ML12334A699
| ML12334A699 | |
| Person / Time | |
|---|---|
| Site: | Indian Point  (DPR-026, DPR-064) |
| Issue date: | 12/16/2011 |
| From: | Duquette D State of NY, Office of the Attorney General |
| To: | Atomic Safety and Licensing Board Panel |
| SECY RAS | |
| References | |
| RAS 21566, 50-247-LR, 50-286-LR, ASLBP 07-858-03-LR-BD01 | |
| Download: ML12334A699 (28) | |
Text
Pre-filed Written Testimony of David J. Duquette Contention NYS-5 1
UNITED STATES 1
NUCLEAR REGULATORY COMMISSION 2
BEFORE THE ATOMIC SAFETY AND LICENSING BOARD 3
x 4
In re:
Docket Nos. 50-247-LR; 50-286-LR 5
License Renewal Application Submitted by ASLBP No. 07-858-03-LR-BD01 6
Entergy Nuclear Indian Point 2, LLC, DPR-26, DPR-64 7
Entergy Nuclear Indian Point 3, LLC, and 8
Entergy Nuclear Operations, Inc.
December 16, 2011 9
x 10 PRE-FILED WRITTEN TESTIMONY OF 11 DR. DAVID J. DUQUETTE, Ph.D 12 REGARDING CONTENTION NYS-5 13 On behalf of the State of New York (NYS or the State),
14 the Office of the Attorney General hereby submits the following 15 testimony by Dr. David J. Duquette, Ph.D, regarding Contention 16 NYS-5.
17 Q.
Please state your name and address.
18 A.
David J. Duquette, Materials Engineering Consulting 19 Services, 4 North Lane, Loudonville, New York 12211.
20 Q.
What is your educational background?
21 A.
My educational and professional experience is detailed 22 in the attached curriculum vitae (CV)(Exhibit NYS000166); also 23 United States Nuclear Regulatory Commission Official Hearing Exhibit In the Matter of:
Entergy Nuclear Operations, Inc.
(Indian Point Nuclear Generating Units 2 and 3)
ASLBP #: 07-858-03-LR-BD01 Docket #: 05000247 l 05000286 Exhibit #:
Identified:
Admitted:
Withdrawn:
Rejected:
Stricken:
Other:
NYS000164-00-BD01 10/15/2012 10/15/2012 NYS000164 Submitted: December 16, 2011
Pre-filed Written Testimony of David J. Duquette Contention NYS-5 2
attached is a list of my publications, awards, and other 1
professional activities. I am a graduate of the United States 2
Coast Guard Academy and the Massachusetts Institute of 3
Technology. I performed my graduate work at the Corrosion 4
Laboratory at the Massachusetts Institute of Technology (MIT),
5 spent two years as a Research Associate at the Advanced 6
Materials Research and Development Laboratory at Pratt and 7
Whitney Aircraft prior to joining the faculty at Rensselaer 8
Polytechnic Institute.
9 Q.
What is your professional experience, particularly as 10 it relates to corrosion prevention?
11 A.
My research is primarily in the area of corrosion 12 science and engineering. I have supervised more than 50 13 graduate research dissertations in corrosion and related 14 sciences. I am the author or co-author of more than 230 15 publications and 20 book chapters. I present invited lectures 16 internationally 20 to 25 times per year. I just completed nine 17 years of service on the United States Nuclear Waste Technical 18 Review Board, having been appointed to the Board by President 19 Bush in 2002. I also maintain an active consulting practice, 20 primarily in the area of corrosion and mechanical failures. A 21 list of my publications is attached at Exhibit NYS000166.
22 Q.
Can you cite specific examples of recognition by the 23
Pre-filed Written Testimony of David J. Duquette Contention NYS-5 3
scientific community?
1 A.
I have been elected a Fellow of three learned 2
societies, ASMI (formerly the American Society of Metals), NACE 3
(formerly known as the National Association of Corrosion 4
Engineers) and ECS (the Electrochemical Society). I have 5
received the Whitney Award of NACE for outstanding corrosion 6
research, an A. v. Humboldt Senior Scientist Award from the 7
German government, as well as other awards from the scientific 8
community.
9 Q.
What materials have you reviewed in preparation for 10 your testimony?
11 A.
Among the materials I have reviewed are Entergys 12 buried and underground piping-related disclosures and NRC 13 documents and technical data as disclosed in this proceeding.
14 Q.
I show you NYS Exhibits NYS00147A-NYS00147D, 15 NYS000151, NYS000152, NYS000154, NYS000160, and NYS000166 16 through NYS000203. Do you recognize these documents?
