NREL is a national laboratory of the U.S. Department of Energy, Office of Energy 

Efficiency & Renewable Energy, operated by the Alliance for Sustainable Energy, LLC.

Contract No. DE-AC36-08GO28308

Blending Hydrogen into 

Natural Gas Pipeline Networks:

A Review of Key Issues

M. W. Melaina, O. Antonia, and M. Penev

Technical Report

NREL/TP-5600-51995

March 2013
NREL is a national laboratory of the U.S. Department of Energy, Office of Energy 

Efficiency & Renewable Energy, operated by the Alliance for Sustainable Energy, LLC.

National Renewable Energy Laboratory

15013 Denver West Parkway

Golden, Colorado 80401

303-275-3000 • www.nrel.gov

Contract No. DE-AC36-08GO28308

Blending Hydrogen into 

Natural Gas Pipeline Networks: 

A Review of Key Issues

M. W. Melaina, O. Antonia, and M. Penev

Prepared under Task No. HT12.2010

Technical Report

NREL/TP-5600-51995

March 2013
NOTICE

This report was prepared as an account of work sponsored by an agency of the United States government. 

Neither the United States government nor any agency thereof, nor any of their employees, makes any warranty, 

express or implied, or assumes any legal liability or responsibility for the accuracy, completeness, or usefulness of 

any information, apparatus, product, or process disclosed, or represents that its use would not infringe privately 

owned rights. Reference herein to any specific commercial product, process, or service by trade name, 

trademark, manufacturer, or otherwise does not necessarily constitute or imply its endorsement, recommendation, 

or favoring by the United States government or any agency thereof. The views and opinions of authors

expressed herein do not necessarily state or reflect those of the United States government or any agency thereof.

Available electronically at http://www.osti.gov/bridge

Available for a processing fee to U.S. Department of Energy

and its contractors, in paper, from:

U.S. Department of Energy

Office of Scientific and Technical Information

P.O. Box 62

Oak Ridge, TN 37831-0062

phone: 865.576.8401

fax: 865.576.5728

email: mailto:reports@adonis.osti.gov

Available for sale to the public, in paper, from:

U.S. Department of Commerce

National Technical Information Service

5285 Port Royal Road

Springfield, VA 22161

phone: 800.553.6847

fax: 703.605.6900

email: orders@ntis.fedworld.gov

online ordering: http://www.ntis.gov/help/ordermethods.aspx

Cover Photos: (left to right) PIX 16416, PIX 17423, PIX 16560, PIX 17613, PIX 17436, PIX 17721

Printed on paper containing at least 50% wastepaper, including 10% post consumer waste. 
iii

Acknowledgments

Funding for this report came from the U.S. Department of Energy’s Fuel Cell Technologies

Program. The authors thank Daniel Ersoy and Zhongquan Zhou from the Gas Technology 

Institute (GTI) for preparing the subcontract report, included as Appendix A. The report has 

benefited greatly due to comments received from multiple reviewers of an earlier version. 

Specifically, we thank Glen Eisman (H2Pump LLC), Onno Florisson (KEMA, European 

NaturalHy Project), Edward Heydorn (Air Products and Chemicals, Inc.), Noel Leeson (Power & 

Energy Inc.), and Frank Lomax (CB&I Lummus Technology). 
iv

Definitions

atm atmosphere

CCS carbon capture and storage

DTI Directed Technologies, Inc.

EHS electrochemical hydrogen separation

FERC Federal Energy Regulatory Commission

GTI Gas Technology Institute

HDS hydro-desulfurization

IEA International Energy Agency

IMP Integrity Management Program

IMT Integrity Management Tool

in. inch, inches

ISQ Instituto de Soldadura e Qualidade

m meter

NREL National Renewable Energy Laboratory

PBI polybenzimidazole

Pd palladium

PE polyethylene

PEM proton exchange membrane

PHMSA Pipeline and Hazardous Materials Safety Administration

ppb parts per billion

ppm parts per million

ppmv parts per million by volume

PSA pressure swing absorption

psi pounds per square inch

psia pounds per square inch absolute

psig pounds per square inch gauge

PVC polyvinyl chloride

SMR steam methane reforming
v 

Executive Summary

Hydrogen is being pursued as a sustainable energy carrier for fuel cell electric vehicles (FCEVs) 

and as a means of storing renewable energy at utility scale. Hydrogen can also be used as a fuel 

in stationary fuel cell systems for buildings, backup power, or distributed generation. Blending 

hydrogen into the existing natural gas pipeline network has been proposed as a means of 

increasing the output of renewable energy systems such as large wind farms. If implemented 

with relatively low concentrations, less than 5%–15% hydrogen by volume, this strategy of 

storing and delivering renewable energy to markets appears to be viable without significantly 

increasing risks associated with utilization of the gas blend in end-use devices (such as 

household appliances), overall public safety, or the durability and integrity of the existing natural 

gas pipeline network. However, the appropriate blend concentration may vary significantly 

between pipeline network systems and natural gas compositions and must therefore be assessed 

on a case-by-case basis. Any introduction of a hydrogen blend concentration would require 

extensive study, testing, and modifications to existing pipeline monitoring and maintenance 

practices (e.g., integrity management systems). Additional cost would be incurred as a result, and 

this cost must be weighed against the benefit of providing a more sustainable and low-carbon gas 

product to consumers.

Blending hydrogen into natural gas pipeline networks has also been proposed as a means of 

delivering pure hydrogen to markets, using separation and purification technologies downstream 

to extract hydrogen from the natural gas blend close to the point of end use. As a hydrogen 

delivery method, blending can defray the cost of building dedicated hydrogen pipelines or other 

costly delivery infrastructure during the early market development phase. This hydrogen delivery 

strategy also incurs additional costs, associated with blending and extraction, as well as 

modifications to existing pipeline integrity management systems, and these must be weighed 

against alternative means of bringing more sustainable and low-carbon energy to consumers. 

Though the concept of blending hydrogen with natural gas is not new (IGT 1972), the rapid 

growth in installed wind power capacity and interest in the near-term market readiness of FCEVs 

has made blending a more tangible consideration within several stakeholder activities (Florisson 

2012; GM 2010), including recent agreements on “Power-to-Gas” initiatives with Hydrogenics 

(2012a; 2012b). Delivering blends of hydrogen and methane (the primary component of natural 

gas) by pipeline also has a long history, dating back to the origins of today’s natural gas system 

when manufactured gas produced from coal was first piped during the Gaslight era to 

streetlamps, commercial buildings, and households in the early and mid-1800s. The 

manufactured gas products of the time, also referred to as town gas or water gas, typically 

contained 30%–50% hydrogen, and could be produced from pitch, whale oil, coal or petroleum 

products (Castaneda 1999; Tarr 2004; Melaina 2012). The use of manufactured gas persisted in 

the United States into the early 1950s, when the last manufactured gas plant in New York was 

shut down and natural gas had displaced all major U.S. manufactured gas production facilities. In 

some urban areas, such as Honolulu, Hawaii, manufactured gas continues to be delivered with 

significant hydrogen blends and is used in heating and lighting applications as an economic 

alternative to natural gas (TGC 2012; GM 2010). 
vi 

This report reviews seven key issues related to blending hydrogen into natural gas pipeline 

networks, which are described briefly in the following sections. Though these issues are 

interrelated, they are presented separately for the sake of clarifying explanation:

1. Benefits of blending 

2. Extent of the U.S. natural gas pipeline network 

3. Impact on end-use systems

4. Safety

5. Material durability and integrity management 

6. Leakage

7. Downstream extraction

The review material presented in this report relies heavily on a study from the Gas Technology 

Institute (GTI), which is included as Appendix A. While conventional means of producing and 

delivering hydrogen are relatively well understood, blending as a means of storing or delivering 

hydrogen is very dependent on specific characteristics of the natural gas pipeline system. The 

GTI assessment therefore details the implications of hydrogen blending in relation to the distinct 

characteristics of the U.S. natural gas pipeline system. This report also relies on the extensive 

studies conducted within the NaturalHy project, associated with the Sixth Framework 

Programme of the European Commission (Florisson 2012), as well as information from a

Greenhouse Gas R&D Programme study sponsored by the International Energy Agency (IEA) 

(Haines et al. 2003). 

Benefits of Blending

Adding hydrogen to natural gas can significantly reduce greenhouse gas emissions if the 

hydrogen is produced from low-carbon energy sources such as biomass, solar, wind, nuclear, or 

fossil resources with carbon capture and storage (CCS). Any social or environmental benefits 

associated with sustainable hydrogen pathways could arguably be attributed to natural gas with a 

hydrogen blend component in proportion to the hydrogen concentration. In the downstream 

extraction pathway, use of hydrogen in FCEVs improves air quality by reducing sulfur dioxide, 

oxides of nitrogen, and particulate emissions and displacing conventional gasoline or diesel 

fuels. The blending benefit would be similar, in some respects, to the introduction of biogas into 

the natural gas pipeline as a means of providing a renewable natural gas product to consumers. 

Conceivably, a credit trading system could apply to natural gas with a specified blend content of 

renewable hydrogen, paralleling the renewable energy credit system used in the electricity sector. 

If properly crafted, this credit system could provide an economic incentive for converting 

otherwise curtailed renewable energy to hydrogen, increasing the energy provided from existing 

renewable energy production facilities, and enhancing the sustainability of the natural gas supply 

system. Understanding the techno-economic potential and spatial logistics associated with this 

type of energy storage and hydrogen delivery system would require additional analysis. Recent 

efforts to develop such a system in Germany will provide useful empirical data to understand 

better the potential to apply renewable credits to hydrogen and natural gas blends (Wilson 2012; 

E.ON 2011). 
vii 

Extent of the U.S. Natural Gas Pipeline Network

The U.S. natural gas pipeline system has evolved from local manufactured gas networks serving 

municipalities in the mid-1800s to a vast network of interconnected pipeline systems comprising 

2.44 million miles of pipe, 400 underground storage facilities, and 1,400 compressor stations. 

Natural gas accounted for 24.6 quads of U.S. energy consumption in 2010, roughly 25% of total 

energy consumed. Moreover, recent increased domestic production rates suggest that the existing 

natural gas system will continue to provide relatively clean and domestic energy for some time, 

especially with increased adoption of energy efficiency measures (EIA 2012). Given these 

characteristics, hydrogen blending could become a widespread, long-term, and integral practice 

to supplement a critical domestic energy infrastructure. 

Impact on End-Use Systems

Several studies have discussed the issue of maximum hydrogen blend levels at which no or 

minor modifications would be needed for end-use systems, including appliances such as 

household boilers or stoves and industrial or power generation (Florisson 2010; De Vries 2009; 

Haeseldonckx 2007; De Vries 2007; Schumra and Klingenberg 2005; Kelly and Hagler 1980). 

The conditions determining a maximum hydrogen blend level that does not adversely influence 

appliance operation or safety vary significantly and include the composition of the natural gas, 

the type of appliance (or engine), and the age of the appliance. The impact of hydrogen blends on 

industrial facilities must be addressed on a case-by-case basis, and stationary gas engines likely 

will require changes to control systems (Florisson 2010). Ranges noted as being acceptable 

generally for end-use systems fall within 5%–20% hydrogen, and most discussions note types of 

changes, precautions, or costs associated with higher blends. For example, Haines et al. (2003) 

estimate the cost of upgrades in the United Kingdom, Netherlands, and France with respect to 

modifications required for 3%, 12%, and 25% hydrogen blends. Given the inertia behind any 

required changes to end-user appliances or industrial facilities, hydrogen blending likely would 

begin at very low concentrations and then increase gradually over time (if warranted) as required 

modifications for higher concentrations are addressed. As noted by Florisson (2009), end-use 

requirements are generally the most restrictive conditions on increasing hydrogen blend levels in 

natural gas. The natural gas composition in a given pipeline is an important consideration 

(Zachariah-Wolff et al. 2007). Meeting these requirements would often preclude risks posed by 

safety and material integrity concerns. 

Safety

Multiple factors must be taken into consideration to assess the safety concerns associated with 

blending hydrogen into the existing U.S. natural gas pipeline system. It is difficult to make 

general claims about safety due to the large number of factors involved; detailed risk assessment 

results likely will vary from location to location. Because hydrogen has a broader range of 

conditions under which it will ignite, a main concern is the potential for increased probability of 

ignition and resulting damage compared to the risk posed by natural gas without a hydrogen 

blend component. The probability of an incident and the consequence of the incident are 

combined into an overall risk factor. In the literature reviewed, these risk factors have been 

assessed for hydrogen blends of various concentrations (e.g., 20%, 25%, and 50%), for different 

sections of the existing natural gas pipeline system (e.g., distribution mains and service lines), 

and for different conditions (e.g., contained or uncontained releases). The context for describing 

safety concerns is therefore the degree to which different types of hazards may increase or 
viii

decrease risks for different hydrogen concentrations, pipeline types, and failure mode conditions. 

The risk assessment results described here would not apply to new, dedicated hydrogen pipelines 

carrying pure hydrogen, and blending risks will vary between natural gas pipeline systems of 

different types, materials, and ages across the United States. 

It is important to place energy-related risks into perspective. All large-scale energy systems—

including nuclear, fossil fuel and renewable energy systems—present different types of risks to 

human health and the environment (Schneider 1979; Holdren et al. 1979). The overall risks 

posed by the existing natural gas pipeline system can be quantified, and these results are used as 

a baseline for comparing risks associated with hydrogen blends. However, in general, natural gas 

systems pose a lower risk of severe accidents than do other large-scale energy systems such as 

coal, petroleum, nuclear, and hydropower (the latter two involving less frequent but higher 

impact accidents), although they appear to pose greater risk than non-hydro renewables such as 

wind and solar (Hirschberg et al. 2004; Bergherr and Hirschberg 2008; Bergherr et al. 2012; PSI 

2012).

The present study reviews new analysis conducted by GTI of various safety hazards with 

reference to a numerical risk assessment scale with rankings that range from zero (no significant 

hazard) to 50 (severe hazard). Within this numerical system, a hazard significance ranking of 10 

is described as “minor,” 30 is “moderate,” and 50 is “severe” (see Appendix A). Though actual 

rankings may vary based on multiple factors, the general conclusion of the research findings 

presented here is that adding low concentrations of hydrogen to existing natural gas pipeline 

systems, at volumes of 20% or less, results in a minor increase in the risk of ignition. Moreover, 

in instances where natural gas leaks result in explosions, inclusion of 20% or less hydrogen 

would result in minor increases in the severity of the explosion. Higher concentrations of 

hydrogen may be acceptable from a safety perspective in transmission lines upstream from 

distribution lines and city gate metering and pressure regulation stations. 

As in any risk assessment, it is important to understand the conditions under which risks are 

being assessed. The GTI assessment presented here is based upon data specific to the U.S. 

natural gas supply system. Findings suggest that higher concentrations of hydrogen in 

distribution mains, up to 50%, present a minor increase in overall risk (including probability and 

severity). Risks associated with service lines are different because service lines are often found 

in confined spaces where leaked gas would be more likely to accumulate. If hydrogen 

concentrations exceed 20% in service lines, the increase in overall risk is more significant than 

for distribution mains. For both distribution mains and service lines, proper risk management 

practices, such as the installation of monitoring devices, reduces overall risk. However, adding 

more than 50% hydrogen to either distribution mains or service lines results in a significant 

increase in overall risk. Again, these risk results are associated with introducing hydrogen blends 

into the existing U.S. natural gas pipeline system and do not apply to new, dedicated hydrogen 

pipelines carrying pure hydrogen, which would be designed and managed differently than the 

existing natural gas pipeline system. 

Material Durability and Integrity Management

The durability of some metal pipes can degrade when they are exposed to hydrogen over long 

periods, particularly with hydrogen in high concentrations and at high pressures. This effect may 

be of concern for cases where hydrogen is injected at high concentrations into existing high-
ix

pressure natural gas transmission lines. The effect is highly dependent on the type of steel and 

must be assessed on a case-by-case basis. However, metallic pipes in U.S. distribution systems 

are primarily made of low-strength steel, typically API 5L A, B, X42, and X46, and these are 

generally not susceptible to hydrogen-induced embrittlement under normal operating conditions. 

At the pressures and stress levels occurring in the natural gas distribution system, hydrogeninduced failures are not major integrity concerns for steel pipes. For the other metallic pipes—

including ductile iron, cast and wrought iron, and copper pipes—there is no concern of hydrogen 

damage under general operating conditions in natural gas distribution systems. There is also no 

major concern about the hydrogen aging effect on polyethylene (PE) or polyvinylchloride (PVC) 

pipe materials. Most of the elastomeric materials used in distribution systems are also compatible 

with hydrogen. These topics are reviewed in Appendix A. 

Hydrogen blends can influence the accuracy of existing gas meters. The deviation of a gas meter 

with hydrogen blends varies with the meter design. This deviation was found to be acceptable 

based on the requirement for recalibration (less than 4%) when a gas mixture containing less 

than 50% hydrogen is being measured. It is anticipated that meters would not need to be tuned 

under low hydrogen blend levels (less than 50%) in natural gas (Appendix A). One of the 

remaining gaps in durability research is the need to study the potential impact of contaminants in 

hydrogen gas that might be introduced into the network. This would be an issue in cases where 

the hydrogen production system does not produce pure hydrogen. 

In most research programs, the focus of integrity management has been on transmission pipelines 

because of concerns at high operating pressures, up to 2,000 psi (139 bar), and the pipeline steels 

that are subject to hydrogen-induced cracking. Hydrogen can be carried by existing natural gas 

transmission pipelines with only minor adaptations to the current Integrity Management Program

(IMP) (Appendix A). The adaptations needed depend on hydrogen concentration and operating 

conditions of the individual pipelines. These are generally insignificant with concentrations up to 

50% hydrogen, but a detailed investigation for every case is mandatory and could result in the 

upper limitation on hydrogen concentration being reduced (Appendix A). 

Natural gas distribution systems are very different from transmission pipelines, and the integrity 

program for transmission pipelines does not apply to distribution systems. One important 

difference between distribution systems and transmission pipelines is location with respect to 

populated areas. The level of hydrogen that is acceptable for transmission pipelines may need to 

be reassessed for distribution systems in terms of the frequency and severity of fire or explosion 

in a highly populated area. In addition, the hazards arising from gas leakage in a distribution 

system may be more severe than in transmission pipelines, especially in a confined service area. 

