ML20080R582
| ML20080R582 | |
| Person / Time | |
|---|---|
| Site: | Crane  |
| Issue date: | 02/24/1984 |
| From: | Churchill B METROPOLITAN EDISON CO., SHAW, PITTMAN, POTTS & TROWBRIDGE |
| To: | Atomic Safety and Licensing Board Panel |
| Shared Package | |
| ML20080R589 | List: |
| References | |
| 83-491-04-OLA, 83-491-4-OLA, ISSUANCES-OLA, NUDOCS 8402280343 | |
| Download: ML20080R582 (242) | |
Text
ED P4 February 24, 1984D27 Y,$
UNITED STATES OF AMERICA I-NUCLEAR REGULATORY COMMISSION Before the Atomic Safety and Licensing Board In the Matter.of
)
.)
METROPOLITAN EDISON COMPANY, ET AL. )
Docket No. 50-289-OLA
)
ASLBP 83-491-04-OLA (Thrca Mile Island Nuclear
)
Station, Unit No. 1)
)
LICENSEE'S MOTION FOR
SUMMARY
DISPOSITION OF EACH OF TMIA'S AND JOINT INTERVENORS' CONTENTIONS SHAW, PITTMAN, POTTS & TROWBRIDGE George F.
Trowbridge, P.C.
Bruce W.
Churchill, P.C.
Diane E.
Burkley Wilbert Washington, II Counsel for Licensee 1800 M Street, N.W.
Washington, D.C.
20036 (202) 822-1000 8402280343 840224 PDR ADOCK 05000 0
/
L February 24, 1984 UNITED STATES OF AMERICA NUCLEAR REGULATORY COMMISSION Before the Atomic Safety-and Licensing Board
. In'the'Matterfof'
)
)
METROPOLITAN EDISON COMPANY, ET AL. )
Docket No. 50-289-OLA
)
ASLBP 83-491-04-OLA
- (Three Mile' Island Nuclear-
)
Station, Unit No. 1)
)
LLICENSEE'S MOTION FOR
SUMMARY
DISPOSITION OF EACH OF TMIA'S AND JOINT'INTERVENORS' CONTENTIONS SHAW, PITTMAN, POTTS & TROWBRIDGE George F.
Trowbridge, P.C.
Bruce W. Churchill, P.C.
Diane E.
Burkley
{
Wilbert Washington, II
{
Counsel for Licensee
\\/"
1800 M Street, N.W.
Washington, D.C.
20036 (202) 822-1000
TABLE OF CONTENTS Page I.
INTRODUCTION...........................................
2 A.
Overview of the-Motion............................
2 B.
Scope of Intervenors' Contentions..................
3 II.
STANDARDS GOVERNING
SUMMARY
DISPOSITION.................
5 III. ARGUMENT ON CONTENTIONS.................................
7 A.
TMIA's Contention 1.a..............................
7 B.
TMIA's Contention 1.b.............................
11 C.
TMIA's Contention 1.c.............................
14 D.
TMIA's Contention 1.d.............................
16 1.
Alleged Inherent Inconsistencies.............
17 2.
Axisymmetric Stress Analysis................. 27 3.
Toughness versus Hardness....................
29 4.
Crack Size...................................
30 E.
TMIA's Contention 2.a and Joint Intervenors' Contention 1(5)...................................
33 F.
TMIA's Contention 2.b.1....
3.....................
38 s
G.
TMI A's Contention 2.b'.2., arid Joint Intervenors' Contention 1(2)-....
...'.......................'... 41 s,
.H.
TMIA's Contention ~2.c..............................
46 s
1.
Inherent In6cnsistencies.....................
46
.,w' 9
'b g\\
s s.
b r
-g 6
V v
'g
\\
%s wA 4, t y _ j g
,wg 7
Page 2.
Other Asserted Bases Relating To Credibility..................................
53 I.
Joint Intervenors' Contention 1(3)................
57 IV.
LICENSEE'S STATEMENT OF MATERIAL FACTS AS TO WHICH THERE IS NO GENUINE ISSUE TO'BE HEARD..................
59 A.
TMIA's Contention 1.a.............................
59 1.
Steam Generator Description.................. 60 2.
Kinetic Expansion Repair.....................
61 3.
Licensing Basis..............................
63 4.
Qualificstion Program........................
64 (a)
Axial Loads.............................
64 (b)
Residual Stresses.......................
65 (c)
Tube Preload............................
68 (d)
Expansion Joint Leakage.................
71 (e)
Other Considerations....................
72 5.
In-Process Repair Testing....................
73 6.
Post-Repair and Plant Performance Testing and Analysis............. 74 (a)
Operational Leak Test...................
75
( b )_
First Thermal Soak......................
76 (c)
Normal Cooldown Transient...............
76 (d)
Second Thermal Soak.....................
76 (e)
Accelerated Cooldown....................
76 (f)
Third Thermal Soak......................
76 (g)
Third Coo 1down..........................
77 7.
License Conditions...........................
77
-ii-
rn Page 8.
Tube Ruptures................................
78 B.
- TMIA's Contention 1.b.............................
82 C.
lD4I A ' s Contention 1. c............................. 83 D.
TMIA's Contention 1.d.............................
87 E.
TMIA's Contention 2.a and 2.c and Joint Intervenors' Contention 1(5)................
90 1.
Characterization of the Failure Mechanism.... 91 2.
Detailed Invests.gation of the Conditions Which could Have Caused the IGSAC............
92 (a)- Aggressive Env.ironment.................. 92 c
(b). Stress.................................. 94 (c). Material................................
95 3.
Literature Review............................
95 4.
Failure Scenario............................. 96 5.
Confirmatory Testing.........................
99 6.
Role of Other Potential Causative Agents......................................
100 (a)
Carbon.................................
100 l
l~
(b)
Chloride...............................
102 I
(c)
Other elements.........................
103 i
(d)
Possible Synergistic Reactions.........
103 (e)
Contaminants Introduced During Repair.. 105 i
'e 7.
Other Issues Discussed in Consultant's Reports........................
106 F.
TMIA's Contention 2.b.1..........................
108 1.
Analysis and Testing Preceding the Cleaning. 109
-lii-
Page 2.
Effects of the Cleaning on the Sulfur on the Tube Surfaces...............................
110 3.
Results of the Actual Cleaning Process...... 112 4.
Cautionary Statements by Consultants........ 112 G.
TMIA's Contention 2.b.2 and Joint Intervenors' Contention 1(2).....................
113 1.
Sulfur Chemistry............................
114 2.
Control of Sulfur Levels in the Reactor Coolant System..............................
115 3.
Control of System Conditions................
117 4.
Confirmatory Testing........................
118 5.
Other Issues Related to Initiation..........
120 H.
Joint Intervenors' Contention 1(3)...............
120 1.
Morphology of IGA...........................
122 2.
Evaluation of the IGA.......................
122 3.
Prevention of Propagation of IGA............
124 V.
CONCLUSION............................................
125 AFFIDAVITS David G.
Slear i
Branch D.
Elam
. Mary Jane Graham Stephen D.
Leshnoff F.
Scott Giacobbe l
l
-iv-l h
L j_
UNITED STATES OF AMERICA NUCLEAR REGULATORY COMMISSION e
Before the Atomic Safety and Licensing Board In the Matter of
.)
)
METROPOLITAN EDISON COMPANY, ET AL.)
Docket No. 50-289-OLA
')
ASLBP 83-491-04-OLA (Three Mile Island Nuclear
)
(Steam Generator Repair)
Station, Unit No. 1)
)
LICENSEE'S MOTION FOR
SUMMARY
DISPOSITION OF EACH OF TMIA'S AND JOINT INTERVENORS' CONTENTIONS
' Licensee hereby moves the Atomic Safety and Licensing Board, pursuant to 10 C.F.R.
$ 2.749, for summary disposition ~
of TMIA's Contentions 1.a, 1.b, 1.c, 1.d, 2.a, 2.b.1, 2.b.2, 1
cnd 2.c, and Joint Intervenors' Contentions 1(2), 1(3), and i'
1(5).
Dismissal of the contentions i:s warranted as a matter of law, because there are no genuine issues of fact requiring ad-judication with respect to any of these contentions.
I.
INTRODUCTION A.
OVERVIEW OF THE MOTION This motion is based upon Licensee's " Statement of Materi-cl Facts As To Which There Is No Genuine Issue To Be Heard" (Part IV hereof), the attached affidavits of F.
Scott Giacobbe, Mary Jane Graham, David G.
Slear, Stephen D.
Leshnoff and Branch D.
Elam, relevant documents in the possession of the In-tervenors,1/ and all the pleadings and other papers previously filed in this proceeding.
Before proceeding to the statement of facts, we briefly discuss the scope and bases for the con-
- tentions, (Section I.B) and the summary disposition (Section II).
We then present an overview as to why there is no genuine issue of material fact to-be heard with respect to any of the contentions (Section III).
As our discussion will make evident, there is a substan-
^ tial overlap among the various contentions.
Where the scope of ceparate contentions are coextensive (or virtually so), Licens-ce has addressed them in tandem.
Licensee has prepared a sepa-rate statement of material facts for each contention or group of coextensive contentions.
1/
Licensee cites herein the NRC~ Staff's "TMI-1 Steam Genera-tor Repair Safety Evaluation Report", NUREG-1019 (SER), and l
Supplement-1 thereto (SER Supp.), Licensee's " Assessment of TMI-1 Plant Safety for Return to Service After Steam Generator Repair", Topical' Report 008, Rev. 3 (TR-008).
! t.
l
B.
Scope of Intervenors' Contentions Because of the vague and unparticularized nature of many of the contentions, Licensee has propounded three sets of in-Lterrogatories and document production requests to TMIA and two
'to. Joint Intervenors in an effort to learn the scope and speci-fic nature of the allegations encompassed in the contentions,
.ns well'as the factual bases'for those allegations.
This has given the intervenors ample opportunity to define and particularize their allegations.
' Licensee has attempted to utilize the intervenors' re-sponses to its and the Staff's interrogatories as much as pos-sible to determine the meaning and scope of the contentions, cnd hence to define reasonable bounds for this motion.
In some instances this has worked well.
In TMIA's Conten-tion 1.d, for example, there are allegations of " inherent l
inconsistencies" between the evaluation of the Staff and that of the independent Third Party Review group, but none are iden-I tified'in the contention itself.
However, TMIA identified dur-l ing discovery five alleged inconsistencies thus defining a man-Egeable. scope to that aspect-of the contention and, as a I
result, to-this motion for summary disposition.
l
-In other instances it has not been as successful.
In TMIA's Contention 1.a, the allegation is made that " post-repair cnd~ plant performance testing and' analysis" are inadequate to provide assurance against the occurrence of tube ruptures. !
k Both Licensee and the NRC Staff have attempted to determine what testing andl analysis are being referred to, and why they cre alleged to be inadequate.
TMIA's response has been that it is " unable" even to define its allegation, far less explain it.
See TMIA lat_ Resp. to Interrogs. 1.a-1 through 1.a-3; TMIA 2d Resp. to-Interrogs. 1 through 9; and TMIA 4th Resp. to Interrogs. II-1.a-1 and II-1.a-2 through -9.
Thus, in seeking
'cummary disposition of Contention 1.a, Licensee has no clues as
.to what TMIA's concerns are,'and is therefore at a severe dis-cdvantage in attempting to fashion a motion for summary dispo-
.sition.
For this particular contention, Licensee had to ad-dress summary disposition in a far broader manner than would have.been necessary if TMIA would have been able to articulate i
~its allegations.
In any event, Licensee has attempted to define the nature and scope'of the contentions as consistently as possible with the'intervenors' answers to the discovery requests.2f 2/'.The references herein and in the attached affidavits are i
to specific interrogatory responses, and will be cited as fol-L lows:
TMIA Response to Licensee's First Set of Interroga-tories, dated January 4, 1984 (TMIA ist Resp. to Interrog.
[ number]); Lee, et al. Responses to Licensee's First Set of Interrogatories, _ dated January 16, 1984 (J.I. 1st Resp. to Interrog. [ number]); TMIA Response to First Set of NRC Inter-rogatories, dated January 16,_1984 (TMIA 2d Resp. to Interrog.
-[ number]); Lee, et al. Responses to Staff Interrogatories,
. dated January 16, 1984 (J.I. 2d Resp. to Interrog. [ number]);
TMIA' Response to Licensee Motion to Dismiss TMIA Contention l
1.a, 1.b,J1.c, and 2.b.1-and Supplemental Interrogatory Re-L
.sponses'to Licensee, dated ~ January 20, 1984 (TMIA 3d Resp. to Interrog. [ number]); TMIA's Response to Licensee's Second Set i
- of Interrogatories and Request for Production of Documents, l
l (Continued Next Page)
L l L-
Accordinglyi since diccovery has been closed since February 17,
.1984 (extended'from January 31, 1984 at the request of TMIA),
the intervenors are clearly estopped from widening or modifying i
othe scope of the contentions on the basis of information which should have been, but was not, provided in response to discov-
-ery requests,-or'from otherwise utilizing such information in opposition to this motion for summary disposition.
II.
STANDARDS FOR
SUMMARY
DISPOSITION The standards governing summary disposition motions in NRC p'roceedings are now well established and are quite similar to the standards applied under Rule 56 of the Federal Rules of Civil Procedure.
Alabama Power.Co. (Joseph M.
Farley Nuclear Plant, Units 1 and 2), ALAB-182, 7 A.E.C. 210, 217 (1974); see Tennessee Valley Authority (Hartsville Nuclear Plant, Units lA, 2A, 1B and 2B), ALAB-554, 10 N.R.C.
15, 20 n.17 (1979).
Simply stated,-a party-is entitled to summary disposition in its favor if its motion and statement of material facts show that there is no genuine issue to be heard.
Equally significant, where, as here,'such a properly supported motion for summary disposi-tion is made, the party opposing the motion may not simply rely l
(Continued)
-dated February 18, 1984 (TMIA 4th Resp. to Interrog.-[ number]);
cnd TMIA's Responses to Licensee's Third Set of Interrogatories cnd Request for Production of Documents, dated February 18, L
1984 (TMIA Sth Resp. to Interrog. (number]).
[ t L
1
.upon allegations.or denials alone.
Rather, it must come for-ward with ubstantial' facts in the form of admissible evidence
-establishing-that a genuine issue ofLfact remains to be heard.
l
~
10 C.F.R.-5'2.749(b); Virginia Electric & Power Co. North Anna Nuclear Power-Station,~ Units 1 and 2), ALAB-584, 11.N.R.C. 451, 453 (1980).
A party cannot avoid summary disposition on the basis of guesses lor' suspicions or on the hope that at the hearing the Licensee's evidence-may be. discredited orithat "something may turn up.".
Gulf States Utilities Co. (River Bend Station, Units 1 and 2), LBP-75-10,'l N.R.C. 246, 248 (1975).
Nor can the r-opposing party avoid summary disposition.merely by "the showing of a material issue of fact' or an ' issue of fact.'
They
[must show).a genuine issue of material fact."
Cleveland Electric Illuminating Co. (Perry Nuclear Power Plant, Units 1 &
2), LBP-83-46, 18 N.R.C. 218, 223 (1983) (emphasis in origi-nal).
To be genuine, "the factual record, considered in its-entirety, must be enough in doubt so that there is a reason to
'hcid'a hearing-to resolve the issue."
Id.
If the party opposing the-motion fails to make the proper-
' showing, summary disposition must be granted.
10 C.F.R. 5 2.749(b).
As the Appeal Board has emphasized, " summary dis-Lposition procedures provide in reality as well as in theory, an efficacious means,of' avoiding unnecessary and possibly time-consuming hearings on demonstrably insubstantial
. L L
-issues.
Houston Lighting & Power Co. (Allens Creek Nu-clear Generating Station, Unit 1), ALAB-590, 11 N.R.C. 542, 550 (1980).
Similarly, the Commission's Statement of Policy on Conduct of Licensing Proceedings, CLI-81-8, instructs Licensing Boards to " encourage the parties to invoke the summary disposi-tion procedure on. issues where there is no genuine issue of ma-terial fact so that evidentiary hearing time is not unnecessarily devoted to such issues."
13 N.R.C.
452, 457 (1981).
Applying the foregoing standards to this case, and for the reasons set forth below, summary disposition should be granted in Licensee's favor as to all aspects of TMIA's Contentions 1.a, 1.b, 1.c, 1.d, 2.a, 2.b.1, 2.b.2, and 2.c, and Joint In-tervenors' Contentions 1(2), 1(3), and 1(5).
III.
ARGUMENT ON CONTENTIONS A.
-TMIA'S CONTENTION 1.a TMIA's Contention 1.a reads as follows:
1.
Neither Licensee nor the NRC Staff has demon-strated that the kinetic expansion steam generator tube repair. technique, combined with selective tube plugging, provides reasonable assurance that the operation of TMI-1 with the as-repaired steam generator can be conducted without endangering the health and safety of the public, for the following reasons:
l a.
Post repair and plant performance testing and analysis including the techniques used, empirical information collected, and data evaluation, and cro-l posed license conditions are inadequate to provide sufficient assurance that tube ruptures, including.
but not limited to those which could result upon restart, a turbine trip at maximum power, thermal shock from inadvertent actuation of emergency t
..r-
e feedwater at high power or following rapid cooldown after a.LOCA, will be' detected in time and prevented to avoid endangering the health and safety of the public through release of radiation into the environ-ment:beyond permissible limits.
In essence, TMIA is here. alleging that what it refers to as " post repair and plant performance testing and analysis" is comehow' inadequate to prevent." tube ruptures" during certain operating conditions and transients.
Four such conditions and
. transients are specified in the contention.
Licensee has attempted during discovery,.without success, to have TMIA identify the testing and analysis which it alleges
- to be inadequate and to explain why, as a result, there is al-leged to be insufficient assurance that. tube ruptures will not.
occur.
TMIA's only response has been that, for one reason or cnother,. it was unable to provide the requested information.
See-discussion in Section II.B, above.
Therefore, not knowing what is being specifically alleged, Licensee has attached an extensive and' comprehensive affidavit-executed by David G.
Slear,.. Licensee's Manager of Engineering Projects, to explain how the1 kinetic expansion repair was qualified'to the original L
licensing basis for steam generator tubes, and to explain why this provides the requisite reasonable assurance that tube rup-
'ture will not occur during the operating conditions-and tran-l sients specified in Contention 1.a.
The statement of facts on this issue'is correspondingly detailed.
i h
- L m..
m
~ - ~. - -.
4-..
a.
-The kinetic expansion repair is confined to the. top of the
. steam generators within the upper'tubesheet, a 24-inch thick sheet ~of'Inconel-clad carbon steel within which holes are drilled to hold the tubes.
The top 17 to 22 inches of the tubes were: expanded explosively against the sides of the
-tubesheet holes'to create a new tube-to-tubesheet bond, or
" joint," which becomes part of the primary pressure boundary.
Slear Affidavit, 11'5,'8,-9.
+
Each joint has a six-inch length of expansion, ending in a
~1/8 to 1/4-inch " transition zone" between the expanded and unexpanded portion of the' tube, which is free of eddy current indications (based on eddy current' testing prior to the re-pair).
Tubes which did not meet these specifications were taken out of service by plugging.
.Slear Affidavit, 11 9, 10, 11.
F
.Also, any repaired tubes with indications of imperfections
-cqualito or: greater than 40% of the tube wall thickness were taken out of service by plugging in accordance with the licens-ing basis requirements.
Thus, assuming the kinetic expansion
~ joint meets to. licensing basis for steam generator tubes, the
. repaired-tube will be returned to its original licensing basis.
.Slear Affidavit, 1 11.
l-
'An extensive testing qualification program has demon-
- strated that the new' tube-to-tubesheet joint created by the ki-t
.netic expansion repair process has restored the tubes to the
_9_
l, L
criginal licensing basis.
This included detailed consideration of the effects of the expansion repair process on the tube, as well as qualification of the joint itself.
Slear Affidavit, 11 12-34.
The repaired tubes have been qualified by testing and cnalysis to a capability in excess of that required to with-ctand the. maximum loads to be imposed by a design basis acci-dent (in this case, the postulated main steamline break).
These loads are well in excess of the loads to be seen by the tubes as a result of the conditions and transients identified by TMIA in the contention.
" lear Affidavit, 11 13, 16, 34, 52-60.
The in-process repair testing, the post-repair and plant performance testing and analysis, and the NRC's special
~
license conditions provide added assurance of the adequacy of the repaired tubes.
Slear Affidavit, 11 35-51, 60.
Accordingly, the detailed statement of facts and the Slear Affidavit, demonstrates conclusively that the repaired tubes have been returned to the original design basis, and that there ois.therefore reasonable assuranen that tube rupture will not occur as a result of the transients alleged by the contention, or as a result of any design basis event.
There is no genuine issue of material-fact to be heard with respect to TMIA Conten-
. tion 1.a.
l l
-lo-k 1..
4 B.
TMIA'S CONTENTION 1.b HTMIA's Contention 1.b reads as follows:
1.
Neither Licensee nor the NRC Staff has demon-strated that the kinetic expansion steam generator tube repair technique, combined with selective tube plugging, provides reasonable assurance that the operation of TMI-1 with the as-repaired steam generator can be conducted without endangering the health and safety of the public, for the following reasons:
b.