17 A.
Yes. These are true and accurate copies of each of 18 the documents that I referred to, used and/or relied upon in 19 preparing my report and this testimony. In some cases, where 20 the document was extremely long and only a small portion is 21 relevant to my testimony, an excerpt of the document is 22 provided. If it is only an excerpt, that is noted on the first 23
Pre-filed Written Testimony of David J. Duquette Contention NYS-5 4
page of the Exhibit.
1 Q.
Did you review anything else in preparing your report 2
or this testimony?
3 A.
Yes, I reviewed other documents Entergy produced in 4
this proceeding, including previous iterations of Entergys 5
corporate documents, and concluded that they were not relevant 6
in preparing my report and this testimony. I reviewed lists of 7
the documents the State of New York, Entergy and NRC Staff 8
produced in this proceeding, using the descriptions provided on 9
the logs provided, and determined that there were none other 10 than the ones I attach as Exhibits that I needed to rely on.
11 Q.
I show you what has been marked as Exhibit NYS000165.
12 Do you recognize that document?
13 A.
Yes. It is a copy of the report that I prepared for 14 the State of New York in this proceeding. The report reflects 15 my analysis and opinions.
16 Q.
What is the purpose of your testimony?
17 A.
My testimony critiques Entergys aging management 18 program (AMP) for buried and underground pipes and tanks.
19 Q.
What is the difference between buried and underground 20 pipes?
21 A.
Entergy indicates that underground pipes include those 22 that are, and are not, in direct contact with soil, and uses the 23
Pre-filed Written Testimony of David J. Duquette Contention NYS-5 5
term buried to refer to pipes which are in direct contact with 1
soil. My report deals primarily with underground systems that 2
are in direct contact with soil so I use the term buried.
3 Q.
What, in general terms, does this report consist of?
4 A.
This report contains a discussion of factors 5
influencing corrosion of buried pipes, how to prevent corrosion 6
using coatings and cathodic protection, briefly discusses 7
corroding and leaking pipes at Indian Point and other nuclear 8
power plants, and explains my understanding and critique of 9
Entergys AMP for buried pipes.
10 Q.
What is corrosion?
11 A.
Corrosion of metals and alloys in underground piping 12 systems occurs when water comes into contact with the metal.
13 Corrosion rates of metals can be very slow in pure deaerated 14 water, but the presence of oxygen, which is admitted to the 15 water from air in most engineering cases, greatly increases the 16 corrosion rates. The corrosion reaction occurs because the 17 metal is oxidized by the oxygen with the production of hydroxyl 18 ions because of the combination of water and oxygen. The metal 19 is oxidized to a positive ion with the surrender of one or more 20 electrons. The site on which this reaction occurs is called the 21 anode. The electrons that are released from the anode 22 participate in the reduction of dissolved oxygen, to produce 23
Pre-filed Written Testimony of David J. Duquette Contention NYS-5 6
hydroxide, on local sites called cathodes. In neutral solutions 1
4<pH<10, the positively charged metal ions combine with the 2
hydroxide, which has a negative charge, to form a nearly 3
insoluble compound. When the metal is iron, the metal hydroxide 4
that is formed is generically called rust-Fe(OH)3. In 5
general, if rust is deposited on the surface of an iron based 6
material, it will have a protective role, reducing the rate of 7
oxygen arrival to the metal surface and accordingly reducing the 8
general corrosion rate.
9 Q.
What factors affect corrosion?
10 A.
Factors that affect the corrosivity of water to iron 11 based surfaces include the aforementioned levels of oxygen, the 12 conductivity of the water, the specific ion concentration of the 13 water, and the pH of the water. The conductivity of the water 14 is important because the local anodic sites on a surface can 15 only react with equivalent cathodic sites. If water has a low 16 conductivity the distance between anodes and cathodes is 17 limited. In high conductivity solutions anodes and cathodes can 18 be widely spaced allowing more interaction between surface 19 sites.
20 Q.
What types of pipes are affected by corrosion?
21 A.
The vast majority of piping systems are constructed 22 from either low carbon steel (sometimes called mild steel), or 23
Pre-filed Written Testimony of David J. Duquette Contention NYS-5 7
cast iron. Both of these materials are iron based. In near 1
neutral environments the specific structure of the steel or cast 2
iron does not have a strong effect on the corrosion behavior.
