ML081120060
| ML081120060 | |
| Person / Time | |
|---|---|
| Site: | Pilgrim |
| Issue date: | 03/06/2008 |
| From: | Gundersen A Pilgrim Watch |
| To: | Atomic Safety and Licensing Board Panel |
| SECY RAS | |
| References | |
| 50-293-LR, ASLBP 06-848-02-LR, Pilgrim-Intervenor 13, RAS J-43 | |
| Download: ML081120060 (57) | |
Text
UNITED STATES OF AMERICA NUCLEAR REGULATORY COMMISSION BEFORE THE ATOMIC SAFETY AND LICENSING BOARD In the matter of Docket # 50-293 Entergy Corporation Pilgrim Nuclear Power Station License Renewal Application TESTIMONY OF ARNOLD GUNDERSEN SUPPORTING PILGRIM WATCH'S CONTENTION 1 March 6, 2008 U.S. MIJC WAREGUJATOYCW01SSION In1 E~terOy (Pilgrim NM.le.
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UNITED STATES OF AMERICA NUCLEAR REGULATORY COMMISSION BEFORE THE ATOMIC SAFETY AND LICENSING BOARD Page 2 of 56
In the matter of Docket # 50-293 Entergy Corporation Pilgrim Nuclear Power Station License Renewal Application March 6, 2008 TESTIMONY OF ARNOLD GUNDERSEN ON PILGRIM WATCH'S CONTENTION 1 REGARDING THE ADEQUACY OF THE AGING MANAGEMENT PROGRAM FOR BURIED PIPES AND TANKS 1
WITNESS BACKGROUND 2
Q1.
Please state your name.
3 A. Arnold Gundersen 4
Q2.
Please state your residential address.
5 A. 376 Appletree Point Road, Burlington, VT 05408 6
Q3.
Please summarize your educational and professional experience.
7 A. My CV is attached. I have a bachelor's and a Master's Degree in Nuclear 8
Engineering from Rensselaer Polytechnic Institute (RPI) cum laude; and began 9
my career as a reactor operator and instructor in 1971 and progressed to the 10 position of Senior Vice President for a nuclear licensee. My more than 35 years 11 of professional nuclear experience include and are not limited to: Nuclear Plant 12 Operation, Nuclear Management, Nuclear Safety Assessments, Reliability 13 Engineering, In-service Inspection, Criticality Analysis, Licensing, Engineering 14 Management, Thermohydraulics, Radioactive Waste Processes, 15 Decommissioning, Waste Disposal, Structural Engineering Assessments, Cooling 16 Tower Operation, Cooling Tower Plumes, Nuclear Fuel Rack Design and
1 Manufacturing, Nuclear Equipment Design and Manufacturing, Prudency 2
Defense, Employee Awareness Programs, Public Relations, Contract 3
Administration, Technical Patents, Archival Storage and Document Control.
4 Q4.
What is the purpose of your testimony?
5 A. My testimony is in support of Pilgrim Watch's Contention 1 that the programs 6
and procedures Entergy uses for the Aging Management of the Pilgrim Nuclear 7
Power Plant's buried pipes are insufficient. Moreover, in my review of the 8
record, the Order has changed significantly during the course of these 9
proceedings.
10 11 OVERVIEW 12 Q5.
What buried pipes and tanks within the "revised scope" contain or may 13 contain radioactive liquid?
14 A. The buried pipes connected to the following systems: Condensate Storage System 15 (CSS); Salt Water Service System (SSW), discharge piping; and the Standby Gas 16 Treatment System (SGTS).
17 18 Entergy's Testimony and the questions issued by the ASLB have focused solely 19 on the CSS and SSW Discharge piping; however both are silent on the SGTS 20 (Standby Gas Treatment System) piping. The SGTS piping may indeed have 21 radioactive liquids, perhaps not in the.same quantity as the CSS, however, in my 22 review of the evidence, the volume of contaminated water was not specified in the 23 Order.
Page 4 of 56
1 2
The SGTS is used to improve the performance of the condenser by enabling it to 3
"draw" more steam through the turbine. The condenser is maintained at a pressure 4
that is as low as possible below atmospheric pressure. The Standby Gas 5
Treatment System must extract air from the condenser in order to maintain it at a 6
lower pressure than the outside air pressure. Furthermore, since part of this 7
system includes a re-combiner to combine hydrogen and oxygen atoms to form 8
water molecules, the non-condensable isotopes (xenon, krypton, iodine, etc) are 9
transmitted via piping from the AOG Building to charcoal beds and then released 10 from the main stack vent.
11 12 This stream of non-condensable gases is contaminated with radioactive isotopes 13 from neutron activation of the reactor water and from leaks in the fuel. While the 14 preponderant gaseous activation product is Nitrogen-16, it has a very short half 15 life and therefore is not a concern for this analysis. However, leaking fuel 16 contributes gaseous fission products and their decay related daughter products, 17 which is of great concern to this analysis. For instance, the short lived Krypton-18 90 is a gaseous fission product that decays to the long lived isotope Strontium-90.
19 Therefore the Standby Gas Treatment System Piping contains many isotopes 20 beyond the original noble gases that it is designed to contain including Strontium-21 90 which is a known bone seeking carcinogen with a known 30-year half-life.
22 23 According to industry documentation, Pilgrim, like many reactors around the Page 5 of 56
1 country, has used fuel assemblies with defective cladding. Therefore, when the 2
plant shuts down during an outage, or at any other time of shutdown, radioactive 3
water might collect Standby Gas Treatment System and potentially leak from the 4
SGTS piping.
5 6
Q6.
From an engineering viewpoint, what is the basic function of a pipe?
7 A. The basic function of a pipe is to carry or transmit the contents inside the pipe to 8
another location while also protecting the environment by keeping its contents 9
from seeping out into the environment, or in other words, pipes must not leak any 10 contents into the environment. Pipes must also keep the liquid inside the pipe, and 11 not let it travel into the ground. A pipe cannot deliver water as designed if it has 12 holes or cracks. Leaks or breaks are not part of the design. At a nuclear power 13 plant like Entergy Nuclear Pilgrim, pipe leakage is especially critical given that 14 many pipes are contaminated with radioactivity that might leach into water tables 15 and Pilgrim's surrounding fragile estuaries.
16 17 REQUIREMENTS 18 Q7.
10 C.F.R. § 54.21(a)(3) requires that Entergy's license renewal application 19 show that for these pipes, "...the effects of aging will be adequately managed so 20 that the intended function(s) will be maintained consistent with the CLB for the 21 period of extended operation." Based on your professional experience, what 22 does "adequately managed" mean?
23 A. Based upon my professional experience of more than 35-years as a nuclear Page 6 of 56
1 engineer, "adequately managed" means that the licensee has demonstrated with 2
"reasonable assurance" at approximately a 95% level of certainty that the effects 3
of aging will be managed so that the intended function of the pipes will be 4
maintained consistent with the Current Licensing Basis (CLB) during the license 5
extension and that the pipes in question will perform their respective safety 6
functions. It does not mean a requirement to demonstrate absolute assurance that 7
structures or components will not fail.
8 9
The 95 percent confidence standard was accepted and applied by the NRC as the 10 measure of "reasonable assurance" [Transcript of ACRS Meeting (Sept. 6, 2001),
11 Citizens' Ex. 62 at 3].
12 13 Therefore, it is my professional opinion that the Applicant must be held to the 14 same reasonable assurance standard of proof by the ASLB that the NRC presented 15 to support its assertion that its programs and procedures for managing the aging of 16 these pipes does in fact provide reasonable assurance to relicense Entergy Nuclear 17 Pilgrim Station. Neither the Applicant nor the NRC may simply rely upon 18 "engineering judgment", unless that judgment is grounded in facts that provide 19 the 95% level of certainty. If a factual analysis is unavailable, the Applicant's 20 judgment may be driven by convenience and/or economics. Assuring a 95%
21 confidence level for license extension upon a 40-year-old reactor is critical, 22 especially given that NRC has loosened regulations to make them less 23 prescriptive by allowing for voluntary initiatives rather than promulgating Page 7 of 56
1 measurable regulations.
2 3
Q8.
Besides, 10 C.F.R. § 54.21(a)(3) requires that Entergy's license renewal 4
application show that for these pipes, "...the effects of aging will be adequately 5
managed so that the intended function(s) will be maintained consistent with the 6
CLB for the period of extended operation." What does consistent with the CLB 7
(Current Licensing Basis) for the period of extended operation mean?
8 9
A.
In my opinion, consistent with the CLB (Current Licensing Basis) for the period 10 of extended operation means that Entergy is required to fully comply with its 11 license and all NRC Regulations.
12 13 Q9.
Therefore, in your professional experience, would you list some key NRC 14 regulations that pertain to buried piping that apply to Pilgrim and explain your 15 reasoning why Entergy is required to comply with said regulations?
16 A.
Yes, let me answer this by first listing the regulation and guidance and then 17 discussing the importance of each one.
