ML20260H072
| ML20260H072 | |
| Person / Time | |
|---|---|
| Site: | Indian Point  |
| Issue date: | 06/18/2020 |
| From: | Allen D Risk Research Group |
| To: | Entergy Nuclear Operations, Office of Nuclear Reactor Regulation |
| Shared Package | |
| ML20260H070 | List: |
| References | |
| 10609672, NL-20-67 IP-RPT-14-00013, Rev 3 | |
| Download: ML20260H072 (91) | |
Text
Attachment 9.1
~ Entergy Engineering Report Cover Sheet & Instructions Engineering Report No. _I_P-_R_P_T_-1_4_-0_0_0_13_ Rev _l_
Page~ of 91 *
- Report contain 90 pages.
ENTERGY NUCLEAR Engineering Report Cover Sheet Engineering Report
Title:
CONSEQUENCES OF A POSTULATED FIRE AND EXPLOSION FOLLOWING THE RELEASE OF NATURAL GAS FROM THE NEW 42" PIPELINE ROUTED ALONG SOUTHERN ROUTE NEAR IPEC Engineering Report Type:
New Revision
~
Cancelled Superseded Superseded by:
Applicable Site(s) ( 4)
IPI IP2 ~
IP3 IZI JAF PNPS VY WPO ANOI ANO2 ECH GGNS RBS WF3 PLP EC No. 87184 Report Origin:
0 Entergy
~ Vendor Vendor Document No.: 10609672 Quality-Related:
0 Yes
~ No Prepared by:
Risk Research Group Date:
6-18-2020 Responsible Engineer (Print Name/Sign)
Design Verified:
NA Date: ----
Reviewed by:
Design Verifier (if required) (Print Name/Sign)
John Skoniecz~ -:;-, ~te:
Reviewer (Print Name/Sign) 6-22-2020 Approved by:
Rich Drake ~
J ~
Date: ----
6-22-2020 Supervisor I Manager (Print Name/Sign)
EN-DC-147 REV 8
SECURITY-RELATED INFORMATIONWITHHOLD UNDER 10 CFR 2.390 Rev. 3, June 18 2020 0
THE RISK RESEARCH GROUP, INC.
Consequences of a Postulated Fire and Explosion Following the Release of Natural Gas from the New AIM 42 Pipeline Taking a Southern Route Near IPEC Prepared for Entergy Nuclear Operations, Inc.
by The Risk Research Group, Inc.
18 Macaulay Road Katonah, NY 10536 Under Contract 10609672 Author: David J. Allen, Ph.D, P.Eng.
6/18/2020 Revision 3
SECURITY-RELATED INFORMATIONWITHHOLD UNDER 10 CFR 2.390 Rev. 3, June 18 2020 1
Consequences of a Postulated Fire and Explosion Following the Release of Natural Gas from the New AIM 42 Pipeline Near IPEC Contents 1
Overview.............................................................................................................................2 2
Summary.............................................................................................................................3 3
Background..........................................................................................................................4 4
The New Pipeline.................................................................................................................7 5
Properties of Natural Gas................................................................................................... 11 6
Risks Posed by Natural Gas Releases................................................................................. 12 7
Regulatory Guidance.......................................................................................................... 16 8
Software and Models......................................................................................................... 17 9
Possible Releases and Their Consequences........................................................................ 19 10 Conservatisms in the Analysis........................................................................................ 36 11 Causes and Likelihood of Releases of Natural Gas and Subsequent Fire and Explosion or Missile Generation.................................................................................................................... 39 12 Discussion...................................................................................................................... 42 13 References...................................................................................................................... 43 APPENDIX A........................................................................................................................ A-1 APPENDIX B......................................................................................................................... B-1
SECURITY-RELATED INFORMATIONWITHHOLD UNDER 10 CFR 2.390 Rev. 3, June 18 2020 2
1 OVERVIEW As part of the Algonquin Incremental Market Project (AIM Project), Spectra Energy1 (Spectra) installed approximately 37.6 miles of new 42 natural gas pipeline. Part of the new 42 natural gas pipeline is routed just south of the Indian Point Energy Center (IPEC).2 Spectras pipeline system includes 26 and 30 pipelines which cross the IPEC property through a 65 right-of-way on the east side of the Hudson River. Near IPEC, the new 42 pipeline takes a southern route in which the new pipeline is routed further away from IPEC, south of the IPEC security barrier3, a route that is significantly more distant from IPECs main plant systems, structures and components (SSC) within the Security Owner Controlled Area (SOCA) that are safety related or important to safety than is the gas pipeline right-of-way for the 26 and 30 pipelines. At its closest, the route is approximately 1580 feet from the SOCA.4 This analysis considers the risks and potential consequences of a postulated failure of the pipeline, including a resulting fire and/or explosion, on safety-related and important-to-safety SSCs at IPEC.
1 Spectra Energy merged with Enbridge Inc. on February 27, 2017 and is now known as Enbridge. In this report, however, the pipeline owner will be referred to as Spectra.
2 Spectra Energy Abbreviated Certificate Application for Public Convenience and Necessity, Docket CP14-96-000, dated February 28, 2014 (Certificate Application).
3 Spectra Energy, Algonquin Incremental Market Project, Resource Report 10, November 5, 2013.
4 Table 1; Figure 1. The distance to the spent fuel pit and that the dry fuel storage location, is much farther from the 42-inch AIM pipeline than the SOCA boundary.
SECURITY-RELATED INFORMATIONWITHHOLD UNDER 10 CFR 2.390 Rev. 3, June 18 2020 3
2
SUMMARY
A hypothetical rupture of the new 42 natural gas pipeline located along the southern route can be postulated to result in a jet flame or cloud fire or, hypothetically and most unlikely, in detonation of a vapor cloud. Missile generation might also accompany rupture. Nuclear Regulatory Commission Guidance for explosions presented in Regulatory Guide 1.91, deems the risk posed by such events to be acceptable if they do not result in safety-related or important to safety SSCs being exposed to overpressures that exceed a 1 psi threshold or if the predicted frequency of events is less than 10-6/year if conservative assumptions are made or 10-7/year if realistic assumptions are made. Similar criteria can be applied for exposure to thermal radiation (a heat flux exceeding 12.6 kW/m2, the heat flux at which plastic melts) and missiles (to be outside a reasonable strike zone). The analysis of potentially hazardous events precipitated by pipeline rupture shows the threshold for damage to safety-related or important to safety SSCs within the SOCA will not be exceeded because of the distance between the SOCA and the new pipeline.
However, damage to certain SSCs important to safety located outside the SOCA and closer to or near the pipeline has also been considered to determine whether the damage thresholds might be exceeded should the pipeline rupture. These SSCs include the electrical switchyard with transmission lines, GT2/3 diesel fuel storage tank, the city water tank, the FLEX building, the Emergency Operations Facility (EOF), the meteorological tower and two steam generator mausoleums.5 It is concluded, however, that such damage poses minimal or no increased risk to safe plant operation as, with exceptions, conservative estimates of the frequency for hypothetical damage lie below the 10-6/year threshold of concern or the SSCs in question can withstand the postulated damage. The exceptions pertain to damage to the FLEX building, meteorological tower and the Unit 3 steam generator mausoleum. This risk is further evaluated as required by 10 CFR 50.59 process. It is also concluded that the new pipeline will not introduce additional risk as a result of terrorism or damage caused by seismic events.
As discussed further below, this analysis takes credit for certain additional pipeline design and installation enhancements agreed to by Spectra for a substantial portion of the pipeline near IPEC, including thicker piping, enhanced corrosion resistance, deeper burial depth, and protective reinforced concrete mats to be located above the buried piping. Such measures substantially reduce the already-low probability of pipeline failures that could impact SSCs near the pipeline. For purposes of this analysis, the section of the pipeline with additional design and installation measures is labeled as enhanced and traditional piping is labeled as unenhanced.
The enhanced portion of the pipeline is depicted in green on Figure 1. The term unenhanced, however, does not imply the piping is vulnerable to failure or damage, as such piping is also of superior quality and installed in accordance with all applicable regulatory requirements.6 5 The tanker trailer once stored outside the SOCA was moved to a location that would not be impacted by the potential failure of the new pipeline and therefore is not evaluated further in this report.
6 See Appendix B, Exhibits A and B.
SECURITY-RELATED INFORMATIONWITHHOLD UNDER 10 CFR 2.390 Rev. 3, June 18 2020 4
3 BACKGROUND Two natural gas transmission pipelines, a 26 and 30 pipeline, owned and operated by Spectra Energy, currently cross the IPEC site along an existing pipeline right-of-way (corridor). The potential threats posed by the postulated rupture of these pipelines and the release of natural gas (essentially methane) from them were originally addressed in the IP3 Licensing process as discussed in the NRC Safety Evaluation Report of September, 9, 1973 Two natural gas lines cross the Hudson River and pass about 640 feet from the Indian Point 3 Containment Structure.
Based on previous NRC staff review, failures of these gas lines will not impair the safe operation of Indian Point 3. Failure was subsequently addressed in the Individual Plant Evaluation for External Events (IPEEE) issued in 1997 [1]. Hypothetical consequences that might ensue following a major release of natural gas were described in the IPEEE, but it was concluded that no major risk was posed because the predicted frequency of major release events was below a 10-6/year threshold of concern.
Subsequently, a question7 was raised regarding the potential impacts from a pipeline rupture near IPEC as a result of intentional and malicious activity and, therefore, it was decided to re-evaluate the consequences of natural gas releases from the existing 26 and 30 pipelines related to exposed portions of the pipeline.8 A study performed for Entergy in 2008 [2], which included jet fire, vapor cloud fire, and vapor cloud explosion scenarios from assumed failures of one or both of the existing pipelines, concluded that the rupture of the natural gas pipelines that cross the IPEC (site) and subsequent ignition of the methane released will result in a jet fire and injury or death to any people exposed to flames or intense thermal radiation. It will not, however, damage any safety related structure. Even in the unlikely event of a hypothetical vapor cloud explosion, structural damage to buildings other than the waterfront warehouse adjacent to the pipelines will not occur. A flammable vapor cloud fire that engulfs the plant is improbable because the turbulent momentum with which the methane exits the pipeline will only confine flammable methane concentrations close to the point of release. The NRC reviewed and dispositioned the request for information with that analysis.
In response to the construction of a new 42 pipeline, this evaluation of the potential impacts on safety related and important-to-safety SSCs that might be posed by this new gas pipeline has been prepared. It reflects advances in the understanding of the consequences of the release and ignition of flammable gases and current regulatory guidance regarding such events provided by the US Nuclear Regulatory Commission [3]. The potential impacts of natural gas releases and their subsequent ignition on SSCs important to safety but located away from the SOCAthe switchyard, the meteorological tower, the city water tank, the GT2/3 diesel fuel storage tank, the 7NRC Request for Information RI-2008-A-021 letter dated March 12. 2008. Entergys response was provided in a letter dated September 30, 2008, ENOC-08-00046.
8 NRC RG 1.91, Evaluations of Explosions Postulated to Occur at Nearby Facilities and On Transportation Routes Near Nuclear Power Plants, does not mention or require consideration of terrorist action as initiating events.
Nevertheless, in response to NRCs questions, Entergy conservatively assumed such actions could result in pipe failures but only where the pipeline comes above ground.
SECURITY-RELATED INFORMATIONWITHHOLD UNDER 10 CFR 2.390 Rev. 3, June 18 2020 5
FLEX building, the Emergency Operations Facility (EOF) and the Unit 2 and 3 steam generator mausoleums are also examined. The closest distances of these SSCs from the pipeline are presented in Table 1 below.9 These SSCs perform the following functions:
Electrical Switchyard: Power to the site is provided from the Buchanan switchyard by 138--kV feeders and two underground 13.8-kV feeders. Electrical power generated by the site is raised to 345 kV and delivered to the Buchanan switchyard for distribution.
While no safety classification has been assigned to the switchyard, it is credited as a preferred source of power and so it is considered important to safety and is included in the technical specifications (TS).
Meteorological Tower: The meteorological tower provides weather information such as wind speed and direction to the EOF and the control room. This structure is considered important to safety. There is a backup meteorological tower and weather forecasting services are also provided by the NOAA in case of tower unavailability.
City Water Tank: The city water tank provides the backup water supply for the IP2 and IP3 auxiliary feedwater systems. It also serves as a backup for other SSCs including the IP2 Appendix R/station blackout A/C source. The tank was designed and evaluated as non-safety but is identified as important to safety for its functions and is included in the TS.
GT 2/3 Diesel Fuel Storage Tank: The diesel fuel oil tank provides a backup fuel oil supply for the IP2 and IP3 diesel generators and its fuel oil can also be used by the IP2 and IP3 Appendix R / station blackout (SBO) diesels. The plant requires a sufficient supply of fuel oil to run the diesels for 7 days. This tank is required by the Technical Specifications. It is designed to industry standards but is considered important to safety because of its function.
The FLEX Storage Building: This building will store the FLEX (flexible strategy) equipment for a Beyond Design Basis Accident, as required by NRCs post-Fukushima action items. The building is not safety related.
The Emergency Operations Facility (EOF): This facility provides a response center for part of the Emergency Response Team. There are several other facilities used simultaneously by the Emergency Response Organization. A backup for this facility is located off-site.
Steam Generator Mausoleums: The Unit 2 and 3 steam generator mausoleums are robust concrete structures used to house the original steam generators.
9 Distances obtained using Google Earth.
SECURITY-RELATED INFORMATIONWITHHOLD UNDER 10 CFR 2.390 Rev. 3, June 18 2020 6
Table 1: Closest Distances of SSCs from the Pipeline Item Closest distance from pipeline where underground (Figure 1)
Closest distance from pipeline where above ground (Figure 2)
Closest distance from transitions between the enhanced and un-enhanced pipeline (Figure 3)
SOCA 1580 ft (482 m)
(redacted) 1580 ft (482 m)
Switchyard (redacted)
GT2/3 diesel fuel storage tank City water tank Meteorological tower The FLEX Building The Emergency Operations Facility (EOF)
Unit 2 steam generator mausoleum Unit 3 steam generator mausoleum
SECURITY-RELATED INFORMATIONWITHHOLD UNDER 10 CFR 2.390 Rev. 3, June 18 2020 7
4 THE NEW PIPELINE The new pipeline is 42 in diameter with a normal operating pressure of 750 psig and a maximum operating pressure of 850 psig. The route taken by the pipeline is shown in Figures 1, 2 and 3 together with the distances presented in Table 1.
Figure 1: Route Taken by Pipeline, Showing Distances from the Nearest Section of Above-Ground Pipeline (redacted)
Rev. 3, June 18 2020 8
Figure 2: Route Taken by Pipeline, Showing Distances from the Nearest Section of Above-Ground Pipeline
SECURITY-RELATED INFORMATIONWITHHOLD UNDER 10 CFR 2.390 Rev. 3, June 18 2020 9
Figure 3: Route Taken by Pipeline, Showing Distances from the Un-enhanced Pipeline The 42 pipeline is of state-of-the-art construction, with a ~ 3935 ft (1199 m) segment near IPEC enhanced with additional design and installation features. This segment is shown in Figures 1 to 3; the additional design and installation features are detailed in Appendix BAnalysis of the Causes of and Determination of Exposure Rates for a Failure of the 42 AIM Natural Gas Pipeline near IPECand Exhibits A, B and C to that appendix.
In addition, consistent with DOT guidelines and requirements, the pipelines will be periodically inspected internally for flaws and reduced wall thickness using smart pigs. Aerial, vehicular and walking surveys of the pipeline routes are also made to detect gas leaks (often revealed by dead vegetation) and possible threats to pipeline integrity. As the portions of the pipeline closest to IPEC are buried in wide, clear and well-marked rights of way, these portions are unlikely to be damaged by careless construction or excavation. Most leakage in gas pipelines results from small pinholes and significant losses of gas do not occur unless induced stresses cause a larger hole or rupture of the pipeline before it is repaired [4]. But in the unlikely event of a pipeline failure, a large break in the line would result in a remote (Houston, Texas) low pressure alarm and subsequent pushbutton isolation of the section of broken pipethe section of pipe between the two outer isolation valves of the four isolation valves near IPEC that are conservatively assumed
SECURITY-RELATED INFORMATIONWITHHOLD UNDER 10 CFR 2.390 Rev. 3, June 18 2020 10 to be closed in the event of pipeline rupture is about 11 miles long10. Details of the maintenance and inspection program are also presented in Appendix B and Exhibit B.
10 The two closest isolation valves on each side of the rupture would be closed. The 11-mile length of line lies between the two outer valves and is the total length of line that would be blown down should the inner valves fail to close.
SECURITY-RELATED INFORMATIONWITHHOLD UNDER 10 CFR 2.390 Rev. 3, June 18 2020 11 5 PROPERTIES OF NATURAL GAS Methane, the primary component in natural gas, has the following hazard-related properties [5, 6, 7].
Table 2: Hazard-Related Properties of Methane Property Value Boiling point
-161.5oC Flash point
-222oC Lower flammable limit11 5.3%
Upper flammable limit 15%
Auto-ignition temperature 650oC Laminar burning velocity 0.448 m/s Initiation energy for immediate detonation 9.9 x 1010 mJ12 Toxic properties Simple asphyxiant Heat of combustion 50,030 kJ/kg These properties demonstrate that methane is a buoyant (lighter than air) gas of low fuel reactivity [8].
11 Detonation limits are narrower than flammable limits [6].
12 The corresponding value for a propane-air mixture is 4.1 x 108 mJ
SECURITY-RELATED INFORMATIONWITHHOLD UNDER 10 CFR 2.390 Rev. 3, June 18 2020 12 6 RISKS POSED BY NATURAL GAS RELEASES The rupture of a natural gas pipeline will result in the release of methane gas at high pressure as a turbulent jet with choked flow. Should this jet or the flammable vapor cloud ignite at some point, a number of consequences might ensue:
A jet fire A cloud (or flash) fire or a fireball should ignition be delayed.
Vapor cloud explosions resulting from the deflagration or detonation of the methane-air cloud Missile generationin addition to fires and explosion, the rupture of a pipeline might be accompanied by missile generation with fragments of the pipeline being thrown considerable distances Pipeline rupture might result from accidents or random or seismic-induced failure of the pipeline.
All these types of causes are evaluated and discussed below. It should be noted that ignition does not require a pre-existing source but might result from sparks created as ejected metal pieces or rocks rub together.
Jet Fire [6, 9]
A jet fire is a turbulent diffusion flame resulting from the combustion of a fuel. Jet fires have no inertiathey reach full intensity immediately after ignition and will change with the fuels release rate. The risk posed by jet fires arise because of the high heat fluxes incident on exposed personnel or equipment. Should the gas jet impinge upon the side of the crater formed in the ground, some of the momentum in the escaping gas will dissipate and the jet will be directed upward, thereby producing a fire with a horizontal profile that is generally wider and shorter than would be the case for an unobstructed vertical jet [10].