Because of the enormous number of tubes in both steam generators which have undergone this re-pair process, (1) the possibility of a simultaneous rupture in each steam generator,.which would force the operator to accomplish cooldown and de-pressurization using at least one faulted steam gen-erator, resulting in release of radiation into the environment beyond permissible levels, "isn't an in-credible event," (see, September 19, 1982 memorandum from Paul Shewmon, then Chairman of the ACRS), (2) and could lead to a sequence of events not encom-passed by emergency-procedures, (3) and in the course of-a LOCA, such a scenario could create essentially uncollable conditions.
~
This. contention is based on the allegation that the oc-curence of a simultaneous tube rupture in each steam generator is sufficiently likely, because of the repair process, that the i
consequences of that hypothetical event should be evaluated as in prerequisite to allowing operation of the plant with the re-L paired steam generator-tubes.
'The NRC's design basis accident for steam generator tube rupture-is a double-ended break of a single tube.
See SECY-82-72, Enclosure 2 at 2.
Neither this plant nor any other L
L plant licensed by the NRC is required to analyze for the conse-E
.quences.of the hypothetical simultaneous tube rupture in each Cteam generator.
Thus, TMIA is challenging the NRC's generic licensing basis for. steam generators.
See NRC Staff's Answer to TMIA's First Set of Interrogatories and Request for Produc-tion of Documents, Interrog.
8, January 30, 1984.
The reason given by TMIA.for challenging the licensing basis is that an "emormous number of tubes" have " undergone the repair' process."
However, as discussed above, the Slear Affi-davit has shown that the repaired tubes have been fully quali-fied to the original licensing basis, and that there is there-
-fore no increased likelihood of simultaneous tube rupture in cach steam generator as a result of the tubes having undergone
~
the repair process.
Slear Affidavit, 11 52, 61.
Because there J
is no genuine issue of material fact to be heard with respect to these conclusions'and the facts upon which they are based, cs set.forth in Section III.B below, Contention 1.b must be summarily dismissed in accordance with the provisions of 10 C.F.R. 5.2.749.
Both Licensee and the Staff have attempted to ascertain from TMIA.the alleged nexus between-the repair process and the alleged need for.the extraordinary requirement of going beyond L
the NRC's established design basis.
The closest either party has come to getting a-response to the question is TMIA's I
February 18, 1984 answer to Licensee's Interrogatories II-1.b-4 through II-1.b-9.
There TMIA simply concluded that "there is a greater probability of simultaneous tube rupture at TMI-1" p.
because the independent Third Party Review Grcup (TPR) had Ctated at page 15 of its February 18, 1983 report (SER, Attach-ment 6) that "[t]he explosive expansion of the tubes could af-fect the stress levels if the process would change the strength or some dimension of the tubes."
The TPR did not, however, say in that statement that there actually was an adverse effect on the tubes; to the contrary, in the very next sentence, which TMIA did not quote, the TPR concluded that the repair process would not be expected to significantly affect the stress levels in the tubes.
And even if stress levels were to be affected, the TPR did not even hint that it would in any way affect the cbility of the tubes to withstand rupture.
In any event, the Slear Affidavit points out that the re-sidual stress levels in the transition zone, due to the change in the diameter dimension, had been extensively evaluated, and that the post-repair transition zone is no more susceptible to damage, and probably less susceptible, than the original rolled transition zone which is being replaced by the kinetic expan-cion process.
Slear Affidavit, 11 17-24.
Thus, there is no effect of the repair process on strength or dimension that would adversely affect the ability of the tubes to withstand rupture.
i 4
C.
TMIA'S' CONTENTION l.c-TMIA's Contention 1.c. reads as follows:
1.
Neither Licensee nor the NRC Staff has demon-strated.that the kinetic expansion steam generator. tube repair technique, combined ~with selective tube plugging, provides reasonable assurance that the operation of TMI-l with.the as-repaired steam generator can be conducted without endangering the health and safety of 'he public, c
forithe following reasons:
c.
The kinetic expansion repair weakened the tubes.
As a_ result, the plugs will not be able to hold and.give a good seal, and thus the plant's abil-ity to. respond to transients and accidents will be adversely affected.
As. set forth.in the attached affidavit of Branch D. Elam, Jr., %icensee's Manager of Mechanical Components in charge of the: engineering design for the plur;4.ng of kinetically expanded
- tubes, plug performance will be-unaffected by the kinetic ex-
.pansion repair process.
Elam Affidavit, 11 12, 15.
One type of plug, the Westinghouse roll plug, is ia'.ualled by a mechani-
-cal roll against the inside diameter of the tube within the upper-tubesheet.
.The roll plugs have been-fully qualified for t
uselin.the TMI-l steam generators, as well as in other op-i orating, pressurized. water nuclear reactors.
Testing and'analy-l l:
sis has shown that the only effect of the expansion on the por-tion of the tubes'to be engaged by the plugs is to press that
?~
L portion harder against the tube _ sheet than it had been in its
-originalirolled condition.
The slight change of inner diameter of f the tube.1:s well within the variation of diameters modeled i
E -
i-
,,.,_..,m..
in'the qualification program.
Thus, the kinetic expansion re-pair did not " weaken" the tubes or otherwise compromise the re-tention capability or leak tightness of the plugs.
Elam Affi-davit, 11 4-8, 11-12.
Moreover, the performance of the roll plugs would be unaf-fected by any circumferential cracks which might be preser.t in the portion of the tube to be engaged by the plugs.
Plug re-tention capability is proportional to the tube area engaged, irrespective of discontinuities, since the plug engages the tube both above and below the crack.
The slight decrease in surface area due to the presence of the crack is insignificant compared to the engagement area.
Elam Affidavit, 11 9-10.
The other types of plugs used in the kinetically expanded portion of the tubes are welded to either the original tube ceal weld or.the cladding on the surface of the tubesheet.
They are not bonded in any way to the tube, and thus tube weakening is not of concern for these types of plugs.
Testing has shown that the kinetic expansion repair process has not af-fected the ability of the welds or the cladding to provide the qualified seal.
Elam_ Affidavit, 11 13-15.
l The leak tightness of the plugs in leaking tubes has been demonstrated by leak testing of the steam generators following repair.
Elam Affidavit, 11 11, 14.
Accordingly, there is no genuine issue to be heard with respect to the statement of facts set out in Section III.C
! l l
L __
below, as-supported by the Elam Affidavit.
Contention 1.c must therefore be dismissed.
D.
TMIA'S CONTENTION 1.d TMIA's Contention 1.d reads as follows:
1.
Neither Licensee nor the NRC Staff have demon-strated that the kinetic expansion steam generator tube repair technique, combined with selective tube plugging, provides reasonable assurance that the operation of TMI-1 with the as-repaired steam generator can be conducted without endangering the health and safety of the public, for the following reasons:
d.
Neither the " Report of Third Party Review of Three Mile island, Unit 1, Steam Gener& tor Repair" nor the Staff's Safety Evaluation Report (NUREG-1019) are credible documents in their evaluation of the ki-netic expansion repair technique, including leak tightness and load carrying capabilities, and thus can not be used as a basis for conclusion that the repairs insure safe plant operation,
[1]
because of the reports' inherent inconsistencies,
[2]
because the basic assumptions and conclusions therein rest improp-erly on axial symetric stress analysis which would not be ap-plicable to all cracks,
[3]
because of the failure to analyze crack resistance on the basis of toughness as opposed to hardness which has no relation to crack resistance, and
[4]
because of the failure to differ-entiate in their analysis between the effects of thermal stress on small versus large cracks.
(em-phasis supplied.)
Contention 1.d has four subparts, with TMIA giving four 1
reasons for alleging that neither the report of the Third Party Review Group (TPR) nor the NRC Staff's Safety Evaluation Re-port, NUREG-1019 (SER) is a credible document in its ev luation of "the kinetic expansion repair technique, including leak tightness and load carrying capabilities."
Each of the four cspects of the contention is addressed separately below.
1.
Alleged Inherent Inconsistencies The first part of the contention alleges that the cvaluation of the " kinetic expansion repair technique, including leak tightness and load carrying capabilities," in the Staff's SER and the TPR report are undermined by " inherent inconsistancies" in the documents.
TMIA has stated in its re-cponse to a Staff interrogatory that the inconsistancies al-leged are between the two documents, rather than within either of the documents by itself.
TMIA 2d Resp. to Interrog. 18.
In response to a direct interrogatory by Licensee, TMIA identified five alleged inconsistencies (TMIA 1st Resp. to Interrog.
1.d-3.) and has not supplemented its answers as of February 17, the date for close of discovery.
Board Memorandum (Memori-clizing Conference Call), February 1, 1934.
Thus, TMIA has de-fined this portion of Contention 1.d to censist of the follow-ing five alleged inconsistencies between the SER and the TPR report:
(a)
The TPR analysis supports the proposi-tion that a " break before leak" under certain situations is possible and an acceptable scenario, (SER) Attachment 6 at p. 17-18.
This.is not recognized _.
1 in the SER, and is inconsistent with the SER conclusions.
[b]
The TPR analysis recognizes that the changed strength and dimensions of the expanded tubes is an important effect,
[SER] Attachment 6 at p.
15, but seems to dismiss its implications without revealing the basis for doing so.
There is no evidence in the SER that this effect is recognized and ana-lyzed.
[c]
The TPR analysis recommends that tubes with-less than 40% thruwall depth should be plugged.
[SER] Attachment 6 at p.
6.
The SER fails to discuss this recommendation,.and is inconsis-tent with the SER conclusions.
[d]
The TPR analysis finds it hard to sub-stantiate a firm conclusion that de-fects below a certain size range will not propagate due to flow-induced vi-brations.
[SER] Attachment 6 at p.
16-17.
This is not recognized in the SER,.and is inconsistent with the SER conclusions.
[e]
The TPR analysis recognizes the impor-tance of understanding the effects of multiple tube ruptures, [SER] Attach-ment 6 at p.'4-5.
This is not ana-lyzed as a separate issue in the TPR itself, or in the SFR.
The TPR group is an independent body of experts selected by' Licensee to provide an independent and objective evaluation l
l-of the kinetic repair process.
Graham Affidavit, 1 2.
Its cvaluation was independent of both Licensee's evaluation and l
that of the NRC Staff as' set out in the SER.
See Licensee's Answer to TMIA's First Set of Interrogatories and Request for l
' Production of Documents (January 13, 1984), at 64 (Response to
! I
~.
Interrogatory T-5).
Thus, because reasonable people do not al-ways' agree with one another, it would not be surprising if the NRC,and the TPR did not totally agree on each specific aspect of.the other's evaluation.
Since the evaluations were con-ducted independently,'had they not agreed on some details it
- wsuld be a difference of opinion, not an " inconsistency."
As it happended,Jhowever, the two bodies reached remarkable agree-msnt, with both approving of the repairs for returning the steam generators to service.
Examination of the SER and the reports issued by the TPR group shows that, in each of the five instances alleged by TMIA, there was no disagreement (or incon-sistency)-between the TPR. findings and the SER.
(a)
TMIA first alleges that the TPR recognizes the
' break before leak" scenario as both a possible and acceptable situation,-and that this is " inconsistent" with unidentified SER conclusions.
No explanation was provided as to why it was 1 alleged to be inconsistent.
i This aspect of the contention should be summari-ly_ dismissed for two reasons.
The first is simply that the al-
.lsged inconsistency bears no relationship to Contention 1.d.
i
'TheLsubject of the contention is the evaluation of the " kinetic l
cxpansion repair technique, including leak tightness and load carrying capabilities."
The " leak-before-break" concept re-i
'letes to the mechanics of crack propagation; it bears no rela-L p
tionship to the evaluation of the kinetic expansion repair t
tschnique.
Leshnoff Affidavit, 1 4.
I p i
The second reason for dismissal is that there is no genuine issue as to any material fact on the question of whether an inconsistency' exists between the two documents on the concept of " leak-before-break."
TMIA cites the February 18, 1983 report of the TPR ("TPR Report," SER, Attachment 6).
That report was supple-mented on May 16, 1983 ("Supp.
1," SER, Attachment 6), and again on December 3, 1983 ("Supp. 2").
The supplements ad-dressed and updated TPR comments in the original report after review and consideration of additiona: information supplied to it as a direct result of its original comments.
Graham Affida-vit, 1 3.
TMIA has not cited the supplements.
TMIA's reference is to.a TPR comment in the February 18 Report to the effect that the stresses in the tran-cition' zone below the expanded portion of the tu'be are such that " break-before-leak"_might be~possible in that zone, but that such a break would be detected and controlled without se-rious consequences because it would be confined well within the tube sheet hole.
TPR Report at 17-18; see THIA 1st Resp. to Interrog.
1.d-3.
1 Subsequent to the TPR's comment, Licensee per-formed additional analyses of stresses in the transition zone which' supplemented the material reviewed earlier by the TPR.
The analyses were documented in GPUN TDR 388, Rev.
3, which was l
'provided to the TPR in early May, 1983.
Graham Affidavit, 1 4.
. f
(
The TPR, in its May 16, 1983 supplement, acknowledged the addi-tional review and stated that the analyses showed "an a cept-tble stress condition" in the transition zone.
Supp.
1, at 7.
Licensee's additional analyses were also avail-cble to the Staff and its consultants for review prior to the issuance of its SER in November 1983.
Graham Affidavit, f 5.
Like the TPR,.the Staff and its consultants found the analyses to be acceptable; the Staff consultants concluded that "...
ccrly through-wall cracking in [the transition zone] should be dstected by the leakage monitoring program.
Additionally, a tube parted in this zone should remain trapped in tne upper tube sheet minimizing the consequences of failure."
SER Supp.
1, (attached to Board Notification BN-83-184, November 23,
'1983), Attach. 7, at 6.
Thus, the TPR findings are not incon-cistent with the conclusion in the SER.
(b)
The second inconsistency between the two docu-mants cited in TMIA's interrogatory answers is that the TPR al-lagedly " recognizes that the changed strength and dimensions is cn important effect," but that there.is no indication that this offect is recognized and analyzed in the SER.
This allegation of inconsistency quickly fails because TMIA has l
mischaracterized the TPR's statement, and because the Staff did indeed address the effects of the kinetic expansion of the tube., -
.--._.-4.
y
._m.
2-What the TPR really said at page 15 of the TRP R; port, Comment 2, is that the " explosive expansion of the tubes could' affect the stress levels, if the process would change the strength or some dimensions of the tubes," but that the testing and analysis shows that "the repair process is not cxpected to affect significantly the stress levels in the tubes..." (emphasis supplied).3/
1/ -
Although not germane to the contention, TMIA complained in 3
its interrogatory answer that the TPR did not reveal its basis for concluding that there was no problem with changed strength cnd dimensions.
In fact, the TPR stated in the same paragraph that its conclusion was based on "the information that (it] has rsceived....the reports on the qualification tests....and the otatements made in publications issued by the tube expansion contractor."
Among the test results that had been made avail-cble to the TPR for its review were the following:
(a)
Axial load tests, which demonstrated that the nsw kinetic expansion joint, the tubing in the transition, and tubing below the joint had the strength to carry all necessary loads;-
(b)
Evaluations of residual stresses included direct maasurement of residual stresses, sizing of the transition zone, comparative corrosion testing, hardness tests in the ex-prnded area, surface examinations, and post-expansion profilometry, demonstrating that the material properties, me-chanical strength, and small dimensional change of the expanded joints are comparable to those in any steam generator tube-to-
-tubesheet joint; and L
(3)
Evaluations axial dimensien changes that rasulted from the expansion process which ascertained that their effect on preload were insignificant.
The results.of these tests were made available to the TPR l
for its review during or prior to the month of December, 1982.
These test results are summarized in the documents referenced in the bibliography attached to the TPR's February 18, 1983 re-port.
In addition, Licensee delivered several detailed presen-tations directly to the TPR during which the aforementioned tasts and evaluations were exhaustively discussed.
Graham Af-l fidavit, 1 6. -
. Moreover, the SER does, in fact, discuss at soms length the effects of the kinetic expansion: repair process on
~
the tubes, with conclusions' entirely consistent with those of the TPR.
SER at 18-21.
Thus, there exists no inconsistency or difference of opinion between the'TPR findings and the SER with respect to the effects of the kinetic expansion.
(c)
TMIA's third allegation of inconsistency between the-TPR findings and the Staff's SER, relates to a recommenda-tion for plugging certain tubes with less than 40% through-wall defects.
Since the subject matter relates to the choice of tubes plugged, this portion of the contention has been rejected as anLissue'in this proceeding by the Board's January 9, 1984 Memorandum and Order at 4-5.
In any event, there is no incon-p
'nistency between.the two documents.
As in item 1 above, TMIA cite'd the TPR Report without noting that the TPR had later modified.its original recommendation on the basis of additional information not previously available to'it.
- At page'6, Recommendation 1,-of the TPR Report, the i.
TPR had recommended that certain tubes be plugged.
In Supple-ment 1, the TPR retracted this recommendation based on addi-
~tional information that showed that the number of tubes in r
Vquestion was smaller than originally. estimated; only indica-tions in regions of low cross flow would be left in service (15th span and below); only very short 40% through-wall indica-tions (2 or fewer coils on the eight coil ECT probe) were left 23-
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in-service; and considerable additional analytical work was cvailable which provided assurance that these indication were considerably smaller than a size which would be expected to propagate to failure due_to fatigue.
Supp.
1, at 2, Recommen-dation A.1 and 2, citing TR-008, Rev. 2, 55 VII.c and IX.D.
Thus, there is no inconsistency between the TPR's ul-timate finding and the SER, which adheres to the 40% plugging criteria in accordance with the original licensing basis.
(d)
TMIA's next allegation of inconsistency is that
'the TPR analysis " finds it hard to substantiate a firm conclu-cion that defects below a certain size range will not propagate due to flow-induced vibrations," which is inconsistent with unidentified SER conclusions.
As was the case for item 1, this ellegation bears no relationship to the subject matter of Con-tention 1.d, and can be dismissed on that ground alone.
Crack propagation due to flow induced vibration has nothing to do with the " evaluation of the kinetic expansion repair technique, including leak tightness and load carrying ability."
l l
There is also no inconsistency between the TPR findings and the SER with respect to the topic of flow-induced vibration.
At page 16 of the TPR Report, the TPR noted that Licensee had done extensive analysis of the fatigue-crack growth rates in tubes subjected to flow-induced vibration.
The j
results were positive, and showed that the time required for a l
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y fatigue crack to pr'opagate'through the tube wall would be longer that the lifetime of the steam generator for any crack cize that would be left"ip' service.
However, the TPR took note of the limited data base available for the analysis.
Also, at pages 10-11, Comments _2 and'3, the TPR noted that Licensee did not include a flow-induced vibration type of loading in its long-term corrosion tests.
The TPR's position on the matter is that the lack of a more extensive data base is not of concern, because if a crack were to propagate thhough-wall via flow-induced vi-bration before the end of the st_eam generator life, it would be S
detected and taken out' of-s,eriich b' fore it would break.
e TPR Report at 17.4/
This is. precisely'the position taken by the Staff in the SER, where._tho' subject was extensively discussed.
At page 21 of the SER, as modified at.pigas-8-10 of SER Supple-x
. ment l' (see Board Notification BN-83-184'd November 23, 1983),
the Staff, after an extensive discussion of the thredhold stress intensity require.d for fatigue brack propagation by L
flow-induced vibration, conci'uded tha't cracks which are large l --
4/
In its first supplement, the TPR observed that "more data were found to~ help substantiate'GPU's analysis," and suggested that Licensee's long-term corrosion tests include a simulated flow-induced vibration loading "if-practical 7 for conserva.
tism."
Supp.
1, at 5.
It was presented as'a comment, not'a i
formal recommendation, and did not affect th; TPR's conclusion that flow-induced vibration was not a problem ~,-or the'TPR's ul-timate conclusion that the " plant can be operated saf'31y with-the repaired steam generators."
Supp.
1, at 2.'
s.
A.
'cnough to propagate to failure can be detected and removed from carvice.
.Thus, the findings of the TPR and the SER are in close agreement, and no inconsistency exists.
(e)
The last of TMIA's alleged inconsistencies is not really presented by TMIA as an inconsistency between the
.TPR findings.and the SER.
TMIA states only that neither the TPR nor the Staff has analyzed multiple tube ruptures as a sep-crate issue.
This is correct, and in that respect the docu-mnnts are wholly consistent.
Since simultaneous tube ruptures are not a design basis accident for any nuclear plant, neither the TPR nor the Staff have required analysis for such an event in their respective approvals for-returning the plant-to ser-
~
vice.
Based on the foregoing, none of TMIA's alleged
" inherent inconsistencies" between the TPR findings and the SER are, in fact, inconsistencies.
Moreover, most of the alleged inconsistencies do not bear on the evaluation of the kinetic repair process, the subject of Contention 1.d.
Thus, Licensee l
l
.cubmits that with respect to TMIA's claim that the TPR findings cnd the SER are not " credible documents in their evaluation of the kinetic repair proci.ss, including leak tightness and load carrying capabilities,...because of the report's inherent r
inconsistencies," there is no genuine issue to be heard as to cny material fact.
t.
I l l-I i
2.
~ Axisymmetric Stress Analysis The second part of Contention 1.d alleges that the svaluations of the. kinetic repair process by the TPR and the Staff are not~ credible "because the basic assumptions and con-
-clusions therein rest improperly on axial symmetric stress
.cnalysis which would not be applicable to all cracks."
This allegation appears to rest on a misconception by TMIA of both
- the: nature and purpose of the axisymmetric stress analyses per-
'fo rmed.
As we will discuss below, this part of Contention 1.d chould be summarily' dismissed because, as stated in the affida-vit of Stephen D.