18 10 CFR Appendix B to Part 50 - Quality Assurance Criteria for Nuclear 19 Power Plants and Fuel Reprocessing Plants, XVI. Corrective Action that 20 reads:
21 "Measures shall be established to assure that conditions 22 adverse to quality, such as
- failures, malfunctions, 23 deficiencies, deviations, defective material and equipment, 24 and nonconformances are promptly identified and Page 8 of 56
1 corrected. In the case of significant conditions adverse to 2
quality, the measures shall assure that the cause of the 3
condition is determined and corrective action taken to 4
preclude repetition. The identification of the significant 5
condition adverse to quality, the cause of the condition, and 6
the corrective action taken shall be documented and 7
reported to appropriate levels of management."
8 9
Appendix C. Article C. 12, "O perability Leakage from Class 1, 2, and 3 10 Components",
to NRC Inspection Manual Part
- 9900, Technical 11 Guidance, Attachment to RIS 2005-20 states:
12 "Upon discovery of leakage from a Class 1,2 or 3 pressure 13 boundary component (pipe wall, valve body, pump casing, 14 etc), the licensee must declare the component 15 inoperable."
16 17 1 believe these rules and guidance make sense. Obviously it is important that 18 leakage not occur so that Pilgrim does not unknowingly:
19 0 expose members of the public to excessive doses of radiation by 20 radioactive leaks migrating offsite; 21 0 that workers on site are not exposed via inhalation, especially in the 22 winter or during heavy rains when radioactive contaminated water 23 could rise to the surface and become airborne; 24
& for decommissioning purposes to reduce Pilgrim becoming an 25 expensive legacy site; 26 0 and lastly to prevent failures that would impact the safety of the Page 9 of 56
1 system.
2 More importantly, the declaration of inoperability assures that a repair will 3
occur in a timely fashion so as to meet the NRC statutory requirements of not 4
jeopardizing public health and safety.
5 6
Q10.
In your opinion, do the answers Entergy and NRC staff applied to the 7
ASLB's questions regarding leakage from the CSS and SWW discharge pipes 8
incorrectly imply that leaks are acceptable?
9 10 A.
First, let me summarize what Entergy and the NRC staff has after which I will 11 state my professional opinion.
12 0 According to NRC regulations and guidance leaks are not acceptable. If 13 pipes leak, they must be fixed, as the component is inoperable.
14 Since the ASLB questions address an entirely separate issue, it is difficult 15 to determine if in fact Entergy and NRC staff are ignoring NRC 16 regulations and guidance in their answers.
17 In my opinion, the NRC, Pilgrim, and the ASLB seem to have turned the 18 issue of underground leakage on its head. If the leaking pipe or tank were 19 above ground, the system would be declared inoperable and fixed, 20 regardless of the size of the leak. I am unaware of any NRC regulations 21 that differentiate between the severity of.a leak as opposed to the existence 22 of an underground leak. Let me elaborate.
23 Page 10 of 56
1 To begin: The ASLB's question (c) read, "UWhat is the smallest leakage 2
rate that could reasonably be expected to challenge the ability of the CSS 3
system piping at issue to fail to satisfy its intended function(s) as relevant 4
for license renewal? Provide a detailed statement of the basis of and 5
sources for your answer.
6 Entergy responded that, "At the outset, no amount or rate of 7
leakage from the CSS buried piping could challenge.the 8
ability of the HPCI and RCIC systems to perform their 9
intended functions. While the CSTs are the preferred 10 source of water for HPCI and RCIC (because of water 11 purity), the assured (i.e. safety-related) source of water is 12 the torus. If the CSS were unable to deliver water to the 13 HPCI and RCIC pumps, for any reason, the HPCI and 14 RCIC suction path would be switched to the torus."
15 And, "While leakage from the CSS piping would not 16 prevent the HPCI and RCIC functions from being 17 performed, it could affect the ability of the CSTs to serve as 18 the preferred source of water for HPCI and RCIC. Make-up 19 to the CSTs is supplied from the demineralized water 20 storage tank (DWST). The demineralized water transfer 21 system (DWTS), which transfers water from the DWST to 22 either CST, is supplied by two pumps each of which is 23 rated at 110 gallons per minute. Since only one of the two 24 pumps is normally in service, a maximum of 110 gallons 25 per minute of makeup could be provided to either CST to 26 compensate for a leak. If leakage from buried CSS piping 27 were to exceed this rate, the volume of water in the CST 28 could not be maintained, which would eventually impact 29 its ability to provide the preferred source of water to the Page 11 of 56
2 3
The smallest leakage rate that would challenge the ability 4
of a CST to serve as the preferred source for HPCI and 5
RCIC within a 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> interval is on the order of 500 gallons 6
per minute. With regard to a leakage rate that would be 7
detected by the 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> monitoring, one could hypothesize 8
the following: Assume initial tank level is at the procedural 9
minimum of 30 feet. A leak develops such that the level 10 drops to the alarm setpoint (12.5 feet) just before the next 4 11 hour1.273148e-4 days <br />0.00306 hours <br />1.818783e-5 weeks <br />4.1855e-6 months <br /> observation. In this case, a level reduction of 17.5 feet 12 over a 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> period would represent a leakage rate of over 13 500 gpm. Because this leakage rate exceeds the make-up 14 capability of the DWTS, the capability of the CST to act as 15 the preferred source would not be recovered without 16 corrective action. However, such a large leakage rate would 17 likely cause visible effects, such as water leaking into the 18 building, erosion of exterior ground surfaces, or significant 19 amounts of visible water in exterior areas, that would be 20 noticeable well within the 4-hour observation period.
21 22
- 1. For example, if the leakage rate from a CST were 23 220 gallons per minute (twice the makeup rate of a 24 DWTS pump), it would take about 20 hours2.314815e-4 days <br />0.00556 hours <br />3.306878e-5 weeks <br />7.61e-6 months <br /> before 25 the CST level would be reduced below the level 26 reserved for HPCI and RCIC. The volume of water 27 that would have to be lost to reduce the water level 28 in the CST from its normal minimum (30 feet) to 29 the level reserved for HPCI and RCIC (10.5 feet) is 30 136,500 gallons ([30 feet -
10.5 feet] x 7,000 31 gallons/foot). Assuming a single DWST pump Page 12 of 56
1 provides makeup at its rated capacity, a leak of 220 2
gallons per minute would correspond to a net loss 3
rate of 1 10 gallons per minute. (220 gallons per 4
minute leakage rate minus 110 gallons per minute 5
makeup rate). The time it would take for this net 6
loss rate to reduce the volume by 136,500 gallons 7
is: 136,500 gallons -- [110 gallons per minute x 60 8
minutes/hour] -20 hours.
9 10 Leakage from the buried piping would not be 11 expected to affect the flow of water through the 12 buried CSS line. The positive pressure in the piping 13 would cause any leakage to flow out of the line, not 14 in, so leakage would not be expected to introduce 15 debris or cause blockage of the piping. Further, the 16 key consideration in system operation,is 17 maintaining adequate suction pressure (i.e. net 18 positive suction head) to the pumps. The CST and 19 piping system design, in conjunction with the 20 setpoints for swapping the HPCI and RCIC suction 21 source to the torus, ensure adequate net positive 22 suction head to the pumps. Thus, while some 23 amount of water would be diverted from the piping 24 to the ground which would serve to increase the rate 25 of level decrease in the CST, this would merely Page 13 of 56
1 accelerate the time at which the suction swap to the 2
torus would be required. HPCI and RCIC functions 3
would be unaffected.
4 5
ASLB 2. With Regard to the Salt Service Water ("SSW") system - Explain 6
how any leak in the SSW buriedpipes that might carry radioactive water from 7
the plant to the canal that dumps into the bay could challenge the ability of 8
the SSW system to satisfy its intended function(s)? For example, is there any 9
correlation between any potential leak in those pipes and any potential plugs 10 in them that might prevent them from discharging water from the SSW, 11 thereby impeding the ability to remove heat from the RBCCW? Provide a 12 detailed statement of the basis of and sources for your answer.
13 14 Entergy Response: The SSW system discharge piping is an 15 open-ended run of unobstructed piping. Leakage is 16 generally not a concern for an open-ended discharge pipe.
17 18 The external surface of the carbon steel discharge pipe is 19 protected by either a coal tar wrapping or epoxy coating.
20 The interior of the discharge piping is protected by a 1/2" 21 thick cured-in-place-pipe (CIPP) lining, consisting of 22 polyester felt material with a resin and catalyst system or an 23 epoxy resin and hardener system, which forms a smooth, 24 hard inner protective surface. These coatings and linings 25 are designed to prevent internal and external corrosion. For 26 leakage to occur, there would have to be a failure of the 27 external coating, a through wall failure of the metal pipe, 28 and a failure of the CIPP liner. The likelihood of these three Page 14 of 56
1 barriers being breached is remote.
2 3
Further, in the unlikely event of leakage from the discharge 4
piping, such leakage would not be expected to have any 5
effect on the SSW system's ability to perform its intended 6
function. Leakage would simply result in some salt water 7
being discharged to the ground rather than to the bay.
8 Further, because there is a positive pressure differential 9
within the discharge piping, in-leakage of dirt or debris that 10 might block the discharge line would not be expected.