Cloud Fires and Fireballs [6, 9]
A cloud or flash fire is a transient fire resulting from the ignition of a cloud of flammable gas without significant flame acceleration as a result of turbulence. No significant overpressures result from a cloud fire and while such a fire might lead to injury and death to exposed personnel and local fires, it would not damage equipment or structuresa vapor cloud fire will be of short duration (a few tens of seconds) and thus the total radiation intercepted by an object near a flash fire is substantially lower than from... a jet fire (p 79, [6]).
The absence of damage to equipment or structures in itself would give sufficient reason to set aside a cloud fire as a threat to the nuclear plants. In addition though, as will be seen in the subsequent discussion of vapor cloud explosions, a turbulent momentum jet will emerge initially from the ruptured pipeline and the concentration of methane will fall below the flammable limit within the jet and so no cloud of flammable methane gas will be created. For the lower release rates that prevail if the rupture does not blow away the soil atop the pipeline or once the rupture
SECURITY-RELATED INFORMATIONWITHHOLD UNDER 10 CFR 2.390 Rev. 3, June 18 2020 13 is isolated and pipeline contents have blown down, the mass release rate will not give rise to a flammable methane cloud more than ~ 100 m from the point of rupture even if the methane behaves as a dense gas. In practice, the buoyant nature of the vapor precludes the formation of a persistent flammable vapor cloud at ground level [10]. Therefore, vapor cloud fires pose little threat and thus need not be considered further.
A fireball results from the rapid turbulent combustion of fuel as an expanding, radiant ball of flame. Normally, however, it results from the release of a pressurized liquid rather than the release of compressed gas and so it will not be considered further here [11].
Vapor Cloud Explosion [6, 9]
There are three pre-conditions for a vapor cloud explosion [6]:
There must be a release of flammable material into a congested area or area of high turbulence.
Ignition must be delayed to allow the formation of an ignitable mixture with the fuel-air concentration in the flammable range There must be an ignition source of sufficient energy to ignite the fuel-air mixture.
Vapor cloud explosions can occur as a result of deflagrations or detonations. In a deflagration, the flame propagates through the unburned methane-air mixture at a burning velocity that is less than the speed of sound. Overpressures generated in such an explosion will vary with the combustion rate. Given the low flame speed of methane, minimal overpressures are expected with deflagrations of methane and airit has been concluded that a deflagration traveling through unenclosed gas cloud will result in negligible overpressures [11]. A deflagration can be initiated by a weak energy source.
In a detonation, the methane-air reaction front propagates as a shockwave that compresses the unburned gas-air mixture so that temperatures in the cells of the mixture exceed the auto-ignition temperature. The shockwave is therefore maintained by the combustion reaction that follows it.
A detonation can be achieved with a high energy ignition source or by flame acceleration within a highly congested area or a high momentum (jet) release. However, because of methanes low reactivity, a detonation within a methane-air cloud will not persist outside the congested or turbulent area [12] and methane outside this area will not contribute to the strength of the blast.
This would suggest that for a gas pipeline that traverses near IPEC, a detonation will not draw upon methane outside the jet or the areas of congestion provided by trees adjacent to the right of way. With respect to congestion, tests performed on natural gas have shown that a high degree of congestion is required to obtain high flame speeds and overpressures with natural gas [13];
other experiments failed to initiate an explosion of natural gas and methane mixtures with air in a semi-open space even when explosive was used as an ignition source [14]. Thus, the consensus amongst experts is that methane gas will not give rise to vapor cloud explosions unless confined
SECURITY-RELATED INFORMATIONWITHHOLD UNDER 10 CFR 2.390 Rev. 3, June 18 2020 14
[8, 15, 1613]. That said, various reports and studies prepared following the 2005 Buncefield explosion suggest that belts of trees provide sufficient congestion to facilitate flame acceleration that might lead to detonation [17-19]. Flame acceleration is particularly likely where thick undergrowth and deciduous trees prevail.
Let us consider next how methane emerges from a ruptured pipeline. Initially, methane will emerge in choked flow from the ruptured pipeline in a high velocity momentum jet that will entrain air and so will be diluted to below methanes lower flammable limit and indeed field evidence suggests that intense turbulent mixing and air entrainment would limit the area in which any gas cloud would be flammable within a horizontal distance of ~ 100 m (328 ft) of the rupture
[8]. Studies of gas releases from high pressure pipelines provide additional insight into what happens within the turbulent jet [29, 30]14, showing that methane will exit the jet below its flammable range. Considering next the situation where the pipeline pressure has fallen [31], so that the methane exits at lower velocities the mass flow rate of the methane emerging would be such that methane might no longer be flammable at distances exceeding ~ 100 m from the point of rupture even if the methane could still be considered a dense gas (its exit temperature would be much closer to ambient). For natural gas releases from the buried pipeline in which soil is not blown away, flammable gas appears only close to the surface within an area within a radius of ~
6 m or less, this depending upon pipeline pressure, the size of the orifice through which methane is discharged and soil porosity [29].
All this would suggest that two vapor cloud explosion scenarios are of hypothetical concern: a vapor cloud explosion occurring in the turbulent jet and, possibly, an explosion within the belts of trees adjacent to the pipeline right of way following pipeline rupture, removal of soil cover over the pipeline and lowering of pipeline pressure such that the gas no longer exits in choked flow with a strong momentum jet.
13 FM Global [16] states that the following materials do not present a significant or credible outdoor (Vapor Cloud Explosion) exposure.methane.
14 Using Computational Fluid Dynamics, Deng et al. [30] simulated the dispersion of natural gas releases from a buried pipeline. They demonstrated that a high velocity jet would be created, the greater the pipeline pressure, the greater the height reached by the jet. The flammable region was shown to lie within the jet, at a short distance from the jet axis for releases occurring over a wide range of pipeline pressures. As wind speeds increase, the furthest distance the flammable region reaches from the point of rupture first increases as the jet bends and then starts to decrease with increasing gas dispersion. Similarly, Novembre et al. [31] showed methane concentrations along the jet axis to fall below the flammable range at about 80 m from the point of rupture (for a release at ~ 145 psig) and >
120 m (for a release at 725 psia).
SECURITY-RELATED INFORMATIONWITHHOLD UNDER 10 CFR 2.390 Rev. 3, June 18 2020 15 Missiles The rupture or bursting of a gas pipeline might also result in large fragments being thrown a considerable distanceLees [8] describes a 1965 incident in Natchitoches, La, in which a high-pressure gas pipeline ruptured, splitting the pipe along a 26-ft (8m) length. In the subsequent blowout, three pieces of metal weighing 1/2 ton in all were thrown 130-360 ft (40 - 110m) from the point of rupture. A greater distance was recorded in an NTSB report (PAR-95-01) for a pipeline rupture in New Jersey in which pipeline fragments, rocks and debris were thrown more than 244 m (800 ft) Similarly, a 2/2/2003 incident in Illinois resulted in pipeline fragments being thrown as far as 554 ft (169 m) 15 and a 8/1/2019 incident in Kentucky resulted in pipeline fragments being thrown 481 ft (146 m). Given this experienceas 274 m (900 ft) exceeds the greatest distance noted in the literature for fragments of the pipeline to be thrown after rupture--
and the greater distance of the pipeline to main plant systems and structures in the SOCA (~
1580 ft or 482 m from the SOCA), missiles from a rupture or burst of the pipeline will not endanger SSCs inside the SOCA. In addition, with respect to these fragments, we would note that Section 16.2.1 of the IP3 FSAR [20] states that Class I buildings and structures at IP3, the unit closest to the pipeline, are designed for tornado loadings calculated assuming the simultaneous application of a tangential wind velocity of 300 mph, a translational velocity of 60 mph, a pressure change (drop or increase) of 3 psi in 3 sec., and postulated tornado missiles with potential missiles including a 4000-lb automobile. Accordingly, we would conclude that the impact of pipe fragments on safety related systems, structures and components at IP3 is bounded by the scenarios considered in the FSAR16. Potential impacts of missiles on the SSCs important to safety outside the SOCA and closer to the pipeline are discussed below.
The release of gas at high pressure will of course also blow off any soil or fill cover above the pipeline and scour away earth from around the pipeline creating a crater. But such action will not harm SSCs within the SOCA or near the pipeline.
15 According to PHMSA (as recorded by an Expert Evaluation Team [28]), the 900 feet reported for this incident was an initial estimate by accident investigators, but the final established distance was 554 feet, 16 While IP2 was not designed to withstand tornado missiles, its distance from the pipeline is greater, far exceeding the distance a missile might be thrown.
SECURITY-RELATED INFORMATIONWITHHOLD UNDER 10 CFR 2.390 Rev. 3, June 18 2020 16 7 REGULATORY GUIDANCE The US Nuclear Regulatory Commission has issued Regulatory Guide 1.91 [3] that provides guidance for the evaluation of potential explosions near nuclear power plants; other potential but lesser hazards such as jet fires were not addressed, however.
Regulatory Guide 1.91 concerns itself with blast damage to nuclear power plant structures occasioned by incident or reflected pressure (overpressure), dynamic (drag) pressure, blast-induced ground motion and blast-generated missiles. Of these the primary concern is with overpressure. The guide states that General Design Criteria for nuclear power plants would be satisfied with respect to potential nearby hazards and explosions if:
The distance between critical plant structures and source of the blast is sufficient to avoid any impact from an explosionif the distances between the explosion and systems, structures and components important to safety are such that no system, structure or component important to safety would be exposed to a conservatively determined positive peak incident overpressure in excess of 1 psi.
The regulatory guide then goes on to state that if the explosion is closer to systems, structures and components important to safety than this minimum safe distance, then the risk of damage caused by an explosion is acceptably low if:
The exposure rate for such incidents is less than 1 x 10-6/year if conservative assumptions are used in the analysis or 1 x 10-7/year if realistic assumptions are used.
or The systems, structures and components important to safety can be demonstrated by analysis to be capable of withstanding the blast and missile effects associated with the explosion.
Looking specifically at explosions that might occur following releases of natural gas from a pipeline, the Guide states that plume modeling based on site topography and meteorological conditions should be evaluated. The reference for such modeling, NUREG CR/6410 [21],
makes explicit mention of the TNT equivalence method for vapor cloud explosion blast modeling. In discussing the atmospheric dispersion models, NUREG CR/6410 also notes a number of limitations to models. Of these, the only limitation pertinent to modeling the release of methane is that it does not consider ground topography in the area affected by the plume.
While the same limitation is present in most simpler dispersion models including SLAB, the dispersion models used within BREEZE Incident Analyst, it should be noted that the terrain near the switchyard and GT2/3 diesel fuel oil tank is relatively flat17.
17 NUREG/CR-6410 [21Section D.6.5.1].
SECURITY-RELATED INFORMATIONWITHHOLD UNDER 10 CFR 2.390 Rev. 3, June 18 2020 17 8 SOFTWARE AND MODELS The consequences of the release scenarios described previously are predicted using the models contained within BREEZE Incident Analyst 3.0 software18. This software comprises a user-friendly implementation of other models widely used to characterize chemical release scenarios.
The models of concern here are The Gas Research Institute model for jet flames SLAB for vapor cloud dispersion and the US Army TNT Equivalence and the TNO multi-energy model for vapor cloud explosions.
The models within BREEZE Incident Analyst 3.0 software used to characterize the anticipated and hypothetical consequences of the release of natural gas from the pipeline crossing near the IPEC site are listed in Table 3. The basis for the selection of these models is also presented in Table 3.
18 Because of doubts cast on its use [28], ALOHA software is not used in this revision to the hazard analysis.
SECURITY-RELATED INFORMATIONWITHHOLD UNDER 10 CFR 2.390 Rev. 3, June 18 2020 18 Table 3: Models Used Scenario Model Basis for Selection Jet flame BREEZE: Gas Research Institute This model addresses fires that may result from the leak or rupture of a pipeline containing a compressed gas.
Cloud dispersion (extent of flammable cloud)
BREEZE: SLAB The maximum cloud centerline concentrations predicted using this simpler model appear reasonable when compared to predictions made using Computational Fluid Dynamics [23].
Earlier, Hanna, et al. stated that the SLAB model demonstrates consistently good behavior across all comparisons with observations [21, 24].
Vapor cloud explosion BREEZE: US Army TNT Equivalence model This model comprises the implementation of equations 1 to 4 presented in Regulatory Guide 1.91
[3]. The predictions closely match those calculated using the equations.
The TNT Equivalence model is best used with point sources; for vapor cloud explosions it has deficiencies in that it gives an overprediction of overpressures in the near field, underprediction in the far field and a shorter duration than is encountered BREEZE: TNO Multi-energy model This model is a simple and practical method used for vapor cloud explosions. It is based on the premise that a vapor cloud explosion can occur only within that portion of a flammable vapor that is partially confined. It remedies the deficiencies in the Army TNT Equivalence model.
SECURITY-RELATED INFORMATIONWITHHOLD UNDER 10 CFR 2.390 Rev. 3, June 18 2020 19 9 POSSIBLE RELEASES AND THEIR CONSEQUENCES While we exclude no cause of release from this evaluation, and in particular we will allow for delayed ignition in the event of a large release, pipeline ruptures and the releases considered are presumed to occur at or from the natural gas pipeline at points nearest to the SOCA, the switchyard, the GT2/3 fuel storage tank, the city water tank, the FLEX building, the Emergency Operations Facility, meteorological tower and the steam generator mausoleums.
The following scenarios will be considered:
A jet fire A hypothetical vapor cloud explosion involving detonation Missile generation.
Releases will be assumed to result from the guillotine rupture of a pipeline, the creation of a 6 diameter hole in a pipeline or the rupture of a 2 line that branches off the pipeline. It should be noted that the underground 42 pipeline has no outlets, taps, branches, fittings, drips or tees near IPEC and therefore the lesser releases are presented solely for comparison purposes. In modeling releases and their consequences, we assume that the contents of an 11-mile length of gas pipeline are released at a pressure of 850 psig (the MAOP of the 42 pipeline), that valves isolating this length of pipeline will be closed within 8 minutes of a major release19 and that the interior of this pipeline is smooth20. The guillotine rupture of the pipeline is assumed to result in a double-ended release of natural gas fed with full-bore flow from both sides of the rupture with the resulting releases merging. This assumption is conservative in that it ignores lesser ruptures and the impact that flows from either side of the rupture will have on each other. To model such a release, we assume the release is equivalent to that from a pipeline with a diameter that is 1.414 (i.e., 2) times larger than the actual 42 pipe diameter. The wind speed and Pasquill air stability assumed are the 1.5 m/s wind speed and F-class stability proposed for worst case consequences in the EPA Risk Management Guidance [22]. Alternative results were obtained using the 3 m/s wind speed and D-class stability proposed by the EPA. These latter 19 This time includes the time required for the pipeline operator to receive and assess alarms, take the compressor at Stoney Point, west of IPEC, off-line and then close isolation valves. It is conservatively assumed that the pipeline isolation valves closest to IPEC will not close and so the length of pipeline isolated and blown down is the 11 mile length between the next valves upstream and downstream of the closest valves. After valve closure, full bore release from the pipeline will persist for another 30 minutes. The release following guillotine rupture will therefore be ~ 40 minutes duration.
20 The release rate is higher if the interior of the pipeline is smooth (20 % higher in the case of a guillotine rupture of the 42 pipeline).
SECURITY-RELATED INFORMATIONWITHHOLD UNDER 10 CFR 2.390 Rev. 3, June 18 2020 20 meteorological conditions are more common21. Missile generation will be assumed to accompany rupture some of the time.
Jet Fires Immediate ignition of the release, possibly caused by sparks created as ejected metal pieces or rocks rubbing together, will result in a jet fire anchored on the pipeline with a flame that might rise ~ 328 feet (100 m) or more; delayed ignition might result in a vapor cloud fire that burns back to the pipeline and ends up as a jet fire. The consequences of thermal radiation at various intensities are presented in Table 4; the thermal consequences of jet fires following specific releases under various wind speed and atmospheric conditions and flame inclinations are presented in Table 5. It can be seen that the distance at which a jet flame results in a given thermal flux depends upon the wind speed and air stability and upon the angle to the horizontal at which the jet emerges, being greatest in a horizontal direction and least in a vertical direction.
In the event of a full-bore guillotine rupture of a deep buried pipeline, the jet is expected to rise vertically. However, to be conservative, the jet is assumed to emerge at an angle of 60o to the horizontal here. Finally, the thermal consequences of jet fires following specific releases are presented in Tables 6 and 7. In general, the threshold for damage caused by jet flames and thermal radiation is 12.6 kW/m2, the heat flux at which exposed plastic melts and damage to instrumentation and electrical equipment can be anticipated. For damage to concrete buildings, however, the threshold heat flux is much higher, ~ 31.5 kW/m2or more. The jet flame created by ignition of a double-sided full bore release of natural gas following the guillotine rupture of the 42 pipeline will result in a thermal flux of 12.6 kW/m2 at a distance of 473 m (1545 ft) from the point of rupture assuming the jet emerges at an angle of 60o from the horizontal, a wind speed of 3 m/s and a Pasquill class D air stability. This predicted impact distance is conservative being based on the average release rate in the minute after ruptureat one minute after rupture of the 42 pipeline, the impact distance will have fallen to from 473 m (1552 ft) to 317 m (1040 ft).
We should also note that this distance assumes that the wind direction and flame inclination as it emerges from the ground incline the flame towards the target.
From these results we can conclude that in the event of a jet fire involving the guillotine rupture of the natural gas pipeline in proximity to the SOCA, personnel across the plant site close to the point of rupture who are unable to quickly take shelter will be injured and might die. However, the levels of thermal radiation seen following the guillotine rupture of the 42 pipeline will neither cause plastics to melt nor cause the spontaneous ignition of wood within the SOCA22.
Similarly, a lesser release through a 6 diameter hole in the pipeline or from the assumed guillotine rupture of a hypothetical 2 line that branches off a larger pipeline will only expose personnel outdoors and near the point of rupture to possible injury or death. There will be no damage to equipment within the SOCA.
21 For example, at night between the hours of 9 pm and 6 am at Westchester County Airport, atmospheric conditions with a wind speed of ~ 3 m/s and Pasquill D air stability are twice as common as those with a wind speed of 1.5 m/s and Pasquill F stability. Furthermore, F stability will not be encountered in the daytime while D will.
22 Furthermore, we would note that no such exposed equipment exists in SOCAmost equipment lies indoors behind concrete walls and the transformers would be shaded from this thermal radiation.
SECURITY-RELATED INFORMATIONWITHHOLD UNDER 10 CFR 2.390 Rev. 3, June 18 2020 21 Considering next possible damage to the meteorological tower, the GT2/3 diesel fuel storage tank, the city water tank, the FLEX building, the EOF, the steam generator mausoleums and switchyard, all located outside the SOCA, as a result of the rupture of a pipeline and jet fire at the closest points to these items, damage is assumed to occur as noted in Table 7. This damage might result from engulfment in flames (e.g., in the event of a jet fire initiated on the pipeline directly impinging on the GT2/3 fuel tank) and intense thermal radiation that might damage equipment and, for the fuel tank, cause a tank vent fire. Without accounting for the very low probability of such events, pipeline ruptures could introduce additional risk to equipment located away from the SOCA. This additional risk is, however, minimal as:
While the 12.6 kW/m2 threshold for damage is exceeded at the city water tank, should the pipeline rupture and a jet fire ensue, damage to the structure itself is unlikely given the distance between the water tank and the rupture and the short duration of exposure to high thermal radiation. Similarly, no substantive damage to the Unit 2 steam generator mausoleum is anticipated due to the robust design of the structure.