Leshnoff, an engineer in Licensee's employ who' performed the fracture mechanics fatigue evaluations for th'e TMI-1 tubes, axial symmetric (i.e.,
axisymmetric) analyses
. are not used to evaluate the effects of cracks.
Leshnoff Af-w
~
.fidavit, 11.5-7.
TMIA-states in the contention that axisymmetric-otress analysis "would not be applicable to all cracks." Simi-larly, TMIA stated in answer to a Licensee interrogatory that
.the.use of' axial symmetric stress analysis meant assuming that
'i the_ cracks themselves have the property of axial symmetry.
TMI ilst. Resp..to^Interrog.
1.d-6.
To the contrary, the cracks were l
not-assumed to exist or to propagate in an axisymmetric manner; the:use of axial symmetry in the stress analysis means that the stresses'on the tubes,. not the crack propagation, are
.cxisymmetric.
Leshnoff Affidavit, 1 5.
l '
l I
i
'Axisymmetric analyses were used only in one structur-cl evaluation of the tubes.
This evaluation was to compute the
-ctress increase in the transition region of the kinetic expan-sion joint between'the expanded and non-expanded portions of the tube. -Axisymmetric analysis was appropriate for this eval-untion because stresses are uniform around the tube circumfer-
.cnce, i.e.,
bending effects are negligible.
The effects of cracks were not evaluated in this analyses; they were evaluated
'in other analyses.
Leshnoff Affidavit, 1 6.
All tube structural analyses performed to evaluate 1
the effects of cracks employed asymmetric analysis for the con-
, sideration of nonuniformities in stress distribution around the
_ circumference of the tube.
Leshnoff Affidavit, 1 7.
.In response to' Staff interrogatories seeking to determine the. basis for the allegation, TMIA stated that "Dr.
Sih told us that the most dangerous direction for cracks to run may:not necessarily,be in a direction normal to axial symmetric intress," and that an EPRI analysis relied upon is " flawed in tEatLit' relies on a limited data base."
TMIA 2d Resp. to Interrogs. 20, 35. 'Neither comment is relevant to this portion
'of the contention.
While Dr. Sih's statement about normal p
i L
cracking may be:true, the cracks experienced were, in fact, circumferential cracks representative of the IGSAC which took place.
Other types of cracks are not present.
Giacobbe Affi-i davit,.11 19-20.
As,for the second statement, the data base of l r. -
I i
w.
- the EPRILstudy was not'used to' support the axisymmetric nature of the'model; the data were developed to characterize the mate-rial properties of1Inconel-600, and are independent of material orfloading geometry.
TPR Report at 10, 17.
Accordingly, there is no genuine issue to be-heard as to any material fact with respect to Licensee's use of exisymmetric~ analyses in its crack propagation studies.
3.
Toughness versus' Hardness In this portion of Contention 1.d,-TMIA alleges that thel evaluations-by the TPR and the Staff of the kinetic repair technique are not credible "because of the failure to analyze crackcresistance on the basis of toughness as opposed to hard-ness which-has no relation to crack resistance."
Again, as discussed in Item 2 above, the analyses for crack resistance, i.e.,
for the mechanical propagation of fatigue cracks in the tubes, was not a part of, and is unrelated to, the evaluation of the kinetic-expansion repair technique, the subject of the
' contention.
Leshnoff Affidavit, T 4.
Moreover, its irrelevance notwithstanding, crack re-sistance was, in fact, analyzed on the basis of " toughness,"
.which was factored into the fatigue model used to evaluate the p
loffects1of stress intensities on crack propagation.
Leshnoff
~ Affidavit, 1 8.
' Stress intensity is a mathematical representation of i
the way stresses concentrate at the crack tips when they are u l t
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transmitted around the perturbation in the stress field caused by crack.
If the stress intensity is very low, the material at
.the_ crack tip can strain to accommodate the additional loading, cnd no crack growth occurs.
The threshold stress intensity is
- the value below which no growth occurs.
If the stress intensi-ty is very high, the material will fracture'since the materi-
.cl s microstructure cannot accommodate the necessary strain.
The lowest stress intensity which results in this fracturing of a material is its fracture toughness.
In general, the more ductile the material, the higher the fracture toughness.
.Lashnoff Affidavit, 1 8.
Hardness, on the other hand, is not germane to a me-chanical crack propagation analysis, and was not used for that purpose.
A hardness test was used solely as a comparison be-tween rolled expansion and kinetic expansion to deter _
. rela-
~ tive susceptibility to IGSAC.
Leshnoff Affidavit, 1 9.
Accordingly, because crack resistance was analyzed on the basis of toughness, rather than hardness, there is no genu-ine issue to be heard as to any material fact associated with this portion of Contention 1.d.
4.
Crack Size In the fourth and final aspect of Contention 1.d, TMIA alleges that evaluations by the TPR and-the Staff of the kinetic expansion repair technique are not credible "because of
- the failure to differentiate in their analysis between the t
, l l
L--
.cffects of thermal stress onLsmall versus large cracks."
Crack propagation analysis was not a part of, and ie not germane to, theLevaluationLof the kinetic expansion repair technique.
For this. reason alone,_this portion of Contention 1.d should be cummarily dismissed.
Leshnoff Affidavit, _1 4.
In.any event, both large'and small cracks were taken into: account in the propagation analysis.
In evaluating crack propagation under normal and anticipated transient loading, a kpectrum of' crack sizes were. interacted with the tube stresses to determine:the number of cycles required to propagate the crack through the tube wall.
Stress intensities were calculat-sdlfor partial through-wall cracks, combining components due to membrane stress, bending stress, and stresses cue to internal pressure acting on the parting crack faces, as well as the thermally induced' axial loads constituting the major portion of Lthe l~oad cycling.
The stress intensity.was recalculated for sach' cycle;and the increment of crack growth determined.
The nsw crackLlength was then used to determine the stress intensi--
ty of'the next cycle.
Leshnoff Affidavit, 1 10.
-TMIA stated in response to a Staff interrogatory that l
'the significanceaof'the alleged failure to differentiate be-tween small and large cracks ~is that "small cracks are more
(
likely to propagate than large cracks because small cracks
[
otore more energy proportionate to their size than large cracks."
TMIA 2nd Resp. to Interrog. 24.
This statement j.-
Et
presumably refers to the fact that a smaller crack grows faster cn a percentage basis (i.e.,
growth per cycle divided by ini-tial crack size) if the stress intensity is the same for both the smaller and larger cracks.
In any event, in analyzing the cpectrum of crack sizes separately, stress intensity was calcu-lated for each load cycle and accounted for crack size during that cycle.
Accordingly, the effect of crack size is appropri-
'ately considered in the fracture mechanics calculations which covered the effects of ternmal stress.
Leshnoff Affidavit, 1 11.
Thus, this aspect of Contention 1.d should be summa-
-rily dismissed because it bears no relationship to the subject matter of the contention, and because Licensee did, in fact, consider small as well as large cracks in its fatigue crack propagation analysis.
Because' as discussed above, there is no genuine issue to be heard as to any material fact with respect to each of the_four subparts of TMIA Contention 1.d, Licensee submits that-the contention must be dismissed in its entirety.
i I
I l
)
- l
E.
TMIA'S CONTENTION 2.a AND JOINT INTERVENORS' CONTENTION 1(5)
TMIA's Contention 2.a reads as follows:
2.
Neither Licensee nor the NRC staff has demon-strated that the corrosion which damaged the steam genera-tor and other RCS components and systems, will not reinitiate during plant operation and rapidly progress, attacking either the steam generator or elsewhere in the primary pressure boundary, thus providing no reasonable assurance that the operation of TMI-1 with the as-repaired steam generator can be conducted without en-dangering the health and safety of of the public, for the following reasons:
a.
There is no assurance that the causative agent or the source of initiation or the conditions under which initiation originally occurred, have been properly identified, thus undermining any conclusion that the causative agent has been removed from the system, and undermining the reliability of any pro-posed clean-up process, procedures meant to eliminate
.tdue corrosive environment, or the reliability of the Licensee and staff stress analysis as to when corro-sion could reoccur.
Joint Intsrvenors' Contention 1(5) read as follows:
1 There is no assurance that the steam generator tube repair program can assure the integrity of the tubes and their joints under the environmental conditions atten-dant to operation.
TMI-1 shall not be permitted to restart before such assurance is provided.
The following elements of the repair program are deficient:
(5)
The possible effects of potential stress cracking agents other than active forms of sulfur have not been studied in relation to the initiation of IGSCC.
Subsequent to the discovery of leakage in the TMI-1 OTSG tubing, Licensee developed and implemented an elaborate series of evaluation programs to identify the extent and cause of tube failure.
The programs identified the location and type of de-fects in the tubes, determined the chemical composition of the.
1 tube surface, and analyzed the conditions under which the dam-cge could'have occurred.
Giacobbe Affidavit 1 4 (attached hareto)
On.the bases of these analyses, the root cause of failure wcs determined to be intergranular stress assisted cracking (IGSAC) i~nduced by intermediate metastable sulfur compounds.
Giacobbe' Affidavit, 11 6, 7, 51 (attached hereto).
The condi-tions under which the corrosion occurred were determined to be the cooldown and shutdown following hot functional testing (HFT) in August and September of 1981.
Id. at 1 25.
The caus-etive' agent and sequence of-events were corroborated by the
. ccientific literature and extensive corrosion testing.
Id. at 11 33, 44-51.
In responding to discovery requests by Licensee, neither TMIA nor Joint Intervenors have pointed to any specific errors in the manner in which the failure analyses was performed.
As with other contentions, intervenors chose, in the main, to rely on vague concerns that the analysis was not vigorous enough, or did not establish the cause with the absolute certainty they would desire.
See TMIA ist Resp. to Interrogs. 2.a-1 through
- 2.a-6, 2.a-15 through 2.a.18, 2.a-20; J.I.
1st Resp., to Interrogs. 1(5)-4 through 1(5)-7, 1(5)-14.
l These qualms are particularly surprising in this case be-l ccuse of the extensive scope and depth of the evaluation pro-grams and because the facts point so ineluctably to sulfur,
IGSAC during the cooldown following HFT as the cause of the tube failure.
These facts are described in detail in the atta-ched affidavit of F. Scott Giacobbe, Manager of Materials Engi-neering and Failure Analysis For Licensee.
As Mr. Giacobbe there explains, the conclusion flowed from the following facts,
'cmong others:
(1) No-unexpected leakage was detected during the August-September 1981 HFT.
Giacobbe Affidavit, 1 25.
(2)
The cracking was almost exclusively circumferential.
This ori-
.cntation of cracks requires axial load stresses.
Axial load stresses are the dominant stresses only during cooldown and
~
cold shutdown.
Id. at 11-18, 19, 25.
(3) Metastable sulfur Epeciesnare the'only corrodants known to cause'IGSAC of Inconel 600'at low temperatures.
Id. at 1 33.
(4) Sulfur contamina-tion of the RCS had occurred.
Id. at TV 26, 27, 28 (5) The
. oxygen necessary.to create metastable sulfur species from this culfur was introduced late in the August-September 1981 HFT and during the subsequent cooldown.
Id. at 11 30, 31.
No conclu-eion other than the one drawn by Licensee, and concurred in by al L other experts who reviewed the question,. is possible.
-TMIA asserts that unidentified forms of sulfur for which Licensee failed to search might have caused the IGSAC.
TMIA Interrog. 2.a-1 through 2.a-6.
The primary emphasis of Licens-ce's reinitiation prevention strategy, however, is to control the total amount of sulfur in the RCS and to prevent combina-tions of temperature and oxidizing conditions which could
, 0
result in the formation of harmful sulfur forms.
This approach will prevent IGSAC reinitiation regardless of specific farm of
'culfur involved..Giacobbe Affidavit, 11 115-116.5/
Joint Intervenors make the related assertion that sulfur
-within the.as fabricated tube wall material could have caused
.the corrosion.
J.I.
1st Resp. to Interrogs. 1(2)-6, 1(2)-10, 11(2)-13, 1(5)-1.
As explained in Mr. Giacobbe's affidavit, the
. studies cited by Joint Intervenors have no bearing on the envi-g ronment and material involved in the TMI-1 OTSGs, and tests using appropriate environment and materials have shown no cor-rosion.
Giacobbe Affidavit, 11 59-61.
Moreover, during the
.cpproximately 100 OTSG years of operating experience at plants using the.same material and environment as TMI-1, no corrosion has occurred in the absence of a contaminant in the coolant.
Id. at 1 60.
The intervenors also point to a number of other potential causative agents, e.g.,
carbonates or carbonaceous material
'(J.I.
1st Resp. to Interrog. 1(5)-1 through 1(5)-3)) lead, phosphorous or mercury (id.), and other unidentified agents for which Licensee did not search (TMIA ist Resp. to Interrogs.
5/
TMIA in a related-vein has alleged that the failure to identify the specific mechanistic steps involved in the pro-E cass,'and las deal with other supposed contaminations of the cystem raises issues as to the causative agent.
[TMIA ist Rssp. to Interog. 2.a-1-2.a-6].
These allegations are ad-1 dressed in the context of Contention 2.c,
- infra,
- p. __.
State-L msnts by consultants which TMIA alleges raise the possibility of other corrosive agents are addressed there as well.
I
! [
I l
I 2.a-1::through'2.a-6, 2.a-16 through 2.a-18.
But Licensee did eearch.for all possible causative agents.
Giacobbe Affiadivt,
'11;62-67.
Those that were potential causes of IGSAC were care-
' fully evaluated, and all but sulfur were ruled out because the conditions under.which those substances cause IGSAC, or the concentration of.the substances needed to cause the damage, were not present in the TMI-1 RCS.
I_d.
at 62.
Joint Intervenors next assert that even if these other E
substances did not directly cause the IGSAC, they nonetheless might have had a synergistic effect on the sulfur-induced IGSAC.
J.I.
1st Resp. to Interrogs. 1(5)-4 through 1(5)-7.
I Again, Licensee took into account such effects.
Of the agents found on the tube surfaces, only chlorides are likely to have a synergistic effect.
Giacobbe Affi' davit, 11 65, 69.
Tests with 10 times the level of chlorides and sulfur species allowed by i
TMI-1 chemical specifications showed no corrosion.
Id. at 69.
Conservatively, then, it can be concluded that any synergistic reaction which does exist will not cause reinitiation of the IGSAC at TMI-1 under the administrative controls on RCB chemis-
.try.
Long term corrosion tests, moreover, are exposing actual TMI-11 tube samples to sulfur species.
They thus contain all contaminants which were on the tubes at the time of failure (including any residue from the kinetic expansion process).
No
- IGSAC has been observed, again demonstrating that any
?
i - i -
. - ~ _ -. _, _. - _. _ -.
cynergistic reaction among the chemicals present will not reinitiate IGSAC under the RCS administrative controls.
Id. at 70.
In sum, intervenors have succeeded only in identifying a fcw issues potentially relevant to Contentions 2.a and 1(5).
There are, however, no facts which suggest their theories have cny validity here.
Especially when-the record is viewed as a whole, it is clear the issues raised are not genuine, and that no material facts are in dispute.
Perry, supra.
The conten-
.tions should therefore be dismissed.
F.
TMIA'S CONTENTION 2.b.1 TMIA's Contention 2.b.1 reads as follows:
2.
Neither Licensee nor the NRC Staff has dem-onstrated that the corrosion which damaged the steam generator and other RCS compo-nents and systems, will not reinitiate dur-ing plant operation and rapidly progress, attacking either the steam generator or elsewhere in the primary pressure boundary, thus providing no reasonable assurance that the' operation of TMI-1 with the as-repaired steam generator can be conducted without endangering the health and safety of the public, for the following reason:
b.1. The Staff's own consultant on this
- issue, R.L. Dillon, believes that the risk associated with cleaning, i.e.,
that a relatively large inventory of sulfur compounds will be put into so-lution, are greater than simply " liv-ing with large S inventory in the sys-tem," supporting a conclusion that the only two possibilities being consid-ered by the Licensee and Staff pose substantial risk that corrosion will reinitiate.. _.
\\
l As the. contention itself indicates, TMIA's allegation that rainitiation of the IGSAC might be prompted by the hydrogen i
paroxide c1 caning process is predicated on a statement by Staff consultant R. L. Dillon expressing his concern that the conver-cion of sulfides on the tube surfaces to soluble sulfates might
.put dangerously high levels of sulfur compounds in solution.
A cimilar concern was expressed by the TPR, namely, that "there in much about the reactions between peroxides and systems mate-rials that is not well understood."
TPR May 16, 1983 Supple-m:nt, at 6.
The concerns of R.
L. Dillon and the TPR were expressed b2 fore the cleaning actually took place.
There is no evidence that cleaning had any adverse effects on the tubes, or that it created conditions which someday might cause IGSAC.
Giacobbe Affidavit, 11 97, 98.
To the contrary, rather than the 5-10 ppm of sulfur com-pounds estimated by Mr. Dillon, only 0.4 ppm total sulfate was g:nerated by the hydrogen peroxide process.
Giacobbe Affida-vit, 1 95.
This concentration is not corrosive, especially at the-elevated pH used during the cleaning; tests performed be-fore the cleaning found no corrosion when actual TMI-1 tubing underwent simulated cleaning in a solution spiked with concen-trations of 20 ppm sulfate.
See id.
The hot functional
-tasting following'the cleaning process served to confirm that the cleaning process was not harmful.
Measured leakage !
rcmained low throughout the test period.
Giacobbe Affidavit,
'1 96.
The successful completion of the hydrogen peroxide cleaning effectively moots the concerns raised by R.
L. Dillon end the TPR.
Giacobbe Affidavit, 1 78.g/
And despite Licens-J cs's repeated inquiries during discovery, TMIA has failed to cxplain why these concerns have any continuing relevancy now that the cleaning is finished.
TMIA 1st Resp. to Interrog.
2.b.1-1.
Nor has TMIA identified additional reasons why it be-lieves the cleaning process might have been harmful.
TMIA 1st Rasp. to Interrogs. 2.b.1-4 through 2.b.1-13.
There would thus cppear to be no issue whatsoever in dispute, material or other-wise.
Licensee has nonetheless prepared an extensive explanation of the reasons why it had concluded it could proceed with the hydrogen peroxide process without harm to tha OTSGs.
As de-tciled in Section III.G of the statement of material facts, and S&ction II of the supporting Giacobbe affidavit, a lengthy se-ries of tests and analyses were performed of (1) the effects of s/
Even prior to the cleaning, the Dillon and TPR statements provided scant basis for the reinitiation contention. Notwith-L standing his inflated 5-10 ppm estimate of likely sulfur com-pounds in solution, Dillon concluded that " restart is appropri-nte" based on his " consideration of corrosion related factors."
SER Attachment 3 at 14.
The TPR similarly viewed the risk as-sociated with cleaning as inconsequential, stating that while paroxide cleaning was not essential to safety, "nor is peroxide
- flushing expected to have an adverse impact on plant safety."
-TPR May 18, 1983 Supplement at 6.
the cleaning itself on the system, without considering the
. presence of sulfur, Giacobbe Affidavit, 11 82-85; and (2) the offects of the cleaning process on the sulfide tube surface films before cleaning was undertaken.
Those tests and analyses cstablished that there would be no adverse effects on the sys-tem as a result of the cleaning.
Id. at 1 86-92.
Of particular note, the short term tests demonstrated that the conversion from nickel sulfide to soluble sulfates occurs very rapidly.
Thus, the concentrations of intermediate and po-tentially harmful metastable sulfur species produced by the conversion are very low--too low to be corrosive to the tubes.
Giacobbe Affidavit, 1 88.
The conclusion that IGSAC would not rainitiate during or because of cleaning, moreover, was con-firmed by long term corrosion tests.
Id. at 11 91, 92.
Accordingly, since the detailed statement of facts and the cupporting affidavit demonstrate conclusively that the cleaning process has not prompted reinitiation of the IGSAC, there is no g2nuine issue to be heard with respect to TMIA's Contention 2.b.l. ---_
G.
TMIA's CONTENTION 2.b.2 AND JOINT INTERVENORS' CONTENTION 1(2)~
TMIA's-Contention 2.b.2 reads as follows:
2.
Neither Licensee nor the NRC Staff has demonstrated that the. corrosion which damaged the steam generator and other RCS components and systems, will not reinitiate during plant op-eration'and rapidly progress, attacking either the steam generator or elsewhere in the primary pressure boundary, thus providing no reasonable assurance that the operation of TMI-1 with the as' repaired steam generator can be conducted without endangering the health and safety of the public, _for the following reasons:
b.2. Even if the proposed cleaning process presented no risks, there is no as-surance that the proposed process can re-move more than 50-80% of the contamination which would be left after the process is complete will not cause reinitiation.
Joint Intervenors' Contention 1(2)' reads as follows:
1.
There is no assurance that the steam generator tubo repair program can assure the in-tegrity of the tubes and their joints under the environmental conditions attendant to operation.
TMI-1 shall not be permitted to restart before such' assurance is provided.
The following ele-ments of the repair program are deficient:
i (2)
Active forms of sulfur can be generated from presumably benign sulfur re-maining on the tubes after cleaning.
Both TMIA's Contention 2.b.2 and Joint Intervenors' Con-l tontion 1(2) allege that the sulfur species present in the RCS after cleanup may cause reinitiation of the cracking mechanism.
TMIA ist Resp. to Interrogs. 2.b.2 2.b.2-4; J.I.
1st Resp..
to Interrogs. 1-(2)-6.
As set forth in Section III of Mr.
Giacobbe's affidavit, Licensee has taken a number of steps to control reactor system conditions so that corrosive levels of the sulfur species necessary for IGSAC will not exist in the RCS..Giacobbe Affidavit, 11 102-110.