11 Indeed, even if dirt were introduced, it would likely be 12 swept away with the discharge flow. Moreover, if dirt or 13 debris were somehow accumulating, any significant 14 diminishment of flow would be detected by the daily 15 monitoring of the heat exchange capability of the SSW 16 system. Thus, only if degradation of the SSW discharge 17 piping were somehow to progress to the point of pipe 18 collapse would the SSW system's ability to satisfy its 19 intended function be challenged. The design and 20 construction of the SSW discharge piping, including 21 external coatings and internal liner, make such a failure 22 mechanism not credible."
23 24 NRC Staff Response ASLB Ouestions Regarding CSS 25 ASLB Q. What is the smallest leakage rate that could reasonably be 26 expected to challenge the ability of the CSS system piping at issue to 27 fail to satisfy its intended function(s) as relevant for license renewal?
28 Provide a detailed statement of the basis of the sources for your 29 answer?
Page 15 of 56
1 NRC Staff response at 5: "In sum, there is no CS system 2
leak rate that would challenge HPCI/RCIC performance for 3
purposes of § 54.4(a)(1), and only a very large leak would 4
compromise the performance for purposes of § 54.4(a)(3)."
5 6
In addition, according to 10 CFR 50 Appendix B leaks are required to be repaired 7
and Entergy must look for leaks and fix them when found in order to comply with 8
its CLB during the relicensed period. In my opinion, this regulation makes 9
absolute sense because if there are any unidentified leaks in the aforementioned 10 pipes, such leaks may jeopardize the design and intended function of safety 11 related systems and components at the Pilgrim Nuclear Power Station.
12 13 Therefore, in my opinion, there are at least three possible scenarios:
14
- 1. In the first scenario, there may be a loss of intended safety function if a 15 leak has occurred and has gone undetected by the Applicant's AMP. If a 16 leak could spontaneously heal itself, we would not need an AMP for pipes 17 and tanks. Unfortunately, leaks, once begun and whether observed or not, 18 will continue to grow as evidenced by the newly discovered Tritium leaks.
19 These leaks may be caused by external abrasion, internal corrosion, 20 galvanic attack or other factors as yet to be uncovered.
21 Leaks not only continue to increase in flow, but in fact the rate of 22 expansion for leaks actually accelerates once a pinhole has been created in 23 the pipe or tank wall.
Page 16 of 56
1 After the initial pinhole, water begins to exit the tank or pipe, at an ever-2 accelerating rate as the hole expands. In fact, mathematically speaking, 3
the leak rate growth is proportional to the square of the radius of the hole.
4 Given the newly discovered Tritium leaks, it then becomes quite likely 5
that if a safety function is required, the leak may either divert the required 6
water or reduce the required line pressure, rendering the pipe and tank 7
system "unable to perform the intended safety function ".
8 Transient flow and pressure changes that would occur if there is a design 9
basis event will exacerbate leak growth and further reduce the ability "to 10 perform the intended safety function ". According to the NRC's website, a 11 design basis accident (event) is "a postulated accident that a nuclear 12 facility must be designed and built to withstand without loss to the 13 systems, structures, and components necessary to assure public health and 14 safety." In my opinion, the recent pipe failures at the Byron Nuclear 15 Power Station in Illinois are the perfect example for this discussion. At 16 Byron, safety-related flanges on pipes were weeping so badly that they 17 certainly would have been unable to have withstand the flow and pressure 18 transient associated with actually requiring the system to operate in its 19 safety mode. Without adequate Aging Management oversight, such a 20 scenario could be mirrored at the Pilgrim Nuclear Power Station.
21
- 2. The second scenario is similar to the first in that a growing leak remains 22 undetected by an inadequate Aging Management System. However, Page 17 of 56
1 unlike the first scenario, in which a system failure is caused by allowing 2
water to exit the expanding hole(s), in this scenario rust particles, dirt and 3
other contamination enter the pipe or tank through the hole thereby 4
clogging downstream filters and heat exchangers, or the debris abrades the 5
moving parts thus rendering the system "unable to perform the intended 6
safety function" 7
Under these conditions, the Venturi Effect' is the governing scientific 8
principle. For illustrative purposes, let my use the simple example of 9
applying lawn fertilizer to a lawn through a garden hose to explain this 10 phenomena. Even though the hose water is at higher pressure than the 11 fertilizer, the Venturi Effect from the moving water pulls the fertilizer into 12 the moving fluid.
13 14 ASLB Question 2 relates to the SSW system. Regard to the Salt Service 15 Water ("SSW") system - Explain how any leak in the SSW buried 16 pipes that might carry radioactive water from the plant to the canal 17 that dumps into the bay could challenge the ability of the SSW system 18 to satisfy its intended function(s)? For example, is there any 19 correlation between any potential leak in those pipes and any 20 potential plugs in them that might prevent them from discharging 1 VENTURI EFFECT-The increase in the velocity of a fluid stream as it passes through a constriction in a channel, pipe, or duct. Calculated by the Continuity Equation, or 0 VA Q = VA where Q is the volumetric flow rate, A is the Area of flow, and V is the fluid velocity. Because Q does not change, as A gets smaller then V must increase.
Page 18 of 56
1 water from the SSW, thereby impeding the ability to remove heat from 2
the RBCCW?
3 NRC Staff response, at 5, "The Staff does not believe 4
that there is any credible mechanism for the discharge 5
piping to become plugged. The discharge piping is 6
constructed using carbon steel which is ductile and 7
would deform before it would rupture. In addition, the 8
pressure from the water inside the pipe would keep it 9
from collapsing. But, even if it did become plugged, the 10 second loop is still available to return the water to the 11 bay."
12 13
- 3. The third scenario acknowledges the presence of the initial leak that may 14 or may not have grown significantly. However, in this scenario, it is the 15 structural weakness created by the hole or holes in the pipe or tank, which 16 render the system "unable to perform the intended safety function ".
17 The hole or holes act as stress risers and increase the likelihood of gross 18 failure under the stress of accident conditions.
19 Given that the inadequacies of the Aging Management Plan have allowed 20 the creation of a hole or holes, and that the applicant has not structurally 21 analyzed the presence of such holes, it is my opinion that the system 22 would be operating outside its regulatory design basis criteria.
23 Holes that reduce the structural integrity of pipes are particularly 24 worrisome at elbows and flanges (similar to the aforementioned Byron 25 incident) and would render the pipe or tank "unable to perform the Page 19 of 56
1 intended safety function" in the event of a Safe Shutdown Earthquake 2
(SSE). As the nuclear industry well knows, the small earthquake at the 3
Perry Nuclear Power Plant in Ohio did cause leaks in plant piping, and this 4
/mild earthquake was not at all comparable to a SSE.
5 According to NRC regulations, all nuclear power stations must have 6
certain structures, systems, and components requisite to safety, designed to 7
sustain and remain fuinctional in the event of maximum earthquake 8
potential. Unidentified holes in safety related underground pipes place 9
those pipes in an unanalyzed condition outside the scope of the regulatory 10 design basis for the Applicant's Pilgrim Nuclear Power Plant.
11 Consequently, in light of the newly discovered Tritium leaks, it may in fact be 12 true that a significant safety system has already been compromised. Moreover, it 1 3 seems in fact that the applicant Entergy's Aging Management System did not 14 uncover those leaks, or did not do so in a timely manner.
15 Q11.
In your professional opinion, explain how pre-existing holes in underground 16 piping might cause a failure during a design basis event, such as an SSE?
17 A. To begin, let me give you an analogy. If the existence of holes appreciably 1 8 increases the likelihood of failure, then essentially the plant has a similar 19 condition to permanent removal of an emergency diesel generator. After all, the 20 EDG might fail, the single failure criterion assumes a single failure, so the EDG is 21 removed and it's the designated single failure.
22 Page 20 of 56
1 In addition, let me address the core question of whether or not the existence of 2
holes will appreciably increase the likelihood of failure? That answer depends 3
upon the cause and nature of the holes. A thousand pinhole leaks distributed 4
uniformly over the length of a 1,000-foot buried piping run is unlikely to cause its 5
failure rate to rise. But the same area of through-wall leakage concentrated in one 6
region - such as in a circumferential weld - might create an entirely different 7
outcome. If Entergy knows that buried underground piping is leaking (for 8
example by observing small, slow level drop in the CST), how would Entergy 9
distinguish from that fact the cause and nature of the leakage? Entergy certainly 10 could excavate the piping and eyeball whether or not the leak has been created by 11 a series of pinhole leaks or a gaggle of weld defects. However, no licensee would 12 excavate piping, determine the cause and nature of said holes and leaks, and not 13 fix them, as such degradation would negatively impact performance and earnings.
14 Besides, there is a federal regulation (10 CFR 50 Appendix B) that requires 15 licensees to repair any degradation. Thus, by regulation, a licensee is not allowed 16 to know about piping degradation and ignore it.
17 18 CORROSION 1 9 Q12. From your professional experience, please review for us some basic facts 20 about pipe corrosion so that we can better evaluate the sufficiency of Entergy's 21 aging management program and procedures.