Damage to the FLEX building may occur from a jet fire. However, given that there is no exposed instrumentation that might be damaged and the short duration of exposure to thermal radiation that exceeds the 12.6 kW/m2 exposure, this will not be important.
Damage to the switchyard may occur from a jet fire caused by a guillotine rupture of the 42 pipeline at the point closest to the switchyard and assuming the jet fire is directed toward the switchyard.23 However, both IP2 and IP3 have three emergency diesel generators (with sufficient diesel fuel stored on-site for these generators to run at least 2 days) and an Appendix R/station blackout diesel generator with additional fuel to mitigate the loss of offsite power. Therefore, there will be more than two days to obtain additional fuel should both the switchyard and GT2/3 fuel tank be unavailable. While a jet fire close to the switchyard might cause simultaneous damage to both the switchyard and GT2/3 diesel fuel storage tank, the probability of such an event involving the enhanced pipeline is below NRCs threshold for further consideration. This possibility is discussed further below.
Damage to the meteorological tower may also occur from a jet fire caused by a guillotine rupture of the 42 pipeline at the point closest to the switchyard and assuming the jet fire is directed toward the tower.24 The potential consequences of damage to the meteorological tower, however, can be mitigated as the data it provides can be obtained from other sources, including a backup meteorological tower and weather forecasting services such as those provided by the NOAA.
As the SSC important to safety closest to the pipeline, damage to the GT 2/3 fuel tank may occur from either a guillotine rupture of the 42 pipeline or from a leak through a 6 hole.
23 Little or no damage to the switchyard is expected from smaller postulated failures or leaks.
24 No damage to the meteorological tower is expected from smaller postulated failures or leaks.
SECURITY-RELATED INFORMATIONWITHHOLD UNDER 10 CFR 2.390 Rev. 3, June 18 2020 22 The consequences of damage to the GT2/3 fuel tank, however, can be mitigated by the availability of alternative sources of diesel fuel should the on-site reserve diesel fuel tanks be unavailable. As the tanker used to transport diesel fuel from the GT2/3 fuel storage tank to the emergency diesel generators might be vulnerable to damage should the pipeline rupture, it was relocated to within the SOCA. Also, as discussed above, the likelihood of a failure of the enhanced pipeline that could cause such damage is below NRCs 10-6/year threshold of concern.
While damage to external instrumentation on the EOF might occur as a result of exposure to a heat flux of 12.6 kW/m2 or more subsequent to pipeline rupture and the creation of a jet flame, there is an alternative EOF. Building damage to the Unit 3 steam generator storage mausoleum might also occur as a result of heat fluxes in excess of 31.5 kW/m2. Such damage, however is unlikely to be of consequence given the robust design of the structure.
Finally, we note that a jet fire originating from a ruptured above-ground portion of the pipeline east of the SOCA, where the new 42 pipeline will connect to the existing right of way, will not cause damage to SSCs within the SOCA, the meteorological tower, the GT2/3 fuel tank, the city water tank, the FLEX building, or the EOF because of the distance between this above-ground portion of the pipeline and the other objects (Figure 2, Table 8). While the switchyard might be exposed to thermal radiation in excess of 12.6 kW/m2 this exposure will be of short duration. In summary, as SSCs important to safety might be exposed to thermal radiation in excess of a relevant threshold subsequent to pipeline rupture and ignition of the release, general potential exposure rates for damage need to be determined.
SECURITY-RELATED INFORMATIONWITHHOLD UNDER 10 CFR 2.390 Rev. 3, June 18 2020 23 Table 4: Consequences of Exposure to Thermal Radiation [8]
Thermal Radiation (kW/m2)
Consequence 2
Pain within 60 s 5
Tolerable to escaping personnel 8
Fatal after exposure for several minutes 10 Potentially fatal in 60 s 12.6 Plastic melts, piloted ignition of wood25 25 Non-piloted ignition of wood 31.5 Building damage [29]
35 Equipment damage Table 5 Consequences of Jet Fire Scenarios ConsequencesDistances at which Level of Radiation Seen Scenario Thermal Radiation (kW/m2)
Vertical flame Wind 1.5 m/s, F stability Flame at 60o to horizontal, Wind 1.5 m/s, F stability Vertical
- flame, Wind 3 m/s, D stability Flame at 60o to horizontal, Wind 3 m/s, D stability Guillotine rupture of the 42 pipeline with double sided release 2
1135 m (3724 ft) 1460 m (4790 ft) 1119 m (3671 ft) 1442 m (4731 ft) 5 646 m (2119 ft) 915 m (3002 ft) 609 m (1998 ft) 950 m (3117 ft) 10 Nominal distance:
50 m (164 ft)
Nominal distance:
50 m (164 ft) 410 m (1345 ft) 606 m (1988 ft) 12.6 Nominal distance:
50 m (164 ft)
Nominal distance:
50 m (164 ft) 259 m (850 ft) 473 m (1545 ft) 25 Nominal distance:
50 m (164 ft)
Nominal distance:
50 m (164 ft)
Nominal distance:
50 m (164 ft)
Nominal distance:
50 m (164 ft) 25 Piloted ignition is defined as the appearance of a flame at the surface of a material which has been exposed to external heating with an ignition source present in the volatile stream created as the material is heated [25].
SECURITY-RELATED INFORMATIONWITHHOLD UNDER 10 CFR 2.390 Rev. 3, June 18 2020 24 Table 6: Consequences of Jet Fire Scenarios, Flame at 60o to horizontal, Wind 3 m/s, D Stability Scenario ConsequencesDistances at which Level of Radiation Seen Scenario Thermal Radiation (kW/m2)
Impact Distance Guillotine rupture of the 42 pipeline with double sided release 2
1442 m (4731 ft) 5 950 m (3117 ft) 10 606 m (1988 ft) 12.6 473 m (1545 ft) 25 50 m (164 ft) 35 50 m (164 ft)
Leak through 6 hole in 42 pipeline 2
554 m (574 ft) 5 108 m (353 ft) 10 51 m (167 ft) 12.6 Not calculated 25 Not calculated 35 Not calculated Leak through 2 line branching off 42 pipeline 2
61 m (199 ft) 5 33 m (108 ft) 10 Not calculated 12.6 Not calculated 25 Not calculated 35 Not calculated
SECURITY-RELATED INFORMATIONWITHHOLD UNDER 10 CFR 2.390 Rev. 3, June 18 2020 25 Table 7: Potential Damage at Closest Distances from Pipeline in the Event of Pipeline Rupture and a Jet Fire Item Damage on pipeline rupture and jet fire Switchyard Yes GT2/3 fuel tank Yes City water tank Yes (to external instrumentation)
Meteorological tower Yes (to instrumentation)
The FLEX Building Yes (building damage is possible though this is unlikely to be of consequence the short duration to thermal radiation exceeding the threshold)
The Emergency Operations Facility (EOF)
Yes (in particular to external instrumentation)
Unit 2 steam generator mausoleum Yes (building damage is possible though this is unlikely to be of consequence given the robust design of the structure and the short duration to thermal radiation exceeding the threshold))
Unit 3 steam generator mausoleum Yes (building damage is possible though this is unlikely to be of consequence given the robust design of the structure)
SECURITY-RELATED INFORMATIONWITHHOLD UNDER 10 CFR 2.390 Rev. 3, June 18 2020 26 Table 8: A Comparison of Distances from Above-Ground Portions of the Pipeline and the Impact Distance to a heat flux of 12.6 kW/m2 Item Impact distance to a heat flux of 12.6 kW/m2 (assuming the guillotine rupture of a 42 pipeline Table 5)
Closest distance from pipeline where above ground at approx. M.P. 5.5 SOCA 1,545 feet (473 m) 2,363 ft (720 m)
Switchyard 1,545 feet (473 m) 1429 ft (436 m)
GT2/3 fuel tank 1,545 feet (473 m) 2622 ft (799 m)
City water tank 1,545 feet (473 m) 1741 ft (531 m)
Meteorological tower 1,545 feet (473 m) 4282 ft (1305 m)
The FLEX Building 1,545 feet (473 m) 3943 (1202 m)
The Emergency Operations Facility (EOF) 1,545 feet (473 m) 2195 ft (669 m)
Unit 2 steam generator mausoleum 1,545 feet (473 m) 2420 ft (738 m)
Unit 3 steam generator mausoleum 1,545 feet (473 m) 4587 ft (1398 m)
Vapor Cloud Explosions As noted above, it is not likely that any release of methane from a natural gas pipeline will result in a vapor cloud explosion and that, should this occur, it will entail a deflagration with low resulting overpressures rather than a detonation. A detonation is hypothetically possible, however, in the turbulent methane jet entrained with air and within the belts of trees adjacent to a right of way associated with the 42 pipeline. In both cases, a detonation might occur as a result of a transition from a deflagration to a detonation or if ignition is caused by a high energy source.
In neither case though would the detonation persist beyond the congested or turbulent area. In calculating the consequences of a hypothetical detonation within the turbulent jet, we assume the detonation to be centered about the point of rupture; in calculating the consequences of a hypothetical detonation within wooded areas, we assume the detonation to be centered about the middle of that wooded area in which a flammable concentration of methane might be found.
In evaluating vapor cloud explosions, the critical distances are:
The shortest distance from the 42 pipeline (the assumed center of an explosion in the turbulent jet) to a system, structure or component important to safety in the SOCA (the Primary Water Storage Tank or PWST) is ~ 594 m (1949 ft). The shortest distance to the SOCA is ~ 482 m (1580 ft).
SECURITY-RELATED INFORMATIONWITHHOLD UNDER 10 CFR 2.390 Rev. 3, June 18 2020 27 For the 42 pipeline, the shortest distance from the mid-point of an explosion initiated in trees to the northeast of the right of way to a system, structure or component important to safety (the PWST) is ~ 584 m (1916 ft) for large releases.
The other distances from the 42 pipeline to the safety-related or important to safety SSCs of concern are presented in Table 1.
Vapor cloud explosions within the turbulent jet were modeled using US Army TNT equivalent explosion model as implemented within BREEZE Incident Analyst. The minimum safe distances beyond which the overpressure will not exceed 1 psi were also calculated using equation (1) in the Regulatory Guide [3]26. The mass of flammable material potentially involved in an explosion is estimated using an approach suggested by both the FM Data Sheets 7-42 [16]
and Woodward [26] as directed by the Regulatory Guide. Essentially this leads to an explosion involving the mass of methane between the upper and lower flammable limits in the turbulent methane jet created by a rupture of the pipeline The calculation of the mass of methane that might contribute to an explosion is described in footnotes to Table 11 and Appendix A; the masses are also presented in Appendix A. In applying the TNT equivalency models, a yield of 5 % is assumed as suggested in Table 1 of the Regulatory Guide. A comparison of the minimum safe distances calculated using equation (1) in the Regulatory Guide and the implementation of the US Army TNT equivalency model in Breeze Incident Analyst shows small but consistent discrepancies. These are the result of a higher energy of explosion being assumed for TNT in the latter Vapor cloud explosions involving a drifting dense cloud of methane were modeled using the TNO multi-energy model as implemented within BREEZE Incident Analyst software assuming that the rupture is not isolated, the volume of flammable material potentially involved in an explosion being the volume of the cloud in the belt of trees immediately to the north of the pipeline right-of-way. The volumes are also presented in Appendix A. It should be noted that the pipeline lies in a clear-cut 100-ft wide corridor. The assumption of explosions arising in belts of trees is conservative particularly as, under the conditions in which a flammable vapor cloud might be createdlater in the release when pipeline pressure was low and choked flow and a high velocity jet no longer prevailed or when the release does not blow away soil atop the pipelinethe mass flow rate from the rupture and so too the likelihood that the release will behave as a dense gas would be low.
The consequences of these overpressures are described in Tables 9, 10 and 11; plots of the overpressure that might be experienced following the guillotine rupture of the 42 pipeline are presented in Figures 4 and 5.
Figure 4 depicts the consequences of a hypothetical vapor cloud explosion initiated in the belt of trees to the northeast of the 42 gas pipeline. The epicenter of the explosion is placed in the middle of the belt of trees adjacent to the pipeline in which a flammable concentration 26 The overpressures are calculated assuming a surface explosion rather than a free air explosion. This results in slightly higher overpressures being predicted.
SECURITY-RELATED INFORMATIONWITHHOLD UNDER 10 CFR 2.390 Rev. 3, June 18 2020 28 of methane might persist should this be allowed by the wind and release directions and speeds.
Figure 5 depicts the consequences of a hypothetical vapor cloud explosion initiated in the turbulent jet of methane following the guillotine rupture of the 42 gas pipeline. The epicenter of the explosion is placed on the pipeline at is closest point to a system, structure or component important to safety in the SOCA.
The sizes of the wooded areas and thus the volumes of natural gas that might be caught within them and the calculated masses of natural gas involved in a hypothetical detonation are presented in Appendix A.
The results presented in Tables 10 and 11 show that no hypothetical detonation following the guillotine rupture of the pipeline will result in overpressures exceeding 1 psi at a system, structure or component important to safety within the SOCA. Similarly, no overpressures in excess of 1 psi are seen by systems, structures and components important to safety located away from the SOCA as a result of the rupture of the closest above-ground portion of the pipeline.
However, as overpressures in excess of 1 psi could be seen by certain systems, structures and components important to safety located away from the SOCA, as a result of the rupture of underground sections of the pipeline and a subsequent detonation27, exposure rates for such damage needs to be determined. This is documented in Appendix B.
Table 9 Consequences of Exposure to Overpressures [6, 8, 27]
Overpressure Consequence 1 psi Glass shatters 2 - 6 psi Serious structural damage to houses 6 - 9 psi Severe damage to reinforced concrete structures 10 psi Destruction of buildings 27 In evaluating releases from the pipeline at points close to important to safety SSCs outside the SOCA, it was decided that, given the low likelihood that a flammable dense cloud of methane would be created and would then drift north into congested areas, detonation within the turbulent jet would be the detonation normally considered.
SECURITY-RELATED INFORMATIONWITHHOLD UNDER 10 CFR 2.390 Rev. 3, June 18 2020 29 Table 10: Consequences of Vapor Cloud Explosions in Trees to the Northeast of the Pipeline (shortest distance to a system, structure or component important to safety in the SOCA the PWST: 584 m (1916 ft))28 Scenario ConsequencesDistances at which a Given Overpressure Seen Guillotine rupture of the 42 pipeline with double sided release at a time when outflow from the pipeline is no longer choked (outflow 71,958 lb/min..(544 kg/s))
8.0 psi at 101 m (331 ft) 3.5 psi at 190 m (623 ft) 1.0 psi at 424 m (1391 ft)
(0.71 psi at closest system, structure or component important to safety in the SOCAthe PWST; 1.25 psi at the meteorological tower; 2.0 psi at the switchyard boundary; 2.3 psi at GT2/3; 1.17 psi at the FLEX building; 1.53 psi at the EOF; 1.3 psi at the city water tank; 1.14 psi at the Unit 2 steam generator mausoleum; and 0.94 psi at the Unit 3 steam generator). Contours shown in Figure 4.
Leak through 6 hole in 42 pipeline 8.0 psi at 36 m (118 ft) 3.5 psi at 59 m (194 ft) 1.0 psi at 153 m (502 ft)
(0.28 psi at closest system, structure or component important to safety in the SOCAthe PWST) 28 The charge assumed in this vapor cloud explosion is assumed conservatively to be the maximum.
SECURITY-RELATED INFORMATIONWITHHOLD UNDER 10 CFR 2.390 Rev. 3, June 18 2020 30 Table 11: Consequences of Vapor Cloud Explosions in Turbulent Jet on Pipeline (shortest distance to a system, structure or component important to safety in the SOCAthe PWST: 594 m 1949 ft))
Scenario ConsequencesDistances at which a Given Overpressure Seen Guillotine rupture of the 42 pipeline with double sided release 8.0 psi at 100 m (328 ft) 3.5 psi at 172 m (564 ft) 1.0 psi at 390 m (1280 ft)
(0.58 psi at closest system, structure or component important to safety in the SOCAthe PWST; 3.6 psi at the meteorological tower; 80 psi at the switchyard boundary; 99 psi at GT2/3, 1.4 psi at the FLEX building, 1.5 psi at the EOF, 0.9 psi at the city water tank, 0.85 psi at the Unit 2 steam generator mausoleum, and 4.5 psi at the Unit 3 steam generator mausoleum assuming rupture at the closest points from the pipeline to these structures)29.
Contours shown in Figure 5.
Leak through 6 hole in 42 pipeline 8.0 psi at 10 m (33 ft) 3.5 psi at 17 m (57 ft) 1.0 psi at 39 m (128 ft)
(0.025 psi at closest system, structure or component important to safety in the SOCA the PWST; 1.2 psi at GT2/3) 29 As noted in Table 3, the TNT Equivalence model gives an overprediction of overpressures in the near field, hence the high overpressures at GT2/3 predicted here, Suffice it to say that should this hypothetical explosion occur, SSCs close to the point of detonation will experience a major overpressureit is believed that overpressures resulting from a vapor cloud explosion exceeded 30 psi at Buncefield [17].
SECURITY-RELATED INFORMATIONWITHHOLD UNDER 10 CFR 2.390 Rev. 3, June 18 2020 31 Figure 4: Consequences of a Vapor Cloud Explosion Following Escape of Methane after the Guillotine Rupture of a 42 Natural Gas Pipeline and Detonation of a Gas Cloud within the Trees to the Northeast of the Pipeline (Red, Orange and Yellow Contours Show Overpressure at 8 psi, 3.5 psi and 1 psi, respectively, as Predicted by TNO Multi-Energy Model in Breeze Incident Analyst)
SECURITY-RELATED INFORMATIONWITHHOLD UNDER 10 CFR 2.390 Rev. 3, June 18 2020 32 Figure 5 Consequences of a Vapor Cloud Explosion after the Detonation of Methane in the Turbulent Jet Created after the Guillotine Rupture of the 42 Natural Gas Pipeline (Red, Orange and Yellow Contours Show Overpressure at 8 psi, 3.5 psi and 1 psi, respectively, as Predicted by US Army TNT Equivalence Model in Breeze Incident Analyst)
Missile Generation Given that missiles might be thrown as far as 274 m (900 ft) in the event of pipeline rupture, the switchyard, GT2/3 diesel fuel tank, the Unit 3 steam generator mausoleum and meteorological tower must all be considered as being vulnerable to missile damage should the pipeline rupture close to these objects. Therefore, we also examine the frequency of a gas pipeline rupture at points close to these SSCs and subsequent missile generation.
Summary of the Vulnerabilities to Risks Potential hazards arising from the rupture of the new 42 gas pipeline that exceed the magnitude thresholds for exposure to thermal radiation, explosions and missiles are summarized in Table
- 12. This table also lists hazards that do not exceed this threshold and the basis for this conclusion. For those hazards that exceed the magnitude thresholds, exposure rates are developed in Appendix B and are presented in Table 14 below.