The integrity management for distribution systems under hydrogen services may require a leak 

detector or a monitoring device or sensor. The maintenance costs for distribution systems under 

hydrogen service likely will increase because these systems will need to be inspected more 

frequently and likely will require additional leak detection systems. Florisson et al. (2010) 

outline general conclusions of detailed studies of both durability and integrity issues, and they 

estimate that modifications to existing integrity management practices may incur an additional 

10% cost increase due to hydrogen blends. 
x 

Leakage

Hydrogen is more mobile than methane in many polymer materials, including the plastic pipes 

and elastomeric seals used in natural gas distribution systems. The permeation coefficient of 

hydrogen is higher through most elastomeric sealing materials than through plastic pipe 

materials. However, pipes have much larger surface areas than seals, so leaks through plastic 

pipe walls would account for the majority of gas losses (Appendix A). Permeation rates for 

hydrogen are about 4 to 5 times faster than for methane in typical polymer pipes used in the U.S. 

natural gas distribution system. Leakage in steel and ductile iron systems mainly occurs through 

threads or mechanical joints. Leakage measurements from GTI for steel and ductile iron gas 

distribution systems (including seals and joints) suggest that the volume leakage rate for 

hydrogen is about a factor of 3 higher than that for natural gas (Appendix A). 

A calculation based on literature data for the permeation coefficient of hydrogen and methane in 

polyethylene (PE) pipes suggests that most gas loss would occur through the pipe wall, rather 

than through joints, in distribution mains smaller than 2 in. and operating at 60 psig (5 bar) or 

higher. Extending this calculation to the larger pipeline network suggests that use of a 20% 

hydrogen blend within the approximately 415,000 miles of PE pipes in the United States would 

result in a gas loss of about 43 million ft3

/yr, with about 60% of the losses being hydrogen and 

40% being natural gas (Appendix A). Though this estimate of gas loss is almost twice the total 

gas loss for systems delivering natural gas only, it is still considered economically insignificant.

As reference, this theoretical distribution main leakage rate (43 million ft3/yr) would be 0.0002% 

of the 24.13 trillion cubic feet of natural gas consumed in 2010 (EIA 2011). Furthermore, this 

calculation likely overestimates actual gas loss because the permeation coefficient taken from the 

literature is considered larger than those observed in experiments using pipe under actual 

operating pressures, especially at lower pressures. In general, hydrogen blends would slightly 

reduce natural gas leakage due to the higher mobility of hydrogen molecules, resulting in a net 

reduction in the greenhouse gas impact due to leakage. A calculation for the Dutch pipeline 

system, based upon experimentally derived permeation coefficients, predicts a gas leakage rate 

of 0.00005% with a 17% hydrogen blend (Haines at al. 2003). Further investigation and 

additional empirical data would be necessary to provide more accurate gas loss estimates

associated with hydrogen blends. 

Though gas loss from service lines is economically negligible, leakage into confined spaces may 

pose a safety risk. Gas leakage from elastomeric seals at joints in service lines may also increase 

the risk in confined spaces, and this topic warrants additional risk assessment. Further 

investigation into specific pipe and seal materials and systems can provide a basis to estimate gas 

leakage more accurately. This basis can be used to determine whether leakage in confined spaces 

might present a safety risk over time and the degree to which detection and monitoring devices 

may be required to manage risks. 

Downstream Extraction

Three gas-separation technologies that could be used to extract hydrogen from mixtures in 

natural gas pipelines have been reviewed: pressure swing adsorption (PSA), membrane 

separation, and electrochemical hydrogen separation (EHS, or hydrogen pumping). PSA units 

operating on low hydrogen concentrations, such as 20% mixtures, are feasible. However, these

units are sized for the impurities in the gas, so with low hydrogen concentrations, the PSA units 
xi 

become very large. PSA units appear to be economically practical only at pipeline pressure 

reduction stations (i.e., pressure regulation stations) where the pressure drop is synergistic with 

hydrogen separation. Without this drop in pressure, uneconomically large amounts of 

compression energy and compressor capital would be needed to reinject hydrogen-depleted gas 

back into a pipeline.

Membrane separation technologies work very efficiently with relatively high concentrations of 

hydrogen, and the purity of the hydrogen product gas can be very high with certain membrane 

technologies, as they can be designed for high selectivity. Most membrane technology 

applications recover bulk hydrogen from industrial facilities and do not require high purity 

levels. Some membrane technologies, however, can realize near 100% pure hydrogen. Dilute 

hydrogen poses a significant challenge for membrane technology. Recovery of hydrogen with 

lower concentrations requires a higher pressure differential across the membrane. This means 

that significant volumes of non-hydrogen gas need to be compressed to high pressures in order 

for the hydrogen to pass through the membrane. This type of technology may be best suited for 

high-pressure pipelines (transmission pipelines), where the gas in the pipeline is sufficiently 

pressurized to allow significant recovery of hydrogen. 

Electrochemical separation (also known as hydrogen pumping) is a more elaborate method for 

bulk hydrogen recovery. Two technologies are currently used: a Nafion-based membrane system

and a polybenzimidazole (PBI) system. Nafion-based pumps have been in development longer 

and are considered more technologically mature, but PBI is more desirable for several reasons. 

One is the lower compression requirement. For a 1,000-psi pipeline, both the product gas and 

hydrogen would come out at essentially 1,000 psi (minus specific process pressure drop).

However, while pressurization requirements are reduced, system complexity can be higher, and 

the technology is not as mature as PSA or some membrane technologies. Electrochemical 

pumping requires water to function, and addition of water involves a humidification system. On 

the other hand, pipeline gases have to be dry, so a water-removal system is required downstream. 

Of the three separation technologies considered, PSA is the most commercially ready. Because 

PSA is mature and cost information is available, NREL staff estimated the cost of PSA hydrogen 

extraction assuming conditions for a hydrogen mixture in a distribution natural gas pipeline. 

Capital cost estimates for the PSA unit are based on quotes and with reference to an Nth plant 

concept, which reflects a mature system that is functionally reliable in the field and has been 

produced in sufficiently high annual and cumulative quantities to have a capital (and unit) cost 

approaching the technology’s asymptotic lower cost limit. The cost estimate represents a future 

technology that may be available when hydrogen mixtures can be carried through natural gas 

pipelines, rather than current PSA technology. This report assesses only the cost of hydrogen 

extraction. The other costs (injection cost, hydrogen losses along the pipeline, underutilization 

during lag-in-demand seasons, analytical costs, etc.) are not accounted for here.

For a 10% concentration and 80% recovery factor, the estimated cost of hydrogen extraction by 

PSA from a 300 psi pipeline is $3.3–$8.3/kg hydrogen extracted, for a range of recovery rates of 

1,000–100 kg/day. For a 20% concentration and 80% recovery factor, the extraction cost is $2.0–

$7.4/kg hydrogen extracted, for the same range of recovery rates. These additional supply chain 

costs are high relative to a competitive hydrogen cost goal of $2–$4/kg for FCEV markets (Ruth 

and Joseck 2011). However, if hydrogen is extracted at a pressure-reduction facility, the high 
xii 

cost of recompressing the natural gas to the original natural gas pipeline pressure can be avoided. 

The resulting estimated extraction cost for a 10% concentration and 80% recovery factor is $0.3–

$1.3/kg, with the range resulting from economies of scale for a system size or recovery rate of 

1,000–100 kg/day (see Figure 18). These costs per kilogram are reduced by approximately 10% 

if the hydrogen concentration is increased to 20%. PSA extraction could therefore become a 

relatively small cost component of the total delivered cost of hydrogen if the extraction is done at 

a pressure-reduction facility. With major pressure reduction stations often located near large 

urban areas, downstream extraction could prove to be an economical delivery option. It has been 

estimated that there are 11,200–14,800 metering and pressure regulating stations with inlet 

pressures greater than 300 psig in the United States (see section 3.1), and 34,600–56,700 stations 

with inlet pressures between 100 and 300 psig. Approximately 23%–25% of the stations with 

inlet pressures greater than 300 psig are contained within vaults, which is typical for stations 

located near urban or suburban areas. Therefore, it is likely that several thousand high-pressure 

city gate stations are located in close proximity to large U.S. urban areas where natural gas is 

transferred from transmission lines to distribution lines, and many of these may be candidates for 

hydrogen extraction. 
xiii

Contents

Introduction ................................................................................................................................................. 1

Benefits of Blending ................................................................................................................................... 3

Lifecycle Assessment – Literature Review by GTI and NaturalHy ....................................................... 3

Renewable Gas Credit Trading Considerations...................................................................................... 3

Extent of the U.S. Natural Gas Pipeline Network..................................................................................... 4

Pipeline Type, Capacity, Miles, Size, and Materials.............................................................................. 4

Major U.S. Pipeline Corridors................................................................................................................ 8

Natural Gas Pipeline Capacity and Utilization....................................................................................... 8

Impact on End-Use Systems.................................................................................................................... 15

Safety.......................................................................................................................................................... 15

NaturalHy Safety Assessment .............................................................................................................. 15

Greenhouse Gas Programme Safety Assessment (IEA)....................................................................... 18

Gas Technology Institute Safety Assessment of Distribution Pipelines .............................................. 18

Material Durability and Integrity Management....................................................................................... 19

NaturalHy Studies Review of Durability ............................................................................................. 19

NaturalHy Studies Review of Integrity ................................................................................................ 19

Leakage...................................................................................................................................................... 20

NaturalHy Pipeline Leakage Assessment............................................................................................. 20

Greenhouse Gas Programme Pipeline Leakage Assessment................................................................ 20

GTI Steel and Ductile Iron Pipe Leakage Assessment......................................................................... 20

GTI Estimate of Gas Loss in U.S.-Grade Plastic Distribution Pipelines.............................................. 21

Downstream Extraction............................................................................................................................ 21

NaturalHy Membrane Studies Review................................................................................................. 21

Technologies for Extracting Dilute Hydrogen from a Pipeline............................................................ 21

Cost Estimate of Hydrogen Extraction from a Distribution Natural Gas Pipeline............................... 27

Summary and Recommendations ........................................................................................................... 30

References................................................................................................................................................. 32

Appendix A: GTI Subcontract Report to NREL “GTI Review Studies of Hydrogen Use in Natural 

Gas Distribution Systems” ................................................................................................................ 35
xiv 

List of Figures

Figure 1. General order of stringency conditions on hydrogen blends for appliances, safety, and 

material durability (Florisson 2009). ...............................................................................................2

Figure 2. Natural gas supply chain consisting of gathering lines, transmission lines, distribution 

mains, and distribution service lines. ...............................................................................................4

Figure 3. Annual mileage of pipe for four natural gas pipeline types (PHMSA 2012). ..................5

Figure 4. Pipeline material as a percentage of miles for gathering lines, transmission lines, 

distribution mains, and distribution service lines (PHMSA 2012). .................................................7

Figure 5. Pipeline material as a percentage of miles of all pipeline types (PHMSA 2012). ...........8

Figure 6. U.S. natural gas pipeline network in 2009 (EIA 2012). ...................................................9

Figure 7. U.S. natural gas pipeline compressor stations illustration (2008) (EIA 2012). ..............10

Figure 8. U.S. underground natural gas storage facilities (2007) (EIA 2012). ..............................11

Figure 9. Major U.S. natural gas transportation corridors (2008). ................................................12

Figure 10. Interstate natural gas supply dependency (2007) (EIA 2012). .....................................13

Figure 11. Interregional natural gas transmission pipeline capacity (2008 data) (EIA 2012). ......14

Figure 12. Risk to an individual per year as a function of distance from the pipeline. .................17

Figure 13. Risk to an individual per year by adding hydrogen to the natural gas pipeline: UK 

data. ................................................................................................................................................17

Figure 14. Simplified PSA arrangement. .......................................................................................22

Figure 15. Estimated cost of hydrogen extraction by PSA unit from 300 psi natural gas 

distribution pipeline (assumed hydrogen recovery factor is 80%). ...............................................29

Figure 16. Hydrogen extraction cost breakdown. ..........................................................................29

Figure 17. Breakdown of capital cost contribution to the hydrogen extraction cost. ....................30

Figure 18. Estimated cost of hydrogen extraction by PSA unit at the pressure-reduction facility 

(from 300 psi to 30 psi). .................................................................................................................30
1 

Introduction

Hydrogen can play an important role as an energy carrier in a sustainable, reliable, and cost-effective 

energy future. This report reviews key issues related to the concept of blending hydrogen into natural 

gas pipeline networks. Under appropriate conditions and at relatively low hydrogen concentrations, 

blending may require only minor modifications to the operation and maintenance of the pipeline 

network. The hydrogen blend component may be carried through to end-user systems, or the hydrogen 

could be extracted downstream and used in applications such as automotive or stationary fuel cells. In 

general, based on research to date, only minor issues arise with blends of less than 5%–15% hydrogen 

(by volume), depending on site-specific conditions and particular natural gas compositions. More 

significant issues must be addressed for higher blends in the range of 15%–50%, such as conversion of 

household appliances or an increase in compression capacity along distribution mains serving 

industrial users. Blends above 50% face more challenging issues across multiple areas, including 

pipeline materials, safety, and modifications required for end-use appliances or other uses. 

Hydrogen blending may prove to be a viable means of increasing the output of renewable energy 

facilities, such as wind farms, by providing a hydrogen storage and delivery pathway across a broad 

range of geographic locations. Given the large geographic scope and scale of the existing natural gas 

infrastructure, even very low blend levels (less than 3%–5%) could absorb very large quantities of 

otherwise curtailed or uneconomical wind or solar power. Blending renewable hydrogen with natural 

gas can improve the carbon intensity and sustainability of the final natural gas product delivered to 

consumers. Though this pathway requires additional analysis and research, and may be limited by sitespecific conditions, it appears to be viable in the near term. 

Blending may also prove to be a viable means of delivering hydrogen produced in remote locations 

and extracting the hydrogen downstream near end-use applications, such as FCEVs or stationary fuel 

cells. Hydrogen pipeline delivery is considered a cost-effective way to move hydrogen from its 

production location to end users, but only at large volumes and long distances. Moreover, the cost to 

construct a large-scale, dedicated hydrogen pipeline system is very high, and completion could take 

decades. Alternative delivery pathways will be employed during the early market growth phase. Some

early market pathways, such as tank trucks or onsite production, may endure alongside pipeline 

delivery in a mature hydrogen infrastructure. If hydrogen blending in natural gas with downstream 

extraction proves to be economically viable during the early market growth phase, it could prove to be 

viable in the long term as an additional mode of delivery. 

This report reviews seven key and interrelated issues related to hydrogen blending: 

1. Benefits of blending 

2. Extent of the U.S. natural gas pipeline network 

3. Impact on end-use systems

4. Safety

5. Material durability and integrity management

6. Leakage

7. Downstream extraction. 

The benefits of hydrogen blending and the extent of the U.S. natural gas pipeline network provide 

context for the concept of blending and are reviewed in Sections 2 and 3. The next three issues limit
2 

the blend fraction that might be found acceptable, in the general order of stringency indicated in Figure 

1; actual blend levels that might be found acceptable will be very location and system specific and will 

depend on a number of factors (Florisson 2009). The impact on existing end-use systems limits the 

hydrogen blend factor the most and is discussed first (Section 4). Safety is the next most limiting 

condition (Section 5). Pipeline material durability imposes fewer limitations than end uses or safety but 

is still an important consideration, especially for high-pressure transmission lines (Section 6). The 

issue of leakage is addressed in Section 7, and Section 8 discussed methods of extracting hydrogen. A 

simple cost analysis suggests that extraction at pressure reduction stations is likely to prove more 

economical than extraction along transmission lines. Though these issues are interrelated, they are 

presented separately for the sake of clarifying explanation. Section 9 provides a summary and 

recommendations. 

Summary of GTI Subcontract Report to NREL

The Gas Technology Institute (GTI) performed a literature review for NREL and assessed some 

aspects of blending hydrogen into the existing U.S. natural gas pipeline system. The full GTI report is 

included here as Appendix A. This review covers the major aspects of blending addressed by the 

European NaturalHy project (Florisson 2012).1 GTI also included additional literature sources on 

material performance in hydrogen environments and provided a scientific basis for assessing the 

durability and integrity of the existing pipeline infrastructure and potential gas leakage under hydrogen 

service.

Figure 1. General order of stringency conditions on hydrogen blends for appliances, safety, and material 

durability (Florisson 2009).

 

1 The goal of the NaturalHy Project is to determine the feasible conditions under which hydrogen produced from a 

centralized production site can be injected into high-pressure transmission pipelines and delivered to end users through 

distribution networks. The NaturalHy project, which was co-financed by the European Commission through the Sixth 

Framework Program for research, technology development and demonstration. spanned from 2004 to 2009, 

(http://www.naturalhy.net/). 

End-use Appliances

Safety

Pipeline materials

Acceptable

Blend Fraction
3 

Benefits of Blending

Lifecycle Assessment – Literature Review by GTI and NaturalHy

The potential benefits of adding hydrogen to natural gas have been addressed in the “NaturalHy 

Project-Work Package 1” through life cycle and socio-economic assessment. This study was led by 

Loughborough University (UK), and participants included COGEN Europe (Belgium), The Energy 

Research Centre (Netherlands), Instituto de Soldadura e Qualidade (ISQ) (Portugal), Planungsgruppe 

Energie und Technik GbR (Germany), SAVIKO Consultants Ltd. (Denmark), and Technische 

Universität Berlin (Germany). The details of this review can be found in Appendix A, Task 4.

In summary, the following are benefits of adding hydrogen to the natural gas network: 

• Overall benefits: significant reduction of greenhouse gas emissions if hydrogen is produced 

from renewable sources. 

• Hydrogen in automotive applications: potential benefits from reducing petroleum consumption 

and improving air quality by reducing sulfur dioxide, oxides of nitrogen, and particulate 

emissions. 

• Greening natural gas: when a hydrogen/natural gas mixture is used in existing appliances for 

heat and electricity generation. This benefit is similar to increasing the mix of renewable 

generation on the electricity grid in that it does not require significant changes in end-use 

equipment. 

A better understanding of the cost-benefit tradeoffs for blending in the U.S. natural gas pipeline 

system, as compared to the European assessment, would require significant additional analysis and 

investigation. 