22 A. Yes, some key points follow.
23
- a. The older the pipe is, the more likely it is that corrosion and leaks will Page 21 of 56
1 occur. Engineers explain the aging phenomenon by using what is known 2
as the "Bathtub Curve." The curve is a graph of failure rate according to 3
age. The failure rate due to unidentified leaks is relatively high in the 4
beginning when "kinks" are being worked out; it flattens out during the 5
middle life phase; and it rises again sharply in the end-of-life or at the 6
"wear-out phase." On average, 30 years usually marks the beginning of 7
the wear-out phase. I would expect that most of Pilgrim Station's pipes, 8
wraps and coatings would be in this "wear out phase" during the 9
relicensed period. This adjudication process must flush out the precise age 10 of each part of the pipes, wraps and coatings and provide documents from 11 the manufacturer certifying their life expectancy.
In my professional 12 opinion, and the standard applied to aging management of systems,
.13 inspections at Pilgrim must increase as any component ages.
- Piping, 14 coatings and wraps age, and just like human beings, require more doctor 1 5 visits. Clearly, the rate of corrosion is not linear over time. Even the most 16 meticulously maintained system, like the Space Shuttles, which are a 17 much newer engineered technology than Pilgrim, are reaching the end of 18 their useful life due to the aging phenomena of the Bathtub Curve.
19 20
- b. Corrosion is not even across the pipe; it is hard to predict. Corrosion 21 occurs more frequently at welds, elbows and dead spots. Therefore 22 inspections cannot avoid the most susceptible locations; instead special 23 attention must be given to examining these areas.
Page 22 of 56
2
- c. Holes or cracks do not fix themselves; and once started, they grow. For 3
example, this is self evident if one imagines a small hole in the Hoover 4
Damn. After the initial pinhole, water begins to exit the tank or pipe, at an 5
ever-accelerating rate as the hole expands.
In fact, mathematically 6
speaking, the leak rate growth is proportional to the square of the hole's 7
radius.
And not only will a hole let the fluid out, it will also allow dirt 8
and debris in which will foul or clog the system. Corrosion may not be 9
assumed to be a gradual process, and corrosion is non-linear.
10 11
- d. Nuclear power plants rely upon buried piping. Unfortunately, when a 12 pipe is buried, its condition is not readily apparent. Therefore pipes must 13 be inspected. Just as the ESW piping at Byron Station had to be fixed, the 14 piping underground must be fixed and that requires looking via an Aging 15 Management Program with frequent and comprehensive inspections.
16 Furthermore because the CSS, SWS, SGTS piping are buried in the soil, 17 these buried pipes are by definition in a more corrosive enviromnment than 18 any aboveground piping.
For instance, oxygen, moisture, chloride, 19 acidity, or microbes found in the soil, in one degree or another, corrode all 20 piping materials. More specifically, because Pilgrim Station is located
- 21.
adjacent to Cape Cod Bay and at a low elevation, it is readily apparent that 22 the soil surrounding the piping is not "friendly." No metal is immune to 23 corrosion. Moreover, piping located near salt water or in salty soil is more Page 23 of 56
1 easily corroded.
2 3
- e. Human error either in manufacturing or installation may never be 4
discounted. Over time movement of the soil creates unanticipated stress on 5
underground pipes.
6 7
In conclusion, a most important basic fact to keep in mind is that corrosion 8
rates are hard to predict and cannot be assumed to be either linear or gradual.
9 10 Q13. In your professional opinion, is Pilgrim Station's environment more or less 11 conducive to the probability of the plant's buried piping corroding?
12 A. Let me answer this question in two (2) parts.
13 First, the basic problem is that Entergy has not performed any recent and thorough 14 hydro-geologic studies; or if Entergy has performed such studies, the results of 15 those studies have not been shared with the parties or placed them in the public 16 domain.
Entergy's own Buried Piping and Tanks Inspection and Monitoring 17 Program [provided in Entergy's Initial Statement as Exhibit 5] states that a 18 corrosion risk evaluation should be performed within 9 months and that it should 19 include soil resistivity measurements etc. and that "soil resistivity measurements 20 must be taken at least every 10 years unless areas are excavated and backfilled or 21 if soil conditions are known to have changed for any reason" [Exhibit 5, at 5.5].
22 Therefore, I believe that we (the NRC, Entergy, ASLB and the parties) are 23 currently traveling "blind."
Page 24 of 56
2 Performing a Corrosion Risk Assessment is critical before any appraisal or 3
decisions are made regarding Entergy's license application. In my o pinion, the 4
ASLB does not have the information in hand to make an adequate assessment of 5
the AMP and meet NRC regulations without knowing either the extent of 6
corrosion risk caused by the local environment and without knowing the corrosion 7
status of the affected components.
8 9
Second, my review of the data has shown several concerns. To begin, the piping 10 is mainly made of carbon steel and stainless steel.
There is no evidence that 11 Entergy has instituted a thorough Cathodic Protection Program (CPP) for this 12 piping. All metals corrode, and corrosion occurs on both external and internal 1 3 surfaces. For instance, regarding external corrosion, it is a known fact that water 14 and moisture are needed for corrosion to occur.
Pilgrim Station is located in 15 Plymouth, MA, which is a relatively moist environment adjacent to Cape Cod 16 Bay. Plymouth's winter climate is characterized by periods of snow and ground 17 freeze, that thaws in Spring. Periods of rainfall occur throughout the year.
18 Chloride speeds corrosion, and chloride is naturally abundant in seawater. Soil 19 acidity is corrosive. Entergy described procedures to reduce the effects of oxygen 20 from moisture and acidity from decaying organic material - removing vegetation 21 and placing the piping on a bed of sand.
However over a period of time
-22 vegetation reappears, decays and works its way down to the pipes. Soil above the 23 sand migrates downward mixing with the sand to provide a moist environment.
Page 25 of 56
1 The low pH resulting from decayed organic matter, acid rain and stray electric 2
currents will accelerate corrosion along with the oxygen from water seepage.
3 Pipes corrode both externally and internally. The rate of degradation on interior 4
surfaces is a function of aggressive chemicals, pH level, dissolved oxygen and 5
biological elements at the site. The recently discovered tritium leaks at Pilgrim, 6
and the nationwide epidemic of tritium leaks from underground pipes clearly 7
prove that these phenomena exist.
8 9
Third, according to a 1990 United States Government Accounting Office Report 10 Pilgrim Station may have received counterfeit or substandard pipefittings and 1.1 flanges. Therefore, I believe it should be factually established whether or not the 12 CSS, SSW, and SGTS piping has counterfeit and/or substandard pipefittings and 13 flanges.
In my opinion, if any parts are counterfeit or substandard, then the 14 probability of failure is increased.
Review of the documents and notices 15 regarding counterfeit or substandard pipefittings and flanges, shows that the NRC 16 allowed the continued use of some or all of these components at numerous reactor 17 sites. If this information is indeed accurate, then both Entergy and the NRC 18 should have documentation that would indicate whether the NRC's decision to 19 allow the use of these components was based upon Pilgrim's 40-year license or 20 upon their use for a specific time period or an indefinite timeframe.
21 22 Fourth, Plymouth is not immune to soil compaction and seismic activity even 23 though the probability of such an event may be low. Buried pipes and tanks are Page 26 of 56
1 not flexible and the coatings become brittle with age and therefore are more 2
susceptible to breakage during seismic events.
3 4
Fifth, as any entry-level engineer learns, straight piping is less susceptible to 5
failure than welds, elbows and dead spots. What is the precise configuration of 6
the CSS, SSW and SGTS piping? Pilgrim Watch has not been provided this 7
information for review.
Prior to commenting further regarding the failure 8
possibility of Pilgrim's piping, I must review the precise configuration of the 9
CSS, SSW, and SGTS piping. I will need this information prior well before my 10 testimony, so that I will have adequate time to review the precise piping 11 configuration. Yes, I did review the Diagrams that were sent to Pilgrim Watch by 12 Entergy Pilgrim, but these were more of a cartoon-style schematic and did not 13 have the accuracy necessary to adequately review the mechanisms required to 14 inspect the CSS, SSW, and SGTS piping.
15 16 MANAGING INTERNAL AND EXTERNAL CORROSION 17 Q14. In your professional opinion, do you think that any leak should be tolerated 18 or that if a pipe within a specific system leaks then that component should be 19 declared inoperable until the leak(s) are repaired?
20 21 A, Once again, NRC rules [Appendix B to Part 50--Quality Assurance Criteria for 22 Nuclear Power Plants and Fuel Reprocessing Plants, XVI. Corrective Action]
23 make it clear that any leak is a leak at too great a rate. My response above Page 27 of 56
1 regarding failure mechanisms explains why this must be so (Answer to Q13).
2 3
Q15. What do you believe Entergy Pilgrim Station's Aging Management Plan and 4
Program requires Pilgrim Station to do regarding the detection of leaks when 5
they occur? Is this sufficient?
6 A. Entergy is required to have a sufficient aging management plan and programs to 7
detect leaks when they occur, and those leaks should be repaired as soon as they 8
are discovered in order to achieve the purpose of their Aging Management 9
Program.
10 11 Q16. Earlier in this declaration, in your answer to Q13, you stated that you had 12 difficulty deciphering the cartoon-style schematic for the diagrams pertaining to 13 the inspection of the CSS, SSW, and SGTS piping. In spite of that obstacle, 14 would you please describe the inspection and Aging Management Programs for 15 underground pipes and tanks at Entergy Nuclear Pilgrim Station?