SECURITY-RELATED INFORMATIONWITHHOLD UNDER 10 CFR 2.390 Rev. 3, June 18 2020 33 Table 12: Potential Hazards SSC Important to Risk or Safety-Related Event of Concern Following the Hypothetical Rupture of the 42 Pipeline Disposition SSCs inside SOCA Exposure to thermal radiation as a result of a jet fire No concern--distance such that 12.6 kW/m2 threshold not reached SSCs inside SOCA Exposure to an overpressure exceeding 1 psi subsequent to a detonation No concern--distance such that 1 psi threshold not reached SSCs inside SOCA Missile generation No concern--missiles will not reach the SOCA Switchyard Exposure to thermal radiation as a result of a jet fire Distance such that 12.6 kW/m2 threshold reached Switchyard Exposure to an overpressure exceeding 1 psi subsequent to a detonation Distance such that 1 psi threshold reached Switchyard Missile generation Missiles might strike the switchyard GT2/3 diesel fuel storage tank Missile generation Missiles might strike the tank GT2/3 diesel fuel storage tank and switchyard30 Exposure to thermal radiation as a result of a jet fire Distance such that 12.6 kW/m2 threshold reached GT2/3 diesel fuel storage tank and switchyard Exposure to an overpressure exceeding 1 psi subsequent to a detonation Distance such that 1 psi threshold reached Emergency Operations Facility Exposure to thermal radiation as a result of a jet fire Distance such that 12.6 kW/m2 threshold reached Emergency Operations Facility Exposure to an overpressure exceeding 1 psi subsequent to a detonation Distance such that 1 psi threshold reached Emergency Operations Facility Missile generation No concern--missiles will not reach the EOF FLEX building Exposure to thermal radiation as a result of a jet fire No concern--distance such that 12.6 kW/m2 threshold reached. However, there is no exposed instrumentation that might be damaged 30 Because of their proximity, simultaneous damage to both the GT2/3 diesel fuel oil storage tank and the switchyard is possible in the event of a jet fire or detonation. This instance of common-cause damage to equipment is of concern as both the switchyard and diesel fuel storage tank pertain to the provision of power to the reactors.
SECURITY-RELATED INFORMATIONWITHHOLD UNDER 10 CFR 2.390 Rev. 3, June 18 2020 34 Table 12: Potential Hazards FLEX building Exposure to an overpressure exceeding 1 psi subsequent to a detonation No concern--distance such that 1 psi threshold reached.
However, the building is of rugged construction and will not be damaged by the 1.19 psi overpressure experienced FLEX building Missile generation No concern--missiles will not reach the FLEX building Meteorological tower Exposure to thermal radiation as a result of a jet fire Distance such that 12.6 kW/m2 threshold reached Meteorological tower Exposure to an overpressure exceeding 1 psi subsequent to a detonation Distance such that 1 psi threshold reached Meteorological tower Missile generation Missiles might strike the meteorological tower City water tank Exposure to thermal radiation as a result of a jet fire While the distance is such that 12.6 kW/m2 threshold is reached, exposure will be short City water tank Exposure to an overpressure exceeding 1 psi subsequent to a detonation Distance such that 1 psi threshold reached City Water tank Missile generation No concern--missiles will not strike the City Water tank Unit 2 steam generator mausoleum Exposure to thermal radiation as a result of a jet fire Distance not such that high heat flux (> 31.5 kW/m2) is possible.
Unit 2 steam generator mausoleum Exposure to an overpressure exceeding 1 psi subsequent to a detonation No concern: distance such that 1 psi threshold not reached.
Unit 2 steam generator mausoleum Missile generation No concern--missiles will not strike the Unit 2 steam generator mausoleum Unit 3 steam generator mausoleum Exposure to thermal radiation as a result of a jet fire Distance such that high heat flux (> 31.5 kW/m2) possible.
However, the structure is rugged and a Safety Evaluation concluded that even if the structure were to fail, dose limits imposed by NRC guidelines would not be exceeded [32].
SECURITY-RELATED INFORMATIONWITHHOLD UNDER 10 CFR 2.390 Rev. 3, June 18 2020 35 Table 12: Potential Hazards Unit 3 steam generator mausoleum Exposure to an overpressure exceeding 1 psi subsequent to a detonation Distance such that 1 psi threshold reached. However, the structure is rugged and a Safety Evaluation concluded that even if the structure were to fail, dose limits imposed by NRC guidelines would not be exceeded [32].
Unit 3 steam generator mausoleum Missile generation Missiles might strike the Unit 3 steam generator mausoleum. However, the structure is rugged and a Safety Evaluation concluded that even if the structure were to fail, dose limits imposed by NRC guidelines would not be exceeded [32].
SECURITY-RELATED INFORMATIONWITHHOLD UNDER 10 CFR 2.390 Rev. 3, June 18 2020 36 10 CONSERVATISMS IN THE ANALYSIS Conservative assumptions have been made in the modeling and analysis of potential hazards that might follow the hypothetical rupture of a natural gas pipeline. These are summarized in Table
- 13. In light of these conservatisms, we believe the appropriate and conservative threshold frequency of concern for pipeline rupture coupled with fire, explosion or missile generation is ~
10-6/year.
Table 13: Conservative Assumptions Made Conservatism Discussion Detonation of natural gas is possible within the turbulent jet created by a release or in congested areas While such a hypothetical event has been considered and an upper-bound probability as to its occurrence applied, in fact no such detonation has been recorded and experts question its possibility.
The largest possible magnitude of release rates is assumedthe instantaneous guillotine rupture of the 42 pipeline with subsequent full-bore flow from both sides combining into a single stream Guillotine breaks generate the maximum possible flow from the pipeline. Here a two-sided release from the break is also assumed with full bore flow from both sides of the rupture combining into a single jet, the flow rate in this jet being assumed to be double the flow rate calculated for discharge only from the upstream pipeline. The assumption made is conservative in that:
Pressures on the downstream side, and thus flow rates from the downstream side, will be lower than those on the upstream side If the releases from the two sides combine, they will interfere with each other; if they do not combine, the total flammable mass in the resultant jets will be less than that in the single jet assumed.
As a result of the high discharge rate assumed, damage contours are extended and the predicted frequency of events that cause damage to a specific SSC increases as ruptures in a longer length of pipeline will be able to cause damage.
SECURITY-RELATED INFORMATIONWITHHOLD UNDER 10 CFR 2.390 Rev. 3, June 18 2020 37 Table 13: Conservative Assumptions Made Conservatism Discussion The jet of natural gas is assumed not to strike the crater walls or floor Many releases from buried pipelines will impact the walls of the crater created, reducing momentum, turbulence and flame temperature in the gas jet and thus the magnitude of the effects of the jet flame or hypothetical detonation The jet of natural gas is assumed to be inclined at an angle of 60o to the horizontal directed, along with the wind, towards the target Should the jet of natural gas be tilted, higher radiant heat fluxes will be experienced in the direction in which the flame is tilted and thus the distance from the pipeline at which a given heat flux is encountered will be greater.
While the jet is likely to be vertical, given that the jet will rise from a crater, possibly after striking the floor or walls of the crater, a jet emerging at an angle of 60o to the horizontal would seem to be a reasonable, conservative compromise. The predictions made assume the prevailing wind blows in the same direction to which the jet tilts. Here we would note that the prevailing winds at Indian Point are from the north, west or south-southwest and thus not towards the SOCA from the plant.
The size of the jet flame and turbulent jet assumes the peak gas release rate The gas release rate will fall rapidly resulting in lower heat fluxes from jet flames and a smaller mass of gas within the jet.
Axiomatically, a vapor cloud explosion requires delayed ignition at which time gas release rates will be lower.
The gas pipeline pressure prior to release is assumed to be the 850 psig MAOP (Maximum Allowable Operating Pressure).
The normal operating pressure will be 750 psig, which is less than the MAOP. Higher gas pressures translate into higher release rates and damage potential.
Missiles are assumed to fly horizontally for a distance of 274 m (900 ft)
As noted in the discussion in Section 6, the 274 m (900 ft) distance assumed for missile throw exceeds the distances noted in the historical record and thus is an upper bound; furthermore. missiles might also fly over closer objects
SECURITY-RELATED INFORMATIONWITHHOLD UNDER 10 CFR 2.390 Rev. 3, June 18 2020 38 Table 13: Conservative Assumptions Made Conservatism Discussion Damage is deemed possible if the closest point of an SSC of concern is impacted by overpressures or heat fluxes in excess of a threshold.
The switchyard covers a large area and only specific equipment will be of concern.
The assumptions that (1) the time required to close isolation valves is 8 minutes whereas the operator thinks isolation is possible in 6 minutes and (2) that the inner pipeline valvesthe two valves closest to a rupture that might affect Indian Pointfail to close.
Conservative assumptions are made with respect to the time taken to close the isolation valves and the length of pipeline that will blow down after isolation. In practice, these assumptions have no effect on the predictions as to damage resulting from rupture of the natural gas pipeline as, with one exception, the predictions are made assuming the release rate that prevails immediately after rupture, a release rate that is both greater than later release rates and not affected by isolation.
The exception pertains to the hypothetical detonation of a vapor cloud created when the pipeline has been blown down, the pipeline pressure is low and choked flow and a high velocity jet prevails no longer. Only the timing of this hypothetical event will be affected by the time required to isolate the rupture and the length of pipeline blown down; the magnitude and consequences of the event will not.
SECURITY-RELATED INFORMATIONWITHHOLD UNDER 10 CFR 2.390 Rev. 3, June 18 2020 39 11CAUSES AND LIKELIHOOD OF RELEASES OF NATURAL GAS AND SUBSEQUENT FIRE AND EXPLOSION OR MISSILE GENERATION Likelihood and Consequences Fire and Explosion The causes and likelihood of the rupture of the 42 natural gas pipeline and subsequent fires, detonations and missile generation are addressed in detail in Appendix B. The conclusions of this analysis, as predicted using conservative models, are presented in Table 14 which itself is drawn from Tables B-2 and B-3 in Appendix B. In Table 14, missile damage following rupture does not preclude subsequent fire or explosion damage. Similarly, explosion damage does not preclude thermal radiation damage. Accordingly, the frequency assigned to a given SSC can be added. That said, it will be recalled that the frequency presented for explosion damage is an estimated upper bound frequency for a hypothetical event.
Table 14: Vulnerability to Risk SSC Important to Risk or Safety-Related Event of Concern Following the Hypothetical Rupture of the 42 Pipeline Is the Pipeline Involved Enhanced or Not?
Exposure Rate
(/year)
Switchyard Exposure to thermal radiation as a result of a jet fire Both enhanced and unenhanced 1.16 x 10-6 Switchyard Exposure to an overpressure exceeding 1 psi subsequent to a detonation Both enhanced and unenhanced 2.44 x 10-8 Switchyard Missile generation Enhanced 1.23 x 10-7 GT2/3 diesel fuel storage tank Missile generation Enhanced
- 1. 41 x 10-8 Switchyard and GT2/3 diesel fuel storage tank31 Exposure to thermal radiation as a result of a jet fire Enhanced 6.65 x 10-7 31 Because of their proximity, simultaneous damage to both the GT2/3 diesel fuel oil storage tank and the switchyard is possible in the event of a jet flame or detonation.
SECURITY-RELATED INFORMATIONWITHHOLD UNDER 10 CFR 2.390 Rev. 3, June 18 2020 40 Table 14: Vulnerability to Risk SSC Important to Risk or Safety-Related Event of Concern Following the Hypothetical Rupture of the 42 Pipeline Is the Pipeline Involved Enhanced or Not?
Exposure Rate
(/year)
Switchyard and GT2/3 diesel fuel storage tank Exposure to an overpressure exceeding 1 psi subsequent to a detonation Enhanced 2.66 x 10-8 City water tank Exposure to thermal radiation as a result of a jet fire Enhanced 3.27 x 10-7 Emergency Operations Facility Exposure to thermal radiation as a result of a jet fire Enhanced 5.60 x 10-7 Emergency Operations Facility Exposure to an overpressure exceeding 1 psi subsequent to a detonation Enhanced 2.01 x 10-8 FLEX building Jet fire Both enhanced and unenhanced 1.13 x 10-6 FLEX building Vapor cloud explosion (detonation)
Both enhanced and unenhanced 2.65 x 10-8 Meteorological tower Exposure to thermal radiation as a result of a jet fire Both enhanced and unenhanced 2.39 x 10-6 Meteorological tower Exposure to an overpressure exceeding 1 psi subsequent to a detonation Both enhanced and unenhanced 9.28 x 10-8 Meteorological tower Missile generation Both enhanced and unenhanced 1.97 x 10-9 Unit 2 steam generator mausoleum Exposure to thermal radiation as a result of a jet fire Enhanced 2.15 x 10-7 Unit 3 steam generator mausoleum Exposure to thermal radiation as a result of a jet fire Enhanced 2.92 x 10-6
SECURITY-RELATED INFORMATIONWITHHOLD UNDER 10 CFR 2.390 Rev. 3, June 18 2020 41 Table 14: Vulnerability to Risk SSC Important to Risk or Safety-Related Event of Concern Following the Hypothetical Rupture of the 42 Pipeline Is the Pipeline Involved Enhanced or Not?
Exposure Rate
(/year)
Unit 3 steam generator mausoleum Exposure to an overpressure exceeding 1 psi subsequent to a detonation Both enhanced and unenhanced 1.26 x 10-7 Unit 3 steam generator mausoleum Missile generation Both enhanced and unenhanced 3.55 x 10-8 The results show that, with four exceptions, the frequencies of all events that might damage important to safety or safety-related Systems, Structures and Components outside the SOCA lie below the 10-6/year threshold for concern. The exceptions are possible damage to the switchyard and instrumentation on the meteorological tower as a result of pipeline rupture and creation of a jet flame, and to the FLEX building and Unit 3 steam generator mausoleum. As noted earlier, however, these remain very low probability events. Furthermore, the potential consequences of damage to the switchyard will be limited as exposure to levels of thermal radiation above the threshold will be of short duration and the predicted frequency of such damage lies well below the frequency of other causes of a loss-of-offsite power. Damage to the meteorological tower can be mitigated as the data it provides can be obtained from other sources, including a backup meteorological tower and weather forecasting services such as those provided by the NOAA.
Damage to the FLEX building is hypothetical as there is no exposed instrumentation. Similarly, damage to the Unit 3 steam generator mausoleums is both unlikely (the structure is rugged) and will not have serious consequences (a Safety Evaluation concluded that even if the structure were to fail, dose limits imposed by NRC guidelines would not be exceeded).
In Appendix B, terrorism or wanton damage to the pipeline and the possibility of seismic damage are also discussed. It is concluded that such damage is unlikely or not credible.
SECURITY-RELATED INFORMATIONWITHHOLD UNDER 10 CFR 2.390 Rev. 3, June 18 2020 42 12 DISCUSSION The rupture of the 42 natural gas pipeline in or close to the IPEC site and subsequent ignition of the methane released might result in a jet or cloud fire and injury or death to any one exposed to flames or intense thermal radiation. Such a fire will not, however, damage a system, structure or component important to safety within the SOCA. Similarly, in the hypothetical event of a vapor cloud explosion initiated by or involving a detonation, no structural damage to buildings in the SOCA is anticipated as the pipeline lies beyond the minimum safe distance established for such a pipeline. A similar conclusion can be drawn about missile generation.
Damage to systems, structures and components important to safety away from the SOCAthe switchyard, GT2/3 fuel tank, city water tank, Emergency Operations Facility (EOF), FLEX building, the Unit 2 and Unit 3 steam generator mausoleums and the meteorological toweris hypothetically possible under very low probability scenarios. We therefore conclude that the pipeline will not introduce material additional risk to the safe maintenance and operation of safety-related and important to safety SSCs at IPEC.
SECURITY-RELATED INFORMATIONWITHHOLD UNDER 10 CFR 2.390 Rev. 3, June 18 2020 43 13REFERENCES 1.
Indian Point Unit 3 Nuclear Power Plant, Individual Plant Examination of External Events (IPEEE), September 26, 1997.
2.
Consequences of Fire and Explosion Following the Release of Natural Gas from Pipelines Adjacent to Indian Point, Study performed for Entergy, Indian Point Energy Center, August 14, 2008.
3.
US Nuclear Regulatory Commission, Regulatory Guide RG 1.91, Evaluations of Explosions Postulated to Occur at nearby Facilities and on Transportation Routes Near Nuclear power Plants Revision 2, April 2013.
- 4. Congram, G. E., Continuous Inspection Needed to Tame Pipeline Corrosion, Pipeline and Gas Journal, December 1994, pp 30-34.
- 5. Sax, N. Irving and Lewis, Richard J., Sr., Hazardous Materials Desk Reference, Van Nostrand Reinhold, New York, 1987.
6.
Center for Chemical Process Safety, Guidelines for Vapor Cloud Explosion, Pressure Burst, BLEVE and Flash Fire Hazards, 2nd edition, New York, 2010.
7.
US Nuclear Regulatory Commission, Fire Dynamics Tools, NUREG-18-5, December 2004.
- 8. Lees, Frank P., Loss Prevention in the Process Industries, Butterworth-Heinemann, Boston, 1996.
9.
Oil and gas fires, UK Health and Safety Executive, OTI 92 596, 1992.
- 10. State of California, 2007 Guidance for Protocol for School Site Risk Analysis.
- 11. Dennis P. Nolan, Handbook of Fire and Explosion Protection Engineering Principles for Oil, Gas, Chemical and Related Facilities, Elsevier, 2010.
- 12. J. K. Thomas, M. L. Goodrich and R. J. Duran, Propagation of a Vapor Cloud Explosion from a Congested Area into an Uncongested Area, Process Safety Progress, Vol. 32, No. 2, pp 199-206, 2013.
- 13. R. J. Harris and Wickens (1989) as quoted in [6] and [8].
- 14. Yoshitomo Inaba, Tetsuo Nishihara, Mark A. Groethe and Yoshikazu Nitta, Study on explosion characteristics of natural gas and methane in semi-open spaces for the HTTR hydrogen production system, Nuclear Engineering and Design, Volume 232, Issue 1, July 2004, Pages 111-119.
SECURITY-RELATED INFORMATIONWITHHOLD UNDER 10 CFR 2.390 Rev. 3, June 18 2020 44
- 15. W. W. Lewis, J. P. Lewis and P. M. Outrim, LNG Facilities, the Real Risks, Gas Tech 2002.
- 16. FM Global, Property Loss Prevention Data Sheets 7-42, October 2013.
- 17. Scott G. Davis, et al., 2005 Buncefield Vapor Cloud Explosion: Unraveling the Mystery of the Blast, GexCon Paper.
- 18. Will Gray, Impossible explosion: the Buncefield blast explained, New Scientist, April 5, 2012.
- 19. Buncefield Major Incident Investigation Board, Explosion Mechanism Advisory Group Report, UK Government, August 2007.
- 20. Indian Point Unit 3 Nuclear Power Plant, Final Safety Analysis Report.
- 21. US Nuclear Regulatory Commission, Nuclear Fuel Cycle Facility Accident Analysis Handbook, NUREG/CR-6410, March 1998.