Renewable Gas Credit Trading Considerations

Renewable natural gas is a very desirable feedstock. In California alone, state incentives for power 

generation offer $4,500/kW and $2,500/kW for fuel cell systems running on biogas and natural gas, 

respectively (self-generation incentive program – SGIP). However, California does not require the 

biogas to be directly used in a fuel cell system, but instead allows credit trading. For example, a water 

treatment plant that generates methane can choose to clean the methane and inject it in the gas pipeline 

system, generating certificates for producing renewable natural gas. These certificates can, in turn, be 

sold to a geographically remote entity that can apply the credits to classifying fossil natural gas as 

renewable. This entity can then use the gas in a fuel cell and claim credits as if the fuel cell were 

operating on renewable gas. Renewable methane in such trading is commonly valued at $12–

$14/MMBtu (GSE 2011). For example, renewable gas can be purchased by this means from Pacific 

Gas & Electric. A similar credit trading system is conceivable for renewable hydrogen blended into the 

natural gas system. 
4 

Extent of the U.S. Natural Gas Pipeline Network

This section reviews general characteristics of the U.S. natural gas pipeline network to provide context 

for the concept of blending hydrogen into natural gas pipelines. Additional analysis would be needed 

to draw more concrete and detailed conclusions about the technical and economic potential for 

hydrogen blending with respect to the large amount of information available on pipeline system 

materials, performance, operation, and regional markets. Advantages of the existing natural gas 

pipeline network include the following: 

• Broad geographic extent 

• Interconnectivity 

• High capacity

• Well-developed maintenance and control structure 

• Well-established safety procedures 

• Well-established grid management 

• Well-established operational strategies 

• Broad public acceptance.

Pipeline Type, Capacity, Miles, Size, and Materials 

Four general types of transmission lines are indicated in the supply chain schematic in Figure 2. 

Gathering lines bring natural gas from various sources to processing plants, typically high-volume and 

long-distance transmission lines deliver gas to the city gate, and two types of distribution lines—mains 

and service lines—deliver it to local consumers. Underground storage facilities, typically depleted 

natural gas caverns or salt domes, and large industrial consumers are connected directly to 

transmission lines. In terms of supply capacity, the U.S. transmission line system is supplemented by 

natural gas storage capacity to meet peak demand during the winter heating season, and the distribution 

pipeline system is sized for this peak demand (EIA 2012). 

Figure 2. Natural gas supply chain consisting of gathering lines, transmission lines, distribution mains, 

and distribution service lines. 
5 

The annual mileage for each of these pipeline types is shown in Figure 3, with gathering lines and 

transmission lines changing only slightly and both types of distribution lines experiencing relatively 

steady growth since 1980. For 2011, the U.S. Department of Transportation reports 1.23 million miles 

of distribution mains and 0.88 million miles of distribution services lines. In 2011, there were 19,662 

and 304,087 miles of gathering and transmission lines, respectively (PHMSA 2012). The network also 

includes 1,400 compressor stations and 400 underground natural gas storage facilities, most of which 

are depleted natural gas fields, oil fields, aquifers, and salt caverns (EIA 2012). These elements are 

indicated in the maps shown in Figures 6, 7, and 8. In 2010, natural gas provided 25% of all energy 

consumed in the United States (EIA 2011). This extensive infrastructure is a critical component of the 

U.S. energy system, comparable in scale to electricity and petroleum-based liquid fuels. 

Figure 3. Annual mileage of pipe for four natural gas pipeline types (PHMSA 2012). 

City gate stations with metering and pressure regulating equipment are relevant to the concept of 

blending hydrogen into natural gas pipelines. These stations are located where high-pressure 

transmission lines transfer gas to distribution systems (also called transmission-to-distribution custody 

transfer stations) and are therefore candidates for downstream hydrogen extraction. A study conducted 

by Radian International LLC for the U.S. Environmental Protection Agency and the Gas Research 

Institute estimated the number of metering and pressure regulating stations, as well as the number of 

stations with only pressure regulating equipment, in the United States in 1992 based upon data 

collected from eleven natural gas distribution companies (Campbell and Stapper 1996). The stations 

were categorized into four types according the inlet pressure (psig): >300, 100–300, 40–100, and <40. 

Gas pressures in the distribution lines were not specified, but it was noted that stations with inlet 

pressures less than 300 psig were more typical of stations located downstream from gate stations. This 

study estimated the total number of U.S. stations using a ratio of the number of stations of each type to 

the total miles of main distribution lines. Applying these same ratios to the total number of main 

distribution miles in 2011 results in an estimate of 14,800 stations with inlet pressures greater than 300 

psig, and 56,700 stations with inlet pressures between 100 and 300 psig. However, the 2010 

Greenhouse Gas Inventory (EPA 2012) estimates the number of stations based upon the ratio of total 
6 

gas consumption in 2010 and 1992, rather than the station per mile ratios. This approach (Weitz 2012) 

provides an estimate of 11,200 and 34,600 stations at >300 psig and 100–300 psig, respectively. These 

estimates may be considered a high and low range on the total number of stations within these pressure 

inlet categories. Stations with lower inlet pressures, less than 100 psig, are more numerous, ranging 

from 102,000 to 134,300 stations based upon these two estimation approaches. 

Nearly 100% of U.S. transmission pipelines are steel with diameters of 4–48 in. They typically operate 

at pressures of 600–1,200 psig (42–84 bar) and in some cases up to 2,000 psig (139 bar). 

Approximately 96% of all onshore and offshore transmission pipelines are steel, wrapped/coated and 

cathodically protected against corrosion. Details about transmission pipelines can be found in

Appendix A. The major U.S. natural gas transportation routes include 11 distinct corridors (Figure 9). 

The volume of gas delivered is proportional to the width of the routes. Five of them originate in the 

Southwest (1–5), four deliver natural gas to the United States from Canada (6–9), and the remaining 

two extend from the Rocky Mountain area (10–11). 

Material use in pipelines is indicated by pipeline type in Figure 4. Steel and polyethylene (PE) are the 

dominant materials (47% and 48%, respectively) in the natural gas distribution system. Main 

distribution pipes are typically 1.5–8 in. wide and made of either PE (48%) or steel (47%). Distribution 

service line sizes are typically 0.5–2 in. wide and made of either PE (63%) or steel (33%). Other 

materials include cast iron and various plastics (see Appendix A). The fraction of miles for all U.S. 

pipelines (gathering, transmission, and distribution) by material type is indicated in Figure 5. 

Distribution pipeline pressures are 0.25–60 psig (1.03–5.15 bar) and sometimes up to 100 psig (8 bar). 

A few distribution pipelines operate at pressures as high as 400 psig (29 bar). Distribution facilities are 

primarily located in populated areas. Distribution lines do not follow class locations, but most lines fall 

into Class 3 and Class 4 locations under transmission class location definitions.2 Distribution piping is 

frequently located in congested urban areas, typically under paved streets, highways, and other public 

right-of-ways or utility easements. Additional details about the U.S. natural gas distribution pipelines 

can be found in Appendix A. 

 

2 The following are class location definitions from the Code of Federal Regulations (GPO 2011). A “class location unit” is 

an onshore area that extends 220 yards (200 meters) on either side of the centerline of any continuous 1-mile (1.6 

kilometers) length of pipeline. A Class 1 location is: (i) An offshore area; or (ii) Any class location unit that has 10 or fewer 

buildings intended for human occupancy. A Class 2 location is any class location unit that has more than 10 but fewer than 

46 buildings intended for human occupancy. A Class 3 location is: (i) Any class location unit that has 46 or more buildings 

intended for human occupancy; or (ii) An area where the pipeline lies within 100 yards (91 meters) of either a building or a 

small, well-defined outside area (such as a playground, recreation area, outdoor theater, or other place of public assembly) 

that is occupied by 20 or more persons on at least 5 days a week for 10 weeks in any 12-month period. (The days and weeks 

need not be consecutive.) A Class 4 location is any class location unit where buildings with four or more stories above 

ground are prevalent.
7 

(a) Gathering lines (b) Transmission lines

(c) Distribution mains (d) Distribution service lines

Figure 4. Pipeline material as a percentage of miles for gathering lines, transmission lines, distribution 

mains, and distribution service lines (PHMSA 2012).
8 

Figure 5. Pipeline material as a percentage of miles of all pipeline types (PHMSA 2012).

Major U.S. Pipeline Corridors

The interstate pipeline grid consists of wide-diameter (20–42 in.), high-capacity pipelines. In 2007, 

more than 36 trillion ft3

 of natural gas were transported by the interstate pipeline system. Figure 10

shows interstate natural gas supply dependency, particularly designating states that are more than 85% 

dependent on the interstate pipeline network for their supply. Intrastate natural gas pipelines operate 

within state borders and link natural gas producers to local markets and to the interstate grid. Intrastate 

pipelines constitute about 29% of the total miles. Texas and California have the largest intrastate

pipeline systems in the nation. Intrastate and interstate pipelines are color coded in Figure 6. 

Natural Gas Pipeline Capacity and Utilization

Even though natural gas companies prefer to operate their systems as close to full capacity as possible, 

the average utilization rate seldom reaches 100% (EIA 2012). Figure 11 shows the interregional 

natural gas transmission pipeline capacity (2008 data). Utilization rates below 100% do not necessarily 

entail additional capacity availability, as some companies serve seasonal markets. Exceeding 100% 

capacity, while remaining within safety limits, is a technique used to temporarily raise pipeline 

throughput. This is achieved by secondary compression, line packing, or both. Average daily 

utilization rates also can be increased by integrating storage capacity into natural gas pipeline 

networks. 
9 

Figure 6. U.S. natural gas pipeline network in 2009 (EIA 2012).

From the U.S. Energy Information Administration (EIA), Office of Oil and Gas Division, Gas Transportation Information System. 

The EIA has determined that this informational map does not raise security concerns.
10 

Figure 7. U.S. natural gas pipeline compressor stations illustration (2008) (EIA 2012).
11 

Figure 8. U.S. underground natural gas storage facilities (2007) (EIA 2012). 
12 

Figure 9. Major U.S. natural gas transportation corridors (2008). 

The volume of gas delivered is proportional to the width of the routes. Five routes originate in the Southwest (1–5), four deliver natural gas to the 

United States from Canada (6–9), and the remaining two extend from the Rocky Mountain area (10–11). Source: EIA 2012. 
13 

Figure 10. Interstate natural gas supply dependency (2007) (EIA 2012). 

States that rely on the interstate delivery system for more than 85% of their natural gas consumption are shown in gray. Note: A state’s relative 

dependence on the interstate natural gas pipeline network for its supplies was determined by the ratio of natural gas consumed within the state in 

2007 to the amount of natural gas produced within the state. A state with no natural gas production was 100% dependent on the interstate natural 

gas pipeline network for its supplies. Source: Energy Information Administration, Form EIA176 “Annual Report of Natural Gas and Supplemental 

Gas Supply and Disposition” (EIA 2012).
14 

Figure 11. Interregional natural gas transmission pipeline capacity (2008 data) (EIA 2012). 
15 

Impact on End-Use Systems

Adaptation of end-use systems is required at higher hydrogen blend levels. NREL reviewed 

NaturalHy studies on the impacts for the end user that might be caused by adding hydrogen to 

natural gas pipelines (De Vries 2009). The study included an assessment of maximal hydrogen 

concentrations that required no or minor appliance adjustments. The study concluded that 

hydrogen concentrations up to 28% may safely be used with properly serviced existing domestic 

appliances. Long-term (more than 15 years from now) material compatibility of domestic 

appliances with hydrogen and natural gas mixtures is uncertain. For poorly adjusted appliances, 

no hydrogen blends would be acceptable (Florisson 2010). The natural gas composition in a 

given pipeline is an important consideration (Zachariah-Wolff et al. 2007). 

Haines et al. (2003) estimate the cost of upgrades—in the United Kingdom, the Netherlands, and 

France—with respect to sensor modifications required for a 3% blend ($430,000 to $470,000 for 

each country) and then the cost of modifying engine controls ($5.6 million in the United 

Kingdom, $30 million in the Netherlands, and no cost in France), medium-pressure transmission 

lines ($500–$850 million for each country), and domestic appliances ($170–$470 million for 

each country) for introduction of a 12% blend. 

NaturalHy recommended that the consequences of mixing hydrogen with natural gas for 

industrial combustion applications be considered case by case. Several restrictions might apply 

for stationary natural gas engines and modern gas turbines. The preferable operating regime of 

stationary gas engines does not favor hydrogen concentration variations. These devices will need 

to be modified or adjusted based on manufacturer specifications. Modern gas turbines have strict 

fuel specifications. Operation outside of these specifications will require modification or 

readjustment of control systems with manufacturer permission. Also, unexpected hydrogen 

concentration variations are unacceptable for gas turbines (Florisson 2010). 

Safety 

The safety review included publications of the NaturalHy Project (Florisson 2010) and the 

Greenhouse Gas R&D Programme (Haines at al. 2003) sponsored by the International Energy 

Agency (IEA). Also, GTI performed a quantitative risk assessment of conveying hydrogen via 

the current U.S. natural gas distribution system. The details of the review and risk assessment 

can be found in Appendix A, Task 4.2. 

NaturalHy Safety Assessment

The potential risks of transporting hydrogen using the existing natural gas pipeline network have 

been investigated by “NaturalHy Project in Work Package 2.” This work was led by 

Loughborough University (UK); Leeds University (UK); Commissriat a’ l’Energie Atomique 

(France); Shell Hydrogen; Health and Safety Executive (UK); and National Grid (UK). The 

NaturalHy Project assessed (through modeling and experimentation) three risks of adding 

hydrogen to natural gas, which are summarized in the following sections (Lowesmith 2009): 

• Gas buildup 

• Explosions in enclosures

• Risk from transmission pipelines. 
16 

Gas Buildup

The NaturalHy study examined gas buildup behavior in two experimental releases, one in a 

smaller household room and another in a larger room more typical of a commercial or industrial 

building. It was found that gas buildup behavior of blends was similar to that of pure natural gas. 

No separation of hydrogen from the mixture was observed. Increased flow rate resulted in higher 

gas concentrations, but to a lesser extent than anticipated due to buoyancy-driven ventilation 

generated by the release. In general, the steady-state concentration following a release is only 

slightly higher for blends of up to 50% hydrogen, but concentration increases become more 

significant for hydrogen blends greater than 70% (Florisson 2010; Lowesmith 2009). 

Explosions in Enclosures

Compared with explosions of pure natural gas in confined areas, the relative increase in the 

severity of confined vented explosions was modest for blends with less than 20% hydrogen. A 

more significant increase in overpressure, and therefore risk or damage, was observed for blends 

with more than 50% hydrogen. Vapor cloud explosion overpressure can be significantly reduced 

for higher hydrogen concentrations if ventilation is used or if the structural congestion causing 

confinement is reduced (Florisson 2010; Lowesmith 2009). 

Risk from Transmission Pipelines

Risk here is determined using the following general equation: 

Risk = Frequency of Pipeline Failure × Probability of Ignition × Consequences of the 

Fire

This risk can be estimated on an individual or societal basis. When defined as an individual risk, 

the result is the likelihood of a person becoming a fatality in a year. NaturalHy used a risk 

evaluation model to determine these values. For transmission pipelines, the risk factor was 

dominated by the rupture of the pipeline (Florisson 2009, p. 24). 

Compared to natural gas transmission pipeline explosions, there is a consistent tendency for the 

severity of the risk with hydrogen mixtures to shift spatially, increasing closer to the point of 

explosion and decreasing further from the point of explosion. This shift in the spatial extent of 

risk is increased for higher concentrations of hydrogen, as shown in Figure 12. For the large, 

high-pressure pipeline represented by results in Figure 12 (914 mm and 70 bar [1,000 psig]), the 

magnitude of risk to an individual per year declines for hydrogen blends at a distance of 265–400 

m and increases closer to the pipeline (0–275 m). The risk associated with explosion of a natural 

gas pipeline drops to zero at just over 400 m from the pipeline (Figure 12). However, adding 

25% hydrogen decreases this distance by about 25 m while slightly increasing risk closer to the 

pipeline. The important causal factor here is the more rapid dispersion of hydrogen mixtures, 

which results in lower concentrations at shorter distances and therefore reduced risk at the far 

edge of the hazard distance. For 50% and 75% mixtures, the hazardous distance is reduced by 

about 75 m and 100 m, respectively, and the increase in risk closer to the pipeline is more 

significant. Given this generic risk result for a transmission pipeline, site-specific risks would 

vary depending on the population density and distribution near the pipeline. As a reference, the 

area contained within a radius of 280 meters is roughly equal to the area contained between the 
17 

radii of 280 and 400 meters, which is where the probability of risk is reduced for higher 

hydrogen blends. 

This shift in the spatial extent of risk has been examined for multiple pipeline sizes (Figure 13). 

The figure compares the risk of explosion for various pipeline diameters with 100% natural gas 

and a blend of 75% natural gas and 25% hydrogen. The 508-mm pipeline is apparently at a lower

pressure than the other pipelines and therefore follows a different trend (Lowesmith 2009). The 

smaller-diameter pipelines have shorter hazardous distances, and the addition of 25% hydrogen 

reduces the hazardous distance while slightly increasing risk near the pipeline. This shift is quite 

small for a 25% blend. As mentioned above, for higher blends and specific pipeline segments, it 

would become more important to consider population density across the hazard distance to 

properly interpret the significance of this spatial shift in risk.

Figure 12. Risk to an individual per year as a function of distance from the pipeline.

Risk shown is individual risk: the likelihood of a person becoming a fatality in a given year. Source: 

Lowesmith 2009. Displayed with permission. 

Figure 13. Risk to an individual per year by adding hydrogen to the natural gas pipeline: UK data. 

Risk shown is individual risk: the likelihood of a person becoming a fatality in a given year. Source: 

Lowesmith 2009. Displayed with permission.
18 

Greenhouse Gas Programme Safety Assessment (IEA)

A review of the IEA report on hydrogen blending is provided by Haines et al. (2003). The study 

focuses on a blend of 25% hydrogen in natural gas and provides a general assessment of hazards 

associated with a matrix of six causes and six consequences. Notably, compared to the use of 

natural gas without a hydrogen component, hazards are increased in cases of fire resulting from 

unburned gas in the air and in the case of burns resulting from the use of gas and open fire in a 

device or heating appliance. Hazardous phenomena are reduced by blends in four other cases: 

explosion resulting from unburned gas in air, suffocation due to unburned gas in air, suffocation 

due to flue gas system (malfunction), and poisoning due to heated media (Haines et al. 2003). 

Ten other hazards are identified as being unchanged in terms of risk when adding hydrogen to 

natural gas. Note that the general claim of a reduction in risk posed by explosion due to unburned 

gas in air is somewhat at odds with the more specific claim of slightly increased overpressure 

resulting from confined vented explosions with 20% hydrogen blends reported by Lowesmith et 

al. (2011). This emphasizes the condition-specific nature of risk assessments and the limited 

degree to which general statements can be used to simplify a complex topic. 