As previously noted, the sulfur currently present in the OTSGs is in the forms of sulfide on tube surfaces and low lev-els of sulfate in the coolant.
Sulfide is not corrosive and would not be corrosive even if none had been removed during the cleaning process.
Sulfates are not corrosive at the present
-low levels existing in the coolant.
Giacobbe Affidavit, 1 111.7/
The crucial question, therefore, is whether signifi-cent levels of aggressive species will be found at any given time under the controls implemented by Licensee.
Id. at 111-116.
Corrosive. levels of aggressive species of sulfur will not occur during operation because of the thermodynamic stability of sulfides.
Sulfide is the stable form of sulfur under normal operating conditions (deoxygenated, high temperatures).
For 7/
TMIA and Joint Intervenors both expressed concern as to the corrosive effects of 0.1 ppm sulfate in solution.
TMIA lst Rasp. to Interrogs. 2.b.2-8 through 2.b.2-10; J.I.
1st Resp. to Interrog. 1(2)-18.
Short tests by Licensee, however, found no corrosion at 10 ppm sulfate and long term corrosion tests have found no corrosion at 0.1 ppm sulfate.
Even tests involving high stress conditions and acid sulfate (of questionable rele-vency here) have not found corrosion below acid concentrations of 1 ppm.
There is thus no factual dispute as to the corrosion potential of 0.1 ppm sulfate.
Giacobbe Affidavit, 11 127, 128. -
l this reason, aggressive intermediate species will not be formed when the system is in. full operation.
Id. at 11 113-116.
Metastable species could be formed under oxygenated condi-tions (such as those which accompanied the cooldown and shut-
-down when the TMI-1 tube failure occurred), however, because the sulfide would then tend to oxidize.
Giacobbe Affidavit, 1 107.
In order to prevent this from occurring, Licensee has imposed operating controls which maintain deoxygenated condi-tions during.cooldown and shutdown.
See id. at 11 108-116.
For these reasons, metastable species will not be formed in significant levels during hot operations, cooldown or shutdown.
Licensee has also implemented controls to ensure that ad-ditional sulfur compounds and other potential corrodants are not introduced into the RCS.
These are detailed in Mr.
Giacobbe's Affidavit, 1 102-110.
Licensee has conducted extensive testing to verify that corrosion will not reinitiate.
Corrosion testing showed the kinetically expanded joint to be as resistant to IGSAC as any other OTSG tube-to-tubesheet joint.
Giacobbe Affidavit, 1 117.
Short and long term corrosion tests using actual tubes have found no IGSAC.
Id. at 11 118-124.
The long term tests simu-late environmental and operational conditions which are repre-contative of the " worst case" conditions that could occur under tcchnical specifications.
Id. at 11 118-124. _ _.
?
The allegations made by intervenors do not raise any genu-ine issues with respect to these facts, nor do they identify other contrary facts material to this contention.
As stated in the contention, TMIA places reliance on the fact that 20-50% of
. the sulfide may remain after cleaning.
TMIA Resp. to Interrogs. 2.b.2-1 through 2.b.2-4.
But this sulfide is not now in a corrosive form, and the operation control procedures dascribed above will prevent the creation of potentially harm-ful intermediate species from that sulfide.
This is so irre-spective of the percentage of sulfides remaining after cleaning.
TMIA also notes that RCS piping of less than one inch in diameter was not flushed as part of the cleaning process.
TMIA let Resp. to Interrogs. 2.b.2-1 through 2.b.2-4.
Inasmuch as the surface areas of these lines represents less than 5% of the curface area of the RCS, the amount of sulfides in these lines is negligible compared to the total sulfur inventory.
It is accordingly well within the capacity of the administrative pro-ccdares to control.
Giacobbe Affidavit, 1 126.
Joint Intervenors' responses to Licensee's interrogatories indicate that they additionally rely here on the same asser-tions they raised with-respect to Contention 1(5)--the presence of sulfur in the tube alloy, and potential synergists.
Our re-cponses to those assertions in Section IV apply equally here.
In addition, it should be noted that the tube samples in the !
1
long' term corrosion tests are exposed.to all synergists poten-tially present in the RCS..(as well as, of course,.the sulfur in the alloy mix).
One test includes :U3 times the administrative limit on the most-likely synergist--chloride.
The fact that corrosion-has not occurred substantiates the conclusion that cny synergistic reaction which does occur will not cause
- roinitiation.of the IGSAC will go unrealized in the TMI-1 RCS,
~~ iven the concentrations of chemicals present.
Giacobbe Affi-g I
dsvit, 1 69.
The facts supporting the conclusion that corrosion will not reinitiate have thus been established beyond peradventure.
TMIA's Contention 2.b.2 and Joint Intervenors' Contention 1(2) i chould therefore be dismissed.
H.
TMIA'S CONTENTION 2.c.
TMIA Contention 2.c.
reads as follows:
2.
Neither Licensee nor the NRC Staff has demonstrated that.the corrosion which damaged the steam generator and other RCS components and systems, will not reinitiate during plant op-eration and rapidly progress, attacking either 1the steam generator or elsewhere in the primary pressure boundary, thus providing no reasonable
= assurance that.the operation of TMI-l with the
.as-repaired steam generator can be conducted without endangering the health and safety of the public, for the following; reasons:
i c.
Neither the " Report of Third Party Review of Three Mile Island, Unit 1, Steam Generator Repair" nor the Staff's Safety Evaluation Report (NUREG-1019) are credible documents in their evaluation of the causative agent, clean up, or proce-dures to prevent contamination reintroduction, and thus can not he used as L
i a basis for conclusion that the repairs in-sure safe plant operation, because of the reports' inherent inconsistencies.
- 1. -
Inherent Inconsistencies-r_
In response to Licensee's interrogatories asking TMIA to 4
dstail all " inherent inconsistencies".which support the allega-tion that the SER and TPR are not credible documents, TMIA identified three alleged inconsistencies, and has not supple-
.msnted its answer as of February 17, 1984, the date for the close of discovery.8/
There,'TMIA has defined Contention 2.c
-to consist of the following alleged inconsistencies (TMIA 1st
_ Rasp. to Interrogs. 2.c-5 through 2.c-8):
(a]
.TMIA notes that at pages 7-8 of the SER, the Staff concludes without any sup-port, that "the sodium thiosulfate concen-tration of: 4-5 ppm is the contaminant which
'most likely' caused the OTSG degradation",
yet states at page 8 that.the failure sce-nario has not been clearly established, and recognizes three previous contaminations which may have. caused corrosion.
[b]
The~ Staff also fails to deal with comments from its own consultants challenging as-F pects of this conciusion, such as M.
' Dillon's comment at page 12 of his? report regarding " inconsistencies'in the cracking environments," which "certainly invite questions," ignores his concerns about L
8/
-In response to Staff Interrogatory'34, which-asked TMIA to sidentify the-alleged " inherent-inconsistencies," TMIA supplied a different list'than it provided to Licensee,-corresponding to those provided for Contention 1.d.
Each of these alleged "in-herent inconsistencies" deals with mechanical considerations of crack propogati'on and has already been discussed above in the
~
l
. context of TMIA's Contention 1.d.
None is related to this Con-L tcntion 2.a, which deals solely with chemical considerations of
'rainitiation of IGSAC.
i-
! r 4,,,-
..,.,,..._...._.,____...m,._.__m,
contradictions regarding the cracking solu-tion chemistry,-and rejects Mr. Dillon's suggestion at page 29 of~the SER that a corrosion test be conducted in a cold, high oxygen and high concentration sulfate envi-ronment.-
[c] JThe Staff also fails to deal with Mr.
MacDonald's' comments at pages 18-24 of his report where he does not rule out other corrosion possibilities, stating that an-other-polysulfur species must be present in the system, that sulfur deposits of an unknown form were. observed in the system, that thiosulfate could have been-introduced in the system sometime earlier than September,.1981'.
'As a review _of-this list makes clear, all of these allega-tions concern the SER and do not involve the TPR.
And as an cxamination of the SER makes clear, the contention remains unsupported because the statements alleged to be inconsistent
'are in. fact, plainly consistent.
(a)
On page 7 of the SER, the Staff does indeed con-clude that "the sodium thiosulfate concentration of 4-5 ppm is the contaminant which most likely caused.the OTSG degradation".
Contrary to TMIA's implications'and allegations, that statement
^
is not onerof uncertainty or doubt, is not made without consid-l erable support,'and is not inconsistent with other statements l-in the SER'(or the TPR Report).
The entire SER Section 3.1 (pages 4-8) supports this conclusion, as do the laboratory and analytical work; Licensee's reports, and the Staff consultants'
'rsports discussed in these pages (SER Attachments 2-4).
The L
L TPR, Licensee and Staff consultants universally concurred in f
I,
-.<w m.s..
the conclusion that sodium thiosulfate contamination was the ccuse of the observed IGSAC.
See SER Attachment 2 at 2, at 2, Attachment 4 at 26, TPR report at 7.
In all of these reports, sodium thiosulfate has been iden-tified as the contaminant leading to the tube failure; it is not the corrodant itself.
The corrodant is identified as one or more intermediate species of sulfur created from the thio-culfate during the. hot functional test period; the precise spe-cies and process which thereafter caused the IGSAC have not bsen definitively established.
It is in this context that the Staff states (SER at 8) that "the specific mechanistic steps involved in the sulfur-induced stress corrosion cracking phe-nomenon have not been clearly established".
See the Staff's response to TMIA Interrogatories N-7(4), N-7(5).
This state-mant has been incorrectly paraphrased by the Intervenor as "the failure scenario has not been clearly established" and later as "ccknowledging that the failure scenario is speculative".
TMIA lot Resp. to Interrogs. 2.c 2.c-8.
As correctly quoted, the reference to identification of a specific reduced sulfur species as corrodant is entirely consistent with the Licensee's O
failure scenario (SER at 6-7), as well as with the quotation i
from page 7 of the SER identifying sodium thiosulfate as the contaminant.
In a related vein, the intervenor has claimed that the SER rscognizes three previous contaminations which may have caused
! l
~
~
~
F corrosion.
Again, TMIA has quoted the SER[out of context.
In the SER (at 9-5), the Staff discusses in detail Licen'see's
- svaluation of the cracked tubes and concurs in Licensee's con-clusion that sulfur was the corrodant in question.
The SER thereafter (at 5-7) discusses contaminations prior to the thio-culfate contamination which may have contributed to the' total culfur inventory -- not contaminations other than sulfur which may have caused corrosion.
Thus, although the intervenor has implied that the Staff evaluation is self-contradictory in this ocction,-careful examination of the SER shows this is not the
- case. - This asserced inconsistency therefore does not raise a genuine factual issue as to credibility of the report.
(b)
TMIA next asserts that the Staff ignored com-m;nts from NRC consultants challenging aspects of "this conclu-cion" (presumably the conclusion that thiosulfate was the most
- likely contaminant).
TMIA has taken several phrases from page 12 of the Dillon report (SER' Attachment 3) and implied that they challenge the identification of the contaminant.
In fact, Mr. Dillon clearly has not questioned the identification of so-dium thiosulfate as the contaminant leading to cracking; Mr.
Dillon's discussions concerned the identification of the corroding specie or species of sulfur.
In the same paragraph, Mr. Dillon concludes that "the reconstructed picture of the
-tube cracking circumstances... is probably close enough to the actual to be acceptable" and states "I don't know that the f _._ -
\\
~
.cpparent inconsistencies in. describing the cracking environment cre importantfto.thecreactor recovery operation".
Thus, it is Mr.-Dillon himself who concludes that these are inconsequential concerns, not the' Staff as claimed by the intervenor.
Further confirmation of Mr. Dillon's position on the issue i
~
id-his-discussiontof sulfur intrusion (Att. 3 at 2), where he rcpeats without challenge the same~ scenario for introduction of centaminants which is discussed in the SER and TR-008.
The
' Staff, rather than rejecting Mr. Dillon's discussion and con-
+
clusions "with no supporting-analysis" as alleged, acknowledges End concurs in.these findings.
See'SER at 7-8.
The interve-I nor's allegation that Mr.- Dillon-disagrees with the Staff con-clusion thus is-clearly unfounded.
l TMIA's companion allegation that the Staff rejected a sug-gastion by.Mr. Dil' ion tha't an additional corrosion test be con-
~
-ducted in,a-cold, high oxygen and high concentration sulfate p
environment is corr'ect, but does not support its contention.
Mr. Dillon.had suggested this test based on his belief that the I
TMI-l steam. generators would experience these conditions for a long period of' time after cleaning.
See complete discussion in SER Att.,3, at'12'. {After the' April 15, 1983'Dillon report was written,rhowever, Lfcensee'c'o'nducted a corrosion test which considered.-instead the' conditions planned and later actually
_ sv cxperienced'before, during, and after condr::t of the chemical cleaning (program. " Based on performance of this more
-i n
. 4
,O
.4
._e
cppropriate-test, the Staff rejected Mr. Dillon's comment.
Seo discussion of the corrosion test actually performed, at page 29
. of the SER.
Contrary to TMIA's allegation, then, the Staff has
- provided supporting analysis for its decision that Mr. Dillon's concern was no longer relevant.
The Staff's acceptance of a tost which has proven to be more representative and more appro-priate than the-one recommended earlier-by its consultant can hnrdly reflect poorly on the Staff's credibility.
(c)
TMIA has also alleged that the Staff did not dnal with comments by Dr. MacDonald (SER Attachment 4) which it claims challenge the identification of 4-5 ppm thiosulfate as the contaminant.
Once again, the intervenor has mischaracterized a discussion of the corrodant and the mecha-nism of IGSAC as a discussion of the contaminant and the fail-ure scenario.
Although TMIA alleges that Dr. MacDonald "does not rule out other corrosion possibilities" in pages 18-24 of his report, in fact, Dr. MacDonald is there speculating as to the identity of the reduced sulfur specie or species created from the thiosulfate contamination.
When it comes to identifi-cetion of the contaminant, Dr. MacDonald states (at 26) that "intergranular stress assisted cracking of the TMI-1 steam gen-orator tubes most probably resulted from contamination of the
~
RCS with thiosulfate".
l Similarly, Dr. MacDonald's statement that another poly-gulfur species must be present in the system, taken in context t-r w
-,v
,--vm-
-c rwewe e---w-
<-*-r
=-,-+----v
=~,w-.
y------
+
(Att. 4 at 22-23), supports:the Licensee's failure scenario.
His discussion refers to the presence of a polysulfur species created at the time of the attack, not to the introduction of a ccparate contaminant.
Inasmuch as polysulfur species are noth-ing more than forms of reduced sulfur, this hardly contradicts the. Staff's statement that sulfur in a reduced form caused the IGSAC of the TMI-1 OTSGs.
Similarly, Dr. MacDonald's statement (at 20) that " sulfur d: posits of an unknown form were observed" does not challenge the failure scenario, as TMIA alleges.
The concluding state-
'm:nt of'the same paragraph is:
"The fact that sulfur deposits w3re found in the CRD, albeit of unknown form, indicates that partially reduced sulfur species penetrated the CRD mechanism sometime during the period of contamination of the RCS with thiosulfate".
Thus, Dr. MacDonald's Statement, taken in con-tsxt clearly indicates his belief that these data support the Staff's conclusions rather than challenge them.
The Intervenor'has also presented Dr. MacDonald's state-l m nt (Att. 4 at 18) that "it is possible that thiosulfate was l
L introduced into the system at times earlier than the September 1981 cooldown" as if it contradicted the Staff's report or the fcilure scenario.
It should be noted, however, that Dr.
.MneDonald is referring not to contamination and ultimate IGSAC of the steam generators, but to an earlier problem with the spent fuel pool cooling system.
In any case, as discussed h,
w
carlier, other instances of sulfer contamination of the OTSGs wore identified by the Staff and Licensee as well.
2.
Other Asserted Bases Relating To Credibility The assertions discussed above.are the sum total of TMIA's response to Licensees interrogatories seeking ident.4.fication of "all" alleged incons~istencies which evidence a lack of credi-bility in the TPR report and Staff SER.
However, in reponse to NRC Interrogatory 33 asking why the documents were not "credi-ble" (which corresponds to Licensee First Interrogatories 2.c-1 through 2.c-3), TMIA provided a totally different list of alle-gations.
The three additional bases identified in TMIA's re-cponse to the Staff relate to the areas of:
administrative controls, flushing of large pipes only, and use of lithium.
Because the alleged bases do not identify any inconsistencies whatsoever, whether between the two documents or internal to one document, these allegations are outside the scope of Con-tention 2.c'as revised by the Board's January 9, 1984 order.
Even if these allegations are admissible, however, they do not raise material issues of fact.
We discuss each of these reasons in turn below.
(a)
The Intervenor first alleges that "The Staff is l
unable to state unequivocally that administrative controls will prevent the introduction of foreign chemicals into the RCS."
This is a complete mischaracterization of the Staff revieJ (at pages 31-33 of the SER),-which acknowledges both an improved -_.
cdministrative program to prevent ingress of unwanted chemicals cnd, as a back-up, an improved sampling program to identify cuch ingresses should they occur.
In the SER (at 32), the SLaff concludes that "these administrative control measures provide additional assurance that tube degradation will not recur."
The SER further states that "[b]ecause [pH and con-ductivity] measurements are effective and reliable in detecting ingress of foreign chemicals, the Staff finds that the Licensee has provided additional assurance that possible intrusion of chemicals would be detected and corrodants identified in case cdministrative controls fail to prevent the introduction of foreign chemicals into the RCS".
Ibid.
The Intervenor has not explained how the Staff's acknowledgement of the Licensee's prudently planned back up system could reflect poorly on the Staff's credibility.
(b)
TM1A has also stated that "in its Supplement to the SER at 14, the Staff comes to the conclusion that flushing of pipes less than 1-inch diameter is not warranted".
TMIA claims that this conclusion renders the SER an incredible docu-m nt.
But the Staff supports its conclusion by stating that
"[djue to the small volume of fluid in pipes with less than a 1-inch diameter compared with the total volume or the reactor ecolant system, flushing of these small lines is not war-rented".
.55-
The Staff's conclusion is patently credible.
These pipes represent less than 5% of the. surface area of the RCS.
Even in the unlikely event an additional 10% of the total sulfur re-moved by chemical cleaning process were present on the 1" or less. diameter pipes, and went immediately into solution, the.
total sulfur in solution (measured as sulfate) would still be loss:than half the administrative limit; as reported in TR-008 ct 33, flushing the.other 95% of the RCS with hydrogen peroxide r
for one month resulted in a maximum sulfur as sulfate concen-tration of only 400 ppb.
The Intervenor has not stated why the i
' Staff's engineering judgment that flushing 95% of the tubing curface is sufficient should indicate a lack of credibility.
,Giacobbe Affidavit, 1 126.
(c)
In the guise of additional allegations claimed to impugn.the TPR and Staff's credibility, the~Intervenor has attempted to reintroduce two contentions previously struck down by the Board'as lacking basis.
The Intervenor has claimed that the following constitutes an attack on the Staff's credibility:
" Licensee's TR-008 at 30 states "The lower limit
'for lithium was increased from.2 ppm to 1.0 ppm.. This was done because lithium may have an inhibiting effect".
(emphasis added)
There is no. discussion regarding post-cleaning' tests which would support a conclusion that the addi-
- tion of lithium.to the coolant has had an inhib-iting effect on the corrodant, particularly at the crack tip.
This is significant, especially l'
.the. cracks'with~1ess than 40% thruwall indica-
.since the'Lienesee has not stated the length of
-tions which both Licensee and NRC Staff have L
concluded need not be removed from service."
l: fI
Ne note.in passing!that since crack growth occurs only at the' crack tip (by definition), the statement'"particularly.-at the crack tip" is without meaning.
More to the point, the
~
Joint Intervenors proposed contention claiming that understand-ing of the-lithium interaction was not adequate was struck down by the Board in its order of November 29, 1983.
TMIA's as-
~
corted basis is therefore outside the scope of the. admitted
-contentions,~and-inadmissibl'e here.
TMIA's attempt to lend significance to its allegation by stating "the Licensee has not otated the length of the cracks with.less than 40% thruwall in-
- dication...
which...need not be removed from service" is also to-no avail. - The Board ruled on January 9, 1984 that the TMIA's. contention on plugging the 40% through wall cracks was
-without basis, and' dismissed this allegation.
The: alleged inconsistencies raise no genuine issue as to
~
cny material' fact on which a hearing should be held.
Summary disposition of Contention 2.c in Licensee's favor should there-
-fore be granted.
I.
JOINT'INTERVENORS' CONTENTION 1(3)-
Joint Intervenors' Contention 1(3) reads as-follows:
1.
There is no-assurance that the steam gener-ator tube repair program can. assure the in-tegrity of the tubes and their joints under the environmental conditions attendant to operation.
TMI-1 shall not be permitted to restart before such assurance is provided.
The following elements of the repair pro-gram are deficient:
4 (3). Morphological changes in the inner tube surface, remote from.the expanded joints could reasonably be' presumed to be-precursers of IGSCC.
. Joint Intervenors have indicated that the " morphological changes" with which they are concerned are " islands" of
~intergranular attack (IGA) in the freespan.
J.I.
lat Resp., to
- Interrog.~1(3)-2.
The fact that IGA islands were sometimes found in association with intergranular stress assisted cracks Euggests to Joint Intervenors that IGA is a " precursor" of
~
~IGSAC, apparently meaning that IGA on the freespan might propa-
. ste into IGSAC.