- 22. US Environmental Protection Agency, Risk Management Program Guidance, EPA 550-B 009, March 2009.
- 23. Steven R. Hanna, Olav R. Hansen, Mathieu Ichard, David Strimaitis, CFD model simulation of dispersion from chlorine railcar releases in industrial and urban areas, Atmospheric Environment, Volume 43, Issue 2, January 2009, 262-270.
- 24. Hanna, S. R., J. C. Chang, and D. G. Strimaitis, 1993: Hazardous response modeling uncertainty. ESL-TR-91-28, US Air Force Engineering and Service Laboratory.
- 25. Neil Schultz, Fire and Flammability Handbook, Van Nostrand Reinhold, New York, 1985.
- 26. John L. Woodward, Estimating the Flammable Mass of a Vapor Cloud, Center for Chemical Process Safety, New York 1998.
- 27. US Federal Emergency Management Agency, Reference Manual to Mitigate Potential Terrorist Attacks Against Buildings, FEMA-426, December 2003.
- 28. Report of the U.S. Nuclear Regulatory Commission Expert Evaluation Team on Concerns Pertaining to Gas Transmission Lines Near the Indian Point Nuclear Power Plant, April 8, 2020.
- 29. Yajun Deng, et al., Numerical Simulation on the Dispersion of Natural Gas Releases from a Buried Pipeline, Heat Transfer Engineering, May 2017.
- 30. Nicola Novembre, Fabrizio Podenzani and Emanuela Colombo, Numerical Study for Accidental Gas Releases from High Pressure Pipelines, European Conference on Computational Fluid Dynamics, ECCOMAS CFD 2006.
SECURITY-RELATED INFORMATIONWITHHOLD UNDER 10 CFR 2.390 Rev. 3, June 18 2020 45
- 31. Omid Adibi, Numerical Simulation of Natural Gas Dispersion from Low Pressure Pipelines, International Journal of Mechanical and Mechatronics Engineering, Vol:12, No:2, 2018.
- 32. Bechtel Associates Professional Corporation, Replaced Steam Generator Storage Facility, Design Package 2, 5-22-87 NSE.
SECURITY-RELATED INFORMATIONWITHHOLD UNDER 10 CFR 2.390 Rev. 3, June 18 2020 A-1 APPENDIX A Volumes of Flammable Clouds and Masses of Methane involved in Hypothetical Vapor Cloud Explosions (Detonations)
Volumes of Flammable Clouds and Masses of Methane involved in Hypothetical Vapor Cloud Explosions (Detonations)
Release diameter (in.)
Volume flammable cloud in congested area (m3)
Mass methane in flammable range in turbulent jet (kg)
Center point of explosion32 (m east, m north)
Detonation in turbulent jet resulting from pipeline rupture 42 (assuming double-sided full-bore release following the guillotine rupture of the pipeline)
Not applicable to turbulent jet 19,925 0,0 6
(through a hole in the pipeline)
Not applicable to turbulent jet 20 0,0 Detonation in trees to the northeast of the pipeline 42 (assuming double-sided full-bore release following the guillotine rupture of the pipeline) 42,250 Not applicable to flammable vapor cloud 70,52 6
(through a hole in the pipeline) 2,000 Not applicable to flammable vapor cloud 44,44 32 Relative to the closest point on a pipeline to the IP3 control building.
SECURITY-RELATED INFORMATIONWITHHOLD UNDER 10 CFR 2.390 Rev. 3, June 18 2020 B-1 APPENDIX B Analysis of the Causes of and Determination of Exposure Rates for a Failure of the AIM 42 Natural Gas Pipeline near IPEC B1. Introduction Nuclear Regulatory Commission (NRC) regulations require that safety-related and important to safety nuclear power plant structures, systems, and components (SSCs) be appropriately protected against dynamic effects resulting from equipment failures and from events and conditions that may occur outside the nuclear power plant. These latter events include the effects of explosion of materials that may be at nearby facilities or carried on nearby transportation routes, including natural gas pipelines. NRC regulations also require that the nature and proximity of hazards related to human activity (e.g., natural gas pipelines) be evaluated to determine if a plant design can accommodate hazards postulated to occur, and if the risk of other hazards is very low.
Based on proximity to IPEC, the Algonquin Incremental Market (AIM) Project 42 pipeline installed along a southern route located, at its closest point, approximately 1580 ft (482 m) south of the IPEC security owner controlled area (SOCA), poses a potential hazard that must be evaluated as to the consequences and likelihood of (or exposure rates for) postulated failures of the pipeline. As part of that evaluation, Entergy has conducted a hazard analysis contained in the main body of this report. The analysis contained in that report indicates that a postulated failure would not adversely impact any SSCs within the SOCA due to the distance from the pipeline to the SOCA. Similarly, the diesel fuel oil tanker that is used to transport fuel oil from the GT2/3 diesel fuel oil storage tank to the plant has been relocated so as not to be adversely affected by hypothetical fire, explosion or missile damage from the pipeline. However, certain SSCs important to safety located outside of the SOCA could be damaged should a failure occur on the 42 AIM pipeline closest to such equipment.
Here we conservatively assume in general that damage to these SSCs might occur were they to be exposed to 1-psi overpressure following an explosion, to a thermal radiation heat flux occasioned by pipeline rupture and the ignition of the natural gas released that exceeds 12.6-kW/m2, or to the possibility they might be struck by missiles when the pipeline ruptures. The 1-psi overpressure is a threshold of concern established by the Nuclear Regulatory Commission in Regulatory Guide 1.91 [3]; the 12.6-kW/m2 heat flux is that required to melt plastic.
In accordance with applicable NRC guidance (Regulatory Guide 1.91), if SSCs important to safety may be damaged due to a postulated failure due to proximity to the hazard, the licensee may show that the risk is acceptably low on the basis that thresholds for damage (e.g., the 1 psi
SECURITY-RELATED INFORMATIONWITHHOLD UNDER 10 CFR 2.390 Rev. 3, June 18 2020 B-2 overpressure) are not exceeded or that exposure rates are low; a demonstration that the exposure rate for damage is less than 1x10-6 per year when based on conservative assumptions, or 1x10-7 per year when based on realistic assumptions, is acceptable.
As demonstrated below, based on design and installation enhancements to the 42 pipeline to be installed near IPEC, the potential for damage or exposure rates for pipeline failure and damage to SSCs near the pipeline are, with two exceptions, below NRCs threshold criteria and, therefore, are not considered credible events. The two exceptions involve the potential failure in a section of pipeline near the meteorological tower and Unit 3 steam generator mausoleum that does not include the enhanced design measures. However, that pipeline also has a very low probability of failure and, even if a failure and damage to the meteorological tower is assumed, there are established alternative means to provide meteorological data to the plant in the event of an emergency. Similarly, thermal damage to the exterior of the Unit 3 steam generator mausoleum will not have other consequences because this structure is of rugged concrete construction.
Furthermore, a safety evaluation performed for the steam generator storage facility project shows that even if the structure were to fail, the dose limits imposed by NRC guidelines would not be exceeded [32].
B2. Purpose and Objective of This Appendix The purpose of this appendix is to determine exposure rates for failure of the AIM project 42 pipeline, now installed along the southern route outside of the main IPEC facility, and subsequent events accounting for the substantial pipeline and installation design enhancements discussed below.
SECURITY-RELATED INFORMATIONWITHHOLD UNDER 10 CFR 2.390 Rev. 3, June 18 2020 B-3 B3. Statistical Analysis of the Exposure Rates for a Fire and Explosion The average rupture frequency of all pipelines installed in or after 198033 with a diameter of 36 or more34 is ~ 1.00 x 10-5 /mile.yr.35 This frequency is derived using US data for all natural gas 33 Looking at the set of natural gas transmission pipeline rupture events that occurred in the period 1/1/2002 to 3/26/2020, the dominant causes of pipeline rupture in all pipelines are found to be external corrosion, construction/installation/fabrication problems and excavation damage. In pipelines installed in or after 1980, however, we see that corrosion disappears as a cause of pipeline rupture.
Causes of Rupture of Natural Gas Transmission Pipeline Rupture Events involving Pipeline of 36 or more in Diameter that Occurred in the Period 1/1/2002 to 3/26/2020 (PHMSA Data)
Cause of Pipeline Rupture Number of Events: all Events Number of Events in Pipeline Installed In or After 1980 External corrosion 6
0 Design/fabrication construction/installation 3
2 Excavation (3rd party) 1 0
Earth movement (landslides, subsidence, heavy rains, etc).
2 1
Miscellaneous/unknown 2
0 Total events 14 3
34 As too few data are available for 42 pipeline alone, data for all pipelines of 36 or more in diameter were considered for this analysis (42-inch pipeline comprised 25 % of all pipeline of 36 or more in diameter in place in 2019 and were associated with 1 rupture event in the period 2010-2020). In selecting data to be used in this analysis, a balance must be achieved between the availability and applicability of data. Noting that rupture rates fall with increasing pipeline diameter, we seek to obtain a reasonable amount of incident (rupture) and exposure data for pipelines with a diameter as close to the 42 diameter of the proposed pipeline. Hence in general, data for pipelines of 36 or more in diameter are used rather than, for example, the larger sets of data with a diameter of 24 or more.
Similarly, while more ruptures would be included were a longer period of time to be selected, the improvements in pipeline reliability seen in recent decades would be masked were data from earlier decades to be used.
35 This frequency is calculated from:
1)
Rupture data for gas transmission pipelines of 36 or more in diameter installed in or after 1980. These data are for the 19.25-year period 1/1/2002 to 3/26/2020 and are provided by the US Department of Transportation Pipeline and Hazardous Material Safety Administration (PHMSA). 3 ruptures were recorded.
2)
A pipeline exposure calculated as the sum of the products for each year of:
The total length of pipeline of 36 or more in diameter installed in or after 1980 present at the end of the previous year plus half the length of new pipeline added that year.
The fraction of the year for which incident data are available (1 for the years 2002 to 2019, 0.25 for 2020).
The calculation of pipeline length makes the conservative assumption that once installed, larger diameter pipeline is not replaced. Detailed length data are provided by the PHMSA for the period 2010 on. Data for the period 2002, 2009, inclusive, present these data in less detail with all pipeline of 28 or more in diameter being bundled together.
To obtain the length of pipeline of 36 or more in diameter in these years, we multiply the recorded length of pipeline of 28 or more in diameter by the predicted ratio of the length of pipeline of 36 or more in diameter to the
SECURITY-RELATED INFORMATIONWITHHOLD UNDER 10 CFR 2.390 Rev. 3, June 18 2020 B-4 transmission pipelines with a diameter of 36 or more regardless of the wall thickness, coating thickness, cover depth and other enhancement. Improvements in the design and manufacture of pipe and corrosion protection and increased wall thickness and cover depth have all served to reduce the likelihood of pipeline ruptures [33, 34]36. As discussed below, because segments of the AIM pipeline near IPEC will be a design-enhanced, state-of-the-art installation, and reflect improvements in manufacture achieved in recent decades, a lower rupture frequency will apply to these segments of the AIM pipeline.
When assessing the US Department of Transportation Pipeline and Hazardous Material Safety Administration (PHMSA) data, we note that in the period 1/1/2002 to 3/26/2020 only 3 of the 14 onshore transmission gas pipeline ruptures in pipelines with a diameter of 36 or more occurred in a pipeline installed after 1980.
Spectra and Entergy have agreed to a number of pipeline enhancements to a ~ 3935 ft (1199 m) segment of pipeline near IPEC in order to further reduce the already low predicted frequency of failure and address the above listed primary causes of pipeline rupture. The location of this enhanced pipeline is shown in Figure 1 of the main report. These additional safety features have been installed and implemented to mitigate internal and external corrosion, excavation threats, abnormal operations, damage from natural forces (i.e., seismic) and other potential threats. In summary, these enhancements include:
The pipeline will have a greater wall thickness increasing it from 0.510 to 0.720 (a 41% increase)
The pipeline is X-70 steel (70,000 psi yield strength). The increased wall thickness and the higher yield steel material will together result in a 41% operating pressure margin above the planned 850 psig MAOP.
The X-raying of 100 % of all welds and approval of the radiographs by trained X-ray technicians The pipeline is buried to a greater depth from the normal 3 feet to a minimum of 4 feet from the top of the pipeline to natural grade (a 33% increase).
The fusion bonded epoxy (FBE) pipeline corrosion coating is increased.
length of pipeline of 28 or more in diameter, this ratio being obtained by regression analysis of 2010 to 2019 data.
The length of pipeline of 36 or more in diameter installed prior to 1980 (16,301 miles, this length being obtained from detailed 1979 data), is then deducted from this length to obtain the length of pipeline of 36 or more in diameter installed after 1980. It should be noted that the total length of pipeline of 36 or more in diameter added in the period 2002 to 2009, inclusive, calculated above (8453 miles) is in close accord with the total length of such line that the US Energy Information Administration records as having been installed (9279 miles [35]). This latter length includes some pipeline of smaller diameter.
The average rupture frequency is then calculated by dividing the number of ruptures (3) by the exposurethe product of the length of the transmission system pipelines of 36 or more in diameter (298,666 mile.years)
This frequency of incidents is in accord with European experience [33] and earlier estimates [40].
36 The lower rupture frequency exhibited by newer pipelines would not appear to be driven by the effects of aging in older pipelines: age can contribute to a pipelines risk, but.. effective integrity management can counterbalance the impact of aging and construction materials: [34].
SECURITY-RELATED INFORMATIONWITHHOLD UNDER 10 CFR 2.390 Rev. 3, June 18 2020 B-5 An Abrasive Resistant Overlay (ARO) is added over the FBE coating.
Fiber reinforced concrete mats with warning tape layers placed over the pipeline.
Details of Spectras normal design, installation and operating practices and these additional design and installation features are presented in Exhibits A and B; a cross-sectional schematic of the enhanced pipeline with reinforced concrete mats and warning tape is shown in Exhibit C.
While US pipeline incident data do not allow the development of direct correlations to calculate the precise probability impact of these additional features on pipe rupture frequencies37, there is strong evidence that the effect will be appreciable. European data [33] suggest that rupture and overall failure frequencies decline markedly when pipe wall thickness and cover depth increase (Figures B-1, B-2 and B-3). This conclusion is supported by US PMHSA data that show of the 14 rupture events involving natural gas transmission pipelines of 36 or more in diameter encountered in the period 1/1/2002 to 3/26/2020, two involved pipelines with a wall thickness of 0.5 or more, one was caused by a construction defect, the other by a valve failure. Similarly, with respect to corrosion it has been concluded that for pipelines with wall thicknesses greater than (0.59 in.) and with corrosion control procedures in place, the corrosion control frequency can be assumed to be negligible [36]. UK studies have also demonstrated that by installing a concrete slab and visible warning tape, the frequency of pipeline ruptures occasioned by external interference will be reduced by 95 % [37]. Finally, X-raying of all welds and verification of the radiographs by trained technicians and the greater wall thickness in the enhanced pipeline will diminish the likelihood that defects in fabrication or construction might result in a subsequent pipeline rupture. A 75 % reduction in the predicted frequency of pipeline rupture as a result of defects in fabrication or construction in the enhanced segments of the pipeline is assumed here to reflect these improvements.
37 As an example, there are no data available that relate the length and diameter of pipelines to specific diameters, wall thicknesses and cover depths.
SECURITY-RELATED INFORMATIONWITHHOLD UNDER 10 CFR 2.390 Rev. 3, June 18 2020 B-6 Figure B-1 Frequency of Pipeline Rupture Occasioned by External Interference as a Function of Cover Depth [33]
Figure B-2 Frequency of Pipeline Rupture Occasioned by External Interference as a Function of Wall Thickness [33]
SECURITY-RELATED INFORMATIONWITHHOLD UNDER 10 CFR 2.390 Rev. 3, June 18 2020 B-7 Figure B-3 Frequency of Corrosion-Induced Pipeline Failure as a Function of Wall Thickness [33]
If we assume that half the ruptures that might occur with new but not enhanced pipeline related to 3rd party excavation and half to fabrication and construction problems, and reduce rupture rates to account for the enhancements, we arrive at an overall rupture rate that is 15 % of that calculated for 42 pipeline that is not enhanced (Table B-1). A frequency of ~ 1.5 x 10-6 /mile.yr will therefore be assumed for pipeline that incorporates these additional safety features.
SECURITY-RELATED INFORMATIONWITHHOLD UNDER 10 CFR 2.390 Rev. 3, June 18 2020 B-8 Table B-1 Relative Pipeline Rupture Frequency After Enhancements Failure Cause Fraction of Rupture Events Attributed to Cause Multiplier to Apply Effect of Enhancement Basis for Effect Contribution After Enhancement 3rd party excavation 0.5 0.05 Reduction for concrete mats and warning tape 0.025 Fabrication/construction problems 0.5 0.25 Engineering judgment as to benefit of 100
% of all welds being X-rayed and thicker walls 0.125 Total 1
0.15 The PMHSA data also allow us to predict the probability of ignition and detonation of the gas released after pipeline rupture: the probability of ignition is calculated to be 0.7138; the upper bound probability that the release will detonate is calculated as 0.03539. Note that while descriptions of pipeline rupture and fire events often make mention of explosions, these appear 38 The latter is calculated from PHMSA data for gas transmission pipelines of 36 or more in diameter for the period 1/1/2002 to 3/26/2020. Fourteen ruptures were recorded in the period. Of these, ignition (or explosion) occurred 10 times (i.e., in 71 % of the incidents). This ignition probability is in accord with European experience where a 0.423 probability of ignition after the rupture of a line exceeding 16 inches in diameter is recorded [29] this probability increasing with pipeline diameterin both recorded ruptures of pipeline exceeding 29 inches in diameter, ignition occurred.
39 The probability of a vapor cloud detonation following a major release from a pipeline is calculated based on the absence of detonation in the 84 ruptures of pipelines of 24 or more in diameter recorded by PHMSA between 1/1/2002 and 3/26/2020 (in no instance do the PHMSA or NTSB (National Transportation Safety Board) reports on these incidents refer to a detonationexplosion in PHMSA documents appears to refer to the explosive rupture of the pipeline or possibly to a vapor cloud explosion entailing deflagration). Assuming a binomial distribution, there is a 5 % probability of no detonations occurring in 84 ruptures if the detonation probability is 0.035. If the detonation probability were higher, the probability of no detonations occurring is approximately 5 % or less. The resulting detonation frequency is higher than the 1 x 10-7 mile-1.year-1 frequency cited as an upper bound probability of an explosion in the State of California guidance protocol for school site risk analysis [10]. Here the data used comprise ruptures in pipelines of 24 in diameter or more. As the rupture of a 24 pipeline might still result in a turbulent jet containing over 1000 kg of methane in the flammable range, the absence of detonation in such ruptures is judged applicable in determining the probability of detonation after the rupture of large pipelines.
SECURITY-RELATED INFORMATIONWITHHOLD UNDER 10 CFR 2.390 Rev. 3, June 18 2020 B-9 to refer to the bursting of the pipeline itself or to a subsequent deflagration of a vapor cloud rather than to a detonation. For example, the pipeline incident described by PHMSA corrective action order 3-2011-1018-H is noted in the PHMSA incident database as having involved an explosion. The corrective action order itself, however, describes the event as involving rupture and a fireball.