16 17 A. Certainly. The Buried Pipes and Tanks Inspection Program (BPTIP) is described 18 in Appendix A.2.1.2. and B. 1.2 of the renewal filing. Itconsists of three parts.
19 20 (1) Appendix A.2.1.2. Buried Pipes and Tanks Inspection Program page A-14 21 states that buried components are inspected when excavated during 22 maintenance and if "trending" identifies a susceptible location. For example, 23 a specific area with a history of corrosion might have additional inspections, Page 28 of 56
1 coating or replacement to assure that either no leaks occur or that if leaks do 2
occur the leaks are quickly discovered and the requisite piping is repaired in 3
order to achieve the two goals of protection of the entire system and 4
mitigation of any release of any radioactive isotopes into the environment.
5 6
(2) Focused inspections will be performed within 10 years of the license 7
renewal unless an "opportunistic inspection" which allows assessment of pipe 8
condition without excavation, occurs within the ten-year period.
The 9
"opportunistic inspection" may be either visual or "Inspections via methods 10 that allow assessment of pipe condition without excavation may be substituted 11 for inspections requiring excavation solely for the purposes of inspection."
12 These latter inspections can include phased array Ultrasonic Testing (UT) 13 technology that provides indication of wall thickness for buried piping without 14 excavation. The application states that use of such methods to identify the 15 effects of aging is preferable to excavation for visual inspection, which could 16 result in damage to coatings or wrapping. (Application, B.1.2. page B-17).
17 18 (3) "Prior to entering the period of extended operation, the applicant is to verify 19 that at least one opportunistic or focused inspection is performed during the past 20 ten years."
21 22 Q17. In your professional opinion, do you believe that Entergy's BPTIP is 23 sufficient?
Page 29 of 56
1 A. My short answer is "No." And, in my opinion, it is apparent that Entergy agrees 2
with me. In its prefiled testimony, Entergy included a new framework for a 3
company-wide Buried Pipes and Tanks Inspection Program [Entergy's, Exhibit 4
5]. Yet, Pilgrim Watch has not received any information noting how or when this 5
new framework for a company-wide Buried Pipes and Tanks Inspection Program 6
will be implemented at Pilgrim Station.
7 8
Q18.
Briefly, please describe Entergy's BPTIP and indicate how it is insufficient?
9 A. Let me respond to this question by first describing the program and then 10 explaining what I see wrong with it.
11 12 Part (1) of the program notes that pipes are inspected if they are excavated 13 during maintenance. The problem is that this leaves inspections and safety to 14 happenstance and does not meet Pilgrim Station's Aging Management goals.
15 16 Part (2) of the program requires a one-time inspection during the first 10-years 17 of the license renewal period by either a visual or an as yet untested UT 18 inspection..
The problem here is that the program lacks specificity and 19 provides merely a general framework. By allowing total flexibility for the 20 licensee, this loose framework once again neglects the very specific 21 requirements of Aging Management Programs in general and, in my opinion, 22 certainly neglects the very goals developed by Entergy for its Pilgrim Station 23 Aging Management Program.
Page 30 of 56
1 2
For example, the BPTIP allows: "A determination of the sample size based on 3
an assessment of materials of fabrication, environment, plausible aging 4
effects, and operating experience." [ NUREG-1801, Rev.1, X I M32].
5 6
My review of the evidence provided by Entergy Pilgrim Station finds four 7
problems with Entergy's alleged plan.
8 The first problem is that operating experience at Pilgrim Station is 9
limited according to the SER. From the evidence I have reviewed, I 10 believe that Entergy Pilgrim Station has not performed a thorough 11 baseline examination of the pipes, which of course should be a 12 prerequisite to any license extension program.
13 The second problem, as I see it, is that Pilgrim Station does not have a 14 monitoring-well program that meets design standards, see Dr.
15 Ahlfeld's declaration.
16
- In my opinion, the third problem is that Entergy's assessment of 17 materials and the environment provided in Entergy's Initial Statement 18 does not seem accurate. For instance Entergy's statements ignored the 19 facts that all metals corrode, that Pilgrim's specific environment is 20 conducive to corrosion, and that no recent hydrological and geological 21 studies have been performed.
22 Fourth and quite simply, there is no new hard data to review, as it 23 seems that Entergy Pilgrim Station has only conducted cursory Page 31 of 56
1 reviews of old studies via walkabouts on the property.
2 3
"Identification of the inspection locations in the system or component 4
based on the aging effect; determination of examination technique; 5
evaluation of the need for follow-up examinations if aging related 6
degradation is found."
7 The problem with this portion of the Entergy Nuclear Pilgrim Station plan 8
is that there is no requirement concerning the number *of sample 9
inspections or the location of said sample inspections.
10 11 In the statement "An evaluation of the need for follow-up examination",
12 no mention is made regarding who will evaluate the need for follow-up 13 examinations, and no statement as to the NRC's role is articulated.
14 Furthermore, and more critical, is that there are no criteria whatsoever 15 with which to determine when there must be "follow-up examination(s)."
16 17 In NUREG-1801, the BPTIP states:
"The inspection includes a 18 representative sample of the system population', where practical, focuses 19 on the bounding or lead components most susceptible to aging due to time 20 in service, severity of operating conditions, and lowest design margin." In 21 my opinion, the obvious flaw here is the word, "Where practical." Such 22 loose terminology does not meet any engineering standards and allows 23 licensee convenience and profit margins to be the driving force for Page 32 of 56
1 inspection rather than "public health and safety" as required by federal 2
statute.
3 4
Lastly, in the BPTIP it is stated: "The one-time inspection, or any other 5
action or program, created to verify the effectiveness of ýthe AMP and 6
confirm the absence of an aging effect, is to be reviewed by the staff on a 7
plant-specific basis." In my opinion the inference presupposes that only 8
on a plant specific basis will a "one time inspection, or any other action or 9
program..
occur depending upon the effectiveness of the AMP as 10 determined and reviewed by the Pilgrim Station staff. Once again, this is 11 not a commitment to an inspection with formal criteria and trigger points 12 by which to deepen an inspection should specific triggers be uncovered, 13 instead this loose wording simply suggests that the inspection may not 14 occur if Pilgrim Station staff determine such an inspection is not 15 warranted.
16 17 Part (3) of the BPTIP says that, "Prior to entering the period of extended 18 operation, the applicant is to verify that there is at least one opportunistic 19 or focused inspection performed during the past ten years." The issue that 20 1 see is that any inspections prior to license renewal have all the 21 weaknesses described above.
Entergy has not stated when these 22 inspection might occur or if they may have already occurred.
Of 23 additional concern is the fact that if Entergy plans to count inspections that Page 33 of 56
1 occurred early in 2000 as part of this process, and. is allowed to do so, than 2
conceivably at least 19 years might lapse between inspections.
The 3
critical nature of these pipes requires more than one inspection over the 4
entire period of license renewal.
5 6
NUREG-1801, Rev 1, XI M-107, September 2005 states that, "... the 7
applicant should schedule the inspection no earlier than 10 years prior to 8
the period of extended operation...as a plant will have accumulated at 9
least 30 years of use before inspections under this program begin, 10 sufficient times will have elapsed for aging effects, if any, to be manifest."
11 Again the wording here is problematic in that there does not appear to be 12 any requirement that the specific component areas sampled be at least 30-13 years-old.
14 15 To summarize my key points: There is not a requirement for a through baseline 16 inspection prior to license renewal so that the NRC and Entergy know the 17 condition of each component in order to make a rational Aging Management Plan 18 for the renewal period. The required inspections are too infrequent. I explained 19 that corrosion is not gradual, and that as components age they wear out at a 20 greater frequency as predicted by the Bathtub Curve. Therefore they need to be 21 inspected more frequently as time goes forward.
Entergy's AMP has no 22 specificity in the program delineating what must be inspected.
Engineering 23 experience shows that certain areas of piping are more susceptible than others to Page 34 of 56
1 corrosion, like welds, elbows, and dead spots.
Lastly, there are no clear 2
requirements for reporting, repair or replacement of degraded piping.
3 4
Q19. In addition to the BPTIP the Applicant has claimed in its Initial Statement 5
that other more routine programs are effective in preventing corrosion, like the 6
Water Chemistry & the Service Water Integrity Program.
Since these two 7
programs address internal corrosion, in your professional opinion, do you 8
believe that these two programs provide adequate assurance in combination with 9
the other programs the Applicant has outlined?
10 11 A. No, the water chemistry program is a mitigation program and does not provide 12 detection for aging effects. More frequent complete inspections as part of the 13 overall program are the only effective assurance that defects created by aging 14 components will be uncovered. Tritium leaks at reactors across the country belie 15 the effectiveness of water chemistry alone to prevent leaks.
16 17 In its Prefiled Testimony (Testimony at A93), Entergy stated that the Water 18 Chemistry Program was effective because, 19 "This is an existing program at PNPS that has been confirmed 20 effective at managing the effects of aging on the CSS as 21 documented by the operating experience review. See PNPS LRA at 22 Appendix B, Section B.1.32.2, p. B-106-07.