No support for this theory was presented in g
Joint Intervenors' responses to Licensee's and the Staff's in-terrogatories.
' IGA is a corrosion phenomenon which, like IGSAC, requires
.cn aggressive environment and susceptible material.
(The dif-farence between-the two phenomena is that IGA formation does not require an applied stress.)
Giacobbe Affidavit, 1 132.
l The required presence of.a corrodant was confirmed by metallur-gical--samples showing that the majority of the IGA on the TMI-l
[
LOTSGs was'(1) in the upper tube sheet area, and (2) associated l
l
-with cracks.
It'is precisely in these areas where the concen-E
,tration and aggressiveness.of the corrodant was highest.
L
.As Mr.~ Giacobbe explains.in detail in his affidavit
~
'(1l133), IGA'cannot be considered a precursor of IGSAC because (1) IGA'can occur without IGSAC; (2) IGSAC can occur without !
l l^
IGA; or (3) IGA.and IGSAC can exist in tandem.
All three pat-
- terns _were found on the TMI-1 tubes.
Moreover, IGA has not ad-versely affected the mechanical properties of the metal.
It therefore is not more susceptible to IGSAC than other material
'in the' absence of a corrodant.
Although IGA is not strictly a precursor of IGSAC, IGA could still propagate.into IGSAC under appropriate conditions.
Significantly, however, this~would. occur.only if an appropriate corrodant were present in sufficient quantities, and stress werecapplied.
Because Licensee has taken adequate measures to ensure that corrosive levels of. contaminants will not be present, IGA will not propagate into IGSAC.
For the same reason, new IGA
~ islands will not-be initiated either.
Thus, there is no genuine issue of material fact to be heard with respect-to the statement of facts set out in Section
-]n7 b'e l o w, as supported by.the Giacobbe Affidavit, 11 131-149.
Contention 1(3) must therefore.be dismissed.
i i
~
IV.
LICENSEE'S STATEMENT OF MATERIAL FACTS AS TO WHICH THERE IS NO GENUT"5: ISSUE
- c..
L TO BE HEARD t
Pursuant to lO C.F.R.-f 2.749(a), and in support of Li-
'esnsee's motion for summary disposition of each of TMIA's and Joint Intervenors' contentions, Licensee states that there is D
no genuine issue Lto l>e heard with respect to the following ma-tarial facts:
i-i l L
~ -,. -
A.
TMIA'S CONTENTION 1.a TMIA's Contention 1.a alleges that " post repair and plant p;rformance testing and analysis" and " proposed license condi-
'cions" are inadequate to provide sufficient assurance that tube ruptures will be prevented during certain operating conditions cnd transients.
1.
Steam Generator Description 1.
Unit 1 of the Three Mile Island Nuclear Station is a 776 MWe pressurized water reactor having two vertical, straight tube and shell, once-through steam generators (OTSGs).
Each OTSG contains 15,531 Inconel 600 tubes, with a 0.625-inch outer diameter, and a 0.034-inch minimum wall thickness.
Slear Affi-dnvit,.1 4.
2.
Each tube is 56 feet and 2 3/8 inches in length.
The cnds are inserted into holes drilled in two 24-inch thick car-ban steel tubesheets at the top and the bottom of the OTSG.
The tube'is fully inserted, and protrudes about 1/2 inch beyond the upper _ face of the Inconel clad upper tubesheet and the lower face of the lower tubesheet, into the primary head at orch end of the OTSG.
Slear Affidavit, 1 5.
3.
There is a nominal 0.005-inch radial gap between the outer surface of the tube and the surface of the tubesheet hole.
The tubes are sealed at each end to the tubesheet by rolling to a depth of about 1 1/4 inches, and welding on the primary side of the tubesheet surface.
Slear Affidavit,
- 6.,
4.
Primary coolant (at a pressure of about 2200 psig) flows within the tubes, and secondary system water and steam (ct a pressure of about 950 psig) are heated outside the tubes; thus the tubes, including the seal at each end, constitute part of the reactor coolant pressure boundary between the primary cnd secondary systems.
Slear Affidavit, 1 6.
2.
Kinetic Expansion Repair 5.
In November 1981, primary-to-secondary leakage was discovered during testing of the reactor coolant system.
De-toiled examination by eddy current testing (ECT) revealed de-fcets in the tube walls of which 95 percent occurred within the top 7 inches of the upper tubesheet based on the initial ECT cxamination results.
Slear Affidavit, 1 7.
6.
The tubes were repaired by expanding them within the upper tubesheet to provide a new seal to the tubesheet at a lo-cction below where the defects were detected.
Slear Affidavit, 1 8.
7.
The kinetic process expansion closed the nominal 0.005-inch gap between the tubes and the tubesheet by
-datonating an explosive cord in a polyethelene insert that transmitted explosive energy to the tube wall therein creating cn interference; pressure between the tube and tubesheet.
Slear Affidavit, 1 8.
?
8.
The use of kinetic expansions to seal heat exchanger tubes within tubesheets has a broad base of successful.
cxperience in heat exchangers such as steam generators.
Slear Affidavit, 1 8.
-9.
The tubes were expanded from the top of the upper tubesheet down either 17 inches or 22 inches, depending on the olevation of the lowest ECT indication within the upper tubesheet.
.The expansion length was selected for each tube to provide at least a six-inch ECT indication-free expanded length bstween the lowest elevation,ECT indication and the bottom of the. expansion to serve as the new pressure boundary.
To accom-plish this, tubes having the lowest ECT indication within the uppermost 11-inches of the tubesheet received-a 17-inch expan-sion, and tubes with the lowest ECT indication within the up-parmost 16 inches received a 22-inch expansion.
This also re-gulted in a minimum of two inches between the expanded /non
-cxpanded transition zone of the tube and the lower face of the tubesheet. 'As a result of standardizing the expansion length,
'i. e., the 17-and 22-inch lengths, many tubes have an ECT indication-free expanded length greater than six inches.
Slear Affidavit,.1 9.
10.
The expansion length was also selected such that there were no ECT indications in the 1/8" to 1/4" transition zone between the expanded and non-expanded portions of the tube.
Slear Affidavit, 1 10.
11.
The repair program at TMI-1 was in accord with the Technical Specifications of the operating license for TMI-1, which,'in accordance with the licensing basis for the OTSG
. tubes, require that' tubes with imperfections equal to or
-greater:than.40 percent of the tube wall thickness be taken out of service by plugging.
If a kinetically repaired tube has a o40 percent or greater through-wall ECT defect indication within the-pressure boundary, that tube is removed from service by_
plugging.-
Thus, the tubes will be in compliance with the OTSG industry standard 40 percent plugging criteria.
Slear Affida-vit, 1 11.
3.
Licensing Basis
.12.
The licensing basis for both the original, unrepaired tubes and for the-kinetic expansion joint is as specified in
- General _ Design Criterion 14, 10 C.F.R. Part 50, Appendix A, i.e.,
"to have an extremely low probability of abnormal leak-age, of rapidly propagating failure, and of gross rupture."
Slear Affidavit, 1 12.
13.
With regard to loads that must be sustained by the kinetic expansion joint, the maximum tube load resulting from dasign basis events for both the original unrepaired tubes and the repaired' tubes is 3140 pounds (for a main steam line break accident) and is applied due to axial tension within the tube l
l balow the expansion joint.
This load is due mainly from tube /
cteam generator axial differential thermal expansion when the J ubes are cooled to a lower temperature than the cylindrical t
- chell of the steam generator.
Slear Affidavit, 11 13, 16, 53.
l l t b
14.
The Technical Specifications for TMI-1 require shut-
'down if the total leakage (including leakage past the kinetic expansion joint) for both steam generators exceeds 1 gpm.
In cddition, the NRC's proposed license conditions for restart with repaired tubes require shutdown for inspection if a leak-cge' increase exceeding 0.1 gpm above a pre-established baseline is detected.
Slear Affidavit, 1 14.
4.
Qualification Program 15.
An extensive testing program was conducted to qualify the kinetically expanded joint to the licensing basis.
The qualification program has demonstrated that the expansion joint maets tie licensing basis, and is at least as effective as the original rolled and welded joint in all relevant respects, including axial loads from the worst case design basis op-erating and. accident conditions, tube preload considerations,
.rasidual stresses in the transition zone.
Slear Affidavit, 1 15.
(a) -Axial Loads r
16.
The expansion joint is required to sustain the maxi-
. mum postulated loads from a design basis accident, which is an i
cxial tensile load of 3140 lbs. resulting from a main steam line break.
Slear Affidavit,- 1 16.
[
~ 17.
Tests were performed on simulated tube / tube sheet configurations to determine the axial load carrying capabili-ties of the expansion joints.
The tests involved pulling i !
~
kinetically expanded' tubes out of simulated tubesheets and m;asuring the " pullout load" required to initiate slippage be-tween the tube and the simulated tube sheet.
The test blocks wsre thermally cycled to envelop the thermal conditions expect-cd to be experienced by a steam generator in operation.
In ad-dition, some tubes were rubjected to a series of compression /
ttnsion load cycles which enveloped expected reactor operating conditions.
All data from the pullout tests indicated that the expanded tubes will have pullout loads significantly in excess of the 3140 lb. axial load-requirement (with statistical sup-port in excess of a 99% confidence level on 99% of the tubes).
-Pullout loads in excess of the requirement were also confirmed on an expansion pull test performed on a full scale generator at B&W's Mt. Vernon Works.
These tests demonstrated that the kinetic expansion process did not adversely affect the strength and dimension of the tubes with respect to their axial load carrying capabilities.
Slear Affidavit, 1 16.
(b)
Residual Stresses 18.
The kinetic expansion process does not change the etrength or dimension of the tubes in any manner which would adversely affect the stress levels seen by the tubes.
This has baen verified by the' qualification program which demonstrated j
that the residual stresses and the resistance to stress as-sisted cracking in the transition zone are consistent with the origir al design of the steam generators, and concurred in by
+
-the' Third Party-Review Group (TPR).at page 15 of the TPR Re-port.
Slear Affidavit, 11 17, 24.
- 19. "The only effect of. potential significance in strength
. or dimension-with respect to residual stresses is the formation of the' transition zone.directly beneath the expansion.
To min-t
- imize the susceptibility of the transition zone to stress as-sisted cracking, the repair process was designed to minimize
^
the residual stresses in that area.
Analysis indicated that Ethe more abrupt th'e. transition, the larger the stress concen-trations.
.Thus, a' number of explosive insert shapes were eval-uated, and'the geometry which provided the most gradual transi-tion was used to expand the. tubes.
This resulted in meeting
.-the design objective'of creating a-transition zone between 1/8"
~
and-1/4" in length.
This is a more gradual transition zone than-the' original rolled joint employed in TMI-1 and other op-orating reactors.
Slear Affidavit, 1 18.
- 20. -The qualification-program has shown that the suscep-
-.tibility of the kinetic expansion transition zone to stress as-
- sisted cracking is-about.the same or-less than the 4
suceptibility of the-transition zones for non-stress relieved
-rolled expansions which have operated without cracking or leaking problems after many years of service in once-through
- oteam' generators and in recirculating steam generators.
Slear
' Affidavit, 1 19.
L
-21.
The residual stress for kinetically expanded tubes wasimeasured in special test blocks using X-ray diffraction and strain gage techniqpes.
The measured stress intensities were about equivalent to those generally reported in the literature for rolled expansion transition zones.
Slear Affidavit, 1 20.
22.
In addition, sample Inconel 600 tubes were expanded.
l by rolling and kinetic processes in order to compare the re-gulting hardness and microstructure.
The hardening effect on both-the inner and outer surfaces of mechanically expanded tubes-is more pronounced than in the kinetically expanded tube.
Thus,.since hardness.is an indication of the amount of cold swork.of the. tube material, and since cold work tends to make the material more prone to stress. assisted corrosion cracking, the kinetic' expansion may be expected to be less susceptible to
- stress assisted corrosion cracking than the mechanical expan-cion..
Slear Affidavit, 5 21.
23-
-Two corrosion testing programs were conducted to Gvaluate the susceptibility of the' transition zone to stress
.nasisted cracking.
In the first program,' accelerated stress corrosion cracking tests were performed on kinetically expanded j
tube /tubesheet mockups.
The mockups were tested in an aggres-sive 10% sodium hydroxide (NaOH) solution at constant potential
^cnd destructively examined for stress assisted cracking due to t
L.
rssidual stressesLfrom the repair expansion process.
Test re-cults showed no' evidence of any significant cracking of the ID t
t L-
curface in.the kinetic expansion joint or transition.
Slear Affidavit, 1 22.
24.
The second test was conducted using a boric acid so-lution containing 1 ppm of thiosulfate and 1 ppm chloride.
This level of thiosulfate was utilized because it was shown to produce cracking in highly stressed specimens of actual TMI-l tube samples.
It was therefore felt that if the residual stresses were sufficiently high, that cracking could be expect-ad in this environment.
The chlorides were added to provide an cdditional accelerating effect.
Tests were conducted at 170*F cnd 550*F.
Testing was conducted on ten single tube /tubesheet mockups that had been kinetically expanded.
These tests have shown no evidence of stress assisted cracking of the ID surface in-the expanded region or in other regions either at 170 F or at 550*F.
Slear Affidavit, 1 23.
(c)
Tube Preload 25.
During the manufacture of the OTSGs, the tubes were stretched slightly so that they would be under a small axial ttnsile load of about 65-lbs. with the OTSG at ambient tempera-ture.
Although the 65-lb. load (preload) is small in compari-con with other operating tube loads, the qualification program svaluated the effect of axial tension preload of the tubes, and changes in the preload.
Strain measurements on expanded tubes in laboratory test blocks and in the B&W full scale steam gen-crator indicated a reduction in the preload of less than
30-pounds due to the change in length of the tubing.
This would result in a less than 30-pound increase in the maximum ccmpressive load which could be experienced by the steam gener-ctor under design basis conditions (heatup to operating temper-ctures), an insignificant increase comparef to the 800 pounds necessary to initiate bowing and the 1025 pounds necessary for lateral tube displacement to contact adjacent tubes (for nomi-nni dimensions).
Slear Affidavit, V 25.
26.
In some cases, the degradation of the tube in the crea of the seal weld prior to expansion allowed the tube to clip down, relieving all or part of the preload in a manner unrelated to tube dimensions.
Slear Affidavit, 1 26.
27.
These tubes have been evaluated to determine the po-t ntial effects of relief of preload, and it was determined that the relief of preload experienced on some of the tubes at TMI-1 does not present a safety consideration and has no sig-nificant effect on the acceptability of these tubes for contin-und use within the licensing basis.
Slear Affidavit, 11 26, 31.
28.
The effects of relieving preload with respect to the limiting transient and accident loads on the tubes were exam-ined.
Slear Affidavit, 1 27.
29.
The maximum compressive tube load under ESAR accident conditions is a 620-lb. load associated with a postulated feedwater line break accident.
This is less than the
- t
cpproximately 775 lb. generic design basis compressive load censervatively associated with a 100 F/hr. heat-up, which in the limiting case (actual heatups are conducted at rates below 100'F/hr).
Loss of preload would add 65-lbs. to the 775-lb.
ccmpressive load.
Thus, for a tube with no preload, 840-lbs.
io the conservative maximum compressive load postulated for normal, transient, or accident design basis conditions.
Slear Affidavit, 1 27.
30.
For added conservatism, an evaluation was performed of the ability of a tube to withstand 1025-lbs. of compressive load.
The analysis showed that a non-preloaded tube will not ba overstressed by the transient load conditions.
Buckling does not occur under a 1025-lb. compressive load.
Tube bowing in limited by the small clearances of the tube support plate holes.
Further, the applied load is secondary in nature; it is
-ccused by thermal differential expansion.
This means that as the tube begins to bow under the loading, the magnitude of the load is reduced.
Slear Affidavit, 11 27, 28.
31.
The Licensee also examined the magnitude of lateral displacement (bowing) to be expected in a tube loaded com-pressively to 1025-lbs.
Slear Affidavit, 1 29.
32.
The magnitude of the lateral displacement in the 16th cpan of the tube (underneath the upper tubesheet) will be the lcrgest since that span is longest.
Slear Affidavit, 1 29. u.
33.
Lateral displacement nominally less than the dimen-cions of the gap between tubes, even under transient condi-tions, is expected as a result of the loss of preload.
Howev-or, even if tubes were to contact each other, no problem is expected.
During a heatup transient, flow rates are very low cnd the tima duration is relatively short; no significant tube vibration or wear would be expected during this short period of
- time.
Slear Affidavit, 1 29.
34.
The effects of the change in prelon.d on the natural vibration frequency of a tube were also considered.
A non-preloaded tube is expected to have a natural frequency cbout 15% lower than one preloaded.
The offect of this fre-quency reduction is not significant.
The Electric Power Re-csarch Institute (EPRI) has reported that other operating plant steam' generators have variations in tube frequencies of as much-es about 10 to 20% within a single steam generator.
In addi-tion,. test data reported by EPRI show that another plant op-orating with similar OTSGs has tube frequencies about 15% lower
'than expected for TMI-1.
Slear Affidavit, 1 30.
(d)
Expansion Joint Leakage 35.
The original design _ basis for steam generator tube leakage was to provide generators with no detectable leaks at chipment and to control leakage to an acceptable operating icvel by monitoring and repair over the 40-year life of the
_ plant; this basis has not been compromised by the kinetic Cxpansion repair.
Slear Affidavit, 11 32, 33.
3 6. - Leak rate.results of testing on the cycled test
-6
-6 blocks varied from 1.18 x 10 to 187 x 10 lb./hr./
Ltube.
If every tube in both steam generators leaked at the mr.ximum rate, the cumulative leak rate would be about one one-hundredth of the Technical Specification limit of 1.0 gpm.
Slear Affidavit, T 33.
(e)
Other Considerations 37.
In addition to verification by testing that the ki-natic expansion joints fully meet the original licensing basis rsquirements, there are other features of the kinetic expansion r; pair joint which provide added assurance of integrity.
The more important;of these are summarized below.
(i)
Although credit is taken only for a six-inch 1sngth of kinetic expansion, the expansions are actually either 17 or 22 inches in length.
This provides substantial addition-al load carrying capability, even though there may be defects in the tube above the six inches which formed the qualification basis for the expansion joint.
(ii)
Even if the kinetic expansion joint were to
-alip for a substantial number of tubes during a main steam line
(
break, there would be no significant effect of concern since the-joint would still be tight and no significant increase in f
-lcakage.would result.
(iii)
Even if a failure could be postulated within the expansion joint or the transition length below the joint, a l I
" tube 1 rupture" Etype of event (large leakage) could not occur bbcause the tube would still be constrained by its hole in the upper tube sheet and flow would be limited by the tube-to-tubesheet annulus.
Slear Affidavit, 1 34.
5.
In-Process Repair Testing 38.
An inspection and monitoring program was conducted during the repair process to verify that the in-generator ex-psnsions conformed to those obtained in the qualification pro-gram.
The program consisted of video surveillance within the OTSG upper head and measurements of the tube inner diameters by profilometry and by diameter gauging on a sampling basis.
Slear Affidavit, 1 35.
39.
Video surveillance of operations during the expansion process were conducted to verify that proper procedures were followed and that the correct tubes were expanded or examined.
Slear Affidavit, 1 36.
40.
Random out-of-generator expansions were also con-ducted to verify that the performance of the explosive inserts htd not changed since the qualification program.
Slear Affida-vit, 1 36.
41.
Profilometry verification sampling was performed on l
the tubes expanded in the first three lots in each OTSG.
In Eddition, random post. expansion diameter gauging and depth check samplings were performed.
Slear Affidavit, 1 37.. - - -
L 42.
The out-of-generator expansions indicated that the process expansion inserts and detonating materials performed as wc11 as those used in the. qualification program.
Slear Affida-
.vit,;1 38.
43.
Profilometry-and diameter and depth gauge checks
- chowe'd that the in-generator expansions were within the range of variation of the qualification program expansions.
Slear Affidavit, 1 38.
6.
Post-Repair and Plant Performance Testing and Analysis 44.
Post-repair and plant performance testing and analy-sis provide additional assurance of the integrity of the re-pair. _As discussed below, the objectives of the post-repair and plant performance testing have all been accomplished.
Slear Affidavit, 1 40.
45.
Post-repair and plant performance steam generator
-tssting and analysis of the kinetically repaired tube joints hLve included both a cold and a hot testing program.
Slear Af-i-
~fidavit;.1 41.
46.
The cold leak testing program consisted of bubble y
tssting 100% of the expansion joints to determine if further rapair or plugging was necessary.
In this test, the primary
. aide is drained to a few inches above the upper tubesheet, and
'escondaryLside water level is lowered and pressurized to 150 paig with an inert gas below the. upper tubesheet.
Kinetic tube I l-
cxpansions and tubing above the lowered water level are leak tssted by visually checking for gas bubbles in the upper head.
This is a highly sensitive standard test used in OTSGs to lo-ccte leaking tubes and welds in the region within and near the upper tubesheet.
Slear Affidavit, 1 42.
47.
In two successive 100% bubble tests, a total of only 26 leaking tubes were found in both steam generators.
None of these leaks were determined to be in -expansion joints, although four of the leaks were so small that their precise location was not determined.
Slear Affidavit, 1 43.
48.
The hot testing program included overall integrated leak tests of the steam generators conducted under hot standby conditions and during heatup and cooldown.
These tests also cpplied axial loads on the kinetic expansion joints.
Slear Af-fidavit, 1'44.
49.