3 There are, of course many miles of pipe that are constructed of 4
stainless steel, copper alloys or, in rare cases titanium 5
alloys, as well as non-metallic materials such as HDPE or PVC.
6 However, those materials will show appreciable corrosion only 7
under rather severe conditions and accordingly I have not 8
devoted much time to these in my report, as I do not believe 9
them to be present, or present in high numbers, at Indian Point.
10 Steel and cast iron pipes can suffer from internal corrosion, 11 but my report focuses on a discussion of external corrosion of 12 pipes, specifically those in contact with soils: the factors 13 that affect external corrosion, and the steps that may be taken 14 to mitigate external corrosion of underground pipe.
15 Q.
What factors affect external corrosion?
16 A.
Soils can be considered to be a kind of poultice, or 17 sponge, when they are in contact with underground piping 18 systems. Accordingly they will hold water against a pipe 19 surface for extended periods of time even after the external 20 environment has changed from wet to dry. Thus, rain at the 21 surface of the ground will provide water to the soil, but the 22 soil may stay saturated with water for long periods after 23
Pre-filed Written Testimony of David J. Duquette Contention NYS-5 8
precipitation ceases. Soils may also contain soluble species 1
such as nitrates, sulfates, chlorides, organic compounds, etc.
2 Each of these species, alone or in combination can dramatically 3
affect corrosion rates of buried metals. The effects may range 4
from simply increasing the conductivity of the soil or by 5
reducing the effectiveness of otherwise protective corrosion 6
products such as the effects of chlorides or the possibility of 7
adding weak acid that may either deleteriously affect the 8
protective properties of corrosion product films or may make 9
soluble corrosion products (for example, chlorides or the 10 addition of weak acids that may deleteriously affect the 11 protective properties of corrosion product films or may even 12 make soluble corrosion products). The ability of a soil to 13 retain water and the chemical make-up of soil are paramount in 14 affecting the corrosion behavior of buried metals such as the 15 iron based alloys used for piping systems.
16 Q.
What steps can be taken to prevent corrosion?
17 A.
Primarily, corrosion is prevented by applying coatings 18 to the piping systems, and by cathodically protecting the pipes.
19 Q. What types of coatings are you referring to?
20 A.
Most steel and cast iron pipes that are intended for 21 long service and are buried use some form of protection from 22 corrosion by soils. Usually some level of protection is afforded 23
Pre-filed Written Testimony of David J. Duquette Contention NYS-5 9
by the application of surface coatings. These coatings range 1
from simple painted surfaces, e.g., conventional or epoxy paints 2
to the use of sacrificial coatings such as galvanizing. In some 3
cases enamels are used while in other cases bituminous coatings 4
such as coal tar are utilized. Other types of coatings include 5
tape wraps that may range from paper to polymer based tapes. In 6
many cases, if wrapping is used, a second layer of coating may 7
be applied over the wrapping. Even with coated pipes, however, 8
there is always a concern about breaks in the coatings 9
(holidays), either introduced during the coating process, 10 installation of the pipes or damage induced after installation.
11 When breaks in the coating occur the corrosion damage, in some 12 cases, can be more severe than if the there is no coating at 13 all. At breaks in the coating all of the corrosion damage may 14 be concentrated in a single location so that a deep pit may 15 perforate the pipe. Another possibility is that the interface 16 between the coating and the pipe surface may introduce an 17 effective crevice. Crevice corrosion can be especially damaging 18 because the electrolyte chemistry in a crevice tends to be much 19 more aggressive than the bulk electrolyte. In order to prevent 20 localized corrosion at holidays in the coatings, cathodic 21 protection is often used.
22 Q.
What is cathodic protection?
23
Pre-filed Written Testimony of David J. Duquette Contention NYS-5 10 A.
Cathodic protection effectively lowers the 1
electrochemical potential of steel to a potential that is below 2
that required to oxidize the steel. Another way of expressing 3
that is in the electrochemical couple between a sacrificial 4
coating such as zinc and steel, the steel becomes the cathode 5
while the zinc becomes the anode. The zinc then corrodes in a 6
sacrificial manner to protect the steel. If the zinc coats 7
the steel the steel is said to be galvanized. In many cases 8
the zinc anodes can also be placed in the same electrolyte as 9
the steel (in the case of IPEC, in water saturated soil). As 10 long as there is electrical contact between the zinc and the 11 steel the zinc will preferentially corrode. There are distinct 12 disadvantages to using zinc coatings or zinc anodes to protect 13 steel from corrosion. In the first instance (coatings) the 14 lifetime of zinc coatings is rather limited, and once the zinc 15 coating has corroded away the underlying steel is subject to 16 corrosion. In the second instance (replaceable anodes) the zinc 17 anodes also have a limited lifetime and must be monitored, 18 retrieved and replaced on a regular basis. For many buried 19 structures the maintenance period is on the order of a year.