The continuous 23 confirmation of water quality and timely corrective actions taken 24 to address water quality issues ensure that the program is effective 25 in managing corrosion for applicable components."
Page 35 of 56
1 2
In my opinion, Entergy's statement alludes to problems within the water 3
chemistry program, and identifies that it has had problems and has improved the 4
program. However, Entergy never discusses the potential damage caused while 5
operating under the older methodology, nor what remediation steps have been 6
taken regarding any damage that occurred.
Furthermore, Entergy provides no 7
factual evidence to validate its verbal assurance that the new program is effective.
8 9
The Service Water Integrity Program addresses internal corrosion. In the 10 Applicant's Testimony, A96, in Entergy's Initial Statement, they describe the 11 program as, 12
"(SPW) Under the program, the components of the SSW system 13 are routinely inspected for internal loss of material and other aging 14 effects that can degrade the SSW system. The inspection program 15 includes provisions for visual inspections, eddy current testing of 16 heat exchanger tubes, ultrasonic testing, radiography, and heat 17 transfer capability testing of the heat exchangers. The periodic 18 inspections include direct visual inspections and video inspections 19 accomplished by inserting a camera-equipped robotic device into 20 the SSW system piping. In addition, chemical treatment using 21 biocides and chlorine and periodic cleaning and flushing of 22 infrequently used loops are methods used under this program."
23 24 At, A97, Entergy's expert says that the program is effective because 25 "This program has been effective in detecting degradation of the 26 internal rubber lining in the original SSW system carbon steel 27 piping. As a result, the inlet pipes were replaced with titanium Page 36 of 56
i pipe, and portions of the discharge pipes were replaced with 2
carbon steel piping coated internally and externally with an epoxy 3
coating, and the entire lengths of the discharge pipes were 4
internally lined with cured-in-place pipe linings. Thus, this 5
program has been successfully implemented at PNPS to manage 6
SSW system degradation from loss of material due to internal 7
corrosion prior to the loss of its intended function. See PNPS LRA 8
at Appendix B, Section B.1.28, p. B-92-93."
9 10 As I see it, the problem is that the program's effectiveness is ascribed to the fact 11 that there was serious corrosion, which was not identified until after 23 years of 12 operations, and it was identified only as a result of prodding from NRC, Generic 13 Letter 89-13. This leads me to wonder how long there were significant corrosion 14 problems and how long the licensee would have waited if it were not for the 15 generic letter.
16 17 According to Entergy, Pilgrim replaced (2) 40' sections of SSW Discharge piping 18 out of 240' in one loop and 225' in the other loop 1999. Once again there is 19 insufficient data to make a valid assessment. The problem here is that there is no 20 indication of the condition of the remainder of these loops.
21 22 In 2001, Entergy states that a new liner was placed in loop B and in 2003 a new 23 liner was placed in Loop A. It strikes me as remarkably convenient that the life 24 expectancy of the liners is given as 35-years, yet there is no factual data with 25 which to corroborate that statement.
Page 37 of 56
1 2
Last at A98 in Entergy's Initial Statement, it is noted that, 3
"the Service Water Integrity Program will be used to monitor the 4
newly installed liner (CIPP). As the CIPP approaches the end of its 5
expected life, increased inspections will be undertaken of the 6
CIPP. The in-service inspection program for the SSW currently 7
requires PNPS to undertake a complete ultrasonic or visual 8
examination of the CIPP, analogous to those undertaken for the 9
original rubber lining, after the CIPP has been in service for 20 10 years, well before the end of its expected 35 year life."
11 12 Once again, there is no timeline delineating the "increased inspections" or 13 enumerating how many inspection will occur. Just as importantly, no definition 14 of "complete ultrasonic or visual inspection" is provided nor is it clear whether 15 this would be a stem to stem inspection or only a partial inspection.
16 17 Q20. In its Initial Statement Entergy describes additional surveillance programs 18 for the CSS and SSW.
In your professional opinion do these additional 19 programs provide the assurance required?
20 21 A. First in regard to the additional programs for the CSS, the simple answer is "No."
22 The CST program consists of level indictors in the Condensate Tank and quarterly 23 testing of the water flow from the RCIC pump and the HPIC pump.
24 25 Entergy responded to the Board's questions on February 11 and stated in regard to Page 38 of 56
1 the 4-hour testing of the CST water level that, 2
"Under normal operation, the level of the CSTs is dynamic (i.e. the 3
CST levels fluctuate as they provide makeup or receive condensate 4
discharge to maintain appropriate condenser water level).
5 Therefore, under normal operation, there is no specific leakage rate 6
that would be detected by or could be readily correlated with the 7
four-hour test results."
8 9
In my opinion, Entergy's response clearly indicates that the monitors cannot 10 predict the level of corrosion in the pipes and whether or not the pipes are leaking.
11 12 In response to the same question, the NRC Staff said at 5, 13 "there is no CS system leak rate that would challenge HPCI/RCIC 14 performance for purposes of § 54.4(a)(1), and only a very large 15 leak would compromise the performance for purposes of § 16 54.4(a)(3). And if there were a large drop in water in the CST, it 17 would be noticed and corrective action taken.
18 19 While the NRC staff assessment may be interesting and informative, in my 20 opinion, it does not address the core question, which is: whether or not leaks will 21 be identified and will be repaired in order to protect public health and safety.
22 23 The second part of the question addresses the surveillance programs for the SSW.
24 and again the simple answer is "No." they do not provide assurance, either.
25 26 Entergy Testimony at 17, A30 states that, Page 39 of 56
1 "By the time the cooling water is in the buried discharge piping, it 2
has completed its intended safety function of providing cooling 3
water for the RBCCW. Therefore, if a leak develops in the 4
discharge piping, it will not affect the intended safety function.
5 There is no correlation between any potential leak in the buried 6
discharge piping and any potential plugs in them that might 7
prevent them from discharging water from the SSW. The SSW 8
system is designed so that no active component failure nor any 9
single passive component failure, or any other system, can prevent 10 it from achieving its safety objective. There are two loops of 11 discharge piping, so if one were inoperable, the second loop could 12 be used to return the cooling water back to the bay. Each ioop can 13 transfer the full heat capacity required for its intended safety 14 obj ective.
15 16 The NRC Staff Exhibit 17 says that, 17 "c... the system would retain the ability to remove heat from the 18 RBCCW. The Staff does not believe that there is any credible 19 mechanism for the discharge piping to become plugged. The 20 discharge piping is constructed using carbon steel which is ductile 21 and would deform before it would rupture. In addition, the pressure 22 from the water inside the pipe would keep it from collapsing. But, 23 even if it did become plugged, the second loop is still available to 24 return the water to the bay" 25 26 Waiting for a leak to grow so big as to effect the intended function of the system 27 would be unthinkable in an above ground portion of the same system.
Single 28 failure criteria do not apply when a system is known to be leaking significantly, in 29 which case it should be considered inoperable already. Therefore, in my opinion, Page 40 of 56
1 a second single failure should be postulated given that Entergy's Pilgrim Station 2
plans to wait an excessive amount of time to repair any leaks.
3 4
In my opinion, the central question of identifying leaks, that is leaks of any size, is 5
not addressed so that the responses and questions, although of general interest, do 6
not answer the question at hand, which is the sufficiency of the AMPs to. assure 7
leaks will be detected and promptly repaired in order to comply with regulation 8
and thereby protect the public health and safety.
9 10 Q21.
On November 19, 2007, Entergy announced its initiation of a new program 11 entitled: the Buried Piping and Tanks Inspection Program and Monitoring 12 Program, Entergy's Prefiled Testimony, labeled as Exhibit 5. Please describe the 13 program and evaluate its effectiveness.
14 15 A. The Program indicates that Entergy agrees with the Petitioners that the programs 16 and procedures are currently in place that would determine whether or not the 17 buried pipes containing radioactive fluids are leaking in such a manner as to be 1 8 unable to satisfy their respective safety functions.
19 20 Section by Section Analysis [extracted from Gundersen Declaration at 12 minus 21 Tables]
22
- 1. Section 5.0, subsection [1] at page 7 acknowledges right at the beginning that 23 "The risk of a failure caused by corrosion, directly or indirectly, is probably the Page 41 of 56
1 most common hazard associated with buried piping and tanks."
2 3
Steps required in building a risk assessment tool are discussed in 4
Section 5.0, subsection [2] on page 7. However the program fails in that it 5
does not require a complete baseline review. There is no indication that 6
the entire component is supposed to be examined; instead escape hatches 7
are provided to the licensee - such as [at 2a] "the size of each section shall 8
reflect practical considerations of operation, maintenance, and cost of data 9
gathering with respect to the benefit of increased accuracy." Any program 10 worth its salt would require a thorough baseline inspection along the entire 11 length of the pipe.
12 13
- 2.
Section 5.2, Scope Program subsection [3] at page 8 acknowledges the 14 validity of Pilgrim Watch's initial contention that, "The program shall include 15 buried or partially buried piping and tanks that, if degraded, could provide a path 16 for radioactive contamination of groundwater. Some examples are: Buried piping 17 containing contaminated liquids." Entergy agrees that "radioactive contamination 18 of groundwater" is an important issue and belongs in the Buried Piping and Tanks 19 Inspection and Monitoring Program.