Applying these probabilities to the pipeline rupture events of concern we calculate a frequency of pipeline rupture and ignition of 1.065 x 10-6 /mile.yr40 and a frequency of pipeline rupture followed hypothetically by a detonation of 5.25 x 10-8 /mile.yr41.
Let us now apply these frequencies to the pipeline rupture events of concern. In calculating exposure rates, the lengths of pipeline that lie within specific distances of the SSCs of concern are determined. It is assumed that if pipelines were to rupture along these lengths and fire, overpressure or missile damage were to ensue, damage to the SSC is possible. The lengths were determined using Google Earth. Details of the exposure rate calculations are presented in Table B-2.
40 Multiplying the 1.50 x 10-6/mile.yr rupture frequency with a 0.71 probability of ignition 41 Multiplying the 1.50 x 10-6/mile.yr rupture frequency with a 0.035 probability of detonation
SECURITY-RELATED INFORMATIONWITHHOLD UNDER 10 CFR 2.390 Rev. 3, June 18 2020 B-10 Table B-2 Exposure Rate Calculation for Jet Fires and Explosions42 Lengths of Pipeline where Rupture Might Lead to Damage Pipeline Rupture Frequency
(/mile.yr)
SSC of Concern Damage Source Enhanced Pipeline Unenhanced Pipeline Enhanced Pipeline Unenhanced Pipeline Probability of Ignition or Detonation Exposure Rate
(/year)
Switchyard Jet fire 195 m/
640 ft/
0.12 miles 233 m/
764 ft/
0.14 miles 1.50 x 10-6 1.00 x 10-5 0.71 1.16 x 10-6 Switchyard Vapor cloud explosion (detonation) 349 m/
1145 ft/
0.22 miles 60 m/
197 ft/
0.03 miles 1.50 x 10-6 1.00 x 10-5 0.035 2.44 x 10-8 Switchyard and GT2/3 storage tank 43 Jet fire 1005 m/
3297 ft/
0.62 miles 0
1.50 x 10-6 1.00 x 10-5 0.71 6.65 x 10-7 42 Where damage ensues only after the rupture of enhanced pipeline or only after the rupture of unenhanced pipeline, the exposure rate for a given type of damage is calculated as the product of:
The length of pipeline where rupture might cause that damage The rupture frequency for the pipeline The probability of the damage event (a jet flame or hypothetical detonation) given rupture).
Where the rupture of both enhanced and unenhanced pipeline might cause damage, these calculations are performed separately for both enhanced and unenhanced pipeline and the resulting exposure rates summed.
43 Because of the proximity of the switchyard and GT2/3 storage tank, the same pipeline rupture event might cause high heat fluxes or overpressures exceeding 1 psi in both the switchyard and GT2/3 storage tank.
SECURITY-RELATED INFORMATIONWITHHOLD UNDER 10 CFR 2.390 Rev. 3, June 18 2020 B-11 Table B-2 Exposure Rate Calculation for Jet Fires and Explosions42 Lengths of Pipeline where Rupture Might Lead to Damage Pipeline Rupture Frequency
(/mile.yr)
SSC of Concern Damage Source Enhanced Pipeline Unenhanced Pipeline Enhanced Pipeline Unenhanced Pipeline Probability of Ignition or Detonation Exposure Rate
(/year)
Switchyard and GT2/3 storage tank Vapor cloud explosion (detonation) 814 m/
2671 ft/
0.51 miles 0
1.50 x 10-6 1.00 x 10-5 0.035 2.66 x 10-8 City water tank Jet fire 494 m/
1621 ft/
0.31 miles 0
1.50 x 10-6 1.00 x 10-5 0.71 3.27 x 10-7 EOF Jet fire 846 m/
2776 ft/
0.53 miles 0
1.50 x 10-6 1.00 x 10-5 0.71 5.60 x 10-7 EOF Vapor cloud explosion (detonation) 617 m/
2024 ft/
0.38 miles 0
1.50 x 10-6 1.00 x 10-5 0.035 2.01 x 10-8 FLEX building Jet fire 275 m/
902 ft/
0.17 miles 215 m/
705 ft/
0.13 miles 1.50 x 10-6 1.00 x 10-5 0.71 1.13 x 10-6 FLEX building Vapor cloud explosion (detonation) 187 m/
614 ft/
0.12 miles 94 m/
308 ft/
0.06 miles 1.50 x 10-6 1.00 x 10-5 0.035 2.65 x 10-8 Met tower Jet fire 350 m/
1148 ft/
0.22 miles 490 m/
1608 ft/
0.30 miles 1.50 x 10-6 1.00 x 10-5 0.71 2.39 x 10-6
SECURITY-RELATED INFORMATIONWITHHOLD UNDER 10 CFR 2.390 Rev. 3, June 18 2020 B-12 Table B-2 Exposure Rate Calculation for Jet Fires and Explosions42 Lengths of Pipeline where Rupture Might Lead to Damage Pipeline Rupture Frequency
(/mile.yr)
SSC of Concern Damage Source Enhanced Pipeline Unenhanced Pipeline Enhanced Pipeline Unenhanced Pipeline Probability of Ignition or Detonation Exposure Rate
(/year)
Met tower Vapor cloud explosion (detonation) 250 m/
820 ft/
0.16 miles 414 m/
1358 ft/
0.26 miles 1.50 x 10-6 1.00 x 10-5 0.035 9.82 x 10-8 U2 steam gen mausoleum Jet fire (intense thermal radiation) 325 m/
1066 ft/
0.20 miles 0
1.50 x 10-6 1.00 x 10-5 0.71 2.15 x 10-7 U3 steam gen mausoleum Jet fire (intense thermal radiation) 240 m/
787 ft/
0.15 miles 625 m/
2051 ft/
0.31 miles 1.50 x 10-6 1.00 x 10-5 0.5 2.92 x 10-6 U3 steam gen mausoleum Vapor cloud explosion (detonation) 167 m/
548 ft/
0.10 miles 552 m/
1811 ft/
0.34 miles 1.50 x 10-6 1.00 x 10-5 0.035 1.26 x 10-7
SECURITY-RELATED INFORMATIONWITHHOLD UNDER 10 CFR 2.390 Rev. 3, June 18 2020 B-13 These predictions pertaining to the exposure rates for fire and explosion following a pipeline rupture are highly conservative in that the assumptions made in calculating the distances at which overpressures and high heat fluxes can reach are conservative (see Table 13 in the main report). Consequently, the pipeline lengths used here to calculate exposure rates will also be conservative. Accordingly, we can conclude that the pipeline satisfies NRC criteria pertaining to explosion (detonation) risk as, with few exceptions, the predicted frequency of any postulated event is below the 10-6/year criterion established in Regulatory Guide 1.91 for circumstances in which conservative assumptions are made. The exceptions are the switchyard, FLEX building, met tower and Unit 3 steam generator mausoleum, which could suffer damage if a failure of the pipeline is postulated to occur. That said, the potential consequences of damage to the switchyard will be limited as exposure to levels of thermal radiation above the threshold will be of short duration and the predicted frequency of such damage lies well below the frequency of other causes of a loss-of-offsite power. Similarly, damage to the meteorological tower poses no additional risk to IPEC as there are established alternative means to obtain meteorological data in the event of an emergency and thermal damage to the exterior of the Unit 3 steam generator mausoleum will not have other consequences because this structure is of rugged concrete construction. Finally, damage to the FLEX building is hypothetical as there is no exposed instrumentation.
B4. Likelihood and Consequences of Pipeline Rupture and Missile Generation Given their proximity to the pipeline the switchyard, GT2/3 diesel fuel storage tank, Unit 3 steam generator mausoleum and meteorological tower must all be considered as being potentially vulnerable to missile damage should the pipeline rupture close to these SSCs. All other targets of concern lie outside the 274 m (900 ft) distance that missiles can be thrown. The frequency of pipeline rupture and missile generation can be predicted as the product of the pipeline rupture frequency (1.50 x 10-6/mile.yr assuming the additional safety features are in place) and the conditional probability of missile generation in a pipeline rupture (0.5444). The resulting frequency is thus 8.10 x 10-7/mile.yr. In the absence of these enhancements, the frequency of pipeline rupture and missile generation is 5.40 x 10-6/mile.yr (a rupture frequency of 1.00 x 10-5/mile.yr multiplied by a 0.54 probability of missile generation). These frequencies cannot be applied, however, without assigning a probability that the missile would strike an object of concern. An upper bound estimate of this probability can be obtained by estimating the angle subtended by the object at its closest point to the pipelineignoring the possibility that missiles will fall short of or fly over the object and assuming that missiles are equally likely to be thrown in all directions. These frequencies, probabilities and the resulting exposure rates for missile damage for various SSCs are presented in Table B-3. From the exposure rates we can conclude that missile generation will contribute minimal additional risk.
44 In 13 events involving the rupture of natural gas transmission pipeline reported upon in detail by the NTSB, mention is made of fragments of the pipeline being thrown off in 7 events (i.e., 54 % of the 13 events). The 13 events in question are those involving the rupture of natural gas transmission pipelines for which detailed reports are available on the NTSB website (https://www.ntsb.gov/investigations/AccidentReports/Pages/pipeline.aspx). The events occurred between 1986 and 2020.
SECURITY-RELATED INFORMATIONWITHHOLD UNDER 10 CFR 2.390 Rev. 3, June 18 2020 B-14
SECURITY-RELATED INFORMATIONWITHHOLD UNDER 10 CFR 2.390 Rev. 3, June 18 2020 B-15 Table B-3 Upper-Bound Missile Damage Frequencies Length of Pipeline within 274 m (900 ft) of the Object45 Pipeline Rupture Frequency
(/mile.yr)
SSC of Concern Conditional Probability of Missile Damage given Missile Generation46 Enhanced Pipeline Unenhanced Pipeline Enhanced Pipeline Unenhanced Pipeline Probability Missiles Generated Exposure Rate
(/year)
Switchyard 0.297 822 m/
2697 ft/
0.51 miles 0
1.50 x 10-6 1.00 x 10-5 0.54 1.23 x 10-7 GT2/3 storage tank 0.047 594 m/
1949 ft/
0.37 miles 0
1.50 x 10-6 1.00 x 10-5 0.54 1.41 x 10-8 Met tower 0.0019 123 m/
404 ft/
0.08 miles 282 m/
924 ft/
0.18 miles 1.50 x 10-6 1.00 x 10-5 0.54 1.97 x 10-9 45 The 274 m (900 ft) distance appears, from a literature survey, to be the greatest distance that missiles can be thrown after pipeline rupture.
46 This conditional probability is calculated from the angle subtended by the SSC in question at the pipeline when the distance between the pipeline and SSC is leastit is the length of the arc that captures the SSC divided by the circumference of the circle in which the arc is to be found. The effective width of the meteorological tower is taken as 2 m assuming that pipe fragments are so large that a fragment passing the tower will strike it if it passes within 1 m.
SECURITY-RELATED INFORMATIONWITHHOLD UNDER 10 CFR 2.390 Rev. 3, June 18 2020 B-16 Table B-3 Upper-Bound Missile Damage Frequencies Length of Pipeline within 274 m (900 ft) of the Object45 Pipeline Rupture Frequency
(/mile.yr)
SSC of Concern Conditional Probability of Missile Damage given Missile Generation46 Enhanced Pipeline Unenhanced Pipeline Enhanced Pipeline Unenhanced Pipeline Probability Missiles Generated Exposure Rate
(/year)
U3 gen mausoleum 0.025 35 m/
115 ft/
0.02 miles 418 m/
1371 ft/
0.26 miles 1.50x 10-6 1.00 x 10-5 0.54 3.55 x 10-8
SECURITY-RELATED INFORMATIONWITHHOLD UNDER 10 CFR 2.390 Rev. 3, June 18 2020 B-17 B5. Potential Acts of Terrorism NRC regulations governing evaluation of potential external hazards do not require consideration of terrorist-induced failures, but we would note that:
No assumed rupture of the pipeline will cause material damage to equipment within the SOCA (Security Owner Controlled Area) due to distance from the southern route to the SOCA. Furthermore, those portions of the pipeline closest to the SOCA lie underground on IPEC property. Therefore, a terrorism threat to this section of pipe is not credible and not considered further.
The segment of the enhanced pipeline near the switchyard, GT2/3 diesel fuel storage and Emergency Operations Facility would also be installed underground with at least 4 of cover and reinforced concrete mats. Therefore, consistent with the explanations provided above a terrorism threat for this section of pipe is not credible and not considered further.
The above-ground portion of the pipeline located east of Broadway at the point at which the 42 pipeline enters the existing right of way is hypothetically vulnerable to wanton damage. However, this point is so distant from the SOCA and systems, structures and components of concern outside the SOCA that a fire or explosion there will not cause material damage to them.
We conclude therefore that the new pipeline will not introduce additional risk as a result of terrorism or other wanton damage.
B6. Seismic Events PMHSA and European [33] data show ground movement has been responsible for a number of pipeline ruptures. While larger diameter pipelines are less susceptible to ground movement [37],
they are still vulnerable2 of 14 rupture events involving pipelines of 36 or more in diameter in the period 1/1/2002 to 3/26/2020 recorded by the PHMSA were attributed to this cause (but in neither instance was the ground movement attributed to a seismic event47). That said, we can conclude that seismic events involving the gas pipeline will not introduce additional risk as The magnitude of earthquakes in the northeast is relatively low and would not pose a problem for a modern welded-steel pipeline [39]. Furthermore, the potential for pipe ruptures as a result of earth movement in a seismic event is low as the liquefaction/cyclic failure potential of the soils above the bed rock (on site) appears to be lowthe calculated Factor of Safety against liquefaction exceeds the threshold value at which liquefaction is deemed unlikely to occur [38].
Finally, we note that in evaluating seismic events at IPEC, a loss-of-offsite power has already been assumed [1], thus any damage to the switchyard or the GT2/3 diesel fuel oil storage tank 47 In one instance the cause was attributed to land subsidence on a steep scarp (NTSB safety order CPF No 1-2018-1016S); in the second, to a lateral movement that exacerbated a crack in a girth weld.
SECURITY-RELATED INFORMATIONWITHHOLD UNDER 10 CFR 2.390 Rev. 3, June 18 2020 B-18 that might follow a hypothetical seismic-induced rupture of the pipeline would not introduce risks that have not been evaluated previously.
SECURITY-RELATED INFORMATIONWITHHOLD UNDER 10 CFR 2.390 Rev. 3, June 18 2020 B-19 B7. References (Note: the numbers assigned to references in this appendix are consistent with those used for references in the main body of the report)
[1] IP3 IPEEE, 1995.
[3] US Nuclear Regulatory Commission, Regulatory Guide RG 1.91, Evaluations of Explosions Postulated to Occur at Nearby Facilities and on Transportation Routes Near Nuclear Power Plants Revision 2, April 2013.
[10] State of California, 2007 Guidance for Protocol for School Site Risk Analysis.
[32] Bechtel Associates Professional Corporation, Replaced Steam Generator Storage Facility, Design Package 2, 5-22-87 NSE.
[33] EGIG, Gas Pipeline Incidents, 10th Report of the European Gas Pipeline Incident Data Group (period 1970 - 2016), March 2018.
[34] US Department of Transportation, The State of the National Pipeline Infrastructure, 2013.
[35] US Energy Information Administration, US Natural Gas Pipeline Projects, 4/30/2020 (http://www.eia.gov/naturalgas/data.php).
[36] Phil Hopkins, et al., Pipeline Risk assessment: New Guidelines, WTIA/APIA Welded Pipeline Symposium, Sydney, Australia, April 3, 2009.
[37] Vania De Stefani, Zoe Wattis and Michael Acton, A Model to Evaluate Pipeline Failure Frequencies based on Design and Operating Conditions, AIChE, 2009 Spring Annual Meeting.
[38] Enercon Services, Inc., Report of Liquefaction Potential Assessment, Prepared for Entergy Nuclear, Report IP-RPT-14-00010, June 26, 2014.
[39] Spectra Energy Partners, Algonquin Incremental Market Project Resource Report 11, Reliability and Safety, FERC Docket No CP14-xxxx-000, February 2014.
[40] Center for Chemical Process Safety, Guidelines for Chemical Transportation Risk Analysis, American Institute of Chemical Engineers, New York, NY, 1995.
SECURITY-RELATED INFORMATIONWITHHOLD UNDER 10 CFR 2.390 Rev. 3, June 18 2020 EA-1 Exhibit A In addition to the much thicker, stronger steel and protected pipe installed along a segment of the southern route described in the report (the enhanced pipe), it is important to note that Spectra Energy has proven Standard Operating Procedures (SOPs) that are implementing before, during and after the AIM pipeline is built. Many of these SOPs have been filed with FERC. These SOPs result in additional significant margins of safety to the pipeline further reducing the impacts from possible threats.
The Spectra SOPs include but are not limited to the following:
Document Title Document Number Description SOP Administration Overview of the Standard Operating Procedures, the organization, who is responsible, frequency of updates, etc.
Integrity Management Program Documents and Procedures Integrity Management Program 09-0000 Details the program used to comply with 49 CFR 192 subpart O and ASME B31.8S.
Action Item Summary Sheet 405 Gives frequency, form number, and responsibility of IMP tasks External Corrosion 410 Part of the Threat Response Guidance Documents Internal Corrosion 420 Part of the Threat Response Guidance Documents Stress Corrosion Cracking 430 Part of the Threat Response Guidance Documents Manufacturing 440 Part of the Threat Response Guidance Documents Construction 450 Part of the Threat Response Guidance Documents Equipment 460 Part of the Threat Response Guidance Documents Third Party Damage 470 Part of the Threat Response Guidance Documents Incorrect Operations 480 Part of the Threat Response Guidance Documents Weather and Outside Forces 490 Part of the Threat Response Guidance Documents Management of Pipeline Dents and Mechanical Damage 510 How to evaluate dents/mechanical damage and how to respond Hardspots 511 Best practices for handling hardspots in piping Selective Seam Corrosion 512 Best practices for handling SSC in piping Effects of Pressure Cycles on DEGT System 513 Risk to system from fatigue crack growth is found to be negligible.
SECURITY-RELATED INFORMATIONWITHHOLD UNDER 10 CFR 2.390 Rev. 3, June 18 2020 EA-2 Document Title Document Number Description Assessment Methodology for Site HCAs 514 How to implement the IMP on non-mainline portions of the system Operating Pressure History 515 How to determine the operating pressure history for a line Methodology for Selection of RCV Sites 516 The function of this technical document is to define the Companys methodology for determining the location of remote control valves (RCV) for the purpose of improving response time and minimizing consequences of pipeline emergencies. This methodology is applicable to both existing facilities and new construction.
Pipeline Operating, Inspection, and Maintenance Procedures CLASS DETERMINATION PROCESS AP-CD1.3 Detailed listing of responsibility for work and deliverables and work flows to create and maintain Class Location Maps MAXIMUM OPERATING PRESSURE CALCULATION AP-CD3.0 Detailed listing of how to calculate and document a pipeline MAOP Action Item Summary Sheet 1-1010 Frequency that various pipeline inspections and surveys should be conducted.