20 From an operating plant point of view the most efficient method 21 for protecting buried structures from corrosion is an impressed 22 current system. When metals corrode the metal becomes a 23
Pre-filed Written Testimony of David J. Duquette Contention NYS-5 11 positively charged ion with the release of one or more 1
electrons. It is those electrons that are available to reduce 2
some dissolved species in the environment. In near neutral 3
environments such as water in most soils, dissolved oxygen in 4
the aqueous environment is often the species reduced to produce 5
hydroxide. The hydroxide is then available to combine with the 6
positively charged ions produced by the corrosion reaction to 7
produce a sparingly soluble metal hydroxide, or hydrated metal 8
oxide; rust in the case of iron alloys. If electrons can be 9
provided to the metal surface from an external source, the metal 10 will not become oxidized (become positively charged), and 11 corrosion will effectively be reduced or stifled altogether.
12 The application of current in this manner is known as an 13 impressed current system and requires a DC power supply to 14 deliver electrons from an anode to the metal surface. The 15 anodes in this case are usually conducting but inert materials.
16 For example graphite is often used as an anode. From a 17 thermodynamic point of view the application of current to the 18 metal lowers the electrochemical potential of the metal to a 19 level where corrosion cannot occur. The method for measuring 20 the effectiveness of impressed cathodic protection systems, 21 especially for buried steel structures, is to measure the 22 potential of the steel vs. an electrode that has a standard 23
Pre-filed Written Testimony of David J. Duquette Contention NYS-5 12 potential. The most commonly used standard electrode is a 1
copper/copper sulfate electrode that has a standard or reference 2
potential of +0.314 volts. For most impressed current systems 3
used to protect steel from corrosion, the measured potential 4
that will provide complete protection is considered to be -0.85 5
volts vs. the standard copper-copper sulfate electrode.
6 A potential disadvantage of impressed current systems for buried 7
structures is that the amount of current required to polarize 8
the steel to the protection potential criterion is proportional 9
to the surface area of the steel to be protected. For bare 10 pipes this can require a significant amount of power. However, 11 for pipes that are wrapped or coated, the cathodic protection 12 system need only protect the holidays and the power 13 requirements are greatly reduced. A further important 14 consideration is that the conductivity of the soil becomes very 15 important because of current-resistance losses in the soil.
16 Thus spacing of the anodes becomes an important aspect of any 17 impressed current cathodic protection system. Nevertheless, 18 design criteria are readily available for installation of anodes 19 if soil conductivities are known. The amount of current that is 20 required to control corrosion of buried steel structures, 21 especially pipelines, is generally controlled by applying 22 coatings to the steel. Accordingly the current is only required 23
Pre-filed Written Testimony of David J. Duquette Contention NYS-5 13 to protect the areas exposed by the holidays in the coatings.
1 The holidays may be incorporated into the coatings during 2
application, or may be induced by damage or deterioration of the 3
coatings after emplacement of the structures.
4 Q.
Turning back to aging management programs, has the 5
industry issued any guidance concerning aging management of 6
buried pipes that you are aware of?
7 A.
Yes. Both the Nuclear Energy Institute (NEI) and the 8
Electric Power Research Institute (EPRI) have issued guidance 9
documents addressing utilities approaches to managing aging of 10 buried pipes. I have reviewed NEIs Industry Guidance for the 11 Development of Inspection Plans for Buried Piping and Guideline 12 for the Management of Underground Piping and Tank Integrity, 13 also identified as NEI 09-14, and EPRIs Recommendations for an 14 Effective Program to Control the Degradation of Buried Pipe. I 15 discuss both in greater detail in my report. There may be 16 additional industry guidance documents in existence also but I 17 have not focused on those.
18 Q.
What are the main points made in the NEI and EPRI 19 reports?
20 A.
Primarily, NEIs Industry Guidance for the Development 21 of Inspection Plans for Buried Piping and Guideline for the 22 Management of Underground Piping and Tank Integrity, states 23
Pre-filed Written Testimony of David J. Duquette Contention NYS-5 14 that the specific inspections and examinations that are 1
performed will be based on degradation observed or expected, the 2
susceptibility of the pipe to leakage, the consequences of the 3
leak, and the location of the pipe. The document further details 4
the number of inspections that should be required, especially 5
for those lines that carry Licensed Material.