Gas Technology Institute Safety Assessment of Distribution Pipelines

Distribution pipeline incidents typically result in a leak instead of a rupture because of their 

relatively low operating pressures (see Appendix A). According to 2007 data from the U.S. 

Department of Transportation (PHMSA 13), the following are eight major distribution pipeline

failure modes caused by leakage: 

• Corrosion 

• Material defect

• Natural force

• Excavation damage

• Other outside force

• Equipment malfunction

• Operation

• Other. 

GTI assessed the risk aggravation of adding hydrogen at various levels for these failure modes 

for distribution mains and service pipes. Detailed results are provided in Tables 13 and 14 in 

Appendix A. In summary, the GTI analysis suggests that adding hydrogen to the natural gas 

pipeline network increases risk posed by leakage. However, this increase is small for service 

lines at concentrations of less than 20% hydrogen, and the increase is moderate for distribution 

mains at less than 50% hydrogen (Appendix A). Again, many different factors influence risk 

estimates, and actual risks can vary widely from location to location. 
19 

Material Durability and Integrity Management

This section briefly notes reviews of pipeline material durability and integrity with the use of 

hydrogen and natural gas blends. Appendix A provides additional detail. Durability refers to the 

potential physical and chemical impact of hydrogen on pipeline materials, especially 

embrittlement of steel, and integrity management refers to the various practices conducted by 

pipeline operators to inspect, maintain and assess pipeline systems. These topics are discussed in 

the Executive Summary, and the sections below notes previously conducted reviews. 

NaturalHy Studies Review of Durability

Durability was studied in “NaturalHy Project-Work Package 3.” This investigation was led by 

GDF SUEZ (France), with participation by Commissariat à l’Energie Atomique (France), CMI, 

CSM, DBI Gas (Germany), DEPA, Ecole Nationale des Ingénieurs de Metz (France), Gasunie 

Technology & Assests (Netherlands), Institut Français du Pétrole, Istanbul Gas Distribution Co. 

Inc. (Turkey), Instituto de Soldadura e Qualidade (Portugal), StatoilHydro (Norway), TNO

Science and Technology (Netherlands), TOTAL (France), and Turkish Scientific and Technical 

Research Council. The details of this review can be found in Appendix A (Task 4.4).

In addition, the GTI report includes literature sources related to the effect of hydrogen mixtures 

on pipeline materials and equipment. The details of this review can be found in Appendix A

(Task 4.4).

NaturalHy Studies Review of Integrity

The need to upgrade the current IMP for transporting hydrogen and natural gas mixtures was 

investigated in “NaturalHy Project-Work Package 4.” The aim of this project was to provide a 

specification for an Integrity Management Tool (IMT) that allows the operator to modify the 

existing IMP for hydrogen service. The cost of the new IMP was also evaluated in this study. 

This work was led by DBI Gas (Germany), with participation by TNO Science & Industry

(Netherlands), Computational Mechanics BEASY (UK), GDF SUEZ (France), PII Ltd. (UK), 

Istanbul Gas Distribution Co. Inc. (IGDAS), N.V. Nederlandse Gasunie (Netherlands), Instituto 

de Soldadura e Qualidade (Portugal), Turkish Scientific and Technical Research Council, 

StatoilHydro (Norway), and TOTAL (France). The details of this review can be found in 

Appendix A (Task 4.5). Florisson et al. (2010) outline general conclusions of detailed studies of 

both durability and integrity issues, and they estimate that modifications to existing integrity 

management practices may incur an additional 10% cost increase due to hydrogen blends.

In the United States, the Pipeline and Hazardous Materials Safety Administration (PHMSA) has 

implemented integrity management requirements for hazardous liquid and gas transmission 

pipelines, but no similar requirements currently exist for non-hazardous gas distribution 

pipelines. In 2009, PHMSA published the final rule effective on February 12, 2010, to establish 

integrity management requirements for gas distribution pipeline systems. Operators are given 

until August 2, 2011, to write and implement the integrity program for distribution pipeline 

systems.

GTI reviewed the natural gas distribution systems and the 14 potential threats to the distribution 

systems identified by the American Gas Foundation through a survey of utility operators. GTI 
20 

reevaluated each threat for the conditions under which the systems transport hydrogen and 

natural gas mixtures. The details of this study can be found in Appendix A (Task 4.5). 

Leakage

Hydrogen is a much smaller molecule than methane, so its leakage rate through pipe walls and 

joints may be greater; it also causes economic and safety concerns because of the total gas loss. 

Leakage assessments include publications from the NaturalHy Project (Florisson 2012), which 

focuses on the permeability of plastic pipe materials, including PE and PVC; a report from the 

IEA Greenhouse Gas R&D Programme (Haines et al. 2003); and other relevant information for 

gas leakage in the natural gas distribution pipeline under hydrogen services. The details of this 

review can be found in Appendix A. The following sections summarize the findings. 

NaturalHy Pipeline Leakage Assessment

The NaturalHy Project investigated permeation gas loss from plastic pipes in Work Package 3. 

This work was performed by Gaz de France. 

PE80 Pipeline (10% Hydrogen)

The pressures tested were 58, 116, and 174 psig (5, 9, and 13 bar). Table 14 of Appendix A 

shows the permeation coefficients and gas losses for hydrogen and methane in a mixture of 90% 

methane and 10% hydrogen. The following are the findings: 

• The hydrogen permeation coefficient is four or five times higher than that of methane. 

• The permeation rate of methane and hydrogen increases with pressure. 

• The aging of pipelines has no apparent significant effect on permeation coefficients.

Polyethylene Disk Samples (20% Hydrogen)

A 20% hydrogen mixture at 58 psig (5 bar) was investigated for leakage (Haines et al. 2003). 

The leakage rates for methane and hydrogen from this blend under these conditions are 1.1 and 

2.3 L/km/day, respectively. For comparison, the permeability of pure methane under similar 

conditions is 1.4 L/km/day. 

Greenhouse Gas Programme Pipeline Leakage Assessment

The IEA Programme performed experimental measurements of the hydrogen permeation 

coefficient in plastic pipes at 68°F (20°C) (see Table 15 of Appendix A). The hydrogen loss for 

the Dutch natural gas distribution grid after 17% hydrogen was added is estimated at 0.0005% of 

the hydrogen transported and therefore was considered insignificant (Haines et al. 2003). 

GTI Steel and Ductile Iron Pipe Leakage Assessment

Hydrogen and natural gas leakage in steel or iron pipes primarily occurs through the threads or 

mechanical joints. The GTI study indicates that the volume leakage rate of hydrogen is three

times higher than that of natural gas. 
21 

GTI Estimate of Gas Loss in U.S.-Grade Plastic Distribution Pipelines

GTI reviewed U.S. studies on gas loss in plastic distribution pipelines (see Appendix A). The 

permeation coefficients of hydrogen and methane for the various plastic materials are shown in 

Table 16 of Appendix A. The hydrogen permeation coefficient in U.S.-grade plastic pipes is five

or six times higher than that of methane. GTI performed calculations on gas loss in U.S.-grade 

plastic pipes for pressures of 60, 3, and 0.25 psig (5.15, 1.22, and 1.03 bar). Results are shown in 

Table 17 of Appendix A. 

Distribution Mains (60 psig [5.15 bar])

Adding 20% hydrogen to natural gas in plastic pipes doubles the total gas loss (77 ft3/mi/yr). 

Higher concentrations aggravate this effect. 

Service Lines

Service pipelines operate at much lower pressure than distribution mains, so the gas loss is much 

less significant. For pure natural gas, the gas losses are 2.5 and 0.2 ft3

/mi/yr at 3 and 0.25 psig 

(1.22 and 1.03 bar), respectively. Even though a 20% hydrogen mixture doubles the gas loss in 

the service pipeline, it is still economically insignificant. 

Downstream Extraction

This section briefly notes the NaturalHy Project’s review of using membranes to separate 

hydrogen from hydrogen and natural gas mixtures. This is followed by a description of 

technologies used to extract hydrogen from hydrogen and natural gas mixtures and an estimate of 

the cost of hydrogen extraction. 

NaturalHy Membrane Studies Review

The NaturalHy Project focused on developing advanced hydrogen selective membranes for the 

separation of hydrogen from natural gas/hydrogen mixtures in Work Package 5 (Task 5.3–5.7). 

This work was led by the University of Oxford, with participation by the Norwegian University 

of Science and Technology and Compagnie Europeenne des Technologies del’Hydrogene. For 

details, see the GTI review of the NaturalHy membrane studies in Appendix A (Task 4.6). 

Technologies for Extracting Dilute Hydrogen from a Pipeline

The following sections describe hydrogen extraction technologies for hydrogen and natural gas 

mixtures of 5%–20%. While we are considering the extraction of hydrogen in high purity for 

transportation, we have to consider that this differs from traditional separations. Most hydrogen 

today is produced via steam methane reforming (SMR), where natural gas and steam are used to 

produce a hydrogen-rich stream via the following reaction:

CH4 + H2O  CO + 3H2 (reforming) 

CO + H2O  CO2 + H2 (shift) (1) 

CH4 + 2H2O  CO2 + 4H2 (overall)
22 

Pressure Swing Adsorption (PSA)

PSA is a well-established technology. The systems are typically produced in sizes of 50 Nm3

/h–

200,000 Nm3/h. In the above reactions, excess water is used to push the equilibrium to higher 

hydrogen conversion and discourage side reactions such as coking. The resulting gas mixture is 

dried by condensing excess steam prior to hydrogen extraction. The dry gas entering the PSA 

unit has the following approximate composition: 

 H2 = 75% 

 CO2 = 19% 

 CO = 3% 

 CH4 = 3% 

PSA operates on the adsorption isotherm principle. Every material has a characteristic 

correlation of surface adsorption of gases versus gas partial pressure. As gas pressure increases, 

the concentration of adsorbed (immobilized) species on the surface increases. For example, 

doubling the gas pressure may double the surface concentration of species. In PSA, highly 

porous packing materials are used. The materials are carefully chosen to adsorb non-hydrogen 

compounds at elevated pressure (150–300 psig). Multiple materials and layers of packing are 

typically used, which are tailored to the specific gas composition entering the bed. As reformate 

gas flows through the packed bed, CO2, CO, CH4, and other impurities are retained, while 

hydrogen passes through the bed. Once the packed bed is saturated, reformate flow is directed to 

a freshly regenerated bed, and the saturated bed is slated for regeneration. In the regeneration 

phase, the pressure in the vessel is reduced, thus allowing surface-adsorbed gases to go back in 

the gas phase. High-purity applications may also utilize hydrogen as a sweep gas to backflow 

any impurities from the bed. Figure 14 provides a simplified graphical layout of a PSA system. 

Figure 14. Simplified PSA arrangement. 

Notes: Bed A is being actively exposed to reformate. In this bed, all species but H2 are adsorbed (filtered), 

and H2 flows through at high pressure. Once this bed saturates with impurities, flow is directed to a fresh 

bed (B). Beds are regenerated by reducing the pressure to near-ambient levels and flowing small 

quantities of product gas to flush impurities.

300 psig: H2

300 psig: 

H2, CO2, CH4, 

5 psig: 

H2, CO2, CH4, CO

A B C
23 

The cost of PSA units falls into four areas: 

• Valving and flow controls 

• Vessels

• Packing materials

• Compressors. 

PSA technology is the industry standard and works best for high concentrations of hydrogen 

such as gas streams from conventional SMR production plants, which can be on the order of 

75% hydrogen. Many design factors impact a PSA bed embodiment. One important factor to 

consider is its size vs. level of impurities. The PSA packing layers have two general operating 

regimes. The upstream portion of the bed is typically saturated with gas during operation and 

does the bulk of the extraction. The downstream portion of the bed is the fine polishing section 

of the bed and reduces the concentration of impurities that break through with hydrogen. Thus, 

the size of the PSA bed is strongly impacted by the concentration of non-hydrogen species 

entering the bed. For example, if we double the concentration of impurities, a PSA bed would 

require nearly double the size of the saturation portion of the bed (bulk extraction). The impact is 

not quite double, as the material saturation point increases for many materials with higher 

impurity concentration. Additionally, more beds may be required for high concentration 

impurities. This is due to a higher regeneration period as well as higher temperature swings. 

As previously described, PSA units operate by pressure reduction. Gas is provided at high 

pressure, and impurities are removed at low pressure. In this technology, pressurization of 

impurities is strictly parasitic as the pressure is not recovered in the regeneration of the bed. As 

we consider lower concentrations of hydrogen, the concentration of non-hydrogen gas species 

increases. This means that we would compress larger quantities of gas to recover smaller 

quantities of hydrogen. For example, in the case of SMR, we would compress approximately 1.3 

parts of total gas per 1 part of hydrogen. However, if we consider purification of 10% hydrogen, 

we would compress 10 parts impurities per 1 part hydrogen. Thus, for equivalent inputs and 

outputs, our compression work would increase by seven times. 

It is notable that typical SMR systems often operate under pressure to avoid bulk gas 

compression. In such systems, natural gas is taken at pressure from a pipeline, and water is 

pressurized via liquid pumps (very low auxiliary power). Steam and methane are reacted at 

pressure to provide high-pressure gas to the PSA units. Hence, the PSA units operate using the 

pressure of the natural gas pipe and the low pressure of the burner of the SMR unit. This is 

analogous to conditions found at pressure reduction stations in a natural gas distribution network. 

In such locations, high pressure gas with potential hydrogen content is present. This gas is taken 

from transmission pressures as high as 1,000 psig, and pressure is reduced to lower distribution 

pressures. Gas can be introduced into PSA units at this point for hydrogen extraction, and the 

beds can be regenerated into the low-pressure distribution lines. 

For production of ultra-high-purity hydrogen, the PSA unit can be operated with more frequent 

cycling of the beds. In such a case, the recovery rate decreases in favor of higher purity product. 

High-purity hydrogen can also be obtained by a second-stage PSA, which recycles its waste gas 
24 

to the bulk PSA extraction of via other purification processes such as membrane purification for 

gas polishing. 

Membrane Separation

Membrane technology is another industry-practiced technology for hydrogen extraction and 

purification. This technology operates on the principle of selective permeation, by which random 

motion of molecules across a permeable membrane will equilibrate to equivalent partial 

pressures on each side of the membrane. For example, if one side of a membrane has 50% 

hydrogen at 1 atm of absolute pressure, and the opposing side has pure hydrogen, the pressure of 

the opposing side would be 0.5 atm. The equation for this equilibration would thus be: 

(2) 

The above equation is for an idealized system, in which the concentrations are equal on both 

sides. In such a system, the flux is zero, as there is no driving force for gases in either direction 

across the membrane. To support an appreciable flux, a differential partial pressure of hydrogen 

would be necessary. For example, the gas pressure of the pure hydrogen side may need to be 0.2 

atm, as this would give a driving force of 0.3 atm. 

Membrane separation technologies work very efficiently with relatively high hydrogen 

concentrations. The purity of product gas can be high at very low fractional recovery but 

monotonically decreases as recovery increases, as the relatively slower co-permeation of 

impurities proceeds to a greater degree. Most applications using membrane technology 

industrially recover the bulk hydrogen at 95%–99% purity. 

Palladium (Pd) membrane technologies can achieve hydrogen at 99.9999999% purity. At 

temperatures of approximately 752°F (400°C), Pd efficiently causes hydrogen molecules to 

dissociate on contact. The resulting protons dissolve into the metal. If the Pd is in the form of a 

thin membrane and a differential partial pressure is maintained across the membrane, the protons 

will migrate from the high-pressure side to the low-pressure side, where the protons recombine 

to form hydrogen atoms. As only hydrogen molecules exhibit this property, extremely pure 

hydrogen can be obtained from Pd membrane devices.

This technology is employed in the electronics industry to supply hydrogen with a total impurity 

load in sub-ppb range, and it is being increasingly used in the mobile power market and in 

renewable fuels research to provide fuel-cell-ready hydrogen from streams of reformate gas.

In practice, the Pd metal is alloyed with another metal to enhance the mechanical strength of the 

membranes. When copper is included, the resulting membrane can resist degradation by sulfurbearing compounds at concentrations in the ppm range. Pd micro-channel membrane purifiers 

would typically be employed in series with a PSA unit and would be used to remove 

contaminants (for example, CO) that may damage a fuel cell. Pd micro-channel membranes 

require a hydrogen partial pressure difference to drive the protons through the Pd metal. 

Typically, a partial pressure of 160–200 psi is optimal (PE 2012). 

Side A: Side B:

(Total pressure)*(mol fraction) = (Total pressure)*(mol fraction)
25 

Dilute hydrogen poses a significant challenge for membrane technology. For example, if 10% 

hydrogen is fed into a membrane separator, and 70% recovery is being considered, the outlet 

composition of the gas would be approximately 3%. This means that to support the flux of the 

outlet elements of the membrane, the pressure ratio would need to be at least 33:1. So, if 

ambient-pressure hydrogen is recovered, the pressure of the natural gas would need to be at least 

33 atm (500 psia). This is, again, an idealized scenario, and a significantly higher ratio than 33:1

would be needed to provide a driving force. 

Membrane technology for transmission pipelines may, however, be a good technology fit. Such 

pipelines often operate at pressures of about 1,000 psig, which provides sufficient driving force 

for hydrogen extraction. In such systems, the bulk of the process gas retains its pressure, and 

only a small amount of repressurization would be required to compensate for any device pressure 

drop. 

Electrochemical Hydrogen Separation (Hydrogen Pumping)

Electrochemical Hydrogen Separation (EHS) is a more elaborate method for bulk hydrogen 

recovery. It operates on principles in common with fuel cell systems, using fuel cell stacks and 

passing the process gas across one side of the stack. By applying a current across the stack, 

hydrogen is atomically dissociated from the process gas and is reassociated into hydrogen on the 

product side. This process operates with very low differential pressure between the process gas 

and the product gas. Two technologies are used for electrochemical separation: one is based on 

Nafion and the other on PBI. Nafion is the more mature technology, but PBI is more desirable 

because the phosphoric acid conditions provide chemical resistance to sulfur contamination and 

its lower sensitivity to hydration. 