A Kr-85 tracer was injected into the primary system to provide a measurable indication of leakage on a continuous bnsis..The tracer was' injected during the initial heatup to 532*F and 2155 psig in accordance with normal operating proce-dure.
Leak testing was then conducted continuously during the following phases:
L (a)
Operational Leak Test.
This test is re-quired by Technical Specifications whenever work has been per-formed on the reactor coolant system.
The pressure in the pri-mary system was raised to approximately 2285 psig, creating a,
differential pressure between the primary and secondary of ap-proximately 1400 psig.
This is expected to be the maximum dif-forential pressure experienced by the repaired tube joints dur-ing normal operation.
(b)
First Thermal Soak.
Conditions were al-lowed to stabilize at 532*F and 2155 psig for approximately ons w ek, to provide baseline leakage data and to allow monitoring of leakage for trends.
(c)
Normal Cooldown Transient.
A controlled cooldown was conducted according to normal procedure, at ap-proximately 60*F/hr. for approximately three hours to 350*F.
A tube-to-shell temperature difference of about 35*F placed ther-mn1 loads.on the tubes.
(d)
Second Thermal Soak.
The reactor coolant cystem (RCS) temperature and pressure was returned to 532*F and 2155 psig and held there for 11 days.
Leakage data was ob-tcined for comparison with the earlier thermal soak, and to m:nitor for any developing trends.
(e)
Accelerated Cooldown.
A controlled cooldown was conducted at.close to the maximum rate permitted by Technical Specifications, at approximately 90*F/hr. for ap-proximately two hours.
This transient was to apply graater
~
loads to the repaired tubes than the earlier cooldown.
A tube-tc-shell temperature difference of about 47 F was achieved.. -.
(f)
Third' Thermal Soak.
The RCS temperature end pressure.was returned to 532*F and 2155 psig, and held there for approximately 11 days.
Leakage data was obtained for c;mparison with the earlier thermal soaks, and to monitor for
-trending.
'(g)
Third Cooldown..During this cooldown, at
. cbout 90*F/hr., additional steps were taken to achieve a tube-to-shell. temperature difference of about-99'F in the "B" OTSG cndill2*F'in the "A" OTSG.
This transient applied greater tube loads than expected during a cooldown conducted according to
-normal operating procedures.
Slear~ Affidavit, 1 45.
50.
The hot testing indicated an integrated leak rate for both steam generators of only 1 to 2-gph.
Technical Specifica-tion limits allow up to 1 gpm (60 gph) for such leakage.
Slear Affidavit, 1.46.
7.
License Conditions 51.
In addition 1to the qualification: program, the i
in-process repair testing, and the post-repair testing and i
~,cnalyses, which demonstrate the adequacy of the kinetic expan-sion repair joint, the NRC will impose special license condi-
-tionsfre' quiring additional surveillance and testing during op-eration. 'These special license' conditions provide added s'
~
ogsurance against the possibility of tube rupture.
Specifical-ly, if any significant degradaticn of the kinetic expansion
. joints were:beginning to occur,during plant operation, leakage would increase and the steam generator (and plant) shut down, tested and repaired, if necessary.
Slear Affidavit, 1 47.
52.
Shutdown for inspection will be required if a leakage increase of only 0.1 gpm is detected.
This value is only 0.1 of the Technical Specifications limit for normal plant op-oration.
Slear Affidavit, 1 48.
53.
The plant will be required to be shut down after a chort period of operation for performance of a special eddy current test (ECT) program.
This testing will be performed 90 calendar days after reaching full power or 120 calendar days efter exceeding-50 percent power operation, whichever comes first.
The special ECT provides additional assurance that deg-redation of the kinetic expansion joint is not occurring and going undetected.
Slear Affidavit, 1 49.
54.
Licensee will be required to perform its power ascen-cion program at staged intervals, with continuous leak testing End intervals for evaluation of the leakage trends after each
'otage.
Slear Affidavit, 1 50.
55.
Licensee will also be required to report at frequent intervals on its on-going long term corrosion lead testing pro-gram.
These tests involve corrosion tests of actual TMI-1 tube ocmples, with specimens representative of both the expanded and unexpanded regions, including the transition zones.
The tests cre under_ simulated operating conditions, including water chem-l istry, and will encompass tube load and thermal cycling
.cffects..These tests will. lead operation of the plant by at loast_one year.
Slear Affidavit, 1 51.
8.
Tube Ruptures 15 6.. The qualification program, together with the
~
in-process repair testing, has demonstrated that the repaired tubes are in conformance with the original licensing basis.
-Slear~ Affidavit, 1 52.
57.
Meeting the design basis provides the same reasonable cssurance that tube ruptures will not occur during any postu-lcted operating transients, including those associated with rastart, turbine trip at maximum power, thermal shock from in-cdvertent actuation of emergency feedwater at high power, and r pid cooldown following a loss-of-coolant accident (LOCA), and
~
Edditional assurance'is provided by the post-repair and plant parformance testing.
Slear Affidavit, 1 52.
58.
The loads on the steam generator tubes have been svaluated for normal operating transients and design basis ac-cidents.
The worst case situation is the main steam line break (MSLB)-which is conservatively analyzed to result in an axial tznsion load of 3140 lbs. on the expansion joint.
All of the loads experienced by the expansion joint during restart, including those resulting from heatup, cooldown, power eccalation, and planned transients during power escalation, are cwall below the MSLB loads to which the repaired tubes have been qualified.
Slear Affidavit, 1 53.
h w
FN m=
y WF.
+1 ye w
-v
&=7-Te7-'T-N
59.
The repaired tubes have already experienced, without loss.of integrity, loads intentionally imposed during post-repair hot testing equal to or greater than those that will be experienced during restart.
Slear Affidavit, 5 54.
i 60.
The loads-which would be experienced by the repaired tubes during turbine trip at maximum power, thermal e5.ock from inadvertent actuation of emergency feedwater at high power, and rapid cooldown following a LOCA are all bounded by, and consid-orably less than, the MSLB loads.
Slear Affidavit, 1 55.
61.
A turbine trip at maximum power will result in an au-tomatic reactor trip, and the plant will be stabilized at reac-tor coolant conditions which are comparable to " hot standby" conditions (RCS temperature at or above 532 F).
This results in less tube load than for a design basis cooldown transient.
Thus, significant changes in the OTSG shell to tube temperature difference and primary and secondary pressures from the power operating conditions are not produced as a result of a turbine trip.
Slear Affidavit, 1 56.
62.
Inadvertent actuation of emergency feedwater (EFW) at high power, i.e.,
a failure that results in starting of the EFW pumps while the plant is operating normally at high power, will not result in the injection of EFW into the steam generators.
Slear' Affidavit, T 57.
63.
The design of the TMI-l EFW system is such that once the EFW pumpn are initiated, the actual flow to the OTSG's is
controlled by valves which respond to a-flow demand signal gen-orated by.the OTSG level control. system.
The water level in the OTSG at high power levels is much higher than the OTSG EFW level-setpoint at which the EFW flow control valves are initi-nted to open..The'EFW pumps are initiated by signals other than and-independent of the OTSG level.
Therefore, inadvertant actuation of the EFW pumps will not result in EFW injection into the OTSG and will not result in any change to the OTSG tube stresses.
Slear Affidavit,.1 57.
64.
Even if EFW injection into the OTSG were to occur, the resulting thermal stresses would-not result in stresses cufficient to cause rupture of the repaired tubes.
Slear Affi-davit, 1'58.
65.
The location of any thermal shock stress condition, edue to impingement of' cold water that could occur on a tube that was repaired, would be remote from the repaired portion of the tube (about.two feet or greater), and the direct thermal chock' stress effects would affect only a portion of the tube.
Slear Affidavit, 1 58.
- 66..The only effect would be a slight decrease in the av-erage tube temperature.. Consequently, only a slight change in tube load would occur, far.less than the qualification loads.
Slear Affidavit, 1 58.
67.
Rapid cooldown following a LOCA will not result in
.ctresses sufficient to cause a rupture of the repaired tubes.
T The maximum tube load for a LOCA, including the effects of sub-cequent rapid cooldown, is 2641 pounds.
This is well below the 3140-lb. load'for which the repaired tubes have been qualified in(~ testing for-the main steam'line break condition.
Slear Af-fidavit, 1 59.
B.
TMIA'S CONTENTION 1.b TMIA's Contention 1.b alleges that because the tubes have undergone the repair process, the possibility of a simultaneous
' tube rupture in each steam generator should be considered.
68.
The kinetically expanded joints, including the ef-fcets of expansion on.the tubes, have been demonstrated to i
fully meet the original licensing basis.
Slear Affidavit, 1 60.
69.
The kinetic expansion joint is well inside the tubesheet where the tight constraints preclude tube rupture and rupture-magnitude leakage.
Slear Affidavit, 1 61.
70.
Added assurance against-the potential for tube rup-ture is provided by the in-process repair testing, the post-rcpair and plant performance testing and analyses, and the ad-ditional special license conditions.
Slear Affidavit, 1 61.
71.
Therefore, the kinetic expansion repair process will not increase the likelihood of a simultaneous tube rupture in occh steam generator, and thus will not increase the attendant likelihood of requiring the operator to accomplish cooldown and d; pressurization using at least one faulted steam generator, m
-~
d t
the likelihood of the occurrence of a sequence of events not cncompassed byLthe TMI-1 emergency procedures, or the like:.1-hood _of the occurrence of a scenario during the course of a DOCA which would create essentially uncoolable conditions.
l Slear Affidavit, 1 61.
C.
TMIA'S CONTENTION 1.c LTMIA's contention 1.c' alleges that the kinetic expansion repair weakened the tubes such that the plugs will not be able to hold and give a good seal.
72.
Three types of plugs have been used in the upper
-tubesheet-area following kinetic expansion.
The first type, a
.Wastinghouse roll plug, is a hollow, cylindrical plug which is inserted in the tube and expanded against the existing tube Lwall.
Elam Affidavit, 1 4.
73.
The expansion contact occurs in.the region of the original tube-to-tubesheet mechanical roll and is produced by mschanically rolling the plug to achieve an interference fit with-the tube.
Elam Affidavit, 1 4.
74.
The roll plug design.had been.previously qualified
-by Westinghouse for use in operating PWR steam generators.
The qualification' program was. supplemented by a specific test pro-
. gram for. application to the TMI-1 steam generators, which spe-
=- c cifically qualified the plugs for leakage and plug retention l
- capability for both normal operating and accident conditions.
Elam Affidavit, 1 5.,
m:....
1:
75.
The kinetic expansion repair process did not in any way " weaken" the tubes or otherwise adversely affect the reten-tion capability or leak tightness of the fully qualified roll plugs.
Elam Affidavit, 1 6.
76.
Following the kinetic expansion, many of the tube cnds extending above the top of the tubesheet and the seal welds, where most of the cracking had occurred, were damaged.
However, for roll plugs, qualification is based on engagement of the original rolled portion of the tube below the seal weld, end no reliance is placed on engagement of the tube ends above
.the seal _ weld.
Furthermore, prior to plugging, the tube ends
-were machined off to the' top of the seal weld.
Elam Affidavit, 1 6.
77.
The only portion of the tube of relevance to plug-ging integrity is the originally rolled portion against which the plug is rolled.
Elam Affidavit, 1 7.
78.
The effect of the kinetic expansion on this portion of the tube was to press the already rolled tube harder against the tube sheet.
This would not " weaken" the tube or adversely effect_the plug retention or leak tightness capability of the ongaged_~ portion of the_ tube.
Elam Affidavit, 7.
79.
During the plug qualification program, a test was performed to determine the effect of kinetic expansion on the tube internal diameter as it relates to plug performance.
The cverage difference between pre-and post-kinetic expansion !
L
measurement was less than.00034 inch, which is approximately 10% of the actual diameter variation modeled in the overall qualification program.
Elam Affidavit, 1 8.
80.
Most of the cracking stopped just below the seal weld before the rolled portion of the tubes began, and hence would not be in the area engaged by the plug.
Elam Affidavit, 19.
81.
Some cracks were also found at a lower elevation, within the tube rolled region.
These cracks were circumferen-tial and of a tight nature, with no evidence of intergranular
" branching," i.e.,-the cracks represented single fracture sur-fcces.
Elam Affidavit, 1 9.
82.
There was no general condition of IGSAC identified in the rolled region.
Elam Affidavit, 1 9.
83.
The existence of circumferential cracks in the plug cngagement region of the tube has a negligible effect on plug parformance.
Plug retention capability is proportional to the host area engaged, irrespective of discontinuities, since the plug engages the tube both above and below the crack.
The l
clight decrease in surface area due to the surface area of the crack is insignificant compared to the engagement area.
This
.wns confirmed in.the qualification test programs which included a test specimen with a 360 through-wall circumferential cut in the tube wall.
Elam Affidavit, 1 10.
84.
Leak tightness of the installed plugs installed in 1Gaking tubes was' demonstrated by extensive cold and hot post
-8s-
~
'l rcpair leak testing programs which demonstrated that the kinet-ic expansion repair did not weaken the tubes, and had no ad-varse affect on the capability of the roll plugs to hold and give a good seal.
Elam Affidavit, 11 11, 12.
85.
The other two types of plugs installed in the kinet-ically expanded tubes are B&W weld plugs.
Elam Affidavit, 1 13.
86.
The ~ welded nail head plug i-s designed to be welded to the original tube-to-tubesheet seal weld, after removal of the drmaged tube end by machining.
Elam Affidavit, 1 13.
87.
The welded taper plug is welded to the tube sheet cladding at locations where a portion of the tube has been re-moved for examination or testing.
Elam Affidavit, 1 13.
88.
Since neither is bonded to the tube itself, the con-dition of the expanded tube is irrelevant to the performance of
'the plugs.
Elam Affidavit, 1 13.
89.
Neither the seal weld nor the tube sheet cladding was effected by the kinetic expansion process.
Elam Affidavit, 1 14.
90.
The kinetic expansion forces are far below those nec-
..cssary to disturb either the seal weld or the tubesheet cladding.
Elam Affidavit, 1 14.
91.
No evidence of seal weld or cladding damage was found during post-expansion strain gauge testing, post-installation p
QA weld inspections, or the subsequent hot and cold leak test i
programs.
Elam Affidavit, 1 14. 1..
c-W J.
' - 92.
Accordingly, the capability of the weld plugs to hold cnd give a good seal is unaffected by-the kinetic expansion re-pair...Elam Affidavit,. 1 15.
- 93. -TMIA has not demonstrated that the kinetic expansion rspair weakened.the tubes such that the-plugs will not be able to hold and give a good seal.
TMIA 4th Resp. to Interrog.
' I I-1. c - L 94.
TMIA has not demonstrated that the plugged tubes will interfere with the plant's ability to respond to transients and
-cccidents as a result of the kinetic expansion repair process.
TMIA 1stfResp' to Interrog.
l.c-6.
~ D.
TMIA'S CONTENTION 1.d TMIA's Contention 1.d alleges that neither the TPR Report nor the'SER is a credible document in its evaluation of the ki-natic' expansion repair technique, including leak tightness and
^1oad carrying capabilities, because of the reports' inherent inconsistencies,.because of improper reliance on axial symetric
.at'ress analysis, because of the failure to. analyze crack resis-tence on the basis of toughness as opposed to hardness, and be-cause~of the failure to differentiate between the effects of thermal stress on small versus large cracks.
- 95..-Many of the tubes located in Licensee's OTSG's have cu'ffered some degreeLof'circumferential cracking representative Jof1IGSAC.
Leshnoff Affidavit, 13....
96.
Licensee has performed many tests and evaluations em-
' ploying various analyses to document the various properties of
-the cracks present in the OTSG tubes. Leshnoff Affidavit, V 4.
97.
The analyses for crack resistance, i.e.,
for the me-chanical propagation.of fatigue cracks in the tubes, were not a part'of, and are unrelated-to, the evaluation of the kinetic cxpansion repair technique.
Leshnoff Affidavit, 1 4.
98.
Axial symmetric (i.'e.,
axisymmetric) analyses were not utilized when evaluating crack propagation because cracks are not assumed to propagate in an axisymmetic manner.
The use of axial symmetry in stress analyses means that the stresses on the tubes, not the crack propagation, are axisymmetric.
Lashnoff Affidavit, 1 5.
99..
Axisymmetric analyses were only used in one structur-al evaluation of the tubes.
This evaluation was to compute the stress increase in the transition region of the kinetic expan-cion joint between the expandad and non-expanded portions of the tube.
Axisymmetric analysis was appropriate for this eval-uation because stresses are uniform around the tube circumfer-
- cnce, i.e.,
bending effects are negligib:e.
This evaluation was not.related to Licensee's evaluations of crack propagation.
Lashnoff Affidavit, 1 6.
100. All tube structural analyses performed to evaluate
-the effects of cracks employed asymmetric analysis for the con-cideration of nonuniformities in stress distribution around the circumference of the tube.
Leshnoff Affidavit, 1 7.
101. Crack resistance was analyzed on the basis of
" toughness," which warcfactored into the fatigue model to eval-unte the effects of stress intensities on crack propagation.
Leshnoff. Affidavit, 1.8.
102.-Stress. intensity is a mathematical representation of the way-stresses concentrate at the' crack tips when'they are transmitted around the1 perturbation in the stress field caused
'by the crack.
If the stress intensity is very low, the materi-bliat the crack.tip can strain'to accommodate the additional
~
loading,7and no crack growth occurs.
The threshold stress in-tensity is the value below which no growth occurs.
If the stress. intensity is very high,;the material will fracture be-cause the' material's microstructure cannot accommodate the strain.
The lowest stress intensity =which results in'this
~
fracturing of a material is its " fracture toughness."
In gen-
~
oral, the moreLductile the. material, the-higher the fracture toughness.
Leshnoff Affidavit, 1 8.
'103. Hardness, on the other hand, is not germane to a me-
'chanical crack propagation analysis,. and was not used for that purpose.-1A hardness test was used solely to facilitate a com-parison between1 rolled expansion and kinetic expansion to de-L
-termine. relative susceptibility to IGSAC.
Leshnoff Affidavit,
~
'1 9.
104.-Licensee accounted for both large and small cracks in h
Litsipropagation analysis.
In evaluating crack propagation I
l ;
L1
under normal and anticipated transient loadings, a spectrum of crack sizes were interacted with the tube stresses to determine the number of-cycles required to propagate the crack through the tube wall.
Stress intensities were calculated for partial through-wall cracks, combining components due to membrane stress, bending stress, and stresses due to internal pressure tcting on the parting crack faces, including the thermally in-duced axial loads constituting the major part of the load cycling.
The stress intensity was recalculated for each cycle end the increment of crack growth determined.
The new crack 1cngth was then used to determine the stress intensity of the n2xt. cycle.
Leshnoff Affidavit, V 10.
105. Smaller cracks grow faster on a percentage basis (i.e.,
growth per cycle divided by crack size) than larger cracks, if the same stress intensity is applied to both.
Therefore, in analyzing the spectrum of crack sizes, stress in-tensity was separately calculated for each load cycle and crack aize was accounted for during that cycle.
Accordingly, the ef-fact of crack size was appropriately considered in the fracture j
machanics calculations relative to the effects of thermal atress.
Leshnoff Affidavit, 1 11.
.E.
<TMIA'S CONTENTION 2.a and-2.c AND JOINT INTERVENORS' E-
' CONTENTION 1(5)
'TMIA's Contention 2.a and Joint Intervenors' Contention 11(5) both allege.that Licensee has failed to properly identify
'the cause~of the intergranular stress assisted cracking-(IGSAC) whihh' occurred in the TMI-1-0TSGs.
TMIA's Contention 2.c y
raises asserted inconsistencies between or within the TPR and 1:
thezSER concerning the cause of the IGSAC.
The following mate-
. rial-facts relating to-these contentions are not in dispute.
106. Subsequent to the discovery of leakage in the TMI-1 once-through steam generator (OTSG) tubing, Licensee developed zand implemented an. elaborate series of evaluation programs to identify the extent and cause of tube failure.
Giacobbe Affi-davit, 1 4.
c..
1-e 107. Two independent laboratories, Battelle Columbus La-boratories and Babcock'& Wilcox (B&W) Lynchburg Research Cen-
-ter, were retained-by Licensee to develop a root cause failure 1
analysis.. !The results and' conclusions of these two independent-f
- enalyses were in-agreement in all material respe cts.
Giacobbe Affidavit, 1 9.
1.
-Characterization of the Failure Mechanism 108; Eddy-current testing (ECT) was performed to determine
~how many tubes were: leaking and at what-location.
It showed
.that'mostLindications occurred in the upper tubesheet area (top
.24 inches-of the tubes), primarily in the top few inches.
Giacobbe Affidavit, 1 5.
I i r-I~
"109. Examination of the tube samples visually,- by metal-legraphy and by electron microscopy demonstrated that the de-fccts were circumferential cracks which were intergranular and inside diameter (ID) initiated.
Giacobbe Affidavit, 1 6.
110. The orientation-specific defect and intergranular morphology demonstrated that the tube failure was caused by an
.intergranular stress assisted cracking (IGSAC) failure mecha-nism.
Giacobbe Affidavit, 1 7.
111. There are three conditions which must bh present for IGSAC to occur:
First, the material must be in an environment which contains a chemical specie (s) (causative agent) that will cause this type of crack.
Second, the material must have a tansile stress applied to it.
Third, the material under con-
' sideration must be susceptible to this type of environment.
Giacobbe Affidavit, 1 8.
2.