Gas Pipeline Shutdown 1-2010 This procedure describes the requirements and the sequence of events which must take place for a pipeline or compressor station to be removed from service.
Drying Gas Pipelines 1-2020 This procedure describes the process for removal of liquid from the pipeline.
Branch Connections -
Hot Taps 1-3020 This procedure describes the necessary communications with Gas Control and the reporting requirements associated with cutting into an operating pipeline and connecting branch piping while the line is under pressure, also called hot tapping.
Pipeline Road and Rail Crossings 1-3030 This procedure describes the requirements and procedures to install pipelines under existing roads and railroads, or making provisions to protect existing pipelines that are to be crossed by new roads or railroads.
SECURITY-RELATED INFORMATIONWITHHOLD UNDER 10 CFR 2.390 Rev. 3, June 18 2020 EA-3 Document Title Document Number Description Changing Pipeline Service Status 1-3040 This procedure describes the activities associated with deactivating pipelines, abandoning pipelines in place or by removal and maintaining pipelines which are currently in inactive (idle), deactivated or decommissioned status.
Uprating Steel Pipelines 1-3060 This procedure describes the raising of the Maximum Allowable Operating Pressure (MAOP) or Maximum Operating Pressure (MOP) of an existing pipeline or a deactivated pipeline that is to be reactivated. In addition, it includes the studies, investigations, repairs, alterations, tests, and documentation necessary.
Excavation and Backfill 1-4010 This procedure describes the steps required to safely excavate and backfill around existing Company pipelines to prevent damage and provide adequate support and protection to minimize the stresses acting on the pipeline.
Locating Buried Pipelines Using Electronic Line Locators 1-4020 This procedure provides guidance for locating and temporary marking of buried Company pipelines.
This applies to all locate requests from third parties and locates prior to excavation activities of Company pipelines. Locating Company pipelines with electronic line locators is intended to provide general location information.
Right-of-Way Maintenance 1-5010 This procedure describes right-of-way maintenance which protects the pipelines, permits access to the pipelines, and aids in avoiding interference with the lands intended use. During patrols, any evidence of erosion, scour, subsidence, or slides, or the potential for any of these conditions to occur will be noted.
Pipeline Facilities Identification 1-5020 This procedure describes the various methods used to identify Company pipelines and related facilities, as well as the activities involved with the placement and maintenance of the different methods of identification.
Pigging and Pig Trap Operation 1-5030 This procedure describes pigging and pig trap operation.
Handling of Pipeline Solids 1-5040 This procedure describes the handling and testing of pipeline solids which may be gathered from pigging operations or during the changing of filters.
SECURITY-RELATED INFORMATIONWITHHOLD UNDER 10 CFR 2.390 Rev. 3, June 18 2020 EA-4 Document Title Document Number Description Clearing Freezes 1-5070 This procedure describes how to provide a safe, proven method for clearing pipeline freezes or blockages due to water or hydrates.
Pipeline Patrol and Leakage Survey Frequency Criteria 1-6010 This procedure describes the frequency of pipeline patrols and leakage surveys that will be conducted on the pipeline system for onshore and offshore pipelines that are in gas service, and for onshore pipelines that are in idle service to ensure the safety of the pipeline.
Leakage Surveys Utilizing Gas Detection Equipment 1-6020 This procedure describes the methods for conducting and documenting leakage surveys on above and below ground piping utilizing gas detection equipment.
Blasting Near Pipelines 1-6030 How to protect pipelines from blasting operations.
Aerial Pipeline Patrol 1-6040 This procedure describes the criteria for conducting and documenting aerial pipeline patrols.
Pipeline River and Waterway Crossing Surveys 1-6050 This procedure describes the criteria for conducting and documenting aerial pipeline patrols.
Mining Subsidence and Soil Slippage 1-6060 The investigation of proposed mining activities or unstable soils can reduce the possibility of pipeline damage due to earth movement and associated stresses, by identifying potential problem areas and allowing sufficient time to take preventive measures.
Right-of-Way Encroachments 1-6070 This procedure describes how to manage right-of-way encroachments which include foreign facility crossings. These outside forces could damage the pipelines or leave them vulnerable to future damage or an unsafe operating condition.
One-Call System
Response
1-6090 This procedure describes the guidelines to be used by Area Management in preparing for and responding to one-call notifications and line locate requests.
Direct Non-LDC Customer Notification of Buried Pipelines 1-6100 This procedure describes how to provide notification of buried piping to customers who receive gas directly from the Company and whose buried Service, Farm or Industrial Lines are not owned by the Company.
Shutdown Worksheet Final.XLS Form used when a pipeline section must be taken off line and blown down Corrosion Control, Inspection, and Remediation
SECURITY-RELATED INFORMATIONWITHHOLD UNDER 10 CFR 2.390 Rev. 3, June 18 2020 EA-5 Document Title Document Number Description Action Item Summary Sheet 2-1010 Lists the frequency that pipeline corrosion inspection procedures should be used.
Glossary 2-1020 The definitions used in the Company Manuals are listed in the document.
Tables and Formulae 2-1030 For use on cathodic protection systems Notes 2-1040 Notes on various Corrosion Control Standard Operating Procedures Structure-to-Electrolyte Potential Measurement 2-2010 It is used to evaluate the level of cathodic protection on a pipe or metallic structure.
Line Current Flow Measurement 2-2020 These line current flow measurements are useful in the overall evaluation of cathodic protection, interference currents, and corrosion activity.
Shunt or Resistor Current Flow Measurement 2-2030 Current flow determination is necessary to evaluate corrosion activity, effectiveness of cathodic protection, and the proper operation of rectifiers, galvanic anodes and effectiveness of critical bonds.
Soil Resistivity Measurement 2-2040 Soil resistivity measurements are used for anode bed design, location of corrosive areas on bare pipe, and evaluating the corrosivity of the soil.
pH Measurement 2-2050 This procedure describes the testing methods to determine the pH of a sample in the field.
Exothermic Weld 2-2060 This procedure describes the requirements to perform an exothermic weld.
Rectifier Inspection and Maintenance 2-2070 The purpose of a rectifier is to provide impressed current cathodic protection to underground metallic structures. The procedure for inspection and maintenance of these units is included in this procedure.
Groundbed Specifications and Inspection 2-2080 This procedure describes the installation and inspection of impressed current cathodic protection groundbeds.
Galvanic Anode Inspection 2-2090 This procedure describes inspection of galvanic anodes where anode leads and pipe contact leads are terminated in an accessible terminal box which allows current output measurements and where anode leads and pipe contact leads are buried, thus preventing current output measurements.
Casing Isolation Testing 2-2100 This procedure describes the tests for electrical short circuits between casings and the carrier pipe at cased pipeline locations.
SECURITY-RELATED INFORMATIONWITHHOLD UNDER 10 CFR 2.390 Rev. 3, June 18 2020 EA-6 Document Title Document Number Description Insulating Joint Isolation
- Design Considerations and Testing 2-2110 This procedure describes the design considerations and testing requirements for isolation joints for maintaining electrical isolation between a pipeline and other metallic structures.
Interference Testing and Mitigation 2-2120 This procedure describes the detection, measurement and mitigation of stray current interference from foreign sources, such as nearby pipeline cathodic protection systems, direct current powered transit systems and mining operations.
Close Interval Survey 2-2130 The survey involves measuring the pipe-to-soil potentials at varying distance intervals directly over a pipeline.
Current Requirement Testing 2-2140 This procedure describes the determination of the approximate amount of current required to cathodically protect a section of pipeline or any other underground metallic structure.
Grounding Cell Inspection 2-2150 Grounding cells are protective devices which prevent high voltage AC fault currents or high voltage surges from damaging insulating joints and coated pipelines in high voltage transmission line rights-of-way.
Coating Systems for Buried or Submerged Piping 2-2160 This procedure describes the application and maintenance of coatings for buried or submerged piping.
Critical Bond Inspection 2-2170 A bond is an intentional metallic path between two or more metallic structures capable of conducting electrical current flow.
Annual Corrosion Control Surveys 2-2180 This procedure describes how to conduct the Annual Corrosion Control Survey of Company pipelines and structures.
Measuring IR Drop 2-2190 This procedure describes how to apply and interpret the IR drop. IR drop caused by current flow in the soil/coating is termed electrolytic IR drop; IR drop caused by current flow in the pipe (metal) circuit is termed metallic IR drop.
Application of Cathodic Protection Criteria 2-2200 Meeting any criterion or combination of criteria in this section is evidence that adequate cathodic protection has been achieved.
Induced AC - Safety and Corrosion 2-2210 How to measure and mitigate induced AC.
Earth Gradient Measurement 2-2220 This procedure describes methods used to perform cell-to-cell and side drain surveys.
SECURITY-RELATED INFORMATIONWITHHOLD UNDER 10 CFR 2.390 Rev. 3, June 18 2020 EA-7 Document Title Document Number Description Cathodic Protection
System Design
2-2230 This procedure describes requirements for cathodic protection design.
Coating Fault Detection Surveys 2-2240 This procedure describes how to use voltage gradient techniques to locate coating defects on buried pipelines.
IR Drop/Coupling Surveys 2-2250 The survey involves measuring IR drop potentials at varying distance intervals with probe rods in direct connection to the coupled pipeline. This survey is employed to determine continuity of bonds on coupled pipelines.
Coating Resistance Measurement 2-2260 This procedure describes testing methods for obtaining coating resistance measurements.
Pipeline Current Mapper (PCM) for Current Attenuation 2-2270 A Current Attenuation (CA) survey (also known as an Electromagnetic Survey or a Pipeline Current Mapper (PCM) Survey) is used to determine the relative coating condition of a buried metallic pipeline.
Pipeline Current Mapper (PCM) A-Frame For Alternating Current Voltage Gradient (ACVG) 2-2280 Alternating Current Voltage Gradient (ACVG) is a survey technique used to detect flaws or holidays in buried pipeline coatings.
Assessment of Pipeline Coating Using Direct Current Voltage Gradient (DCVG) 2-2290 This SOP describes the process used to assess the condition of underground pipeline coating using Direct Current Voltage Gradient (DCVG) survey techniques to identify coating flaws (holidays).
Pin Brazing 2-2300 How to perform a pin brazing connection.
Internal Corrosion Monitoring and Mitigation 2-2310 Contains requirements and guidelines for inspection, evaluation, monitoring and mitigation of internal corrosion on distribution, transmission, storage and jurisdictional gathering lines within the Company pipeline system.
Evaluation of Remaining Strength of Pipe with Metal Loss 2-4020 This procedure describes the details of those evaluation methods currently approved to determine the remaining strength of pipe with metal loss.
Inline Tool Pipeline Inspection 2-4030 Describes inline inspection with magnetic flux leakage (MFL) technology.
Buried Pipe Inspections 2-4040 How to inspect buried pipelines for coating deterioration or external corrosion.
SECURITY-RELATED INFORMATIONWITHHOLD UNDER 10 CFR 2.390 Rev. 3, June 18 2020 EA-8 Document Title Document Number Description Shorted Casing Repair and Mitigation 2-4050 This procedure provides guidelines for remedial action to be taken at shorted casings which have been verified to be shorted using an approved test method.
Physical Observations and Collection of Liquid and Solid Samples 2-4060 Samples are for determining if internal corrosion is present.
Bacterial Corrosion Tests 2-4070 This procedure describes testing for the presence of Sulfate Reducing Bacteria (SRB) and/or Acid Producing Bacteria (APB).
Corrosion Control Remedial Action 2-4080 Used when existing corrosion controls must be altered.
Gas Sampling 2-4090 Samples are for determining if internal corrosion is present.
Water Detection 2-4100 How to test for the presence of water in a liquid sample.
Alkalinity Testing of Liquids 2-4110 How to test for total alkalinity of a liquid sample.
Dissolved CO2 Testing in Water 2-4120 How to test for carbon dioxide in a liquid sample.
Dissolved H2S Testing in Water 2-4130 How to test for hydrogen sulfide in a liquid sample.
Sulfide and Carbonate Testing of Solids 2-4140 How to test a sold for sulfides and carbonates.
Coupon Installation and Removal 2-4150 How to install, remove, and analyze corrosion coupons.
Aboveground Coating Systems 2-5010 This procedure describes coatings for aboveground piping and equipment, such as aerial markers, casing vents, milepost markers, pig traps, and valves and fittings located in the Company right-of-way outside and including the station suction and discharge valves.
Atmospheric Pipe Inspection 2-5020 How to inspect above ground piping for coating deterioration or pipe corrosion.
SOP's for Emergency Response and for Common Procedures Action Item Summary Sheet 5-1010 Frequency that various emergency response procedures should be conducted or maintained.
Area Emergency Response Procedures 5-2010 This procedure provides the foundation for responding to emergencies by Transmission (Operations) Foundation elements include the SET US Operations Crisis Management Plan and Incident
SECURITY-RELATED INFORMATIONWITHHOLD UNDER 10 CFR 2.390 Rev. 3, June 18 2020 EA-9 Document Title Document Number Description Command Structure.
Emergency and Security Event Simulation 5-2020 This procedure describes the requirements for preparing and conducting emergency and security event simulations.
Investigation of Failures 5-2030 This procedure and the SET U.S. Operations Crisis Management Plan are to be implemented together to enable Company personnel to analyze a system failure or accident.
Safety-Related Conditions Reporting 5-2040 This procedure list the conditions related to leaks, damage or defects that would potentially be reported as a safety-related condition. It also explains the tests, which should be administered to determine if a reportable condition does exist, and defines the reporting responsibilities.
Response to Abnormal Operations 5-2050 This procedure describes how to respond in instances of abnormal operations.
DOT/BOEMRE Incident Reporting 5-2060 This procedure describes the requirements for making verbal and written notification to the National Response Center (NRC), DOT, BOEMRE, and state agencies on Incidents (onshore or offshore) and offshore damages.
Above Ground Facility -
Minimum Security Practices 5-2070 This document specifies the minimum-security practices for Compressor stations, Processing plants, Main line block valve, launcher and receiver sites, Meter and regulator (M&R) stations, Reservoir and cavern storage wells, and Aerial pipeline crossings.
Releasing Security Sensitive Information 5-2080 The purpose of this document is to specify the requirements for processing the release of sensitive information to Federal, State and local government officials and agencies as well as private companies and individuals. This document also specifies information that is acceptable to distribute to the public without review.
Internal DOT Audit Procedure 5-2090 This procedure provides a program outline for a comprehensive team based pipeline safety compliance audit program. This program will include an audit guide for compliance and SOP application review at each Region and Area Office on a
SECURITY-RELATED INFORMATIONWITHHOLD UNDER 10 CFR 2.390 Rev. 3, June 18 2020 EA-10 Document Title Document Number Description systematic periodic basis.
Region Hurricane Response Plan 5-2100 This procedure defines the guidelines for the regions, which are affected by hurricanes, to develop hurricane response plans.
TSB/NEB Incident Reporting 5-2140 This procedure describes the steps and responsibilities for reporting incidents, accidents and occurrences to the Transportation Safety Board of Canada (TSB).
Purging 5-3010 This procedure describes purging requirements for pipelines, compressor station piping, meter station piping and other related equipment. There are three reasons to purge a pipeline.
- 1) Purging is performed to remove natural gas from a pipeline and replace it with nitrogen or air.
- 2) Purging is performed to remove air or nitrogen from the pipeline and subsequently replace it with natural gas. Purging is necessary to minimize inert constituents in the gas and eliminate a potentially combustible mixture of gas and air inside the pipeline.
- 3) Purging is also performed to evacuate gas away from a pipeline tie-in.
Filter (Pipeline -
Operations, Maintenance
& Inspection) 5-3040 This procedure describes safe standard procedures for inspecting and/or removing and installing gas pipeline filter elements.
Pressure Testing 5-3050 This procedure describes how pressure testing substantiates the Maximum Allowable Operating Pressure (MAOP) and verifies the integrity of steel pipelines.
Pipe-Type and Bottle-Type Holders 5-3060 This procedure describes provisions for the routine testing of pipe-type or bottle-type holders as defined in O&M Plan, Section 3.0. Pipe-type or bottle-type holders must be monitored for adequate cathodic protection levels to mitigate possible external corrosion and must be checked for dew point of vapors contained in the stored gas, that if condensed might cause internal corrosion.
SECURITY-RELATED INFORMATIONWITHHOLD UNDER 10 CFR 2.390 Rev. 3, June 18 2020 EA-11 Document Title Document Number Description Hazardous Energy Control (Lockout/Tagout) 5-3070 This procedure is designed to meet requirements established in OSHA 29CFR 1910.147. This purpose of this procedure is to provide guidance to safely perform service and/or maintenance on equipment where the unexpected energizing, startup or release of stored energy may occur.
Verification and Certification of Test Equipment 5-3080 This procedure describes inspection, verification and certification requirements for test equipment to maintain operability and required accuracy.
Collection of Liquid and Solid Samples and Physical Observations 5-3090 This procedure describes the steps for obtaining and handling samples of liquids, and/or solids for internal corrosion evaluation and /or gas measurement purposes.
Third Party Damage 5-4020 This procedure describes third party damage which includes, but is not limited to, any damages inflicted upon the pipeline and its facilities by the encroachment of foreign construction equipment, vehicular traffic, welding operations, or nearby blasting. This procedure is required to protect and maintain the serviceability of the pipelines and facilities.
Valve Inspection and Maintenance 5-5010 This procedure describes the activities associated with valve inspection and maintenance. It also describes the safe and proper operation of valves.
Valve Actuators (Automatic) -
Maintenance/ Inspection 5-5020 This procedure describes the safe and proper maintenance of automatic valve actuators.
Remotely Controlled Valves Inspection and Maintenance 5-5030 This procedure describes the methods of inspecting and maintaining the equipment that remotely control mainline valves.
Overpressure Protection and Capacity Verification 5-6010 This procedure describes the methodology utilized for protecting both the Maximum Allowable Operating Pressure (MAOP) and MAOP plus the build-up allowed for operation of pressure limiting and control devices for all compressor stations, mainline piping, and measurement and regulating stations per the pipeline regulations and other incorporated references.
Relief Valves - Testing, Inspection and Maintenance 5-6020 This procedure describes the testing and inspection (T&I), and maintenance of relief valves used in natural gas, air and storage tank service.
SECURITY-RELATED INFORMATIONWITHHOLD UNDER 10 CFR 2.390 Rev. 3, June 18 2020 EA-12 Document Title Document Number Description Regulators and Control Valves 5-7010 This procedure describes the requirements for inspection, testing, maintenance and repair of pressure regulators, pressure monitors, and flow control valves.
Controllers 5-7020 This procedure describes the inspection, testing, maintenance and repair of pneumatic and electronic controllers.
Vault Inspection and Maintenance 5-7030 This procedure describes the activities associated with vault inspection.
Hot Work Permits 5-8010 This procedure describes the activities associated with welding, cutting, and electric power tools or other spark-producing equipment in a classified work area.
Methanol Injection 5-9010 This procedure describes the method for injecting methanol into the pipeline at a measuring station.
Gas Control and Pipeline Operation Procedures Initial Notification of Potential Emergency 8-2010 This procedure describes the requirements and the sequence of actions to be taken by Gas Control in the event of an initial notification of a potential emergency condition on the pipeline.