6 The Buried Pipe Integrity Task Force, which is affiliated 7
with NEI, released a report which cites criteria for inspection 8
including that depending on pipe length, two, or in some cases 9
three direct examinations of the highest susceptible locations, 10 with acceptable results, may be sufficient to demonstrate 11 reasonable assurance. The phraseology highest susceptible 12 locations is critical since susceptibility of buried pipes to 13 corrosion is determined by the characteristics of the soil/water 14 combination at all locations at a given site. Accordingly it is 15 paramount that, as a minimum, soil conductivity, chemistry, 16 drainage, and water retention are characterized to determine the 17 best locations for direct measurements.
18 The EPRI program contains six elements: (1) developing 19 a corporate program including training, implementing procedures, 20 documentation, and performance indicators; (2) prioritizing 21 buried pipe systems and locations to be inspected based on risk 22 of failure (including likelihood and consequence of failure);
23
Pre-filed Written Testimony of David J. Duquette Contention NYS-5 15 (3) performing direct inspections to quantify the degree of 1
degradation and damage; (4) evaluating the fitness-for-service 2
of degraded buried pipes; (5) selecting the appropriate repair 3
technique where required, including both non-welded and welded 4
repairs; and (6) taking preventive actions to reduce the risk 5
(likelihood and consequence) of future leaks or failures. The 6
EPRI report recommends that specify not only periodic and 7
opportunistic inspections, but inspections based on local 8
conditions of the piping. Both the NEI and EPRI documents 9
recommend cathodic protection for critical piping systems.
10 Q.
Do you believe an aging management program is 11 necessary to manage the aging of buried pipes at Indian Point?
12 A.
Yes. The fact that Indian Point has already 13 experienced leaks, detailed in my report, indicates to me that 14 there are already corrosion problems at the facility and that 15 appropriate measures must be taken to prevent such piping 16 failures in the future.
17 Q.
Has Entergy agreed that it needs an aging management 18 plan to address aging of buried pipes and tanks?
19 A.
Yes. I also note that Entergy has endorsed the 20 EPRI report and I believe Entergy took part in drafting the NEI 21 initiative also.
22 Q.
What is your understanding of what constitutes 23
Pre-filed Written Testimony of David J. Duquette Contention NYS-5 16 Entergys AMP?
1 A.
As I understand it, Entergys AMP is contained in its 2
License Renewal Application (LRA), section B.1.6, as well as 3
subsequent commitments and/or license renewal amendments. The 4
LRA at Section B.1.6 said only that Entergy would take 5
preventive measures to mitigate corrosion and perform 6
inspections to manage the effects of corrosion and provided for 7
only opportunistic inspections. The AMP states that the 8
inspection program will be consistent with program attributes 9
described in NUREG-1801,Section XI.M34, but offers no details.
10 This is a version of the GALL Report which has since been 11 superseded. Obviously, these bare statements are insufficient to 12 provide an understanding of what exactly Entergy would be doing 13 to manage aging of buried pipes.
14 Subsequently, Entergy revised its LRA to include a new 15 commitment, in which Entergy said it would:
16 include in the Buried Piping and Tanks Inspection 17 Program described in LRA Section B.1.6 a risk 18 assessment of in-scope buried piping and tanks 19 that includes consideration of the impacts of 20 buried piping or tank leakage and of conditions 21 affecting the risk for corrosion. Classify pipe 22 segments and tanks as having a high, medium, or 23 low impact of leakage on reliable plant 24 operation. Determine corrosion risk through 25 consideration of piping or tank material, soil 26 resistivity, drainage, the presence of cathodic 27 protection and the type of coating. Establish 28 inspection priority and frequency for periodic 29
Pre-filed Written Testimony of David J. Duquette Contention NYS-5 17 inspections of the in-scope piping and tanks 1
based on the results of the risk assessment.
2 Perform inspections using inspection techniques 3
with demonstrated effectiveness.
4 5
This commitment was made in 2009 in a document identified 6
as NL-09-111, Attachment 2. No information is provided 7
concerning what factors Entergy will take into account in 8
performing a risk assessment or to classify its pipes, or how 9
frequently Entergy will inspect pipes according to their 10 priority, among other things. Moreover, Entergy makes no 11 commitment to taking any mitigative measures if problems are 12 found.
13 Q.
Has Entergy provided other information that is related 14 to its AMP?