Detailed Investigation of the Conditions Which-Could Have Caused the IGSAC (a)
Aggressive Environment 112. Analysis of tube surfaces by energy dispersive x-ray analysis (EDAX), auger electron spectroscopy (AES) and electron spectroscopy for compound analysis (ESCA) were performed as de-l ccribed in 11 7, 10 of the Giacobbe Affidavit.
An ion sput-taring process was used to strip away the tube surface oxide, Icyer by layer,- in order to measure the precise amount of each cubstance present at any given depth of the film.
Giacobbe Af-fidavit, 1 10.
I
. i
113. Sulfur was detected in the form of both sulfate and rrduced forms (primarily sulfides), on both the tube films and the films on fracture surfaces.
On the tube itself, up to 1.5 ctomic percent of sulfur was detected.
On fracture surfaces this level was as high as 8 atomic percent.
At the outer sur-fece of the tube films, nearest the atmosphere, the sulfur
- t2nded to be in the form of sulfates.
Deeper into the film, cpproaching the tube surface, the predominant form of sulfur w s sulfide.
Giacobbe Affidavit, 1 11.
114. Low levels of chloride were also found on the sur-fcces of these tubes.
Chloride levels were less than 1 atomic parcent at the very tops of the tubes where the most extensive
. cracking occurred.
'A. maximum of 1 atomic percent of chloride was also.found on the fracture surfaces of tubes.
After remov-
.sl of the top layer and proceeding into the film a short dis-tence, the chloride. level dropped to where it was non-detectable.
(The corresponding sulfur level at this location on this tube film was between 6 and 8 atomic percent.)
i Giacobbe Affidavit, 1 -12.
115. Carbon was typically detected on the tube surface films.
At the outer surface, 50 to 60 atomic percent of carbon l
[
ganerally was present.
The carbon level quickly dropped to 20 ctomic percent or below when the outer layer of the surface films was stripped away by use of the ion sputtering process.
The carbon l form was determined to be the graphitic or long chain hydrocarbon form.
Giacobbe Affidavit, 1 13.
i l
ll6.' Analyses of the reactor coolant water samples, after
.ccme attempts had been made to remove impurities from the reac-ter coolant water in December 1981, found measurable levels of Gulfate.
Sulfur is not normally expected to be found in the RCS, but sulfur levels of 700 parts per billion (ppb) were found in the decay heat system.
Low levels (less than 100 ppb) of chle' des and'florides were present as well.
Giacobbe Affi-davit, t 26.
(b)- Stress 117. For various operating modes, the dominant loads contributing to tube stresses can be described as follows:
(1) When When the unit is pressurized, primary system hot,
.cmall axial tensile or compressive loads may be present; howev-cr, the largest load will be the hoop tensile component.
(2)
During unit heatup, there will be a small axially compressive component of the loading on the tubes (because the thick OTSG chell heats and expands more slowly than the tubes), but since the primary system is pressurized, the hoop tension is the lcrgest load component.
(3) During cooldown, pressure (and therefore hoop stress) decreases while the lowering of temper -
tures causes.the axial tensile load to increase.
The largest tube stress will thus be in the axial tensile direction.
(4)
At shutdown, since the primary system is depressurized, the only significant load is the axial tensile preload.
Giacobbe Affidavit, 1 15.,
l 118. The cracking of the TMI-l OTSG tubes was found to be
'cimost exclusively circumferential.
Because stress assisted cracking ~always produces cracks-perpendicular to the tensile otress,.this' orientation of the cracks implied that the
.ctresses.caucing the cracks here were axial, rather than in the circumferential'or hoop direction. -This condition occurs dur-ing cooldown and cold shutdown. -Giacobbe Affidavit, 1 19.
119. Vertical cracks were observed only at the tube ends.
This is to be expected since the tube ends are subject only to residual circumferential stresses produced by the weld joining the: tube to-the tubesheet.
Giacobbe Affidavit, 1 20.
(c)
Material 120. The Inconel 600 tubing used in the TMI-1 OTSGs is typical of the material class and condition of tubing used in I
most= pressurized water reactors'in the United States today.
Inconel 600 has high corrosion resistance under many corrosive conditions, e.g.,
caustic corrosion, and chloride-induced cor-rosion.
Giacobbe Affidavit, 1 22.
121. Licensee's research on the tube fabrication process rzvealed that, like other OTSGs, the tube metal alloy had been
.ssnsitized by its stress-relief heat treatment.
This provided I
the necessary susceptibility to IGSAC.
Giacobbe Affidavit, l'23.
7.
3.
Literature Review 122. Available scientific literature indicates that sensi-tired Inconel 600 is susceptible to rapid IGSAC in the presence of reduced sulfur species, and that such metastable sulfur is the only corrodant known to cause IGSAC at low temperatures.
The.IGSAC occurs under intermediate oxidizing conditions, where culfur species in intermediate oxidation states, such as thio-culfate and polythionates, are present.
Giacobbe Affidavit, 1.33.
4.
Failure Scenario 123. TMI-1 operational records, the literature surveys concerning IGSAC of Inconel 600 and the results of the indepen-dant failure analyses indicate conclusively that the IGSAC was culfur-induced, and that other known possible sources of the cracking were not the causes of the TMI-1 OTSG failure.
Giacobbe Affidavit, 1 37.
124. The IGSAC occurred between the end of the hot func-tional tests done in August and September 1981 and the time the loaks were discovered in November 1981.
This is corroborated by the fact that no leakage was observed during the hot func-tional testing and by the rapid crack'ing behavior of the ob-cerved IGSAC.
Giacobbe Affidavit, 1 25, 40.
125. IGSAC of the TMI-1 OTSG tubes occurred through the following sequence.
First, sulfur compounds, primarily sodium thiosulfate, were accidentally introduced to the reactor L. __
7 w:
coolant system ~during system layup via the transfer of sodium
'thicaulfate-containing water from the reactor building spray
.cystem to the borated water storage tank.
These contaminations were reflected by increases in conductivity in July 1980 and May 1981.
Introduction of sulfuric acid and oil during layup
~1n 1979 may also have contributed to the total sulfur invento-
-ry.
Giacobbe Affidavit,- 11 27,~38.
126. Most of the thiosulfate was removed by demineraliza-tion of the reactor coolant, but 1-2 parts per million (ppm) of thiosulfate may have remained in the reactor coolant in August
-1981.
Concentrations of thiosulfate reached 4-5 ppm during hot functional testing due to additional sodium thiosulfate contam-ination.
Giacobbe Affidavit, 1 28.
127. During the 1981 hot functional test, the combination of reducing (deoxygenated) conditions and high temperature ccused the thiosulfate species to transform toward more reduced
-matastable species.
The cracking did not occur at this time, however, because oxygen was not present in the system.
l Giacobbe Affidavit, 1 39.
128. Late in the hot functional test sequence and during i
the following cooldown, reactor coolant conditions became oxidizing.
This was due to a combination of (1) direct injec-tion of a relatively large volume of oxygen saturated water and (2) venting to the atmosphere on cooldown.
The oxidizing con-dition in the presence of relatively high concentrations of f ls i
-r
N cggressive metastable sulfur species led to the corrosive po-tential.
Giacobbe Affidavit, 1 40.
129. The IGSAC occurred.during the cooldown following the
~hotifunctional testing.
This was when the axial loads and low
.tcmperatures necessary-to cause circumferentially oriented IGSAC were present.
Giacobbe Affidavit, 11 19, 25, 42.
130. The combination of factors most' favoring cracking oc-curred' in the upper tubesheet region.-
At this location, the tubes are subjected to high residual stresses due to the tube-to-tube sheet welds and tube rolling.
Oxygen introduced during system venting would also be concentrated in this region be-ccuse of the vapor space resulting from lowering the water 1Gvel.
Moreover, the' vapor spaces caused the sulfur to concen-trate on the tube surfaces in the upper tubesheet region.
Giacobbe Affidavit, 1 41.
131. The environment in.the OTSGs was dynamic during cooldown from the hot functional testing.
Oxidizing potential cnd water level were changing.
Under these conditions some in-I
.dividual tubes below the upper tubesheet experienced cracking i
conditions long enough to cause the widely scattered IGSAC seen in the lower elevations.
Giacobbe Affidavit, 1 42.
132. The continuing change in conditions also caused ter-mination of the cracking.
As time allowed further oxidization of polysulfur species, the presence of an aggressive intermedi-cte sulfur species becamse less probable.
The combination of _
-this change in conditions with other dynamic changes, cuch as dilution of surface films by the bulk OTSG water, caused the
~
cracking to terminate.
Giacobbe Affidavit, 1 43.
't 3 3. The " specific mechanistic steps" involved in the cracking phenomenon, i.e.,
the individual chemical reactions involving the various metastable forms of sulfur present at the time of the cracking during the transition from oxidized to re-duced states, have not been definitely established.
Knowledge of the corrosive elements and environmental conditions that cause IGSAC, however, is sufficient to develop a control strat-cgy that will prevent reinitiation of IGSAC; not defining the cpecific mechanistic steps does not invalidate the approach.
Giacobbe Affidavit, 1 54.
134. The primary emphases of Licensee's control strategy are to control the total amount of sulfur in the reactor coolant system, and to prevent the combinations of temperature end oxiding conditions which result in the conversion of rela-tively harmless' sulfur forms to potentially harmful sulfur forms.
Giacobbe Affidavit, 1 55.
135. Control of total sulfur and prevention of contribu-tions of. conditions-which result in conversion of harmless sul-fur species to corrosive species will prevent reinitiation of IGSAC and will be effective regardless of the specific mecha-
-nism and form of sulfur involved in the IGSAC process.
'Giacobbe Affidavit, 1 55'. -_
IL 5.
Confirmatory Testing 136. Short term corrosion testing programs were performed by B&W and Oak' Ridge Laboratories.
They verified that the lev-sls of reduced sulfur species that could have existed in the TMI-IRCS.was capable of causing IGSAC during cooldown or shut-
-down after hot functional tests.
They also verified that sig-nificantly higher levels of sulfate and chloride could not have ccused the IGSAC.
The procotal and results of these tests are ga described in Giacobbe Affidavit 11 44 - 51.
137. The tests demonstrated'that (a) no propagation of the cracking occurred when an actual. cracked tube was placed in re-cctor coolant water and loaded to representative tube loads; (b) actual tubing removed from the OTSGs is susceptible to
-IGSAC in' simulated reactor coolant containing from 1 to 5 ppm
-of sodium thiosulfate; (c) no cracking occurred in coolant containing up-to 10 ppm of either sulfate or chlorides; (d) the morphology of cracking caused by thiosulfate was identical to the intergranular cracking observed in the actual OTSG tubes; (o) there appears to be a temperature near 170*F at which stress relieved Inconel 600 is most susceptible to thiosulfate induced IGSAC; at temperatures above this, the cracking propen-city.is' reduced and ultimately inhibited.
Giacobbe Affidavit, 11 45-47, 50.
I i
-100-l
p 6.
Role of Other 2otential Causative Agents (a)
Carbon 138. Carbon was not the cause of the TMI-1 OTSG failure.
Giacobbe Affidavit, 1 63.
139. Carbon in the form found on the TMI-1 OTSG tubes has b2en found during several failure analyses of Inconel 600 steam g:nerator tubes in other plants, but has been determined not to bs the cause of the IGSAC.
Like the carbon found on the TMI-1 tube surfaces, the carbon in those cases was detected in the
-long chain or graphitic form in high percentages at the outer surface of the tube film.
There is no evidence that the graphitic form of carbon causes IGSAC.
Giacobbe Affidavit, 11.13,'34, 63.
140.' Sodium carbonate can cause IGSAC.
However, this at-tack occurs under high pH, _high temperature conditions, and enustic-type of IGSAC.
Sensitized Inconel 600 is very resis-tant to caustic IGSAC.
No carbonates were detected on the TMI-1 tube sample.
Giacobbe Affidavit, 1 64.
141. The statement of the Third Party Review Group in its Ecbruary = 16, 1983 report (at 9) that "[c]arbonates in the pres-ence of oxidants at high temperature can produce IGA and IGSCC offInconel 600" was referring to research performed by Westing-
~
house Electric Corporation under an EPRI funded program.
The Efinal report on this project was released in May 1983 and is L
.cntitled "Effect of Calcium Hydroxide and Carbonates on IGA and lIGSCC of Alloy 600" RP-3060.
Giacobbe Affidavit, V 65.
l
-101-
142. The Westinghouse tests were conducted exclusively ucing secondary side water chemistry environments.
The all-volatile high_pH chemistry of the secondary side is signifi-ccntly different from the borated water, buffered system of the primary side.
Giacobbe Affidavit, 1 65.
143. These tests were performed to study the influence of carbonates on crevice corrosion of Inconel 600 at tube support plate and tubesheet cravices.
No such crevices exist on the primary side.
Giacobbe Affidavit, 1 65.
144. The test tubes used in the program were in the mill cnnealed-condition and were not sensitized as in the B&W OTSGs.
The sensitized microstructure is significantly more resistant to the alkaline cracking mechanism caused by sodium carbonate, which is similar to caustic corrosion.
Giacobbe Affidavit,
-1.65.
(b)
Chloride 145. Chloride was not the cause of the TMI-1 OTSG failure.
Giacobbe Affidavit, V 66.
'146. Sensitized Inconel 600 is highly resistant to chloride-induced corrosion cracking.
Giacobbe Affidavit, 1 66.
147. To prevent stress corrosion of stainless steel mate-rials in the RCS, chlorides were limited to less than 500 parts par billion during ahutdown and 100 parts per billion during hot operations.
These levels are well below those at which I
chlorides have been found to cause IGSAC of stainless steels.
-102-l
'There is no evidence that these limits were-ever exceeded be-fore the cracking of the TMI-1 OTSGs.
Giacobbe Affidavit, 1-29..
148.-The low levels of chloride was found on the tube sur-fcce, and the fact that its level rapidly diminished deeper
.into the film, are indicative that chloride was not the caus-ctive agent.
The fact thtt chloride in levels as high as 10 ppm did not cause cracking in short term tests also supports
'this conclusion.
Giacobbe Affidavit, 11 12, 36, 66.
(c)
Other elements 149. Other elements (e.g.,
antimony, cobalt, zirconium, silicon, phosphorous and titanium) were found only in trace cmounts in isolated locations during the tube surface analyses.
No trends were established.
Giacobbe Affidavit, 11 14, 67.
150. These substances are normal trace elements expected to be found on surface films as a result of oxidation of vari-ous coolant materials putting metal ions into solution.
They ware not the cause of the IGSAC of the TMI-1 tubing.
Giacobbe
-Affidavit, 1 67.
151. Lead and mercury, other potential corrodants men-tiened by the TPR (February 16, 1963 report at 9), were not de-tceted on the TMI-1 tubes.
They were accordingly not the cause of the IGSAC.
Giacobbe Affidavit, 1 67.
152.-Nickel, chromium and iron were found during the tube curface analyses.
These are major alloying elements in Inconel
-103-
600, and were not the cause ofTthe IGSAC.
Giacobbe Affidavit, 11 7, 62.
(d)- Possible Synergistic Reactions 153. Sulfur forms were the cause of the tube damage.
Without the conditions necessary to recreate the sulfur induced cracking. mechanism, the tube damage will not reoccur.
The pos-sibility of synergistic reactions were nonetheless taken into cccount in Licensee's efforts to identify the source of the tube damage, in its short and long range testing programs, and in its operational chemical control programs.
Giacobbe Affida-vit, 1 68.
154. Licensee searched for all possible causative or con-tributory agents on the tube surfaces.
Of the agents identi-fied on the tube surface, only chloride is likely to have a cynergistic effect.
Any synergistic reaction which does exist will not cause IGSAC at TMI-1 OTSGs under RCS administrative chemistry controls.
Giacobbe Affidavit, 1 69.
155. This conclusion is supported by the long term corro-clon test, showing no IGSAC in maximum levels of sulfur species cnd chlorides' allowed by current TMI-l chemical specifications, cnd'by the short term tests, shoding no IGSAC in 10 times the allowable. levels of thiosulfate and' chlorides.
Giacobbe Affi-devit, 1 69.
156..In-the actual plant systems, sulfur and chlorides are baing controlled to low levels which will not cause IGSAC, even
-104-
if-they react synergistically.
The analysis frequency (b times a week) for these species is often enough that an out of speci-fication condition will be recognized and corrected before tube damage can occur.'
Giacobbe Affidavit, 1 71, 111.
157. Even if other elements present in the TMI-1 OTSGs do have synergistic effect, IGSAC will not reiniate under RCS ad-ministrative-controls.
This conclusion is supported by both
' the-short and long term corrosion tests, which used actual TMI-1 tubing, including some which had been repaired and sub-jseted to the hydrogen peroxide cleaning process.
These sam-ples therefore would have had any other contaminant to which
- the tubes were exposed represented in the tests.
No IGSAC has dtveloped.
Giacobbe Affidavit, 1 70.
158. The requirement that conductivity be monitored will
[
identify the introduction of any chemical species for which there is no routine analysis, so that they can be removed.
Ad-ministrative controls on the levels of contaminants in chemi-ccis'to be added to the system also cover other contaminants than sulfur.
Giacobbe Affidavit, 1 71.
159. Licensee's administrative limits on primary system p
chemistry are adequate to prevent synergistic effects which could cause reinitiation of IGSAC.
Giacobbe Affidavit, 1 72.
160. The work of Dr. R. H. Hansen, retired from Bell La-b0ratories in Murray Hill, New Jersey, is unrelated to nuclear snergy,-steam generators, or the corrodants in issue here.
Giacobbe Affidavit, 1 73.
-105-
W~
s (e)
Contaminants' Introduced During Repair 1161.iThe residue-_ remaining.after the kinetic expansion re-
,pnir process'will not'cause the reinitiation of IGSAC either by itself or'in' tandem with other. elements in the level's they are e
Lpresent.
.Giacobbe Affidavit, 1 74.
.162. In' order to-assure that the residue remaining after the kinetic _ expansion repair process will not contribute to I
reinitiationtof'the IGSAC, tall consumable materials used during
~
the_OTSGLrepair.were analyzed to. prevent' introduction of harm-fu'l~ levels of contaminants to the reactor coolant system.
Sul-fur;-halogens (chloride and-fluoride), and'the heavy metals
' controlled.
Giacobbe' Affidavit, 1 74.
4 163.'After repairs were' complete, large pieces of material ware physically: removed.
Th6 OTSG tubes and tubesheets were then flushed until soluble contaminants had been essentially
- i
.rsmoved. 'Giacobbe Affidavit, 1 74.
164. The short'and long term corrosion tests included tubes subject.to the repair. process.
These tubes were cleaned
-'in the same manner as the actual tubes, with the exception.that
-they were only rinsed.
Thus,.the levels.of any harmful species in'the explosive: residue on1these tubes would be higher than in I he. actual OTSG.
No corrosion occurred in the tests under con-t l.
-ditions comparable to those which will be present during actual L
(:
F operation. ~Giacobbe Affidavit, 1 75.
p i
i l-
-106-I-
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--,m-
,-----.,.,,.,.,vr....-eww.w,,-w.-e,-.--,-w.c
-c i
7.
Other Issues Discussed in Consultant's Reports 165.-Mr. Dillon's suggestion (SER Att. 3 at 12) that Li-censee perform an: additional corrosion test in a cold high oxy-g:n and high concentration' sulfate environment was made because of his concern that the cleaning process might cause damage to
~
the:OTSGs; Dillon expressed no concern that the corrosion would otherwise reinitiate.
Ciacobbe Affidavit, 1 57.
o 166. After the April 15, 1983 Dillon report was written Licensee conducted a long term corrosion test which considered
--instead the' conditions planned and later actually experienced b3 fore, during, and after conduct of the chemical cleaning pro-gram.
This test was more appropriate than the one recommended by Dillon.
Giacobbe Affidavit, V 58.
167. The pure water cracking found by H. Coriou and other rosearchers (described in the article " Historical Review of the Principal Research Concerning the Phenomena of Cracking of Nickel-Base Austenitic Alloys") is not germane to the present cracking problem.
The Coriou study considered mill annealed Inconel, while TMI-1 tubing is sensitized and hence more resis-tent-to pure water cracking.
The " pure water" environment of f-the test.is alco not relevant to the boric acid environment in the TMI-1-primary system.
Giacobbe Affidavit, 1 59.
168. Tests by B&W using the appropriate environment and material which exists in.the primary system have shown that cracking would not be anticipated in the absence of a
-107-r.
[
F sufficiently high level of a metastable sulfur species contaminant.
Giacobbe Affidavit, 1 60.
169. During the approximately one hundred reactors years of operating experience at TMI-1 and other plants no corrosion has occurred when the environment has been maintained within reactor coolant specifications.
Giacobbe Affidavit, 1 60.
170. The TMI-1 tubing has been verified to fall within the range of material properties represented by the B&W tests de-acribed in 1 59 above.
Giacobbe Affidavit, 1 61.
171. The " minor differences" in findings between the two independent failure analyses (referred to in the Third Party R; view ("TPR") February 18, 1983 report, finding C.1), do not undermine the failure analysis.
Such differences in outcome are the consequence of the-two consultants using different cquipment and techniques, and testing different tube samples.
Giacobbe Affidavit, 1 76.
172. The "three previous contaminations" discussed in the SER at pp. 5-7 concern previous contaminations which may have contributed to the total sulfur inventory present after hot functional testing.
These contaminations did not themselves cause corrosion.
Giacobbe Affidavit, 56.
i, t
F.
' CONTENTION 2.b.1.
TMIA's Contention 2.b.1 concerns the possibility that the h
paroxide cleaning process undertaken by Licensee posed a sub-P' stantial risk of corrosion reinitation;-TMIA supports its I
-108-
centention'by relying on R. L. Dillon's statement that cleaning might put a large inventory of sulfur into solution.