20 21
- 3. Section 5.4 Identification of Buried Piping and Tanks to be Inspected and 22 Prioritized, page 9, Subsection [1] directs the licensee to develop a list of all 23 systems containing buried piping and tanks and to identify those sections, Page 42 of 56
1 collecting physical drawings, piping/tank installation specifications, piping design 2
tables and other data needed to support inspection activities. Pilgrim Watch 3
knows that the criteria must specify other key parts of the components. For 4
example: wall thickness; number and location of welds, elbows, flow restrictions; 5
blank flanges; high velocity portions; whether the component has substandard 6
parts; the age of the components parts; cathodic protection; last inspection date 7
and report number; and manufacturers warranty, if any. This information is the 8
type of information that is needed when the NRC Staff conducts their safety 9
evaluation so that the SER Report will be meaningful; unfortunately it was not 10 available. The license application decision should be delayed until the information 11 is available and critically reviewed.
12 13 Subsection [41 categorizes the piping into high, medium and low impact. High 14 impact components require prompt attention. We agree that they should require 15 prompt attention however Entergy's definition of "prompt" allows considerable 16 delay -high impact buried sections shall be examined within 9 months of issuance 17 of the procedure; and no date is given when the procedure shall be initiated. The 18 impact assessment lists radioactive contamination as "High Risk" once again 19 confirming the validity of Pilgrim Watch's initial contention that radioactive 20 contamination belongs in this adjudication process...
21 22 23
- 4.
Section 5.5,
..."Inspection Intervals vs. Inspection Priority" reflects the Page 43 of 56
1 outcome from an assessment of the risks from buried piping and tanks.
2 For example:
3 (a) Buried piping and tanks having high risk are specified as having an 4
initial inspection period of 5 years with a re-inspection interval of 8 years.
5 The time interval is too long.
6 7
(b) It does not tell how much of the component will be inspected.
8 9
(c) There is no requirement to shorten a subsequent inspection based upon 10 the degree of corrosion discovered at the time of the prior inspection.
11 12 (d) Absent from this procedure is the prudent and practical guidance to 13 conduct the inspection provisions of this procedure when opportunities 14 present themselves, regardless of the inspection intervals in Table 4. For 15 example, if a section of buried piping categorized as having "Low" 16 inspection priority is excavated for other reasons, this excavation 17 procedure should direct/require workers to take advantage of the 18 opportunity and perform inspections-corrosion is neither linear nor 19 constant across the component's length.
20 21 (e) In subsection [5], the determination of inspection locations may also 22 consider the "ease of access to inspection point." However we know that 23 ease of location and lack of corrosion do not necessarily go together. In Page 44 of 56
1 fact the odds are that a component that is difficult to access has never been 2
inspected - all the more reason to inspect it.
3 4
- 5. Section 5.6, Parameters to be Inspected, page 13, lists: external coatings 5
and wrapping condition; pipe wall thickness degradation; tank plate thickness 6
degradation; and cathodic protection system performance, if applicable. The 7
attributes that must be considered in tabulating risk are too narrow. They include:
8 (a) soil resistivity measurement; (b) drainage risk weight; (c) material risk weight; 9
(d) cathodic protection/coating risk weight.
10 11 The list should be expanded to include, for example, the age of the component's 12 parts; the number of high risk corrosion areas in component such as welds, dead 1 3 spots etc; counterfeit or substandard part not replaced. The list is silent on internal 14 corrosion and we know that corrosion from the inside can bring about a failure.
15 The section is silent on the size of the sample required; its location; and the 16 rational for the sampling protocol -
if, in fact, a sample is taken and not an 17 inspection of the entire component.
18 19
- 6. Section 5.7, on page 13, provides vague remarks about acceptance criteria 20 for any degradation of external coating, wrapping and pipe wall or tank plate 21 thickness. It says that they should be based on current plant procedures; and if not 22 covered by plant procedures then new procedures need to be developed before the 23 inspections. The pass/fail grade should be clearly defined. For example what Page 45 of 56
1 precisely constitutes an "unacceptable" from an "acceptable" degraded external 2
wrapping? The LLTF was very specific that "significant" and other such 3
descriptions need definition.
4 5
- 7. Section -5.8, Corrective Actions, page 14, says that "a condition report (CR) 6 shall be written if acceptance criteria are not met. Pilgrim Watch knows that any 7
and all inspections should generate a written 'condition report' regardless of what 8
is or is not found to maintain a permanent paper trail of all inspections.
9 10 The corrective actions may include engineering valuations, scheduled 11 inspections, and change of coating or replacement of corrosion susceptible 12 components. Components that do not meet acceptance criteria shall be 13 dispositioned by engineering. [Emphasis added].
14 15 This provides no assurance to public safety for the following reasons:
16
- a. The corrective actions may include engineering valuations, 17 scheduled inspections, and change of coating or replacement of 18 corrosion susceptible components; and they just "may not." There 19 are no guarantees.
20 21
- b. The licensee's own engineering department will deal with it; but 22 there is no clear definition of how they will deal with it. Whatever 23 happened to the concept that this Program would consist of layers Page 46 of 56
1 of supervision so that the NRC would play some sort of oversight 2
role in this program? Who sees the Condition Reports - or to put it 3
another way, where are the reports kept, who has access to those 4
reports, do they have to be sent to the NRC and if so under what 5
conditions and time schedule?
A more basic issue is that 6
Condition Reports are unlikely to be written or, if they are written, 7
to actually say anything as explained directly below.
8 9
- 8. Section 5.12 Inspection Methods and Technologies/Techniques, subsection 10
[1] on page 15 specifies st eps to be taken for Visual Inspections of buried piping 11 and tanks.
Step.(g) directs the workers: "A CR [condition report] shall be 12 initiated if the acceptance criteria are not met."
13 14 A review of steps (a) through ()reveal a lack of objective, or even subjective, 15 acceptance criteria that could trigger a condition report:
16
- a. When opportunities arise, buried sections of piping and tanks "should 17 be examined to quantify deposit accumulation... and those results 18 documented." As long as exposed piping is examined and damage 19 chronicled, the acceptance criteria are met -no condition report.
20
- b. "Look for signs of damaged coatings or wrapping defects"-as long as 21 workers look the acceptance criteria are met. Only not looking would 22 fail to meet the acceptance criterion and trigger a condition report.
23
- c.
"The interior of piping may be examined by divers, remote cameras, Page 47 of 56
1 robots or moles when appropriate." The combination of "may" and 2
"when appropriate" means the acceptance criterion is met when 3
examinations are performed or not.
4
- d. "Use holiday tester to check excavated areas of piping for coating 5
defects." When coating defects are found for exposed area of piping 6
using a holiday tester, the acceptance criteria is met and no condition 7
report is written.
8
- e. If visual inspection reveals coatings or wrappings not to be intact, 9
further inspection of piping for signs of pitting, MIC, etc is required. If 10 the additional inspection is performed, the acceptance criterion is 11 satisfied and no condition report is warranted whether damage is found 12 or not.
13
- f. Inspect below grade concrete for indication of cracking and loss of 14 material. As long as the inspection is performed, the acceptance 15 criterion is satisfied whether damage is found or not.
16 17
- 9. Section 5.12 subsection [2] on page 16 specifies the steps to be taken for Non-18 Destructive Testing of buried piping and tanks. No steps direct workers to initiate 19 condition report(s) regardless of how extensive the piping and/or tank damage is 20 identified.
21 22
- 10. Section 5.9 Preventive Measures, at 14, "...the existing cathodic protection 23 system may be updated or a new Cathodic Protection system may be installed.
Page 48 of 56
1 Pilgrim Watch has explained that cathodic protection should be installed. The 2
emphasis should be on prevention not waiting to discover failures before acting.
3 4
Q22. Entergy contends that the standard of reasonable assurance provided is 5
based upon conformance to: NRC Guidance; the GALL Report; industry 6
practices; PNPS operating experience; and the SER review, in your professional 7
opinion do you agree with Entergy's assessment?
8 9
A. No, I do not agree at all.
10 In my opinion, the GALL Report simply represents general guidance and is not a 11 mandate.
The NRC has repeatedly stated that plant specific data such as 12 operating experience must be considered.
Furthermore, the GALL Report is 13 changed periodically informing us that it is neither plant specific nor a regulatory 14 mandate.
15 16 Conformance to NRC Guidance again is not convincing because guidance is 17 simply "guidance not mandate" and like the GALL, NRC Guidance continues to 18 evolve as industry-wide lessons are learned. In my opinion, the proliferation of 19 leaks from buried pipes and tanks at nuclear power plants around the country is a 20 good example of exactly why public health and safety standards are not met by 21 nuclear power plants by simply referring these firms to either NRC Guidance or 22 industry practices.
23 Page 49 of 56
1 As I have previously stated, a thorough baseline inspection has not been 2
performed or required, so there is no baseline data by which to judge Pilgrim's 3
past operating experience. Also, there is no industry-wide experience with which 4
to compare corrosion and leakage in buried components at 40 to 60-year-old 5
reactors. More regrettably the NRC did not perform a thorough "autopsy" of the 6
parts from reactors which have been closed and dismantled, like Yankee Atomic 7
and Maine Yankee. Such an analysis and study of the impact of aging on various 8
materials and components would have enabled the entire industry to make 9
predictions based upon sound data. Finally, there is no operating experience for 10 the AMP and the UT examinations are completely untested.