PBI membranes require electrical potential to drive substantial current across the stack. As 

hydrogen concentration differs across the membrane, it needs to be compensated by applying a 

voltage. Additional voltage is necessary to drive activation, conduction, and diffusion 

resistances. In the presence of competing adsorption species such as H2S and CO, the diffusion 

resistance can increase significantly. This can, however, be balanced with operation at higher 

temperature (for example, 356°F [180°C]). The power required for EHS is a strong function of 

the partial pressure of the hydrogen and the total pressure of the product gas. Similar to fuel cell 

systems, the overpotential required for pumping hydrogen is penalized due to lower hydrogen 

concentrations. This is exhibited by dilute hydrogen streams requiring higher potentials than 

concentrated hydrogen streams. Additionally, resistive losses are proportional to the operating 

current density of the electrochemical separator. At high current density, more resistive losses 

are experienced. High current density is nevertheless desirable, as the size of the extraction 

hardware would be smaller and the purity of the resulting gas would be higher. Hydrogen purity 

is compromised at low current densities due to a constant rate of impurity diffusion across the 

membrane. At low current density, the diffusion of impurities such as CH4 would result in a 

larger fraction in the product. Temperature is another factor of operation. In PBI systems, CO

tolerance is accomplished after about 248°F (120°C); beyond that temperature, any CO content 

of the feed gas degrades performance as a diluent. 

EHS systems operating with PBI function with very small differential pressures. High 

differential pressures are a cause of acid migration in the membrane, which can inactivate the 

catalytic surfaces of the membrane. However, such a problem is not a major concern when 
26 

considering high-pressure pipelines such as transmission or distribution pipelines, which are on 

the order of 500 to 1,000 psig. Hydrogen would be extracted in such systems via EHS to 500 to 

1,000 psig. Subsequent gas polishing may be needed, and could be further accomplished with 

membrane separation as discussed in the previous section. Gas polishing of this type would have 

a relatively low pressure drop due to the high partial pressure of the feed gas. 

Electrochemical processes operating on phosphoric acid or proton exchange membrane (PEM) 

platforms require water to operate. Phosphoric acid (in PBI) is more tolerant to dry operation, but 

in the total absence of water it dehydrates to a solid form that is not ionically conductive. PEMs

require even more water to operate as the gas needs to be saturated at the operating temperature 

and pressure. Addition of water involves a humidification system, while pipeline gases have to 

be dry. Therefore, a water removal system would be necessary. Additionally, the membranes are 

susceptible to contamination from sulfur and ammonia. Sulfur is always present; ammonia is 

rarely seen. In cases of natural gas containing ammonia, an upstream gas separator may be 

required to remove species such as ammonia and sulfur. Of course, sulfur would also be 

reinjected in the gas downstream to provide odorization. It is also important to consider that PBI 

will also produce some phosphoric acid vapors (typically in the form of P2O5 or P4O10). These 

species are highly corrosive and need to be filtered out of the effluent gasses. This species is 

relatively easily trapped, however, due to its high reactivity. 

It is worth noting the additional potential functionality of proton exchange membranes (PEM). 

While phosphoric acid cannot support more than 2 psi of differential pressure, PEM systems can 

operate with differential pressure in excess of 1,000 psi. It is well within the state of the art to 

operate a PEM when pumping hydrogen from about15 psi to 1,000 psi. This can be 

advantageous with other upstream bulk separations (for example, PBI or a diffusion membrane 

system). In such a case, a PEM can operate in two functions:

• Electrochemical compressor

• High-purity filter. 

Electrochemical compression can be especially valuable at small scales where cost scaling 

factors for compressors become prohibitive. Unlike compressors, the scaling factor for 

electrochemical compression is much more linear with size. And because the membrane has few

moving parts and avoids fuel cell degradation drivers (catalyst oxidation and contamination), 

maintenance costs would likely be low. 

Sulfur and Constituent Considerations

In all the above technologies, sulfur and odorants would largely need to be removed before the 

process gas enters the purification equipment, and a scrubbing or hydrodesulfurization (HDS) 

application would be required. HDS may be the ideal technology, as hydrogen is already present 

in the feedstock. This technology offers a high density of sulfur capturing and a very low slip 

rate from the scrubber. Downstream, the gas would need to be reodorized by reinjection of 

mercaptans. This can be a significant hurdle. Deodorizing gas with 10% hydrogen and 70% 

recovery would mean that 33 parts of gas would need to be deodorized to recover 1 part of 

hydrogen gas. It is thus worth investigating in more detail which system type might have higher 

tolerance for sulfur. For example, the industry-standard HDS process typically operates at 600°F 

(316°C). This is not practical in a pipeline application. HDS would need a burner, recuperator, 
27 

and air cooler, with the burner consuming a significant amount of energy. More practical 

techniques may include metal-doped carbon, damp iron oxide systems, and methyl 

diethanolamine (MDEA) for large-scale units.

Another major consideration is double-bonded hydrocarbons (ethylene, propylene), which can 

readily polymerize on many process surfaces and make impermeable coatings. Such components 

are present in small concentrations in natural gas, and in some pipeline practices (such as 

propane peak shaving) they can account for more than 1% of the total gas composition. Injection 

of propane is also likely in case of hydrogen pipelines as heavy hydrocarbons may be used to 

increase the gas heat content due to it being lowered by hydrogen (Zachariah-Wolff et al. 2007). 

This is especially challenging for ambient-temperature sulfur-scrubbing technologies, although 

they are not a significant problem for polymer membranes or PSA. 

Oxygen is another constituent sometimes found in pipelines. It is more of an issue downstream 

from transmission pipelines. For example, gas appliances at high altitudes such as Denver, 

Colorado, operate more efficiently when premixed with air to compensate for the lower 

atmospheric oxygen. In this case, air is mixed in at the city gate and would not affect hydrogen 

transmission along the main line. Oxygen can also be introduced in rare instances such as peak 

shaving. For example, this is still encountered in areas in the Northeast during peak demands in 

cold winters. Again, this is typically performed downstream of any transmission line. As both 

hydrogen and oxygen react instantly on a catalytic surface, EHS would not be able to operate 

under such conditions. However, oxygen could also be a benefit by reacting with hydrogen to 

form water on the membrane surface. This water is beneficial as the membrane needs to be 

hydrated to operate, but is a hazard due to the associated exothermic reaction. As oxygen 

injection is a rather rare practice, system selection would be a function of local conditions. 

Cost Estimate of Hydrogen Extraction from a Distribution Natural Gas 

Pipeline

NREL performed a cost estimate of hydrogen extraction from a distribution natural gas pipeline 

employing PSA units. We used Directed Technologies, Inc.’s (DTI) PSA capital cost estimate 

(DTI 2011) and H2A (DOE 2012) economic assumptions to develop the extraction cost 

modeling. 

DTI’s capital cost estimate for PSA units is based on the Nth plant concept, which reflects a 

mature system that is functionally reliable in the field and has been produced in sufficiently high 

annual and cumulative quantities as to have a capital cost (and unit cost) close to its asymptotic 

limit. At low manufacturing volumes, capital costs are high due to relatively time-intensive 

manufacturing and assembly methods. As the manufacturing rate increases, more efficient 

production methods become economical, capital cost (per unit output) decreases, and unit cost 

decreases. At extremely high manufacturing rates, all possible cost improvements have been 

achieved, and production rates are increased only by replicating process machinery. At those 

levels, capital cost (per unit output) and unit cost flatten in relation to the manufacturing rate.

The Nth plant assumption affects the H2A cost computations in two ways. The primary effect is 

in the estimated value of plant capital cost. The capital cost used in the H2A computation should 

not pertain to the initial or “one off” cost of a system, but rather to a relatively mature system 

produced in high volumes. Blended into the capital cost estimate are factors such as bulk 
28 

discounts on material costs and low-cost manufacturing and assembly methods. These are made 

possible by serial production of the systems, efficient and streamlined business operations, and a 

lower profit margin consistent with a mature product that must be priced competitively.

We assess only the cost of hydrogen extraction here. The other costs (injection cost, hydrogen 

losses along the pipeline, capital cost increase caused by underutilization during lag-in-demand 

seasons, analytical costs, etc.) are not accounted for here. 

The estimated cost of hydrogen extraction by PSA from a 300-psi pipeline is shown in Figure 15. 

The hydrogen recovery factor from PSA is assumed to be 80%. For a 10% hydrogen 

concentration, the extraction cost is $3.3–$8.3/kg of hydrogen extracted, depending on the scale 

of extraction or recovery rate in kg/day, as shown in Figure 15. For a 20% hydrogen 

concentration, the extraction cost across the same scale of extraction drops to $2.0–$7.4/kg. The 

high cost of hydrogen extraction from a natural gas pipeline is largely due to high capital costs. 

For example, for a 10% hydrogen pipeline, the capital cost contribution to the levelized cost of 

hydrogen extraction is 61% (Figure 16), 66% of which is the cost of the compressor (Figure 17). 

Gas pressure at the PSA exit is about 2 atm (30 psi). If hydrogen is extracted from a pipeline at 

300 psi, the separated natural gas has to be recompressed back to the pipeline. Due to low 

concentrations of hydrogen, the amount of natural gas that has to be recompressed is high and 

requires a large compressor.

High recompression costs can be avoided if hydrogen is extracted at a pressure-reduction facility 

so natural gas does not need to be recompressed. Pressure differentials can vary between 

pressure-reduction facilities, but are often significant at the city gate where transmission lines 

feed into distribution lines. The hydrogen extraction cost for a 10% hydrogen blend under these 

circumstances is 6 to 11 times lower ($0.3–$1.3/kg of hydrogen extracted) depending on the 

scale of extraction or recovery rate in kg/day, as shown in Figure 18. These extraction costs were 

modeled for a pressure drop from 300 to 30 psi. Based on this significant cost reduction, it 

appears that hydrogen extraction from a natural gas distribution pipeline at a pressure-reduction 

facility will prove to be a lower-cost option, mostly due to the fact that natural gas exiting the 

PSA unit would require minimal or no recompression. 
29 

Figure 15. Estimated cost of hydrogen extraction by PSA unit from 300 psi natural gas distribution

pipeline (assumed hydrogen recovery factor is 80%). 

Figure 16. Hydrogen extraction cost breakdown.

Extraction by PSA unit from 300 psi natural gas distribution pipeline with 10% hydrogen added. The 

hydrogen recovery rate is 100 kg/day and the assumed hydrogen recovery factor is 80%. Cost items in 

the Other category include labor and O&M.

$0.0

$1.0

$2.0

$3.0

$4.0

$5.0

$6.0

$7.0

$8.0

$9.0

0 200 400 600 800 1000 1200

Cost of Hydrogen Extraction ( $/kg H2)

Hydrogen recovery rate (kg/day)

10% H2

20% H2

Capital

61%

Energy 

9%

Other

30%
30 

Figure 17. Breakdown of capital cost contribution to the hydrogen extraction cost. 

Extraction by PSA unit from 300 psi natural gas distribution pipeline with 10% hydrogen added. The 

hydrogen recovery rate is 100 kg/day and the assumed hydrogen recovery factor is 80%. Other Indirect 

Capital Costs include land, engineering and design, and permitting.

Figure 18. Estimated cost of hydrogen extraction by PSA unit at the pressure-reduction facility 

(from 300 psi to 30 psi). 

Assumed hydrogen recovery factor is 80%.

Summary and Recommendations

Blending hydrogen into natural gas pipeline networks at low concentrations has the potential to 

increase output from renewable energy production facilities in the near term. In the longer term,

blending may provide an economic means of hydrogen delivery when the hydrogen is injected 

upstream and then extracted downstream for use in fuel cell electric vehicles (FCEVs) or 

stationary fuel cells. This report reviews several studies of hydrogen blending and provides an 

PSA

11%

66%

23%

Compressor

OtherIndirect

Capital Costs

$0.0

$0.2

$0.4

$0.6

$0.8

$1.0

$1.2

$1.4

0 200 400 600 800 1000 1200

Cost of Hydrogen Extraction ($/kg H2)

Hydrogen recovery rate (kg/day)

10% H2

20% H2
31 

assessment specific to the U.S. natural gas pipeline system, included in Appendix A. The 

implications of hydrogen blending vary with the concentration of hydrogen. Relatively low 

concentrations of hydrogen, 5%–15% by volume, appear to be feasible with very few 

modifications to existing pipeline systems or end-use appliances. However, this assessment of 

feasibility will vary from location to location. Higher concentrations introduce additional 

challenges and required modifications. Preliminary cost estimates suggest that hydrogen could be 

extracted economically at pressure regulation stations. For a station with a pressure drop from 

300 to 30 psi, we estimate an extraction cost ranging from $0.3–$1.3 per kg hydrogen for a 10% 

hydrogen blend, depending upon the capacity and recovery rate. 

This report reviews seven key issues concerning blending hydrogen into natural gas pipeline 

networks: (1) benefits of blending, (2) extent of the U.S. natural gas pipeline network, (3) impact 

on end-use systems, (4) safety, (5) material durability and integrity management, (6) leakage, 

and (7) downstream extraction. These issues are interrelated, but are addressed separately for the 

sake of clarifying explanation. The first two issues place the concept of blending in context. 

Issues 3–5 impose restrictions on the acceptable level of hydrogen blending, with requirements 

for end-use systems imposing the greatest restrictions. 

Extensive recommendations for future work to better understand the potential costs and benefits 

associated with hydrogen blending have been proposed in other studies, particularly in the 

NaturalHy project funded by the European Commission (Florisson 2012). For additional work on 

the concept of blending renewable hydrogen into the U.S. natural gas pipeline system, we 

recommend the following: 

1. Research and analysis of the costs associated with modifying U.S. pipeline integrity 

management systems to accommodate different levels of hydrogen blending. 

2. Development of case studies assessing the pipeline system modifications required for 

specific U.S. regions at multiple hydrogen blend levels. 

3. Detailed assessment of the impact of hydrogen blending on U.S. end-use systems, such as 

household appliances and power production technologies (i.e., engines and turbines). 

4. Analysis of hydrogen blending in the near term (e.g., 5–10 years) as a means of 

economically increasing the output of renewable energy production facilities. 

5. Dynamic analysis of the role of natural gas and hydrogen storage in future scenarios 

where hydrogen blending is prevalent in the U.S. natural gas systems. 

6. Analysis of the role of hydrogen blending as a least-cost delivery option in the 

development of a hydrogen infrastructure for fuel cell electric vehicles. 

7. Consideration of hydrogen blending as a strategic option to increase the public benefit 

derived from the existing U.S. natural gas infrastructure, with a focus on long-term

implications for energy supply, energy security, integration of renewable natural gas, and 

greenhouse gas reductions. 
32 

References

Burgherr, P.; Hirschberg, S. (2008). “Severe Accident Risks in Fossil Energy Chains: A 

Comparative Analysis.” Energy (33); pp. 538-553. 

Burgherr, P.; Eckle, P.; Hirschberg, S. (2012). “Comparative Assessment of Severe Accident 

Risks in the Coal, Oil and Natural Gas Chains.” Reliability Engineering and System Safety 

(105); pp. 97-103. 

Castaneda, C.J. (1999). Invisible Fuel: Manufactured and Natural Gas in America, 1800-2000. 

New York: Twayne Publishers. 

Campbell, L.M; Stapper, B.E. (1996). Methane Emissions from the Natural Gas Industry, 

Volume 10: Metering and Pressure Regulating Stations in Natural Gas Transmission and 

Distribution. Radian International LLC, GRI-94/0257.27, EPA-600/R-96-080j. 

http://epa.gov/gasstar/documents/emissions_report/10_metering.pdf. 

DOE (2012). U.S. Department of Energy (DOE), Hydrogen Analysis (H2A) website: 

www.hydrogen.energy.gov/h2a_analysis.html. 

DTI (2011). Directed Technologies, Inc. (DTI), private communications. 

De Vries, H.; Florisson, O.; Thiekstra, G.C. (2007). “Safe Operation of Natural Gas Appliances 

Fueled with Hydrogen/Natural Gas Mixtures (Progress Obtained in the NaturalHy-Project).” 

Presented at the International Conference on Hydrogen Safety, September 11-13, San Sebastian, 

Spain. 

http://conference.ing.unipi.it/ichs2007/fileadmin/user_upload/CD/PAPERS/13SEPT/6.0.00.pdf. 

De Vries, H. (2009). NaturalHy Project, Final Presentation, October. www.naturalhy.net/. 

E.ON. (2011). “E.ON examines options for storing wind power in the German gas grid.” 

November 11, 2011. E.ON company website, Dusseldorf, Germany. Retrieved May 11, 2012: 

http://www.eon.com/en/media/news/press-releases/2011/11/11/e-dot-on-examines-options-forstoring-wind-power-in-the-german-gas-grid.html#. 

EIA (2011). “Annual Energy Review 2010.” U.S. Energy Information Administration (EIA). 

www.eia.doe.gov/emeu/aer/contents.html. 

EIA (2012). “About U.S. Natural Gas Pipelines.” U.S. Energy Information Administration. 

http://www.eia.gov/pub/oil_gas/natural_gas/analysis_publications/ngpipeline/index.html. 

EPA (2012). ANNEX 3 Methodological Descriptions for Additional Source or Sink Categories, 

U.S. Environmental Protection Agency, Annex to the Inventory of U.S. Greenhouse Gas 

Emissions and Sinks: 1990-2010. Report number EPA 430-R-12-001. U.S. Environmental 

Protection Agency. http://www.epa.gov/climatechange/ghgemissions/usinventoryreport.html. 

Florisson, O. (2009). “NATURALHY, an Overview.” Presented at the NATURALHY Final 

Public Presentation, November 19, Nederlandse Gasunie at Groningen, The Netherlands. 

Florisson, O. (2010). Preparing for the Hydrogen Economy by Using the Existing Natural Gas 

System as a Catalyst. NaturalHy project Report SES6/CT/2004/502661. 

http://www.naturalhy.net/docs/project_reports/Final_Publishable_Activity_Report.pdf. 

Florisson, O. (2012). NaturalHy website. http://www.naturalhy.net/. 
33 

GM (2010). “GM Looks to Hawaii for Hydrogen Infrastructure Pilot.” General Motors News, 

May 11, 2010. Retrieved May 12, 2011: 

http://media.gm.com/media/us/en/gm/news.detail.html/content/Pages/news/us/en/2010/May/051

1_hawaii.html. 

GPO (2011). Code of Federal Regulations: Title 49 - Transportation, Vol. 3, Section 192.5 - 

Class locations. October 1. http://www.gpo.gov/fdsys/pkg/CFR-2011-title49-vol3/xml/CFR2011-title49-vol3-sec192-5.xml. 

GSE (2011). Golden State Energy, private communication. 

Haines, M.R.; Polman, W.; de Laat, J.C. (2003). “Reduction of CO2 Emissions by Addition of 

Hydrogen to Natural Gas.” Presented at the 2004 Greenhouse Gas Control Technologies 

conference, Vancouver, Canada. http://www.ghgt.info/. 

