[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