural and operator weaknesses that were described and evaluated in
the staff's AIT report (Inspection Report 50-529/93-14, dated April 16,
1993).28 Specifically, the AIT report stated that the use of a
diagnostic logic tree caused the operators to misdiagnose the SGTR
event twice and subsequently enter a Functional Recovery Procedure,
contributing substantially to the delay in isolating the faulted steam
generator. The staff concluded in its safety evaluation of August 19,
1993, that the licensee's modifications to the EOPs and the subsequent
operator training provide sufficient enhancement for both diagnosis and
mitigation of various SGTR scenarios.
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\26\ The Petitioners assert (Petition supplement, Basis 5) that
the licensee (a) failed to classify the event in accordance with the
EOPs, (b) failed to actuate the Emergency Operations Facility for
the 1-hour time, (c) failed to activate the Emergency Response Data
System, (d) violated 10 CFR Sec. 50.72 requirements, activation of
the Emergency Response Data System, (e) failed to take prompt
corrective actions to repair the condenser vacuum pump exhaust
radiation monitor, (f) failed to obtain required approvals for alarm
setpoint change on waste gas area combined ventilation exhaust
monitor, (g) failed to fully implement an alarm response procedure
and, (h) failed to check the owner-controlled area.
\27\ The Petitioners assert (Petition supplement, Basis 7) that
the licensee's (a) alert and alarm setpoints for condenser vacuum
pump exhaust and main steam line radiation monitor limits appear to
be based on offsite dose limits rather on an SGTR event, (b)
simulator alarms occur within 2-3 minutes of an SGTR event, contrary
to control room indications, (c) plant staff failed to fully respond
to assembly notification, (d) plant staff failed to perform a formal
evaluation of the safety significance of an abnormal crack growth in
the Unit 2 SG.
\28\ The licensee addressed the issues raised in the AIT report
by implementing the necessary procedural changes and providing
training. For example, with regard to the AIT finding (summarized by
the Petitioners) regarding differences between alarm response on the
simulator and in the control room, the staff's safety evaluation of
August 19, 1993, stated that ``the simulator has been modified to
more realistically model the plant, particularly the response of the
radiation monitoring system to an SGTR.''
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Additionally, the licensee recently revised its EOPs to make them
consistent with Combustion Engineering Owners Group (CEOG) guidance
(CEN 0152, Rev. 3 29). NRC Inspection Report 50-528/50-529/50-530/
95-12, dated July 27, 1995, documents the staff's observations on the
``high intensity team'' training conducted for each crew in preparation
for implementing the EOPs. In the inspection report, the staff stated
that the EOPs enhanced crew performance and allowed for greater
flexibility in responding to events. As an example, during the
simulator-based SGTR scenario, the crew was able to isolate the faulted
SG within 14 minutes of the start of the event. In contrast, during the
March 1993 Unit 2 SGTR event, operators took about 3 hours to isolate
the faulted SG, partly because of restrictions in the EOPs in use at
the time. The staff will further evaluate the effectiveness of EOPs
during future licensed operator examinations.
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\29\ A letter from the NRC to Combustion Engineering dated
August 2, 1988, stated that, ``pending NRC final review and
approval, CE facilities may base their plant-specific emergency
operating procedures on Revision 3 of CEN-152. Should future NRC
review reveal modifications to Revision 3 to be necessary, CE
facilities would be expected to update their procedures to reflect
the identified changes. Schedules for such changes should be based
on perceived safety significance of the changes.'' The objective of
the CEN-152 report is to describe the CEOG emergency procedure
guidelines system. The report contains the methodology used to
develop and validate the licensee's emergency procedure guidelines
and information on the implementation of guidelines.
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On the basis of its review of the Petitioners' request that the
licensee demonstrate that its EOPs for SGTR events are adequate and
that plant operators are sufficiently trained in EOPs, the staff has
concluded that the Petitioners have not presented a basis for further
NRC action.
III. Conclusion
The institution of proceedings in response to a request pursuant to
Section 2.206 is appropriate only when substantial health or 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). This standard has been applied to the
concerns raised by the Petitioners to determine whether the actions
requested by the Petitioners are warranted. With regard to the specific
requests made by the Petitioners discussed herein, the NRC staff finds
no basis for taking additional actions beyond those described above.
Accordingly, the Petitioners' requests for additional actions pursuant
to Section 2.206, specifically Requests 1, 2, 3, 5, and 6 submitted in
the Petitioners' supplement dated July 8, 1994, are denied.
Accordingly, no action pursuant to Section 2.206 is being taken in this
matter.
A copy of this Decision will be filed with the Secretary of the
Commission for Commission review in accordance with 10 CFR
Sec. 2.206(c) of the Commission's regulations. As provided by this
regulation, the 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 within that time.
Dated at Rockville, Maryland, this 25th day of June 1996.
For the Nuclear Regulatory Commission.
William T. Russell,
Director, Office of Nuclear Reactor Regulation.
[FR Doc. 96-16878 Filed 7-1-96; 8:45 am]
BILLING CODE 7590-01-P