Hirschberg, S.; Burgherr, P.; Speikerman, G.; Dones, R. (2004). “Severe Accidents in the Energy 

Sector: Comparative Perspective.” Journal of Hazardous Materials (11); pp. 57-65. 

Holdren, J.P.; Smith, K.R.; Morris, G. (1979). “Energy: Calculating the Risks (II).” Science 

(204:4393); pp. 564-568. 

Holdren, J.; Morris, G.; Mintzer, I. (1980). “Environmental Aspects of Renewable EnergySources.” Annual Review of Energy (5); pp. 241-291. 

Hydrogenics (2012a). “Hydrogenics Announces Agreement with Enbridge to Develop Utility 

Scale Energy Storage in North America.” Hydrogenics News Release, April 20. 

http://www.hydrogenics.com/invest/News_Details.asp?RELEASEID=666521. 

Hydrogenics (2012b). “Hydrogenics Wins Order from E.ON for ‘Power-to-Gas’ Energy Storage 

Project in Germany.” Hydrogenics News Release, June 1. 

http://www.hydrogenics.com/invest/News_Details.asp?RELEASEID=678878. 

IEA (2012). International Energy Agency, Greenhouse Gas R&D Programme website: 

www.ieaghg.org/. 

IGT (1972). A Hydrogen–Energy System. Institute of Gas Technology, report prepared for the 

American Gas Association, Catalog No. L21173, August. 

Jasionowsky, W.J. (1980). Study of the Behavior of Gas Distribution Equipment in Hydrogen 

Service-Phase II. Gas Technology Institute report.

Lowesmith, B. (2009). “Adding Hydrogen to the Natural Gas Infrastructure: Assessing the Risk 

to the Public.” NaturalHy Project, Final Public Presentation, November 19.

http://www.naturalhy.net/index.php?option=com_content&view=article&id=52:workshoppresentations&catid=35:workshop-presentations&Itemid=44. 

Lowesmith, B.J.; Mumby, C.; Hankison, G.; Puttock, J.S. (2011). “Vented Confined Explosions 

Involving Methane/Hydrogen Mixtures.” International Journal of Hydrogen Energy (36:3); pp. 

2337-2343. 

Melaina, M. (2012). “Market Transformation Lessons for Hydrogen from the Early History of 

the Manufactured Gas Industry.” Grasman, S.E., ed. Hydrogen Energy and Vehicle Systems. 

CRC Press (forthcoming). 
34 

PE (2012). Power & Energy company website: www.powerandenergy.com/h2purifiers-9000mzseries.html. 

PHMSA (2012). “Natural Gas Transmission, Gas Distribution, and Hazardous Liquid Pipeline 

Annual Mileage.” U.S. Department of Transportation Pipeline and Hazardous Materials Safety 

Administration. 

http://phmsa.dot.gov/portal/site/PHMSA/menuitem.ebdc7a8a7e39f2e55cf2031050248a0c/?vgne

xtoid=036b52edc3c3e110VgnVCM1000001ecb7898RCRD&. 

Polman, E.; de Laat, H.; Stappenbelt, J.; Peereboom, P.; Bouwman, W.; de Bruin, B; Pulles, C.; 

Hagen, M. (2003). Reduction of CO2 Emissions by Adding Hydrogen to Natural Gas. GASTEC, 

Netherlands, IEA Report PH4/24, October.

PSI (2012). “Comparative Risk Assessment and the ENSAD Database.” Paul Scherrer Institute 

(PSI). http://gabe.web.psi.ch/research/ra/. 

Ruth, M.; Joseck, F. (2011). “Hydrogen Threshold Cost Calculation, DOE Program Record # 

11007.” U.S. Department of Energy, March. 

http://www.hydrogen.energy.gov/pdfs/11007_h2_threshold_costs.pdf. 

Schmura, E.; Klingenberg, M. (2005). “Existing Natural gas Pipeline Materials and Associated 

Operational Characteristics.” Presented at the Annual Merit Review Meeting of the U.S. 

Department of Energy’s Hydrogen and Fuel Cells Program, Washington, D.C., May 23-26. 

Schneider, S.H. (1979). “Comparative Risk Assessment of Energy Systems.” Energy (4:5); pp. 

919-931. 

Tarr, J.A. (2004). “History of Manufactured Gas.” Encyclopedia of Energy (3); pp. 733-743. 

TGC (2012). The Gas Company, Honolulu, Hawaii. Company website: www.hawaiigas.com.

Weitz, M. (2012). “Current U.S. Inventory Methods and Key Areas for Updates, Distribution 

Sector.” Presented at the Stakeholder Workshop on Natural Gas in the Inventory of U.S. 

Greenhouse Gas Emissions and Sinks, conducted by the U.S. Environmental Protection Agency, 

September 13-14, 2012. 

http://www.epa.gov/climatechange/ghgemissions/Sept2012stakeholderworkshop/Agenda.html. 

Williamson, H.; Daum, A.; Klose, G.; Andreano, R. (1959). The American Petroleum Industry: 

The Age of Illumination 1859-1899. Evanston, Illinois: Northwestern University Press.

Wilson, D. (2012). “Power-to-Gas: Utility Scale Energy Storage.” Presentation to the Hydrogen 

Technical Advisory Committee, May 10. 

http://www.hydrogen.energy.gov/pdfs/htac_may2012_hydrogenics.pdf. 

Zachariah-Wolff, J.L.; Egyedi, T.M.; Hemmes, K. (2007). “From Natural Gas to Hydrogen Via 

the Wobbe Index: The Role of Standardized Gateways in Sustainable Infrastructure Transitions.” 

International Journal of Hydrogen Energy (32); pp. 1235-1245. 

Zhou, Z.; Ersoy, D. (2010). Review Studies of Hydrogen Use in Natural Gas Distribution 

Systems. Gas Technology Institute, Project Number 21029. Report to the National Renewable 

Energy Laboratory (Appendix A of the present report). 
35 

Appendix A: GTI Subcontract Report to NREL “GTI 

Review Studies of Hydrogen Use in Natural Gas 

Distribution Systems”
GTI PROJECT NUMBER 21029

Review Studies of Hydrogen Use in 

Natural Gas Distribution Systems 

Reporting Period: 

June 15, 2010 to Oct. 15, 2010 

Report Issued (Period Ending): 

Oct. 15, 2010 

Rev. No. 2: Dec. 16, 2010 

Prepared For: 

National Renewable Energy Laboratory 

Olga Sozinova 

Technical Monitor 

1617 Cole Blvd., Golden, CO 80401 

303-275-3755 

Olga.sozinova@nrel.gov 

 

 

Prepared By: 

Zhongquan Zhou 

Principal Investigator 

zhongquan.zhou@gastechnology.org

847-768-0901

Daniel Ersoy 

Project Manager 

daniel.ersoy@gastechnology.org

847-768-0663 

Gas Technology Institute 

1700 S. Mount Prospect Rd. 

Des Plaines, Illinois 60018 

www.gastechnology.org

FINAL REPORT
Page i 

Signature Page 

Print or typed

First M. Last Signature Date

AUTHOR:

Ms. Zhongquan Zhou 2010-10-14

Title:

Principal Investigator/Principal 

Engineer

REVIEWED BY:

Mr. Daniel Ersoy 2010-10-14

Title: Project Manager/R&D Director

APPROVED BY:

Mr. Daniel Ersoy 2010-10-14

Title: Project Manager/R&D Director
Page ii

Legal Notice 

This information was prepared by Gas Technology Institute (“GTI”) for National Renewable Energy 

Laboratory (NREL) (Contract Number: AEV-0-40629-01).

Neither GTI, the members of GTI, the Sponsor(s), nor any person acting on behalf of any of them: 

a. Makes any warranty or representation, express or implied with respect to the accuracy, completeness, 

or usefulness of the information contained in this report, or that the use of any information, apparatus, 

method, or process disclosed in this report may not infringe privately-owned rights. Inasmuch as this 

project is experimental in nature, the technical information, results, or conclusions cannot be predicted. 

Conclusions and analysis of results by GTI represent GTI's opinion based on inferences from 

measurements and empirical relationships, which inferences and assumptions are not infallible, and with 

respect to which competent specialists may differ. 

b. Assumes any liability with respect to the use of, or for any and all damages resulting from the use of, 

any information, apparatus, method, or process disclosed in this report; any other use of, or reliance on, 

this report by any third party is at the third party's sole risk. 

c. The results within this report relate only to the items tested. 
Page iii 

 Table of Contents 

Page 

Signature Page ............................................................................................................................ i

Legal Notice ................................................................................................................................ii

Table of Contents ....................................................................................................................... iii

Table of Figures ......................................................................................................................... vi

List of Tables ............................................................................................................................ vii

Executive Summary ....................................................................................................................1

Introduction .................................................................................................................................3

Overview – Natural Gas Distribution System in US .....................................................................5

US Natural Gas Pipeline Infrastructure ....................................................................................5

Comparison of Transmission and Distribution Systems ...........................................................5

Piping Materials of Distribution Network ..................................................................................5

Elastomeric Sealing Materials in Distribution Network .............................................................6

Operating Pressure of Distribution Network.............................................................................6

Typical Failure Mechanism of Distribution Pipelines ................................................................6

Locations of Distribution Infrastructure Facilities .....................................................................7

Safety Records .......................................................................................................................7

Task 4.1 – Life Cycle Assessment ..............................................................................................9

Life Cycle and Socio-Economic Assessment Literature [1] ......................................................9

Standard Procedures for Life Cycle and Socio-Economic Assessment [2] ..............................9

Overall Benefits of Adding Hydrogen to Natural Gas [2] ........................................................10

Summary on Life Cycle and Socio-Economic Assessment ....................................................10

Task 4.2 – Safety ......................................................................................................................12

Risk Assessment by NaturalHy Project (Work Package 2) [3] ...............................................12

The Impact on the Likelihood of Incident by Adding Hydrogen: ...................................................... 12

The Impact on the Consequence of an Incident by Adding Hydrogen: ............................................ 12

Risk Assessment: .......................................................................................................................... 13

Overall Safety Effect by Adding Hydrogen to Natural Gas Network (Greenhouse Gas 

Programme, IEA [11]) ...........................................................................................................13

Risk Assessment for US Natural Gas Distribution Systems under Hydrogen Service ............13

Summary and GTI’s Concluding Remarks on Safety.............................................................15

Task 4.3 – Leakage Assessment ..............................................................................................16

Assessment of Permeation Loss by NaturalHy Project (Work Package 3) [3, 18] ..................16
Page iv

Additional Information on Leakage Assessment ....................................................................17

Gas Leakage from Steel or Ductile Iron Systems [19]: ................................................................... 17

Gas Leakage from Plastic Pipes and Elastomers [11, 13, AGA handbook] ..................................... 17

Leakage Assessment by IEA Greenhouse Gas Programme [11] ............................................... 17

Estimation of Gas Loss for US Distribution Network................................................................... 17

Summary and GTI’s Concluding Remarks on Gas Leakage..................................................18

Task 4.4 – Durability .................................................................................................................20

Durability (NaturalHy Projects-Work Package 3) [8, 17, 18] ..................................................20

Hydrogen Affect on the Initiation and Growth of Defects in Transmission Pipelines ........................ 21

Hydrogen Permeation in Plastic Pipes in Distribution Network ....................................................... 21

Aging of Plastic Pipes in Hydrogen/Natural Gas Blends ................................................................. 21

The Reliability of Gas Meters for Hydrogen Services ..................................................................... 21

Additional Information for the Durability of Pipeline Materials under Hydrogen Services .......21

Hydrogen Damage of Metals ......................................................................................................... 21

Hydrogen Impact on Steel Linepipe ............................................................................................... 22

Hydrogen Embrittlement of Steel Pipe [11] ................................................................................ 22

Hydrogen Assisted Fatigue [13] ................................................................................................. 22

Enhanced Crack Growth on Existing Defects [11] ...................................................................... 22

Welding Requirements for Hydrogen Services [13] .................................................................... 22

Hydrogen Impact on Non-Metallic Materials ................................................................................... 22

Compatibility of Polymer Materials with Hydrogen [13] ............................................................... 22

Hydrogen Permeability in Plastics [11]....................................................................................... 23

Impact of Hydrogen on the Durability of Gas Meters [11] ............................................................... 23

Summary and GTI’s Concluding Remarks on Durability ........................................................23

Impact of Hydrogen on the Durability of Metallic Pipes in Distribution Systems .............................. 23

Impact of Hydrogen on the Durability of Plastic Pipes and Elastomers in Distribution Systems ....... 23

Impact of Hydrogen on the Durability of Gas Meters ...................................................................... 24

Task 4.5 - Integrity ....................................................................................................................25

Integrity Management Program for Transporting Hydrogen/Natural Gas Mixtures [4,5,6] ......25

Defects in Natural Gas Pipeline Systems and the Potential Impact by Hydrogen ............................ 25

Impact of Hydrogen on the Defect Criticality .................................................................................. 26

Inspection/Monitoring Tools and Inspection Intervals ..................................................................... 26

Cathodic Protection (CP) Integrity Management ............................................................................ 26

Repair Methods ............................................................................................................................. 26

Cost of the Integrity Management for Hydrogen Service ................................................................ 26

Additional Information for Distribution Pipeline Integrity under Hydrogen Services ................26
Page v 

Major Threats to Distribution Infrastructure .................................................................................... 26

Summary and GTI’s Concluding Remarks on the Integrity under Hydrogen Services ...........27

Conclusions in NaturalHy Project on Transmission Pipeline Integrity ............................................. 27

GTI’s Comments on Distribution Integrity....................................................................................... 28

Task 4.6 - End Use-Hydrogen Separation .................................................................................29

Development of High Selectivity Palladium-Based Membranes.............................................29

Development of Carbon-Based Membranes..........................................................................29

Carbon Molecular Sieves (CMS).................................................................................................... 30

A Mixed Matrix (MM) Material ........................................................................................................ 30

Development of Hybrid Membrane Separation System .........................................................30

Summary on Hydrogen Separation Technologies .................................................................30

Task 4.7 – Impacts (Environmental and Macroeconomic Benefits) ...........................................31

Conclusions ..............................................................................................................................32

References ...............................................................................................................................67

List of Acronyms .......................................................................................................................72

List of Acronyms .......................................................................................................................73
Page vi 

Table of Figures 

Page 

Figure 1. Schematic of the Natural Gas Delivery Pipeline Infrastructure* ..................................35

Figure 2. Piping Materials of Mains and Service Lines in Distribution Systems* ........................36

Figure 3. The Distribution of Pipe Size of Steel and PE Pipes in Distribution Mains* .................37

Figure 4. The Distribution of Pipe Size of Steel and PE Pipes in Service Lines*........................38

Figure 5. Statistical Data for Leak Incidents in Distribution Mains and Service Lines* ...............39

Figure 6. Incidents by Part of the Distribution System* ..............................................................40

Figure 7. Serious Incidents by Construction Materials of Mains* ...............................................41

Figure 8. Serious Incidents in Steel and Polyethylene Service Lines by Cause* .......................42

Figure 9. The Calculated Gas Loss Rate vs. Hydrogen Concentration in Hydrogen/Methane 

Mixtures at the Typical Distribution Operating Pressures (60 psig (4.1 bar), 3 psig (210 mbar) 

and 0.25 psig (17.2 mbar))*.......................................................................................................43

Figure 10. The Calculated Gas Loss from the Gas Mixtures Containing Different Levels of 

Hydrogen in Distribution System at 60 psig (4.1 bar) Operating Pressure .................................44

Figure 11. A Hybrid Separation Membrane System for Hydrogen Recovery* ............................45
Page vii 

List of Tables 

Page 

Table 1. Regulation Mandated Inspection of Gas Pipeline Facilities* ........................................46

Table 2. Pipe Sizes and Materials in Distribution Systems* .......................................................48

Table 3. Steel Grades for Distribution Pipelines and Their Material Properties* ........................49

Table 4. Elastomers in Natural Gas Distribution System* ..........................................................50

Table 5. Number of Leak Incidences by Causes for Distribution Mains and Services* ..............51

Table 6. The cause of Transmission and Distribution Incidents* ...............................................52

Table 7. Coverage of Technology Areas in the Literature Database* ........................................53

Table 8. Effect of Hydrogen Addition in Natural Gas on Gas Properties and Hazards* ..............54

Table 9. Ranking of the Hazards in Natural Gas Distribution Systems* .....................................55

Table 10. The Risk Factor a for Pipe Material Categories and the Overall Risk Factor b at Each 

Failure Modes in Distribution Mains ..........................................................................................56

Table 11. The Risk Factor a for Pipe Material Categories and the Overall Risk Factor b at Each 

Failure Modes in Service Lines .................................................................................................57

Table 12. Risk Assessment for Distribution Mains at Three Hydrogen Levels ...........................58

Table 13. Risk Assessment for Distribution Services at Three Hydrogen Levels .......................59

Table 14. The Permeation Coefficient and the Calculated Gas Loss from a 32 mm (1.26 ) PE80 

Pipe Under the Pressures of (58 psig (4 bar), 116 psig (8 bar) and 174 psig (12 bar))* .............60

Table 15. Permeation Coefficient (10-3×ft3-mil/ft/day/psig) of Hydrogen Gas for Plastic Pipe 

Materials at 20 C*.....................................................................................................................61

Table 16. Permeation Coefficient (10-3×ft3-mil/ft/day/psig) of Hydrogen in Plastic Pipe and 

Elastomeric Materials ................................................................................................................62

Table 17. The Calculated Gas Loss Rate (ft3/mile/year) Based on Literature Data for HDPE 

Pipes at the Operating Pressures of 60 psig, 3 psig and 0.25 psig* ..........................................63

Table 18. Classification of Hydrogen Degradation of Metals* ....................................................64

Table 19. Hydrogen Compatibility of the Plastics and Elastomers Used in Natural Gas Pipeline*

.................................................................................................................................................65

Table 20. Operator Perceptions on Threat Significance* ...........................................................66
Page 1 

Executive Summary 

There is an extensive natural gas pipeline network in the United States. Some studies suggest that it 

could be a viable solution for the early market to partially use existing natural gas pipelines to deliver 

hydrogen, mixing it with natural gas in certain proportions, and then separate and purify it for use by an 

end consumer. 

The existing natural gas pipeline networks include the gathering, transmission and distribution 

pipeline systems. It is considered that hydrogen can be injected into natural gas transmission pipelines and 

delivered to end users through distribution networks. As hydrogen and natural gas differ significantly in 

their physical properties, addition of hydrogen to the natural gas pipeline systems must be acceptable in 

terms of safety and integrity of the network. 