11 12 The SER review was recently evaluated by the NRC Office of Inspector General.
13 Since the NRC OIG found serious flaws with the review process, in my opinion, 14 the SER review should not be applied to Pilgrim until the process has been 15 corrected and once again reviewed by the NRC OIG.
16 17 Finally I believe, Entergy's own corporate program, the Buried Piping and Tanks 18 Inspection Program and Monitoring Program (Entergy's Prefiled Testimony, 19 Exhibit 5), which was introduced quite late during the discovery process on 20 November 19, 2007, should be specifically applied to the Pilgrim site prior to 21 anyone drawing any conclusion based upon the adequacy of Pilgrim's proposed 22 solutions to inspecting underground systems.
Absent specific implementing 23 procedures to Entergy's elective corporate guidance, the ASLB and the Page 50 of 56
1 1 Petitioners are forced to guess, rather than have the requisite 95% assurance in the 2
adequacy of Pilgrim's program.
3 4
Q23.
From your professional experience, please describe what the aging 5
management program for buried pipes and tanks at Pilgrim Station must look 6
like in order for the public and ASLB to have confidence that public health and 7
safety will be protected during the license extension.
8 9
A. Yes, let me answer with Section 18 from my Declaration Supporting Pilgrim 10 Watch's Contention 1, January 26, 2008. At the end of this discussion, I will also 11 add some additional points.
12 "18. It is my belief, as the Expert Witness retained by Pilgrim 1 3 Watch, that there are at least four solutions, available to Entergy 14 and the ASLB3 to mitigate the serious consequences of undetected 15 leaks. Contention 1, as delineated in this proceeding, is that the 16 frequency of the monitoring proposed by the Applicant is 17 insufficient to ensure that the required safety margins would be 18 maintained throughout any extended period of operation.
The 19 Board appropriately suggested a possible weakness in the 20 Applicant's (Pilgrim Nuclear Power Station) Aging Management 21 Program to detect leaks, and this problem seems to be borne out by 22 the recently discovered on-site Tritium leaks.. I suggest that this 23 problem may be minimized by four separate approaches:
24
- 1. Establish critical Baseline Data; 25
- 2. Reduce the future corrosion rate; Page 51 of 56
1
- 3. Improve monitoring frequency and coverage.
2
- 4. Increase the Monitoring Well Program to actively look for 3
leaks once they have occurred.
4 18.1. Establish Critical Baseline Data:
In view of the fact that 5
industry as a whole and Pilgrim, specifically, have experienced 6
corrosion and leaks, as evidenced at Pilgrim by the recently 7
discovered Tritium leaks, it is important that critical Baseline Data 8
be collected via a top to bottom examination of the safety-related 9
buried pipes/tanks.
10 18.1.1. Such an inspection must entail special attention to points of 11 vulnerability - such as at elbows, welds, joints, and at any dead 12 spaces where liquid can sit.
13 18.1.2. Examinations must include inspection both inside and 14 outside.
15 18.1.3. Special attention must also be given.to those welds located 16 upstream or downstream of a flow disturbance.
17 18.1.4. Since it is not possible to assess possible damage below the 18 coating in the pipe body, in addition all piping must be pressure 19 tested to at least twice the operating pressure. Inability to perform 20 pressure tests for any reason should not be cause for relief.
21 18.1.5. Baseline data is critical so that trending is established.
Page 52 of 56
1 NUREG/CR 6876 states, at 32, "... it is evident that predicting an 2
accurate degradation rate for buried piping systems is difficult to 3
achieve..."
4 18.1.6. After a baseline is established then regular examinations 5
afterwards can better determine the need for mitigation before, not 6
after, a problem develops.
7 18.2.- Reduce corrosion rates:
The Applicant can and should 8
implement a thorough Cathodic Protection Program (CPP) on all 9
underground pipes and tanks.
I found no reference to such a 10 program in the application submitted by Energy.
A CPP would 11 reduce the likelihood of leaks.
12 18.3. Improve monitoring frequency and coverage: In an attempt 13 to minimize the size and frequency of leaks, in my opinion, the 14 AMP should be augmented to require more frequent and more 15 comprehensive inspections of all underground pipes and tanks.
16 18.3.1. Specifically, I believe that a 100 percent internal visual 17 inspection of all underground pipes and tanks must be 18 implemented.
19 18.3.2. The inspection cycle should be such that all pipes and tanks 20 are inspected every ten years, however, I believe that the Applicant 21 should be required to break the testing interval down such that one Page 53 of 56
1 sixth of all pipes and tanks are inspected during each refueling 2
outage. (This assumes 18 month refueling outages, or six every 3
ten years.)
4 18.3.3. Finally, it is my opinion that the Applicant should be 5
required to inspect one sixth of the lineal piping, one sixth of the 6
elbows and flanges, and one sixth of the tank seams at each outage, 7
even if such inspections lengthen the outage time.
8 18.3.4.
For example, when I was reviewing the Aging 9
Management System at Entergy's Nuclear Vermont Yankee 10 (ENVY) Power Station, I noted that the AMP was often neglected 11 in order to assure the outage was not extended. Therefore is my 12 opinion that the Applicant Entergy should certify that each portion 13 of the AMP on the pipes and tanks is accomplished in the order 14 agreed upon and completed at every outage. As an Intervenor with 15 standing on Contention 1, Pilgrim Watch should be allowed to 16 review copies of the certified piping inspection reports prior to the 17 end of each outage to assure that the work was completed as 18 ordered.
19 18.4. Increase the Monitoring Well Program to actively look for 20 leaks once they have occurred: According to Pilgrim Watch's 21 expert, Dr. David P. Ahlfeld, in order to meet the minimum criteria 22 for an effective monitoring well program at Pilgrim, such a Page 54 of 56
1 program should made part of the license going forward so that it is 2
enforceable and not simply voluntary and must follow the steps in 3
monitoring network design as outlined in Dr. Ahifeld's declaration.
4 In the absence of any leaks at the Applicant's Pilgrim Nuclear 5
Power Station, I believe that my recommendations would be 6
necessary to the evaluation of Pilgrim's application for a 20-year 7
extension to its current operating license. However, given the 8
recently discovered Tritium leaks at Entergy's Pilgrim Plant and 9
other reactors around the country, my recommendations are critical 10 to the continued operation of Pilgrim to the end of its current 11 license, without any consideration of a license extension.
12 18.4. 1. In light of the newly discovered Tritium leaks, it may in 13 fact be true that a significant safety system has already been 14 compromised.
15 18.4.2. I believe it will most likely take at least one year to trace 16 the path of the unanticipated Tritium releases.
17 18.4.3. The release of Tritium indicates a leak in a system that in 18 the past was radioactive.
1 9 18.4.4. I believe such a leak means that testing should immediately 20 be undertaken that searches for Cesium 134 and Cesium 137, 21 C obalt 60, and other gamma emitters as well as Strontium 90.
Page 55 of 56
1 18.4.5. As a nuclear engineering senior vice-president overseeing 2
decommissioning of nuclear sites and an author of the DOE 3
Decommissioning Handbook, I believe it is critical that these 4
newly discovered Tritium releases be accurately monitored. The 5
evidence I reviewed as an expert witness regarding Florida Power 6
and Light's St. Lucie Nuclear Power Plant, and the documents I 7
have reviewed pertaining to the decommissioning effort at the
- 8.
former Connecticut Yankee Nuclear Power Plant Site, clearly 9
show how far and wide Tritium and other radioactive isotopes may 1 0 spread before their release is uncovered.
11 18.4.6. Therefore in my opinion, and given Pilgrim's proximity to 12 the environmentally sensitive Bay and salt marshes, a rigorous and 13 expanded Monitoring Well program should be ordered and 14 immediately undertaken at and around the Pilgrim Nuclear Power 15 Plant Site."
16 17 In closing, let me reiterate that in my opinion until Entergy Nuclear Pilgrim 18 Station implements Entergy' s corporate guidance concerning inspection of 19 underground pipes and tanks, provides tho se implementing procedures to the 20 Petitioners for complete review and assessment, and begins implementation of 21 concrete procedures, these proceedings should be halted, and the license extension 22 should not be granted.
Page 56 of 56
Mar 30 08 01:01p P. 1 Fairewinds.Associates, Inc Arnold gundersen 376 -Appetree Point Road, 2BurCington, YVo5 4 o8 phone 802-865-9955 - fax 802-304-1051 fa.Ja rewfindsiaz*mac.comr arnie @saiCchamyCain.net March 5, 2008 To: Mary Lampert, Pilgrim Watch Please find attached my Declaration in Q&A format in the matter:
Entergy Corporation Pilgrim Nuclear Power Station License Renewal Application, Docket # 50-293 before the Atomic Safety And Licensing Board of the United States Of America Nuclear Regulatory Commission.
My testimony is in support of Pilgrim Watch's Contention #I.
I declare that under the penalty of perjury that the foregoing reflects my true opinion in these matters.
Sincerely,
/
Arnold