173. The concerns relating to cleaning expressed by Staff c nsultant R. L. Dillon and by the TPR were expressed prior to the cleaning.
Giacobbe Affidavit, 1 78.
174. Prior to the decision to remove residual sulfides from the tube surfaces by a hydrogen peroxide cleaning process Licensee gave careful consideration to any risks the process might have on recurrence of tube damage induced by sulfur or the peroxide cleaning process. Short and long term corrosion tosting confirmed the safety of the process.
Giacobbe Affida-vit, 1 78.
175. The cleaning process used low levels of hydrogen per-exide to rapidly convert the insoluble reduced sulfide left on the tube surfaces to an oxidized soluble form (sulfate) under protective, high pH conditions.
It took approximately 400 hnurs.
Giacobbe Affidavit, 1 79.
176. The cleaning has successfully been completed, with no cdverse effects on the RCS.
The sulfate concentration never cxceeded 0.4 ppm, and no damage was detected in the system as confirmed by hot functional testing of the OTSGs after the cleaning process was completed.
Giacobbe Affidavit, 1 79.
177. In light of the successful completion of the cleaning, the concerns expressed by Mr. Dillon and others have no bearing on the TMI-l restart.
Giacobbe Affidavit, 1 78.
-109-2-
w-t 7T'
-?
mF 7
l 1.
Analysis and Testing Preceding the Cleaning 176. 5he pH range employed during cleaning (8.0-8,5), was within.TMI-l's technical specifications.
Ammonium hydroxide was used as the reagent.to raise the pH.
This avoided the pos-cibility of hideout and future corrosion.
No corrosion was ex-pected to result from the use of ammonia hydroxide.
Giacobbe Affidavit, 1 82.
179. Hydrogen peroxide is normally created in the area of the core during shutdown at levels of 5-10 ppm.
Up to 15-20
. ppm peroxide had been added to the coolant of other PWRs, once the RCS had cooled to 130*F, with no adverse effects.
The TMI-1 cleaning was done at the same temperature and approxi-mately the same corcentration.
Giacobbe Affidavit, 1 83.
180. The by-products of the peroxide cleaning process would not harm the system.
Giacobbe Affidavit, 1 84.
181. The potential for impurity introduction associated with the cleaning process (e.g.,
the potential for chloride throw from the resin during removal of the sulfate) was evalu-cted and found not to have an adverse impact on the rest of the plant.
Giacobbe Affidavit, 1 85.
2.
Effects of the Cleaning on the Sulfur on the Tube Surfaces 182. Metastable forms of sulfur such as thiosulfate can induce cracking at-low concentrations but higher concentrations of sulfate cannot.
While sulfur in metal sulfides is being ox-idized to form sulfates, it can be expected to pass through
-110-
these metastable states.
The more rapidly the conversion to culfate takes place, therefore, the lower the concentration of matastable species which exist at any given time.
Giacobbe Af-fidavit, 1 86.
183. During the cleaning process, parameters such as pH cad maximum sulfur concentration were selected to assure that the conditions under which Inconel 600 tubing is attacked by culfur would not occur.
A high pH during the test maximized rcaction rate and minimized corrosion potential.
The high pH was maintained until after the sulfate was reduced to within operation specifications (less than 100 ppb).
This level is not harmful to RCS materials.
Giacobbe Affidavit, 11 86, 94.
184. An extensive corrosion testing program was performed to confirm that the conditions of the cleaning process would not reactivate the~ cracking mechanism.
The protocol and re-cults of these tests are as described in 11 87-92 of the Giacobbe Affidavit.
185. These tests dcmonstrated that (a) the conversion from nickel sulfide to soluble sulfates occurs at a very rapid rate; indeed, the levels of intermediate sulfur species produced dur-ing the sulfide to sulfate conversion was below the level of datectability; (b) no cracking or corrosion occurred in U-bend 1
cpecimens of sensitized 304 stainless steel and Inconel 600, as wall as internally stressed C-rings fabricated from TMI-l tubing specimens, exposed to the cleaning solution for periods
-111-i
i i
i up to 500 hours0.00579 days <br />0.139 hours <br />8.267196e-4 weeks <br />1.9025e-4 months <br />; and (c) at a pH of 8.0 - 8.5, no corrosion oc-curred when actual TMI-l tubing underwent simulated cleaning in o solution spiked with concentrations of 20 ppm sulfate.
Giacobbe Affidavit, 11 88, 91, 95.
'186. Tube specimens that had been subjected to the perox-ide cleaning process testing for 500 hours0.00579 days <br />0.139 hours <br />8.267196e-4 weeks <br />1.9025e-4 months <br /> were included in long term corrosion tests in which the specimens are being ex-posed to simulated reactor coolant containing the maximum amount of contaminant permitted under current specifications.
The tests have undergone simulated hot functional testing fol-lowed by simulated operatsng cycles.
No evidence of corrosion has been detected.
Giacobbe Affidavit, 1 92.
2.
Results of the Actual Cleaning Process 187. During the entire cleaning process, a total of 0.22 lb of sulfate was generated and removed.
Actual sulfate levels g:nerated during the cleaning process.were lower than antici-pnted, with a maximum of about 0.4 ppm observed.
This is not corrosive at the elevated pH in use.
Giacobbe Affidavit, 1 95.
188. Primary to secondary leakage monitored during the hot functional testing which followed the cleaning was very low I.
during the entire test period.
This serves to confirm the re-cults of the corrosion testing and demonstrates that the cleaning process did not reinitiate the original cracking pro-cOss.
Giacobbe Affidavit, 1 96.
-112-t
3.
Cautionary Statements by Consultants 189. Dillon's pre-cleaning reservations as to the hydrogen peroxide process were based on estimates that 5-10 ppm of sul-fur compounds would be put into solution.
Even with his esti-cate, Dillon viewed the risks as too small to preclude restart.
Giacobbe Affidavit, 1 97.
190. The Third Party Review Group concluded that peroxide flushing was not expected to have an adverse impact on plant
.cofety.
The TPR recognized there was some risk with cleaning, but viewed the risk as inconsequential.
Giacobbe Affidavit, 1 98.
G.
TMIA'S CONTENTION 2.b.2 AND JOINT INTERVENORS' CONTENTION 1(2)
TMIA's Contention 2.b.2 asserts that the sulfur contamina-tion'which is left after cleaning could cause reinitiation of the IGSAC.
Joint Intervenors' Contention 1(2) similarly as-corts that active forms of sulfur can be generated from the
.culfur remaining on the tubes after cleaning.
There is no gen-uine dispute as to the following material facts relating to these contentions.
191. The peroxide cleaning process was to remove the
.culfides most likely to dissolve from the tube surfaces, so that active, harmful forms of sulfur will not be generated and ccuse reinitiation of the cracking mechanism.
Giacobbe Affida-vit, 1 101.
-113-
. _ =
11.
Sulfur Chemistrv
~
'192. Licensee has taken a number of steps which'are ade-quate to1 assure these active forms are not formed from the re-maining sulfide, given.the thermodynamic stability of sulfide.
Giacobbe' Affidavit,.11 101, 106, 107-114.
193.
Sulfur has a number of oxidation states ranging from culfate, which is present in the reactor coolant, to sulfide, which is present in film on the tube. surfaces.
Neither of these two forms of sulfur is harmful to the tubes.
- However, intermediate species between the two extremes are aggressive, cnd if present in sufficient quantities, could cause reinitiation of the. cracking m?:hanism.
Giacobbe Affidavit,
-11 102-104.
194.
Sulfate and sulfide are the dominant equilibrium cpecies within the pH and temperature ranges of interest for
. normal' reactor coolant system operation.
Giacobbe Affidavit, 1 104.
195. Sulfate is-stable under oxidizing conditions, and therefore.is the equilibrium specie at room temperature in oxy-g2nated water at pH equal'5.
Giacobbe Affidavit, 1 104.
196.
Sulfide, on the other hand, is the stable specie under reasonably reducing conditions, that is, normal operating l~
-conditions (deoxygenated, temperature above 250 F) and pH lev-els;.Giacobbe Affidavit, 1 104.
197.
M6 tastable intermediate species such as thiosulfate
-114-
can only persist within a very restricted.pH and oxidation range. -Giacobbe Affidavit, 1 104.
198..
Under.the reducing conditions which existed in the RCS during the August-September 1981 hot functional test, the thiosulfate'which contaminated the PWR primary system trans-formed towards more reduced metastable species.
However, dur-ing the following cooldown,. oxygen was introduced into the sys-tem.
The oxidating conditions in the presence of aggressive metastable sulfur species were responsible for cracking.
Giacobbe Affidavit, 1 105.
199.
Under normal operating conditions when the primary system is.deaerated and hydrogenated, nickel sulfide will re-main stable, and aggressive intermediate species will not be
- formed.
Limited quantities of nickel sulfide may, however, be clowly dissolved in the primary coolant and be removed by the
. ion exchange resins.
Giacobbe Affidavit, 1 106.
-200.
Oxidation of residual nickel sulfide to sulfate can occur to.some extent if the primary system is cooled and oxy-
.genated.
However, control of system oxygenation during cooldown will avert this formation.
Giacobbe Affidavit, 1 107.
~2.
Control of Sulfur Levels in the Reactor Coolant System 201. The sodium' thiosulfate tank has been physically dis-connected from the' reactor coolant system, and sodium thiosul-fate i uno longer used at TMI-1.
Giacobbe Affidavit, 1 108.
s
-115-
l 202. Administrative controls on the addition of chemicals to the reactor coolant system have been strengthened to ensure that all chemicals for use in the reactor coolant system are within specifications which have been upgraded since the tube failures.
Giacobbe Affidavit, 1 109.
203. Chemistry limits for that reactor coolant system have been modified.
These limits control the concentration of culfate to 100 parts per billion (ppb), chloride to 100 ppb, cnd fluoride to 100 ppb.
IGSAC will not be caused at er below these levels.
Giacobbe Affidavit, 1 110.
204. The lithium concentration range has been administra-tively established, within the original B&W specified limit, to be present in the highest concentrations allowed (i.e.,
1-2
. ppm).
Giacobbe Affidavit, 1 110.
205. Sulfate,_ chloride and fluoride levels in the RCS are cnalyzed a minimum of five times per week.
Total sulfate is cnalyzed periodically, and reduced sulfur is to be analyzed whenever the difference between the sulfate and total sulfur level suggests intermediate species may be present.
Giacobbe Affidavit, 1 111.
206. Conductivity is analyzed fives times a week and is verified to be consistent with analyzed leve:s of chemical spe-cies.
Inconsistencies in conductivity, measured in this fre-quency, will indicate the. presence of other contaminants in the
'cystem.
Giacobbe Affidavit, 1 111.
-116-
207. The capability to analyze low levels of sulfate (down to 30 ppb) has been achieved by the addition of an ion chromatograph.
Giacobbe Affidavit, 1 112.
208. A total organic carbon analyzer has been put into op-oration by Licensee.
This will preclude undetected introduc-tions of organic compounds such as oil and solvents.
Giacobbe Affidavit, 1 112.
209. The total organic carbon analyzer satisfies the TPR's ccncern with carbon Giacobbe Affidavit, 1 65.
210. Removal of sulfur compounds and other ionic species from the bulk reactor coolant will continue to be done by ionic cxchange.
This will prevent the build up of contaminants.
Giacobbe Affidavit, 1 113.
3.
Control of System Conditions 211. Licensee's control procedures for reactor coolant cystem conditions minimize the conversion of sulfide surface films to potentially harmful intermediate species by preventing the combination of temperature and oxidizing conditions neces-cory'for the formation of the intermediate species. Giacobbe i
l
' Affidavit, 1 115.
l 212. During system cooldown, Licensee's control procedures r quire that reducing conditions be maintained until the system tGmperature is close to ambient; the system is then to be ni-trogen blanketed to exclude oxygen.
In this way, intermediate culfur' species are not created in significant levels.
Giacobbe Affidavit, 1 116.
-117-
213. The routine monitoring of sulfur levels during layup will verify that corrosive concentrations have not been formed.
Giacobbe Affidavit, 1 116.
214. Irrespective of the percentage of sulfides actually rzmoved by the cleaning process, these controls will ensure that inactive sulfides do not generate harmful rative species in sufficient quantities to damage the OTSGs.
G'
- obbe Affida-vit, 1 116.
215. Dr. Digby MacDonald had initially raised a concern as to the possibility of oxidation of nickel sulfide causing cor-rosion.
At the March 10, 1983 meeting of the NRC, however, Dr. MacDonald indicated he was satisfied, on the basis of tests p2rformed by Licensee and the controls it has' initiated, that no harmful oxidation of the nickel sulfide will occur. Giacobbe Affidavit, 1 130.
4.
Confirmatory testing 216. The qualification of the explosively expanded joint confirmed that the joint meets licensing standards for mechani-cal tube-to-tubesheet joints.
Corrosion testing provided data that the expanded region was in a condition which was as resis-tcnt to IGSAC as any OTSG tube-to-tubesheet joint. Giacobbe Af-fidavit, 1 117.
217. Short term tests using TMI-l OTSG tubes samples, some of which had been exposed to the cleaning process and thus were rcpresentative of the tubes in use, verified that corrosion
-118-l l
L
!will not reinitiate at up to 1 ppm sulfur species.
Giacobbe
' Affidavit, 1 119.
218. To assure that Licensee's controls on sulfur levels cnd system conditions will prevent the sulfide-containing oxide films on tube surfaces from causing initiation or propagation sof IGSAC, Licensee has established and is conducting a series of long term corrosion tests on actual OTSG tube samples.
Giacobbe Affidavit, 1 120.
The protocol and results of these tests are as specified in paragraphs 120 - 125 of the Giacobbe Affidavit.
219. These tests simulate environmental and operational conditions which are representative of the worst-case chemistry conditions which could exist in the primary system within tech-nical specification limits.
The test loops are undergoing sim-ulated hot functional test cycles followed by simulated op-orating cycles, and duplicate actual operations in terms of temperature, pressure, operating stress on the tubes, and typi-cal duration of heatup, operation, and cooldown.
Giacobbe Af-fidavit, 11 122, 123.
220. No propagation of eddy current indications has oc-curred.
Also,' visual metallographic examination and ECT of C-ring specimens removed from all four test loops have shown no IGSAC.
Giacobbe Affidavit, 1 124.
221. The hot functional test performed in August and September'1983 provided further assurance that Licensee's
-119-
control scheme for preventing reinitiation of IGSAC is effec-tive.
During this test, the reactor coolant system was main-tained at full operating temperature and pressure.
Steady state leak rate remained very low throughout the test program.
There has continued to be no evidence of initiation or propaga-tion of IGSAC after this test.
Giacobbe Affidavit, 1 125.
5.
Other Issues Related to Initiation 222. Piping less than 1 inch in-diameter was not flushed co part of the hydrogen peroxide cleaning process.
The surface creas of these lines is small relative to the balance of the raactor coolant system, representing less than 5% of the sur-fcce area of the RCS.
The amounts of sulfur that could be transported to these lines is negligible compared to total sul-fur inventory.
It is within the capacity of the reactor coolant clean up system to control.
Giacobbe Affidavit, 1 126.
223. Sulfate is a potential corrodant only at high concen-trations; the levels specified for normal reactor chemistry are not aggressive to Inconel 600 tubing.
This was confirmed by
.the short and long term corrosion tests in which no IGSAC was dotected.
Giacobbe Affidavit, 1 127.
224. Sulfate corrosion has only been observed in high tem-p;rature, high concentration acid sulfate solution under highly otressed conditions.
Giacobbe Affidavit, 1 128.
-120-
H.
JOINT-INTERVENORS' CONTENTION 1(3)
Joint Intervenors assert that " morphological changes" in the' inner. tube surface, remote from the expanded joints, might be " precursors of IGSCC" (referred to herein as IGSAC).
There is no genuine issue of with respect to the following material issues.
225. The only morphological changes other than IGSAC that have been identified in the TMI-1 OTSG tubes consist of iso-
-lated, small areas of intergranular attack (IGA).
Giacoboe Af-fidavit,-1 132.
226. IGA is a corrosion phenomena which, like IGSAC, re-quires an aggressive environment as well as a susceptible mate-rial.
Unlike IGSAC, however, IGA formation does not require nn cpplied stress.
Giacobbe Affidavit, 1 132.
1 227. IGA is primarily found as a network of attack associ-cted with a main intergranular crack.
IGA can also exist as a acparate form of corrosion.
Conversely, IGSAC can be found in the absence of IGA.
Giacobbe Affidavit, 1 132.
228. It is possible that IGA could propogate into IGSAC if the appropriate corrodant were present and a tensile stress ware applied.
Even under applied stress, however, IGA cannot continue to propagate or become IGSAC in the absence of a corrodant.
Giacobbe Affidavit, 1 133.
229. Because sulfur and other contaminants are not now and will not be present in the future in corrosive levels, IGA will
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l 1
not reinitiate or propagate into IGSAC in the TMI-1 OTSGs.
Giacobbe Affidavit, 1 133.
1.
Morphology of IGA 230. Intergranular attack manifests itself with three lev-ols of severity, each with a different morphology.
First, the majority of the tube-observed IGA consists of only minor sur-fcce etching, a maximum of 1-2 grains deep (.001 inch).
This curface IGA has been identified in the industry as an etching phenomena typical of Inconel 600 tubes and is not indicative of cny increased propensity for corrosion.
Giacobbe Affidavit, 1 134.
231. The second type of IGA is called IGA " islands".
These are small patches generally 4-5 mils in depth and 3-4 mils wide where a small network of IGA exists.
The grains re-main in place, although the grain boundaries have been at-tecked.
Giacobbe Affidavit, 1 135.
232. The third type of IGA is called " pitting".
This is simply an IGA island from which some grains have fallen out.
Giacobbe Affidavit, 1 136.
2.
Evaluation of the IGA 233. The metallographic examination of the 29 TMI-1 tube acmples demonstrates that the majority of intergranular attack ic (1) located in the upper tubesheet region, and (2) associ-cted with cracks.
It also demonstrates that there is IGA with-out IGSAC, and IGSAC without IGA.
Giacobbe Affidavit, 11 137,
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139.
The specific results of the examination are as stated in paragraphs 137 - 142 of the Giacobbe Affidavit.
234. That IGA was located primarily near cracks and in the upper.tubesheet region is expected because concentration /
cggressiveness of the corrodant was highest in the upper tubesheet region, particularly in the area of the cracks.
Giacobbe Affidavit, 1 139.
235.-The magnitude of any intergranular attack is depen-d2nt on the strength of the corrodant at a particular location, the susceptibility of the material and other localized condi-tions.
Giacobbe Affidavit, 1 139.
236. No IGA islands in the_freespan were found by metal-lurgical examination and visual examination.
Giacobbe Affida-vit, 1 138.
237. Surface analysis of the freespan indicated that some-times the freespan had no sulfur present; where sulfur was de-tacted in surface film below the UTS region, concentrations ware significantly lower (less than 2%) than that observed in the vicinity of cracks found within the UTS region.
Giacobbe Affidavit, 1 141.
238. Although some IGA islands might be found on the freespan, the number and extent are not likely to be signifi-cent, given the low level of sulfur present.
Giacobbe Affida-vit, 11 139, 141.
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i 239. Examination of the effect of the IGA on the mechani-col properties of the tubes by metallographic examinations and m:chanical testing demonstrated that the material not directly offected by' IGA or IGSAC retains its original strength and ductility.
Giacobbe Affidavit, 1 144, 240. Since the' cross-sectional area occupie'd by IGA is-lends is very small, its presence has an insignificant affect on strength and ductility.
Giacobbe Affidavit, 1 144, 241. The conditions which resulted in IGA Of the TMI-1 OTSG tubes'did not adversely affect the tubes' mechanical prop-crties.
Giacobbe Affidavit, 1 144, 3.
Prevention of Propagation of IGA 242. Because the presence of a corrosive agent is neces-cory for the propagation of IGA, the same strategies which have buen instituted to control the presence of contaminants and
. conditions necessary for IGSAC will also serve to prevent prop-Egation of IGA, and to prevent IGA from propagating as IGSAC.
Giacobbe Affidavit, 1 145.
243. Tests performed on actual OTSG tubing have confirmed that propagation of IGA is not occurring and that the control m3asures will be effective.
In particular, one of the objec-
~
tives of the long term corrosion test was to study the influ-Ence of prolonged operation on IGA.
There is no evidence of further intergranular attack or IGSAC.
This is despite the fcct that these samples also contain shallow surface IGA.
In
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no cases has this IGA propagated into an intergranular stress casisted. crack.
IGA cannot be considered a precursor of IGSAC.
Giacobbe Affidavit, 11 146-47.
V.
CONCLUSION There are no genuine issues of fact requiring adjudication of TMIA's Contentions 1.a, 1.b, 1.c, 1.d, 2.a, 2.b.1, 2.b.2, cnd 2.c, and Joint Intervenors' Contentions 1(2), 1(3), and 1(5).
The dismissal of each of these contentions is therefore wcrranted as matter of law.
Summary disposition in Licensee's fcvor should be granted.
Respectfully submitted, SHAW, PITTMAN, POTTS & TROWBRIDGE f
/
Geohge'F. TrMridge, P.C.
Bruce W.
Churchill Diane E.
Burkley Wilbert Washington, II Counsel for Licensee 1800 M Street, N.W.
Washington, D.C.
20036 (202) 822-1000 Dated:
February 24, 1984
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.