In order to assist the development of a delivery go/no-go decision on the use of existing natural gas 

infrastructure to transport hydrogen from production to end users, GTI performed this literature review 

for National Renewable Energy Laboratory (NREL) to provide the scientific basis and engineering 

assessment on some of the aspects related to adding hydrogen in natural gas distribution systems. The 

scope of this review covers the seven aspects that have been investigated in NaturalHy including “Life 

Cycle Assessment”, “Safety”, “Leakage Assessment”, “Durability”, “Integrity”, “End Use” and 

“Environmental and Macroeconomic Impacts”. 

In this study, GTI reviewed the available studies related to using the existing natural gas pipeline for 

hydrogen transportation. The primary focus was on the studies performed by the NaturalHy Project. GTI 

also provided a summary and discussion related to the use of the natural gas network for hydrogen 

service. This included analysis of the report from the Greenhouse Gas R&D Programme sponsored by the 

International Energy Agency (IEA) and related results from this study and other publications. The results 

from this study indicate that adding hydrogen into natural gas has beneficial effects on the environment 

by reducing greenhouse emissions and air pollutions. But there is not enough information from currently 

available literature sources to support benefits to the economy and employment. 

In addition to the report from the NaturalHy Project, GTI included additional literature sources on 

material performance in hydrogen environments. GTI provided a scientific basis for assessing the 

durability and integrity of the existing pipeline infrastructure and potential gas leakage under hydrogen 

service. The reviewed information finds that there is no major impact from hydrogen on the material 

integrity under natural gas distribution operating conditions. However, hydrogen leakage through plastic 

pipe materials and elastomers is much higher than methane, and this may becomes a safety concern in a 

confined space where accumulation of the gas may increase the likelihood and severity of a fire or 

explosion. 

GTI performed a quantitative risk assessment based on the current natural gas distribution system 

using the statistical data of US distribution system incidents, together with the survey results on the 

significant threats in distribution systems provided by utility operators. Using the risk of the system under 

natural gas service as a baseline, the overall risks at three hydrogen levels (<20%, 20 to 50%, and >50%) 

were assessed using the results from NaturalHy and other literature sources. 

Compared to the current situation with natural gas, the risks present by natural gas distribution 

systems are increased by adding hydrogen into the system. The impact depends on the hydrogen 

concentration in the gas mixtures. If less than 20% hydrogen is introduced into the distribution system, 

the overall risk is not significant, though having hydrogen in natural gas has more impact on the safety in 

service lines than mains. If the hydrogen level in natural gas increases beyond 20%, the overall risk in 

service lines can significantly increase and the potential hazards can become severe, while the overall risk 

in distribution mains still can be moderate up to 50%. For hydrogen level above 50% in natural gas, the 

risks in both distribution mains and service lines significantly increase, and the overall risk in distribution 

system becomes unacceptable. 
Page 2 

The study of the influence on pipeline integrity by adding hydrogen in the NaturalHy Project focuses 

on transmission pipelines. It cannot easily be applied to distribution systems because these systems are 

inherently different from transmission pipelines. The level of hydrogen that is acceptable for transmission 

pipelines may need to be reassessed for distribution systems in terms of the frequency and severity of fire 

or explosion in populated areas. 

In addition, the hazards arising from gas leakage in a distribution system can be more severe than 

with transmission pipelines, especially in a confined service area. The integrity management for 

distribution systems under hydrogen services may require the implementation of a leak detecting or 

monitoring device or sensor. Currently, there is no available odorant for hydrogen, and this remains a gap 

to be further investigated. 

It is likely that the maintenance costs for distribution systems under hydrogen service will be 

increased due to the needs for increased inspection frequency and leak detection. Since there is no 

existing integrity program for distribution system (although a new federal mandate is just being 

implemented), it is difficult to determine the stepwise maintenance cost of adding hydrogen. 

Currently, the membranes used for extracting hydrogen from hydrogen/natural gas mixtures are under 

development. It is indicated by a recent study that extracting hydrogen from the gas mixture will not 

adversely affect the downstream gas quality since the Wobbe index and heating value will not be outside 

statutory requirements. 

Electroless plated palladium membranes and carbon molecular sieves (CMS) are two promising 

technologies that are being considered for further development. Palladium membranes can provide high 

purity hydrogen, but they are expensive and have to operate at 300oC. CMS membranes are low cost and 

can operate at temperatures between 30oC and 90oC, but the maximum hydrogen content obtained using 

CMS membranes is 98%. The most promising future technique would be a hybrid separation system 

consisting of both palladium and CMS membranes. 

 
Page 3 

Introduction 

Hydrogen is considered as an important energy carrier in the future for sustainable, reliable and costeffective energy. As an energy carrier, hydrogen will provide a secure energy supply by utilizing locally 

available energy resources such as wind, solar, biogas, nuclear, etc. 

One of the main barriers to moving towards a hydrogen economy is developing a reliable and costeffective hydrogen delivery system. Compared with trucks and trains, pipeline transportation and 

distribution systems are considered as a safe, environmentally friendly and cost effective way to move 

hydrogen from its production location to its end users. However, the cost to construct a new widespread 

pipeline system for hydrogen delivery is huge and it may take decades to complete. 

A cost effective transitional hydrogen delivery system would be to use the existing natural gas 

pipeline network, which offers advantages such as being: (a) widely spread and interconnected, (b) very 

high capacity, (c) well developed maintenance and control structure, (d) well established safety 

procedures, (f) well established grid management and operation strategies, and (g) broad acceptance by 

the public. 

Because the physical and chemical properties of hydrogen are quite different from natural gas, the 

existing natural gas pipeline system is not suitable for delivery of pure hydrogen without significant 

modifications. However the existing natural gas pipeline system may be able to be used for cotransporting hydrogen with natural gas (i.e., a mixture) with no or minor modifications of the pipeline 

design, operation, and maintenance. This hydrogen/natural gas mixture could then be used in end user’s 

systems, given appropriate modifications of the appliances, or could be used as pure hydrogen by 

developing devices to extract hydrogen selectively from the mixture. 

Existing natural gas pipeline networks are made up of the gathering, transmission, and distribution 

pipeline systems. Hydrogen would be injected into natural gas transmission pipelines and delivered to end 

users through distribution networks. 

GTI performed a literature review for the National Renewable Energy Laboratory (NREL) to 

provide the scientific basis and engineering assessment on the potential for adding hydrogen to natural 

gas distribution systems. The review is broken down into seven (7) subtasks: 

Task 4.1: Life Cycle Assessment: 

The review in this task includes the major natural resource inputs and environmental outputs, 

socio-economic assessments of employment and economic costs for: (a) current natural gas and 

related energy systems, (b) transitional natural gas/hydrogen systems, and (c) future complete 

hydrogen systems. 

Task 4.2: Safety 

Review the impact of adding hydrogen on safety and the conditions under which the risk in 

natural gas pipeline systems is acceptable for transporting hydrogen in natural gas. 

Task 4.3: Leakage Assessment 

Review the gas leakage from the pipeline system and the effect that the addition of hydrogen 

might have on this leakage. 

Task 4.4: Durability: 

Review the durability of pipeline materials under hydrogen service at the operating conditions 

and potential hydrogen levels to be introduced into the system. Indentify potential concerns for 

pipeline safety and integrity from the impact of hydrogen on material durability. 
Page 4 

Task 4.5: Integrity: 

Review the potential impact of hydrogen on pipeline integrity. Also review the suitability of 

current integrity management program (IMP) for hydrogen service and the maintenance cost under 

hydrogen service. The distribution system is the focus of this task. The current situation of integrity 

management for distribution pipelines and the issues that may arise with adding hydrogen in natural 

gas are addressed in the review. 

Task 4.6: End use: 

Review the development of membranes for the efficient separation of hydrogen from a 

hydrogen/natural gas stream and the effect on the downstream gas quality after removal of hydrogen. 

Task 4.7: Impacts: 

Review the environmental and macroeconomic benefits of using the existing natural gas network 

to transport hydrogen. 
Page 5 

Overview – Natural Gas Distribution System in US 

US Natural Gas Pipeline Infrastructure 

The natural gas delivery pipeline infrastructure is divided into gathering, transmission, and distribution 

systems, see Figure 1. The distribution system consists of mains, service lines and meter set assemblies 

which comprise meters, regulators and other installations. 

Transmission pipelines are typically linear systems that transport gas over a relatively long distance. 

These systems have relatively few connections on the main lines. 

Distribution pipeline systems are arranged in a network to fit geographical configurations of the 

service area. There are many connections to the main lines. Networks can be designed in branch or tree 

configurations, be redundant or supplied by a single feed. Because of the interconnections, each section of 

pipe could receive its gas flow from more than one direction. A distribution system can be subdivided 

into pressure districts, where each district is operated at its own pressure level to ensure an adequate and 

reliable supply of gas to the area’s customers.

Comparison of Transmission and Distribution Systems 

Transmission pipelines traverse long distances and have few branch connections, predominately 

located in Class 1 and Class 2 locations as defined in 49 CFR Section 192.5. They are generally large 

diameter (up to 48 ) pipes and nearly 100% of the pipes are steel. Transmission pipelines typically 

operate at pressure levels between 600 psig (41.4 bar) and 1200 psig (82.7 bar), and in some cases up to 

2000 psig (137.9 bar) and the stress levels mostly exceed 20% of the specified minimum yield strength 

(SMYS) of the steel pipes. Over 96% of the total transmission mileage is wrapped/coated steel pipe that is 

cathodically protected. Approximately 3% of the total transmission mileage is bare steel with and without 

cathodic protection. Failure of transmission pipelines usually occur as a catastrophic rupture of the 

pipeline, caused by the high pressure of the contained gas. 

Distribution pipelines are generally small in diameter (as small as 5/8 ) and are constructed of several 

kinds of materials including a significant percentage of plastic pipes. Distribution pipelines also have 

frequent branch connections for service lines to individual customers. The dominant cause of distribution 

incidents is excavation damage with third party damage being the major contributor to these incidents. 

Distribution pipeline failures almost always involve leaks, rather than ruptures because the internal gas 

pressure is much lower than for transmission pipelines. 

Both distribution and transmission facilities are subjected to a variety of periodic inspections 

mandated by 49 CFR Part 192, see Table 1. The requirements are similar for both transmission and 

distribution systems with some exceptions. Odorants are required for distribution pipelines and 

transmission pipelines in populated areas. 

Piping Materials of Distribution Network 

Department of Transportation (DOT) 2007 Annual Distribution Data shows the piping materials used 

to construct mains and service lines in distribution networks (Figure 2 and Table 2). The natural gas 

distribution system in the US includes 1,201,000 miles of distribution mains and 64,804,000 service lines. 

Steel and polyethylene plastic pipes are the dominant piping materials in distribution systems. The 

majority of the steel pipes in distribution mains and service lines are coated and cathodically protected. 

Historically, distribution mains were primarily made of carbon steel pipe. Since the 1970s, a larger 

portion of the gas distribution main lines have been made of plastic, mostly polyethylene (PE) and 

sometimes polyvinyl chloride (PVC). PE pipes are increasingly being used to construct distribution 

pipelines and replace the aging iron and steel pipes in the low-pressure distribution system because of 

lower construction and maintenance costs. 
Page 6 

As shown in Table 2 and Figure 2, distribution mains are almost evenly divided between steel and 

polyethylene pipes which account for 47% and 48% respectively. Typical steel grades for the main 

distribution pipeline include A, B, X42, and X46, see Table 3 for their material properties [10]. Cast iron 

(CI) and wrought iron (WI) pipes only accounts for 3% of the mains. Many of the cast iron systems were 

installed over fifty years ago when they were originally used to transport town gas. These lines have been 

operated for many decades at pressures from 0.25 psig (17.2 mbar) to 60 psig (4.1 bar). There is also a 

small amount of ductile iron (828 miles) and copper pipes (36.5 miles) used for distribution mains. In 

addition to polyethylene pipes, PVC and Acrylonitrile Butadiene Styrene (ABS) are the other two plastic 

pipes used in distribution mains, accounting for 1.8% and 0.2% respectively. 

Distribution service lines are primarily made of polyethylene (63%) and steel (33%). The remainder 

consists of small percentages of copper (1.73%), cast and wrought iron (0.17%), PVC (0.4%), ABS 

(0.02%) and ductile iron pipes (0.001%). About 1.96% of the total service line pipes are not identified. 

The sizes of the typical distribution pipes are between 1.5" and 8" for mains and 0.5" to 2" for service 

lines. The distribution of the pipe size for steel and PE pipes in distribution mains and service lines is 

plotted in Figure 3 and Figure 4 respectively. A small percentage of distribution mains and services have 

a larger diameter pipe, typically for commercial and industrial application. 

Elastomeric Sealing Materials in Distribution Network 

Elastomers have been used as mechanical coupling seals and gaskets, meter and regulator 

diaphragms, boots, O-rings, flange seals, valve seats, etc. There are many types of elastomers and the 

formulation varies with the application. Table 4 lists the type of elastomers that have been used in natural 

gas distribution systems. Butadiene-Styrene (SBR) and Butadiene-Acrylonitrile (NBR) are the two major 

elastomers that have been used as gasket, O-ring, diaphragms, flange and quad seals in natural gas 

industry. 

Failure of elastomers could result in leaks. The major failure of elastomers comes from the chemical 

reaction between the elastomers and chemicals or the adsorption/permeation of the chemicals by the 

elastomers. This attack results in swelling and softening with a reduction of their tensile strength. The 

temperature and concentration of the chemical medium determines the degree of deterioration. The 

absorption and desorption of a gas medium during the change of gas compositions may result in 

permanent damage of the elastomers. 

Some elastomers can be degraded in outdoor conditions when they are exposed to sunlight, ozone, 

and oxygen. This type of degradation can cause surface cracking, discoloration, significant loss of tensile 

strength, elongation and other rubbery properties. 

Pure mechanical damage is not a frequent failure mode of elastomers. Most mechanical damage 

occurs as a result of chemical deterioration of the elastomer. When the elastomer is chemically 

deteriorated, it is more susceptible to mechanical damage. Elastomers become brittle when cooled below 

their glass transition temperature, and this can lead to brittle fracture of the elastomers. 

Operating Pressure of Distribution Network 

Distribution pipelines typically operate at pressures ranging from 0.25 psig (17.2 mbar, gas delivered 

directly to customers without any additional reduction in pressure) to 60 psig (4.1 bar) and sometimes up 

to 100 psig (6.9 bar). A few distribution pipelines operate at higher pressures of up to 400 psig (27.6 bar 

high pressure distribution pipelines). The stress levels of the steel pipes in distribution system are 

normally less than 10% of the Specified Minimum Yield Strength (SMYS). 

Typical Failure Mechanism of Distribution Pipelines 

Distribution pipeline incidents typically result in a leak instead of a rupture due to their relatively low 

operating pressures and the correspondingly lower operating stress. The primary safety concern is that if a 

leak goes undetected and the gas collects in a confined space, it can eventually ignite and causing an 
Page 7 

explosion. The total numbers of the leak incidences in distribution systems from the DOT 2007 annual 

report are summarized in Table 5. The data are plotted as a function of failure mode in Figure 5 . 

The exceptional case for distribution systems is “brittle-like cracking” in certain types of plastic pipe, 

which relates to crack initiation in the pipe wall, followed by stable crack growth, and eventual gas leak. 

Although significant cracking may occur at points of stress concentration, and near improperly designed 

or installed fittings, small brittle-like cracks may be difficult to detect until a significant amount of gas 

leaks out of the pipe and potentially migrates into an enclosed space. Premature brittle-like cracking 

requires relatively high localized stress intensification that may be the result of geometrical 

discontinuities, excessive bending, improper fitting assemblies, and/or dents and gouges. 

Locations of Distribution Infrastructure Facilities 

Distribution facilities are primarily located in populated areas. Distribution lines do not follow class 

locations, but the majority of the lines would fall into Class 3 and Class 4 locations under transmission 

class location definitions. 

Distribution piping is frequently located in congested urban areas, typically under pavement in streets, 

highways and other public right-of-ways or utility easements. 

Safety Records 

The incident data in the Office of Pipeline Safety (OPS) database reported by operators for the period of 

1990 through 2002 are summarized in Table 6 showing the causes of transmission and distribution 

incidents. During the period, there were a total of 957 transmission pipeline incidents and 1579 

distribution incidents. The causes of incidents are classified into five major categories: 

1. Corrosion 

2. Outside Forces 

First or second party damage; 

Third party damage; 

Earth movement (landslide/washout, subsidence, frost heave, earthquake, etc.); 

Lightning or fire; and 

Other 

3. Construction Operating Error 

4. Accidently Caused by Operator 

5. Other 

Outside force is the predominant cause of incidents for transmission and distribution pipelines, but it 

is more significant in distribution (60.4% of total incidents and 46.6% of serious incidents) than for 

transmission (39.8% of total incidents and 36.9% of serious incidents). Corrosion is a much more 

significant cause in transmission pipelines (23.4%) than in distribution pipelines (3.7%). The other 

category is a significant cause in both transmission (22.3%) and distribution (23.9%) pipelines. No 

additional information is available to further determine the cause of these “other” incidents.

Figure 6 shows the serious incidents categorized by system part in the distribution systems reported to 

OPS from 1990 to 2002. Most of the serious incidents are associated with the mains, followed by 

services, meter set assemblies and a category termed “Other” and “No Data”. 

The incident causes also vary with material of construction. Figure 7 shows the serious incidents 

categorized by construction materials in mains. The serious incidents in mains are primarily from 

polyethylene plastic pipes, steel, and cast iron pipes. These three materials are the most common pipe 

materials in distribution systems. Corrosion is an issue with steel systems, less so with cast iron and not at 

all with polyethylene. Third party damage is the dominant outside force category with all materials, but 

cast iron is subject to a higher proportion of incidents from earth movement. 
Page 8 

The principal materials of construction for service lines are steel and polyethylene plastic. Other 

materials make up such a small percentage of the piping and are considered negligible. As shown in 

Figure 8, outside force is the largest cause of serious incidents in service lines, 54% and 76% for steel and 

polyethylene service lines respectively. 

The dominant causes of failure for meter set assemblies are outside forces and “other”, with third 

party damage comprising most of the outside forces. No corrosion related serious incidents were reported 

for meter set assemblies during the study period from 1990 to 2002 [27]. 
Page 9 

Task 4.1 – Life Cycle Assessment 

Hydrogen is considered an important energy carrier for a sustainable energy future. Developing a 

reliable hydrogen delivery system would remove one of the main economic barriers of a hydrogen 

economy. Pipeline transportation and distribution systems are cost effective ways to move hydrogen from 

its production location to its end users. There is a potential to transport hydrogen using the existing 

natural gas pipeline network. The potential benefits of adding hydrogen to natural gas have been 

addressed in the “NaturalHy Project-Work Package 1” through life cycle and socio-economic assessment. 