15 A.
Yes. Entergy has produced a number of documents which 16 are not explicitly part of its LRA, AMP. These include CEP-UPT-17 0100 Underground Piping and Tanks Inspection and Monitoring, 18 issued 31 October 2011; EN-DC-343 (Rev. 4), Underground Piping 19 and Tanks Inspection and Monitoring Program, an inclusion in 20 the IPEC Nuclear Management Manual, issued May 16, 2011; and 21 SEP-UIP-IPEC, Indian Point 2 & 3 Underground Components 22 Inspection Plan approved April 29, 2011. I do not understand 23 these to be part of Entergys LRA but have addressed them in my 24 report.
25
Pre-filed Written Testimony of David J. Duquette Contention NYS-5 18 Q.
What, generally, is your conclusion about the adequacy 1
of Entergys AMP for buried pipes and tanks?
2 A.
There is nothing in the AMP at all to determine what 3
Entergy is committing to doing except a conceptual framework. It 4
is wholly deficient. Even if these other documents (which are 5
not part of the LRA) were adopted, Entergy still would not have 6
an adequate AMP, for numerous reasons.
7 Q.
What are the specific reasons you believe Entergys 8
AMP for buried pipes is deficient?
9 A.
There are many reasons. First, Entergys AMP, as 10 I described it above, contains very few actual commitments.
11 It is conceptual and aspirational in nature, stating only 12 that it will will be effective for managing aging effects 13 since it will incorporate proven monitoring techniques, 14 acceptance criteria, corrective actions, and administrative 15 controls without including those monitoring techniques, 16 acceptance criteria, corrective actions, or administrative 17 controls. Likewise, the newest revised commitment, in the 18 attachment to NL-11-090, states that Entergy will classify 19 pipe segments, determine corrosion risk through 20 consideration of piping or tank material, soil resistivity, 21 drainage, the presence of cathodic protection and the type 22 of coating, establish inspection priority and frequency for 23
Pre-filed Written Testimony of David J. Duquette Contention NYS-5 19 periodic inspections of the in-scope piping and tanks based 1
on the results of the risk assessment, and perform 2
inspections using inspection techniques with demonstrated 3
effectiveness - but Entergy offers no pipe classification, 4
determination of corrosion risk, inspection priority or 5
frequency list, or specific inspection techniques it will 6
use. Without seeing the actual program, including 7
acceptance criteria and commitments to undertake repairs 8
that Entergy intends to adopt, it is not possible to 9
determine at this time whether the inspection program will 10 meet the requirements for an adequate AMP.
11 Q.
Do the corporate documents Entergy provided shed 12 light on these missing details?
13 A.
Yes, Entergy has offered more detail in corporate 14 documents it disclosed (of primary relevance EN-DC-343 15 (Rev. 4), CEP-UPT-0100, and SEP-UIP-IPEC), but these 16 internal documents are not included in the commitment from 17 Entergy or made a part of the LRA. They are presumably 18 subject to modification by Entergy without NRC approval and 19 would not be obligations imposed on Entergy by a renewed 20 license. The procedures and oversight section of EN-DC-343 21 refers to Entergys document CEP-UPT-0100 as the 22 requirement associated with the scope, risk ranking and 23
Pre-filed Written Testimony of David J. Duquette Contention NYS-5 20 examination techniques to be followed. In the risk ranking 1
section, an assemblage of a set of as-built drawings is 2
required. It is not clear if such a set actually exists or 3
if it was or will be provided for review in the LRA 4
licensing process.
5 Q.
You said that even if Entergys corporate 6
documents were adopted into the LRA, Entergys AMP would 7
still fall short. What do you mean by that?
8 A.
For example, the procedures and oversight section of 9
EN-DC-343 refers to Entergys document CEP-UPT-0100 as the 10 requirement associated with the scope, risk ranking and 11 examination techniques to be followed. In the risk ranking 12 section, an assemblage of a set of as-built drawings is 13 required. It is not clear if such a set actually exists or if 14 it was or will be provided for review in the LRA licensing 15 process.
16 Additionally, EN-DC-343 calls for each plant to develop its 17 own site-specific Underground Piping and Tanks Inspection and 18 Monitoring Program. However, I have not been provided with an 19 Indian Point-specific Program, and have reviewed only Entergys 20 fleetwide program. Nor am I aware that one exists. Thus, I 21 cannot assess what Indian Points specific program will entail.