Emergency Response 8-2020 Emergencies include pipeline rupture Alarm Management 8-2030 How to manage alarms received through the SCADA system Outage Management 8-2040 An Outage is any pipeline facility that becomes unavailable for any reason.
Early Notification Disaster Recovery 8-2050 How to prepare for and conduct Disaster Recovery when given sufficient notification.
Short Notification Disaster Recovery 8-2060 How to conduct Disaster Recovery with no notice.
Abnormal Operating Conditions 8-2070 How to respond to abnormal operations Shift Change 8-2080 This procedure describes the requirements and sequence of actions necessary to adequately brief the incoming control room personnel after a shift change.
Change Management 8-2090 Change Management of the equipment or operations of the pipeline.
Inspection, Testing, and Repair Specifications and Procedures In-Line Tool Pipeline Inspection 9-2010 An overview of inline inspection in the company.
SECURITY-RELATED INFORMATIONWITHHOLD UNDER 10 CFR 2.390 Rev. 3, June 18 2020 EA-13 Document Title Document Number Description External Corrosion Direct Assessment (ECDA) 9-2020 The purpose of this procedure is to describe the process of performing External Corrosion Direct Assessment (ECDA) surveys on identified pipeline segments. This procedure is written in accordance with NACE SP 0502, Pipeline External Corrosion Direct Assessment Methodology.
Dry Gas Internal Corrosion Direct Assessment (ICDA) 9-2030 The purpose of this procedure is to describe the process of performing the Dry Gas Internal Corrosion Direct Assessment (DG-ICDA) methodology on specified pipeline segments carrying normally dry gas. This procedure is in accordance with Federal Rulemaking on integrity management for gas pipelines (49 CFR Part 192 and ASME/ANSI B31.8S-2001) and NACE SP 0206, Internal Corrosion Direct Assessment (ICDA) Methodology for Pipelines Carrying Normally Dry Gas.
Stress Corrosion Cracking Direct Assessment (SCCDA) 9-2040 The purpose of this procedure is to describe the process that the Company uses to perform Stress Corrosion Cracking Direct Assessment (SCCDA) on identified pipeline segments. This procedure is written in accordance with NACE RP0204-2004, Stress Corrosion Cracking Direct Assessment Methodology.
Hydrostatic Testing for Stress Corrosion Cracking 9-2050 This procedure details the Companys methods and requirements for conducting hydrostatic testing to verify the integrity of a pipeline by testing sections that have shown evidence of stress corrosion cracking (SCC) as leaks or failures, Category 2, 3 and 4 SCC found during direct examination of the pipeline, or may have a higher vulnerability to SCC due to historical operating conditions.
Direct Examination 9-2060 The purpose of this procedure is to describe the process of performing the Direct Examination (DE) methodology on specified pipeline segments carrying natural gas.
Assessment of Pipeline Segments Using Guided Wave UT 9-2070 This SOP describes the process to assess the integrity of pipeline segments using the guided wave ultrasonic testing process (GWUT). GWUT may be used to assess above ground, buried, or cased pipe.
SECURITY-RELATED INFORMATIONWITHHOLD UNDER 10 CFR 2.390 Rev. 3, June 18 2020 EA-14 Document Title Document Number Description Response to In-Line Inspection 9-3010 This procedure describes the process for evaluating anomalies that are detected by in-line inspection tools, the process to determine which anomalies will be selected for direct examination, and a prioritized schedule for conducting the excavation.
Monitoring and Mitigation (ECDA) 9-3020 This procedure outlines the requirements for conducting an external corrosion direct assessment on certain segments of the Companys pipeline system. Contained within this SOP are plans for addressing immediate, scheduled and monitored indications which were identified as part of the assessment process.
Defect Assessment &
Repair Options for Internal Corrosion 9-4010 This document covers guidelines for the evaluation of internal corrosion for pipelines carrying natural gas to ensure pipeline integrity. The methodology is applicable to pipelines which are in gas service and can only be inspected manually, or with automated instrumentation, from the exterior of the pipe.
Defect Assessment &
Repair Options for External Corrosion 9-4020 This procedure describes the process for examining and evaluating external corrosion anomalies. This procedure describes details of those evaluation methods currently approved to determine the remaining strength of pipe with metal loss.
Direct Examination &
Repair Options for Stress Corrosion Cracking 9-4030 This procedure provides guidance to personnel performing direct examination (nondestructive examination and assessment) of exposed underground pipelines for stress corrosion cracking (SCC).
Defect Assessment &
Repair Options for Dents and Mechanical Damage 9-4040 This procedure defines a methodology for field assessment of plain dents and dents interacting with other defects in natural gas pipelines. Provisions of ASME B31.8-2007 §851.41 - §851.43 are incorporated.
Defect Assessment &
Repair Options for Miscellaneous Defects 9-4050 This procedure provides guidance for the assessment of exposed pipelines for miscellaneous defects.
Miscellaneous defects are generally the result of pipe manufacturing defects, construction damage, or obsolete construction practices.
SECURITY-RELATED INFORMATIONWITHHOLD UNDER 10 CFR 2.390 Rev. 3, June 18 2020 EA-15 Document Title Document Number Description Magnetic Particle Inspection of Pipelines for Surface Cracks 9-4060 This procedure contains recommendations for performing Magnetic Particle Testing (MT) inspection for the purposes of detecting pipeline surface cracks including all forms of SCC. The recommended method for inspecting Company pipelines is the water based, wet visible black-on-white contrast method.
Ultrasonic Inspection of Line Pipe 9-4070 Either manual or automated ultrasonic inspection (UT) can be used to identify and quantify corrosion on line pipe.
CorrEval Software &
Users Guide 9-4110 The CorrEval spreadsheet provides a method for calculating the failure pressure levels of longitudinally oriented part-through flaws of varying depths in pressurized pipe. The method is applicable to blunt defects such as corrosion-caused metal loss.
Mechanical Damage Assessment Software &
Users Guide 9-4120 The Company developed Excel spreadsheet programs utilizing ASME B31.8-2007 equations for dent curvature strain assessment, and calculating maximum allowable grinding repair lengths.
Pipeline Repair Procedures 9-5010 This procedure outlines the approved pipeline repair methods available for existing pipelines and details the steps required to perform each repair method for damaged or defective pipe. Area Management shall supervise all repairs to ensure that the work is done in accordance with Company procedures.
Repair Sleeve Design 9-5020 This procedure should be used in conjunction with SOP #9-5010, Pipeline Repair Procedures, and provides the engineering requirements for design of full encirclement, steel repair sleeves used as temporary or permanent repairs of corrosion, mechanical damage, weld defects, or material defects in pipe.
Clock Spring Procedures 9-5030 This procedure presents the requirements and procedures for the installation, inspection and removal of Clock Spring composite wraps and is a supplement to the criteria set forth in Section 4.0 of SOP #9-5010, Pipeline Repair Procedures.
Specifications and Procedures for Pipeline Projects including Construction, Procurement, and Inspection
SECURITY-RELATED INFORMATIONWITHHOLD UNDER 10 CFR 2.390 Rev. 3, June 18 2020 EA-16 Document Title Document Number Description Onshore Pipelines and Meter Stations CS-PL1.7 Specification for the construction of onshore natural gas pipelines.
Onshore Compressor Stations - Painting And Coating CS-CS1-14.4 Specification for the coating of above and below ground piping.
Quality Assurance Inspection Plan For Purchase Of API Pipe And FBE Coating IS-QP1.0 The Spectra Energy Quality Assurance plan for the purchase of line pipe and coatings in the United States of America covers manufacture and testing at the pipe mill, shipping the pipe to the coating mill, coating the pipe at the coating mill, load-out of pipe from coating mill to method of transport.
Valves IS-IV1.1 Valve inspection procedure at the manufacturer Ultrasonic Weld Seam Inspection Of ERW Linepipe IS-IP2.0 This specification is established to outline the responsibilities of the ERW linepipe inspection contractor in fulfilling the requirements for supplemental ultrasonic weld seam inspection. This supplemental inspection is to be performed in addition to all other weld seam inspection conducted by the pipe manufacturer and shall be in accordance with Company requirements and the American Petroleum Institute (API-5L).
Pipe IS-IP1.1 Pipe inspection procedure at the pipe mill General -
Material/Equipment Inspection Reporting Requirements IS-IG2.1 This specification outlines the formats, procedure for submittal and submittal schedule for the inspection reports required by the Company for inspections of material/equipment at a Manufacturer's facility.
General -
Material/Equipment Inspection Requirements IS-IG1.1 This specification outlines the responsibilities and general requirements of the Third Party Inspection Company and its representatives as representatives of Spectra Energy Transmission in a material/equipment inspection capacity at a Manufacturer's facility.
Fabrications IS-IF2.1 Fittings and flanges inspection at the manufacturer Fittings And Flanges IS-IF1.1 Fabricated items inspection at the manufacturer Coating - Induction Bends, Fusion Bonded Epoxy IS-IC4.1 Inspection of FBE coated induction bends at the coating yard Coating - Concrete And Anode IS-IC3.1 Inspection of the concrete coating and anodes at the coating yard Coating - Fusion Bonded Epoxy IS-IC2.1 Inspection of FBE coating on pipe at the coating yard Coating - Internal IS-IC1.1 Inspection of the internal coating at the coating yard
SECURITY-RELATED INFORMATIONWITHHOLD UNDER 10 CFR 2.390 Rev. 3, June 18 2020 EA-17 Document Title Document Number Description Induction Bends IS-IB1.1 Inspection of induction bends at the bend manufacturer Pipeline/Plant Construction Inspection Manual - Introduction IG-CIM.1 An overview of inspection methods and form intended for use on construction projects.
Facility Audit Report TS-711.0 Form to be used when auditing a supplier or manufacturer Fabrication Surveillance Inspection Checklist Form to be used when inspecting equipment at a manufacturer Assessment Document List Form requesting data related to safety and quality from a manufacturer Pipe, Double Submerged Arc Weld ES-PP3.9 Specification for API 5L pipe Audit Protocol AP-AM2.1 How to perform a plant audit of an unapproved manufacturer Onshore Compressor Stations - Pressure Testing CS-CS1-19.4 Specification for hydrostatic testing of above and below ground piping.
Pressure Testing DP-CT1.3 Pipeline specific hydrostatic testing requirements to ensure compliance with DOT requirements.
Non-Destructive Examination CS-NDE1.0 Minimum requirement for the NDE of welds Radiography CS-NDE2.0 Minimum requirement for radiographic inspection of welds Pressure Testing Of Gas Transmission Facilities TP-CT-1.5 This procedure provides detailed process requirements for conducting a Pressure Test for Company pipeline or station facilities and provides the criteria for acceptance and documentation of a Pressure Test.
In addition to the above SOPs AGT (Spectra) has stated they will also incorporate the following items during the engineering, procurement and construction of the AIM pipeline project.
a) Quality Assurance/Quality Control (QA/QC) Procedures for the engineering, design, procurement, fabrication and construction.
b) The latest state of the art cathodic protection (CP) systems is designed and installed by an experienced third party contactor and CP surveys will be conducted in accordance with DOT Part 192 requirements.
SECURITY-RELATED INFORMATIONWITHHOLD UNDER 10 CFR 2.390 Rev. 3, June 18 2020 EA-18 c) A robust AC mitigation system has been engineered and installed in areas where the pipeline has been installed adjacent, parallel and crosses high voltage power lines in the area near IPEC.
d) The pipeline coatings were 100% inspected electronically as the pipeline was lowered into the ground.
e) An Alternating Current Voltage Gradient (ACVG) or Direct Current Voltage Gradient (DCVG) survey has been performed to ensure coating integrity following pipe installation and backfill.
f)
Inline inspections (ILI) or smart pig surveys will be conducted as described in the Integrity Management Plan and has been conducted as often as required by Federal Pipeline Integrity Rules and Regulations and ASME B31.8S.
g) The pipeline will be patrolled on a weekly basis per DOT Part 192 to identify possible unapproved encroachments on the ROW.
h) Spectra is also a member of the one-call (call before you dig) system which is monitored continuously by full-time trained personnel who respond to these calls daily and approved excavations are monitored/supervised by trained inspectors.
i)
Operating pressures will be limited to the pipeline maximum allowable operating pressure (MAOP) by the activation of automatic overpressure alarms, shutdown of upstream compressors and isolation devices.
j)
Pipeline failures will be detected automatically and immediate alarms will be sent to Spectras 24/7 control operator who will take the appropriate action in accordance with Spectras SOPs.
k) 100% of all welds along the segment of pipe near IPEC assets were radiographed and approved by trained X-ray technicians.
l)
The completed pipeline has been subjected to a hydrostatic test continuously for 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> in accordance with 49 CFR 192 and Spectras SOPs.
m) The pipeline will be periodically swept of trapped liquids using swabs or pigs designed for this purpose.
SECURITY-RELATED INFORMATIONWITHHOLD UNDER 10 CFR 2.390 Rev. 3, June 18 2020 EB-1 Exhibit B Pipeline Design Enhancements Proposed by Spectra for IPEC (in Response to Entergy Questions)
Question Typical Gas Pipeline Installation/design IPEC Enhanced Installation/design Remarks Pipe pressure safety factors (include national design standard) 49 CFR § 192.111:
Class location 1, design factor 0.72 -
equates to 72%
Specified Minimum Yield Strength (SMYS). Class location 3, design factor 0.5 - equates to 50% SMYS.
Pipe to be used for~
3935 for Entergy will exceed design factor for Class 4, design factor 0.4 -
equates to 40%
SMYS. Proposed 0.720 wall thickness (wt) pipe equates to 36%
SMYS.
Pipe material type (include national design standard)
Pipe Grade is X-70, 70,000 psi minimum yield strength and 82,000 psi minimum tensile strength, all manufactured to API 5L PSL-2 standards.
Pipe Grade is X-70.
In addition, pipe is procured from vendors who have passed a stringent quality audit, and full-time mill inspection is performed by AGT during pipe production. AGT pipe specifications require additional quality testing and integrity requirements above and beyond API-5L standards.
Pipe thickness 0.469 wt for Class 1 and 0.510 wt for Class 3 0.720 wt - exceeds Class 1 and Class 3 requirements Class 4 required wt is 0.6375 for X-70.
The proposed 0.720 wt exceeds Class 4 requirements, the
SECURITY-RELATED INFORMATIONWITHHOLD UNDER 10 CFR 2.390 Rev. 3, June 18 2020 EB-2 Exhibit B Pipeline Design Enhancements Proposed by Spectra for IPEC (in Response to Entergy Questions)
Question Typical Gas Pipeline Installation/design IPEC Enhanced Installation/design Remarks most stringent DOT Code classification.
Coating material and design details, include specifications Standard coating to be Fusion Bond Epoxy (FBE) coating, 16 mils (one thousandth of an inch) nominal (14 mils is industry standard).
Enhanced coating is dual layer FBE and Abrasion Resistant Overlay (ARO) with a nominal thickness of 24 mils.
AGT will specify 40 mils of coating consisting of 16 mils of FBE and 24 mils of ARO.
ARO will provide for enhanced protection during installation and provide additional corrosion protection.
This has changed to a combined thickness of 25mils (min.). See Exhibit C.
Depth of pipe, show via sketch mats, over lay, etc.
3 cover typical and required by the DOT Code (49 CFR § 192.327) 4 cover along with physical concrete mat barrier protection installed 2 below grade (to bottom of slab).
See Exhibit C Concrete mat cover details, width, thickness, composition, etc.
Not required 2 parallel sets of fiber reinforced concrete slabs (dimensions 3x 8x
- 6) along the pipeline with a 1 separation over the center of pipe.
See Exhibit C Seismic considerations Spectras design takes into account seismic considerations (Note additional response received from Spectra for this The accelerations from earthquakes in the range experienced in the eastern United States do not pose a risk for high-strength welded steel pipelines.
Note that the worst earthquakes in the eastern United States are of much lower magnitude than the quakes on the west coast where the gas transmission
SECURITY-RELATED INFORMATIONWITHHOLD UNDER 10 CFR 2.390 Rev. 3, June 18 2020 EB-3 Exhibit B Pipeline Design Enhancements Proposed by Spectra for IPEC (in Response to Entergy Questions)
Question Typical Gas Pipeline Installation/design IPEC Enhanced Installation/design Remarks item shown on the last page of this Exhibit B) pipelines have proven to operate safely using the same pipeline design methods.
Radiography of welds 10% for Class 1; 100% for Class 3 100% for Class 1 and Class 3 Additional misc. safety features i.e., safety tape Not Required Yellow warning tape has been placed in two layers - one layer at the top of concrete slabs and another layer 1 above the pipe.
Warning ribbons are a minimum of 18 wide.
See Exhibit C Backfill details, color, material, etc.
Standard AGT Construction Specifications for backfill.
Install physical concrete mat barrier protection 2 below grade (to bottom of slab). Other backfill is in accordance with AGT Construction Specifications.
Coating integrity assessment following pipeline installation (such as ACVG &
DCVG)
A coating fault test (Jeeping) of pipe was performed prior to backfill and any coating faults were repaired.
In addition to Jeeping, AGT will conduct a DCVG survey, following partial backfill, prior to installation of concrete slabs and any coating faults were repaired.
SECURITY-RELATED INFORMATIONWITHHOLD UNDER 10 CFR 2.390 Rev. 3, June 18 2020 EB-4 Exhibit B Pipeline Design Enhancements Proposed by Spectra for IPEC (in Response to Entergy Questions)
Question Typical Gas Pipeline Installation/design IPEC Enhanced Installation/design Remarks Mitigation of AC induced current from high voltage power lines.
Provisions for AC Mitigation AGT is in the process of modeling the AC interference along the proposed pipeline route. An AC mitigation design will include the ~ 4,290 feet of pipe in this area to address any AC corrosion or personnel safety concerns.
Minimization/Mitigation of internal corrosion No special measures required The proposed pipe will contain an internal coating.
Historically, the existing pipeline system runs quite dry and has never exhibited any signs of internal corrosion problems. Quality of gas at receipt points is monitored to ensure the absence of corrosive components.
Cleaning pigs are run on a regular basis to remove any accumulated material.
Additional response from Spectra regarding seismic considerations:
The potential for geologic hazards, including seismic events, to significantly affect construction or operation of the proposed Project facilities is low. Although the Ramapo Fault has been linked to recent earthquake occurrence in the area, the design of the pipeline takes into
SECURITY-RELATED INFORMATIONWITHHOLD UNDER 10 CFR 2.390 Rev. 3, June 18 2020 EB-5 consideration site-specific conditions, including earthquakes. The recorded magnitude of earthquakes in the Project area is relatively low and the ground vibration would not pose a problem for a modern welded-steel pipeline
SECURITY-RELATED INFORMATIONWITHHOLD UNDER 10 CFR 2.390 Rev. 3, June 18 2020 EB-6 Exhibit C AGT Pipe Enhancement Cross-Section for Entergy NOTTO SCALE I Final Grade Line !
Internal Coating -
FBE 1.5 mils (Nominal)
Center Line 4'
External Coating-FBE/ARO 25 mils combined (Min.)