22 With regard to repairs, EN-DC-343 says only that 23
Pre-filed Written Testimony of David J. Duquette Contention NYS-5 21 Contingency planning should be in place for prompt 1
implementation in case an underground segment fails to meet 2
acceptance criteria. (EN-DC-343, Rev. 4 at 16.) But Entergy 3
has not provided its acceptance criteria, making it impossible 4
to assess its effectiveness.
5 EN-DC-343 calls for newly installed piping to be coated, 6
that proper use of fill should be used when excavating and re-7 burying components, and that baseline inspections should be 8
performed prior to piping installation. However, this is not an 9
aging management program. These are simply best practices for 10 any underground pipes, and do not indicate any efforts that will 11 be taken to manage already-aging pipes such as those present at 12 Indian Point.
13 Q.
What is the second reason you believe Entergys AMP is 14 deficient?
15 A.
Second, an inspection program, per se, is not adequate to 16 ensure the safe operation of engineering systems. The 17 acceptability of the results of the inspection program, 18 including the criteria to be applied to continued operation, 19 remediation, or replacement, should be specified. Entergy has 20 not identified when it will take mitigative measures if problems 21 are found, or what those mitigative measures will be. Also, 22 although Entergy says it will conduct many pre-period of 23
Pre-filed Written Testimony of David J. Duquette Contention NYS-5 22 extended operation inspections, it is not clear how many 1
inspections, if any, have already taken place that Entergy is 2
counting against this requirement but that were not conducted to 3
the standards to which Entergys new program would dictate they 4
should be conducted.
5 Q.
Are there other reasons why you believe Entergys AMP 6
is deficient?
7 A.
Yes. Entergy has not committed to reinstalling 8
cathodic protection at Indian Point, despite NEI, EPRI, 9
Entergys own corporate guidance documents and consultants 10 reports, and NRC Staff in the new GALL Report revision stressing 11 the importance of cathodic protection. Apart from the industry-12 wide focus on cathodic protection in general, Entergys own 13 studies show that the soils at Indian Point are mildly to 14 moderately corrosive, warranting cathodic protection as an 15 objective matter. Entergys consultant PCA Engineers, issued a 16 report called which assessed the status of cathodic protection 17 at Indian Point, and found a latent organization weakness in 18 that the risk associated with the lack of a CP system was not 19 clearly understood by personnel approving resource allocation to 20 complete the modification process. PCA Engineers found that 21 nearly all cathodic protection systems at Indian Point were out 22 of service, and recommended reinstallation. Entergy did not 23
Pre-filed Written Testimony of David J. Duquette Contention NYS-5 23 take PCA Engineers recommendation and neither Entergys AMP nor 1
its corporate documents even reference the PCA study.
2 This is another example of where Entergys corporate 3
documents do not say the same thing as their AMP. EN-DC-343 says 4
that for plants with installed cathodic protection systems for 5
underground piping and tanks, Entergy should ensure that the 6
proper operation of the systems is verified semi-annually. EN-7 DC-343 calls for cathodic protection degradation affecting 8
safety-related structures, systems, and components (SSCs) to be 9
repaired with the Work Week T-process, which I presume to be 10 an expeditious schedule (as compared with the non-safety-related 11 SSCs, which are to be repaired within only six months of 12 detection of a problem). CEP-UPT-0100 states that existing 13
[cathodic protection] systems may be upgraded or a new [cathodic 14 protection] system installed and requires that plants with 15 installed cathodic protection systems verify proper operation of 16 these systems, periodically test them, ensure the system is 17 evaluated in accordance with EN-DC-343, put an individual in 18 charge of the cathodic protection system, and verify that 19 cathodic protection systems are corrected on a schedule 20 commensurate with the safety significance of the system or 21 component being protected. But Entergy knows there is 22 widespread cathodic protection system degradation of both safety 23
Pre-filed Written Testimony of David J. Duquette Contention NYS-5 24 and non-safety-related SSCs at Indian Point, and has not 1
committed to repairing these systems. Given that Entergy has 2
chosen to follow an outdated version of NUREG 1801 specifically 3
because it does not require cathodic protection, it does not 4
appear that Entergy is proposing to implement EN-DC-343 or CEP-5 UPT-0100 at Indian Point.
6 Q. Did PCA Engineers find the soils at Indian Point to be 7
corrosive?
8 A.
Yes. Soil resistivity measurements conducted by PCA at 9
a limited number of locations indicated that the resistivity 10 ranged from approximately 8,000 ohms/cm to approximately 63,000 11 ohm/cm. Eight of the locations indicated resistivities in the 12 10,000 ohm/cm to 30,000 ohm/cm range. Soils with resistivities 13 in that range are considered to be mildly corrosive. One 14 location that measured a resistivity of approximately 8,000 15 ohm/cm is considered to be moderately corrosive.
16 Q.
Are there other reasons you believe Entergys AMP for 17 buried pipes is insufficient?
18 A.
Yes. I find that Entergy has made a number of 19 inconsistent statements concerning what exactly it plans to do.
20 In addition to the above example about cathodic protection, for 21 example, Entergy says its inspection intervals are determined by 22 using inspection priority. For buried sections with a 23
Pre-filed Written Testimony of David J. Duquette Contention NYS-5 25 high/high, high/medium, or medium/high impact-corrosion risk 1
(which would include the piping systems within the scope of this 2
contention, since Entergy has designated all radioactive fluid-3 containing piping systems high priority in CEP-UPT-0100),
4 inspections are supposed to be done every ten years. As an 5
initial matter, such a long period between inspections is 6
questionable, especially for the highest risk piping systems.
7 But in its response to NRCs most recent RAI on buried pipes, 8
Entergy stated it would perform more than 80 inspections. It is 9
not clear how Entergys response to the RAI squares with the 10 information in Entergys corporate documents setting inspection 11 priority and scheduling every ten years. It bears repeating 12 here again that Entergy has not committed to either of these 13 inspection schedule, as neither appears in the AMP or in a 14 regulatory commitment, and that the only thing Entergy has 15 committed to in its AMP is creating an unspecified plan that 16 will manage aging.
17 Q.
In your opinion, is Entergys AMP for buried pipes and 18 tanks adequate to manage aging even though it does not require 19 cathodic protection?
20 A.
No.
21 Q.
Are you aware that NRC Staff, in its Supplemental 22 Safety Evaluation Report, found that the AMP was sufficient even 23
Pre-filed Written Testimony of David J. Duquette Contention NYS-5 26 though it does not require cathodic protection?
1 A.
Yes. I do not agree with that conclusion.
2 Q.
What do you recommend Entergy do in order to create a 3
sufficient AMP for buried pipes?
4 A.
I recommend that Entergy adopt the recommendations of 5
the NEI and EPRI reports, including cathodic protection of 6
buried pipes, follow the dictates of NUREG-1801, Revision 2, 7
Section XI.M41, clearly identify acceptance criteria for 8
corrosion damage to buried pipes, and clearly state the repair 9
and remediation procedures to be followed if the corrosion 10 damage lies outside of the acceptance criteria.
11 Q.
Why do you believe cathodic protection is important at 12 Indian Point?
13 A.
Plant conditions at IPEC indicate that the soil is 14 corrosive. As I discuss in my report, Entergys inspections 15 indicate that in at least one location, piping degradation has 16 reduced pipe wall thickness by 85% (that is, to only 15%). IPEC 17 has experienced through-wall failures in the condensate storage 18 line, and Entergys own consultants have issued a report 19 indicating that the soils are corrosive.
20 Q.
Did you see any mention of Unit 1s buried piping 21 systems in the documents you reference above?
22 A.
No.
23
Pre-filed Written Testimony of David J. Duquette Contention NYS-5 27 Q.
Have you now completed your initial testimony 1
regarding the contention?
2 A.
Yes.
3 I have reviewed all the exhibits referenced herein. True 4
and accurate copies are attached.
5
Pre-filed Written Testimony of David J. Duquette Contention NYS-5 28 UNITED STATES 1
NUCLEAR REGULATORY COMMISSION 2
BEFORE THE ATOMIC SAFETY AND LICENSING BOARD 3
x 4
In re:
Docket Nos. 50-247-LR; 50-286-LR 5
License Renewal Application Submitted by ASLBP No. 07-858-03-LR-BD01 6
Entergy Nuclear Indian Point 2, LLC, DPR-26, DPR-64 7
Entergy Nuclear Indian Point 3, LLC, and 8
Entergy Nuclear Operations, Inc.
December 16, 2011 9
x 10 DECLARATION OF DAVID J. DUQUETTE 11 I, David J. Duquette, do hereby declare under penalty of 12 perjury that my statements in the foregoing testimony and my 13 statement of professional qualifications are true and correct to 14 the best of my knowledge and belief.
15 Executed in Accord with 10 C.F.R. § 2.304(d)
David J. Duquette, Ph.D.
Materials Engineering Consulting Services 4 North Lane Loudonville, New York 12211 Tel: 518 276 6490 Fax: 518 462 1206 Email: duqued@rpi.edu December 16, 2011