This study was lead by University of Loughborough, and participants included by COGEN Europe; 

ECN - the Energy Research Centre; Instituto de Soldadura e Qualidade (ISQ); Planungsgruppe Energie 

und Technik GbR (PLANET); SAVIKO Consultants ApS; and Technische Universität Berlin. 

Life Cycle and Socio-Economic Assessment Literature [1] 

The complete life cycle consists of: 

The production of natural gas, related fuels, and hydrogen; 

The construction, operation, maintenance and decommissioning of relevant networks, and 

The utilization of natural gas, related fuels, natural gas/hydrogen mixtures and pure 

hydrogen. 

The life cycle assessment concentrated on primary energy inputs relevant to energy resource 

depletion, green house gas emissions associated with global climate change, and other gaseous, liquid and 

solid emissions related to acidification, ozone depletion and eutrophication. Social-economic assessments 

address direct and indirect job creation, maintenance, and the internal economic costs. 

A literature review was performed in this study to examine the existing work on relevant life cycle 

and socio-economic assessment. In total, 214 references were identified and 172 reviews were conducted. 

The coverage by technology and type of assessment is extremely diverse. Table 7 lists the technology 

areas in the literature database. 

The references on employment are very limited. Most of the studies were completed during the 

1970's and early 1980's and are currently considered outdated. 

Standard Procedures for Life Cycle and Socio-Economic Assessment [2] 

Standard procedures were established for calculating various environmental impacts, economic costs 

and employment implications of existing and possible future energy systems. The variables determined in 

the procedure for calculation include: 

Primary energy inputs as indicator of energy resource depletion; 

Greenhouse gas emissions associated with global climate change (carbon dioxide, methane 

and nitrous oxide); 

Pollutants affecting urban air quality (sulfur dioxide, oxides of nitrogen, and particulate); 

Internal economic costs; and 

Direct and indirect jobs in the European Union. 

The calculations for the existing natural gas network were used as a baseline scenario for 

comparison against the intermediate scenario with addition of hydrogen: 

1) Baseline Scenario 

Natural gas supply 
Page 10

Natural gas network construction 

Natural gas network operation 

Natural gas network decommissioning 

2) Intermediate Scenario 

Adjustment on gas leakage by adding of hydrogen 

Adjustment on Integrity Management Program for transporting hydrogen/natural gas 

mixture 

Hydrogen separation technologies 

Effect of hydrogen on end-user appliances 

Hydrogen production from different hydrogen generation technologies include: 

- Natural gas reforming without Carbon Capture and Storage (CCS); 

- Natural gas reforming with CCS; 

- Coal gasification with CCS; 

- Nuclear Power electrolysis; 

- Biomass; and 

- Wind power electrolysis. 

Overall Benefits of Adding Hydrogen to Natural Gas [2] 

The results from the calculation indicate some benefits of adding hydrogen to natural gas: 

1) Significant reduction of greenhouse gas emissions if hydrogen is produced from biomass, 

wind power, and nuclear power 

2) Some advantage on greenhouse gas emissions with hydrogen production from fossil fuels 

with CCS, but no benefits for decreasing primary energy demand or energy resource 

depletion 

3) Potential benefits of selective extraction of hydrogen (this depends on the performance of the 

separation technology and the subsequent use of the hydrogen and the residual gas) 

4) Potential benefits on improving air quality by reducing sulfur dioxide, oxides of nitrogen and 

particulate emissions if hydrogen is used in transportation and displaces conventional diesel 

fuel 

5) Potential benefit on “greening” natural gas if the hydrogen/natural gas mixture is used 

directly in existing appliances for heat production and electricity generation 

Summary on Life Cycle and Socio-Economic Assessment 

The results from this study clearly support the beneficial effects on the environment from adding 

hydrogen to natural gas including the reduction of greenhouse emission and the improvement of air 

quality. However, the published work supported by this study addressed to a lesser degree the economic 

evaluation and employment aspects, and no concluding remarks were made. 
Page 11

Hydrogen has been acknowledged as an alternative energy carrier in US National Energy Policy, and 

is considered to be a substitute for petroleum-based fuels in light-duty transportation vehicles. A welldeveloped hydrogen economy will make use of the lowest cost sources of hydrogen, and central station 

natural gas and coal are the two lowest cost hydrogen sources, followed by various electrolysis-based 

systems. This could significantly reduce green house gas emissions if carbon capture and storage 

technologies are used. Large scale hydrogen production plants will likely be built in the future and a 

national hydrogen transmission and distribution system would be a cost effective way to distribute large 

volumes of hydrogen over long distances. 

Currently, hydrogen is produced in a number of plants and is used primarily in the manufacture of 

chemicals and petroleum products. There are approximately 700 miles of hydrogen pipelines in US, 

which lie in the Gulf Coast region where large hydrogen refineries and chemical plants are concentrated. 

However, there are natural gas networks throughout the US. By utilizing the existing natural gas network 

for effective delivery of hydrogen in large volumes, there will be beneficial impacts on the society, 

economy, and environment. 

 

 
Page 12

Task 4.2 – Safety 

The existing natural gas pipeline networks are designed, constructed and operated for conveying 

natural gas. The safety of the pipeline system and the risk posed to the public by the supply and use of 

natural gas are well understood and considered acceptable. Hydrogen has different chemical and physical 

properties which may adversely affect the risk presented to the public. The major concerns of the impact 

on safety, by adding hydrogen in the existing natural gas pipeline systems, include the potential rupture of 

pipeline by hydrogen and the increased probability of gas ignition, and the risk of fire and explosion 

hazards in an incidental leakage of a hydrogen/natural gas mixture. 

GTI has reviewed the publications from NaturalHy Project and the Greenhouse Gas R&D Programme 

sponsored by International Energy Agency (IEA). The results from the above studies are used as a basis 

for ranking the severity of fire and explosion hazards in natural gas distribution systems at different 

hydrogen levels. 

In addition, GTI performed a quantitative risk assessment based on the current US natural gas distribution 

system for conveying hydrogen containing natural gas. The risk factors for the existing distribution 

systems operated with natural gas was defined with: (a) the statistical data of the fatal incidents occurring 

in US distribution systems from 1990 to 2002 together with, (b) the survey results on the significant 

threats in distribution systems provided by utility operators. The overall risks for natural gas service are 

used as a baseline to compare the risks when hydrogen is added into natural gas distribution systems. The 

overall risk in distribution systems is assessed at three hydrogen levels that have been investigated in the 

NaturalHy project and other related research programs. 

Risk Assessment by NaturalHy Project (Work Package 2) [3] 

The potential risks of transporting hydrogen using the existing natural gas pipeline network have been 

investigated by “NaturalHy Project in Work Package 2”. This work was led by Loughborough University, 

and Leeds University, CEA, Shell Hydrogen, UK HSE, and National Grid participated also.

The risk is a combination of the likelihood and the consequence (hazard) of an incident. The data and 

results from NaturalHy Project Work Package 3 and 4 on the durability and integrity of natural gas 

pipeline for transporting hydrogen/natural blends were used to aid the re-evaluation of the failure 

frequency of pipelines under hydrogen services. Laboratory scale and large scale experiments were 

developed to examine the consequence of fire and explosion situations pertinent to hydrogen/natural gas 

mixtures. Simple and Computational Fluid Dynamic (CFD) models were developed and validated using 

the experimental data, and the models were used to assess the impact of different level of hydrogen on the 

severity of the hazards which may arise from a wide range of accident scenarios. 

The Impact on the Likelihood of Incident by Adding Hydrogen: 

Failure frequency of pipelines is unchanged compared to that of natural gas pipelines with up to 50% 

hydrogen addition when an appropriate integrity management system is in place. The ignition probability 

is higher for hydrogen and natural gas mixtures due to the significant reduction in the minimum energy 

required for ignition and the increase in the upper flammability limit. 

The Impact on the Consequence of an Incident by Adding Hydrogen: 

The gas buildup behavior is similar in nature to natural gas. The concentration of the gas buildup is 

slightly higher with hydrogen addition of up to 50% in natural gas, but gas build up concentration 

significantly increase at hydrogen level above 50%, especially when the hydrogen addition is larger than 

70%. 

In a vented explosion, 20% hydrogen addition made little difference on the explosion severity, but 

50% or higher hydrogen additions will increase the severity. 
Page 13

In an event of gas buildup in a confined space, the explosion severity increases moderately up to 30% 

hydrogen addition, but it significantly increases for 40% or more hydrogen addition. Fire hazard slightly 

decreases with hydrogen addition. 

Risk Assessment: 

A risk assessment tool (LURAP) was produced, based on the analysis of likelihood and consequence, 

to calculate the risk at different levels of hydrogen in natural gas. It was found that adding hydrogen in the 

natural gas pipeline increases the risk to an individual at location near the pipeline, but decreases the 

extent of the hazardous region. 

In addition, the risk assessment of the expected background level leakage from the pipeline network 

indicates that the level of leakage overall is very small and poses no hazard from a safety standpoint. 

Overall Safety Effect by Adding Hydrogen to Natural Gas Network (Greenhouse Gas 

Programme, IEA [11]) 

The potential change of gas properties by adding hydrogen up to 25% in natural gas and the resulting 

impact on the hazards have been assessed relative to the use of standard natural gases in this study, and 

the results are summarized in Table 8. Based on this assessment, adding hydrogen up to 25% increases 

the explosion risk in a confined room and the probability of a fire. It is concluded in this study that the use 

of hydrogen blended natural gas under well regulated circumstances should not increase the risk of 

explosions in comparison to those with unblended natural gas. 

Risk Assessment for US Natural Gas Distribution Systems under Hydrogen Service 

The potential risks posed to the public by natural gas distribution pipelines are generally assessed by the 

probability of pipeline failure and the consequence of the failure, i.e.: 

Risk = Probability * Severity (1) 

The major failure mode in natural gas distribution pipelines is by leak, and the statistical data published 

by DOT in the 2007 annual report are categorized into eight failure modes for the leak incidences (see 

Table 5):

1) Corrosion 

Leak resulted from corrosion is one of the failure modes in distribution system. It includes the 

external corrosion from bare steel pipes, coated/wrapped steel pipes and cast iron pipes, and internal 

corrosion. The leak from corrosion defects in distribution system can result in the gas buildup in a 

confined area and create a hazard of fire or explosion. 

2) Material Defect 

Manufacture related defects are one type of material defects for pipes. These include defective 

materials, pipe, pipe seam or piping components, etc. The other type of defects are related to 

construction, such as defective pipe girth welds, defective fabrication welds, stripped threads, broken 

pipes or couplings for steel pipe, and defective fusion, installation error, and improper back fill for 

plastic pipes. 

This type of failure can result in slow release of gas and will pose fire or explosion hazard if the 

leak occurs in a confined space. 
Page 14

3) Natural Force 

Natural force includes the forces that are applied to the pipeline from earth movement in the 

event of landslide/washout, subsidence, frost heave, earthquakes, etc. Natural force can result in 

severe damage of the pipeline and significant release of gas. 

4) Excavation Damage 

This is the damage of pipes during excavation which normally result in a leak or in rupture of 

the pipeline. 

5) Other Outside Force

This is the damage from the outside force other than natural force or excavation. 

6) Equipment Malfunction 

This failure results from equipment malfunction, such as gasket or O-ring failure, control/relief 

equipment malfunction, seal failure, piping component failure, etc. 

7) Operation 

This is the failure from incorrect operations, e.g., the operator doesn’t follow correct operational 

procedure. 

8) Other 

This includes the failure modes that don’t fall into any of the above categories.

Table 5 and Figure 5 show the percentage of the leak incidents from each failure mode in distribution 

mains and service lines. Corrosion and excavation are the two frequent leak incidents. In view of adding 

hydrogen into the distribution system, the likelihood of each failure mode will not be significantly 

changed. However, the possibility and severity of a fire or explosion can be increased by the presence of 

hydrogen in natural gas. 

The hazards of fire or explosion in natural gas distribution systems are ranked into six levels (no 

hazard (0), minor (10), minor to moderate (20), moderate (30), moderate to severe (40) and severe (50)) 

based on the risks posed to the public by pipeline failure, see Table 9. For each category of pipe materials 

in distribution main and service lines, the hazards are assessed on the eight failure modes based on the 

incident data from OPS database and the survey results on the significance of the threats in natural gas 

distribution pipelines provided by utility operators (see Task 4.5) [27]. 

The risk factors for the five material categories are defined using the ranking in Table 9 for each 

failure mode and shown in Table 10 and Table 11 for distribution mains and service lines respectively. 

The last column in Table 10 and Table 11 is the overall risk factors for each failure mode presented by 

natural gas, and it is calculated by the sum of the risk factor of each type of material times the percentage 

of this type of material in the system, i.e.: 

RFOverall = ∑(i=1 to 5) [RFi * Pi] (2) 

RFoverall: the overall risk factor 

RFi: risk factor for each material category (total of five categories) 

Pi: percentage of each type of material in distribution mains or service lines 

The overall risks for each failure mode in Table 10 and Table 11 are further assessed for 

hydrogen/natural gas mixture at three hydrogen levels (< 20%, 20 to 50% and > 50%). These three levels 
Page 15

are identified based on the studies in NaturalHy and other literature sources that have investigated the 

influence of hydrogen concentration on the occurrence of fire or explosion by hydrogen/natural gas 

mixtures and the severity of the hazards. 

In distribution mains, most of the pipelines are considered as in the vented condition. Adding 

hydrogen in the natural gas will increase the gas buildup near the pipeline, but the change of gas buildup 

behavior is slight for hydrogen up to 50%. The hazard resulted from slow release of gas, such as the gas 

leak from corrosion or manufacture defects are not significantly increased by adding up to 20% hydrogen 

in natural gas, but it will be significantly increased at higher hydrogen level, especially above 50% 

hydrogen. In the case of pipeline failure by outside forces such as excavation damage or natural force, the 

explosion hazard is increased with the presence of hydrogen, and the risk factor is significantly increased 

at hydrogen level above 50%. Table 12 and Table 13 show the influence of hydrogen on the risk factor 

(for mains and services respectively) of each failure mode and the overall risks at the three levels of 

hydrogen concentration. The overall risk calculated using Equation (1) indicates that the overall risk in 

distribution mains is increased by adding hydrogen in natural gas. The increase of the risk is moderate by 

adding up to 50% hydrogen, but the increase becomes significant when more than 50% hydrogen is 

added. 

On the contrary to distribution mains, many of the pipelines in distribution services are in the 

confined space, such as within the building area. The leaked gas cannot be vented quickly and the gas 

buildup in the confined space will increase the possibility of a fire or explosion. Adding hydrogen in 

natural gas increases the risk factors for all the failure modes in service pipelines. The overall risk is 

significantly increased at all hydrogen levels, and it becomes severe at hydrogen levels above 20% as 

shown in Table 13. 

Summary and GTI’s Concluding Remarks on Safety

GTI performed a quantitative risk assessment on US natural gas distribution systems for carrying 

hydrogen containing natural gas. The risk analysis is based on the research findings from NaturalHy and 

other studies related to the influence of hydrogen on the potential risks posed to the public by transporting 

hydrogen in the existing natural gas network. The statistical data of the fatal incidents occurring in US 

distribution systems from 1990 to 2002 together with the survey results on the significant threats in 

distribution systems were used to define the baseline risk factor for each failure mode under natural gas 

service. The influence of hydrogen were assessed based on the research findings from NaturalHy and 

other studies, and the risk factors defined for each failure mode at three hydrogen levels that have been 

investigated in the literature. 

Compared to the current situation with natural gas, the risks present in natural gas distribution 

systems are increased by adding hydrogen into the system. The impact depends on the hydrogen 

concentration in the gas mixtures. If less than 20% hydrogen is introduced into distribution system, the 

overall risk is not significant. But the service lines are more critical than distribution mains because they 

are mostly installed in the confined spaces. In this case, adding hydrogen in the gas increases the 

explosion risk in the event of a gas leak. If the hydrogen level in natural gas increases beyond 20%, the 

overall risk in service lines can significantly increase and the potential hazards can become severe, while 

the overall risk in distribution mains still can be moderate up to 50%. For hydrogen level above 50% in 

natural gas, the risks in both distribution mains and service lines significantly increase compared to the 

situation with natural gas, and the overall risk in distribution system becomes unacceptable. 
Page 16

Task 4.3 – Leakage Assessment 

Because of the smaller molecular size of hydrogen, the leakage rate of hydrogen though pipe wall and 

joints may be larger than methane, and result in economic and safety concern of the total loss of gas. GTI 

has reviewed the publications from NaturalHy Project which mainly focus on the permeability of plastic 

pipe materials including polyethylene (PE) and polyvinyl chloride (PVC). GTI also reviewed the report 

from IEA Greenhouse Gas R&D Programme and other relevant information for gas leakage in the natural 

gas distribution pipeline under hydrogen services. 

Assessment of Permeation Loss by NaturalHy Project (Work Package 3) [3, 18] 

Permeation loss of gas from plastic pipes has been investigated by “NaturalHy Project in Work 

Package 3”. This work was performed by Gaz de France. In this investigation, real pipes and assemblies 

were tested at the operating temperatures and pressures with hydrogen/methane mixture in order to more 

precisely evaluate the permeation of hydrogen through the plastic pipe in the natural gas distribution 

network. 

Three different PE grades (PE 63, PE 80, and PE 100) in the diameter range from 20 mm (0.79") to 

200 mm (7.87") with pressure between 14.5 psig (1 bar) and 174 psig (12 bars) or over and temperatures 

in the range from 5oC to 25oC. These represent commonly used polyethylene materials and pipe sizes in 

the natural gas networks and typical operating conditions. Pure methane and hydrogen/methane mixture 

containing 10% hydrogen were used in the tests to investigate the permeation behavior of 

hydrogen/natural gas mixture compared to natural gas. Table 14 shows the permeation coefficient of 

hydrogen and methane from a test under 58 psig (4 bar), 116 psig (8 bar) and 174 psig (12 bar) with a 32 

mm (1.26 ) PE 80 pipe. The calculated gas loss based on the experimental data at the test pressures is also 

included in this table. The results from this study are summarized in the follow [18]: 

There is an incubation time for methane to diffuse through the pipe, while the incubation time 

for hydrogen is close to zero. 

The permeation rate of methane and hydrogen increases with the increase of the internal 

pressure. 

The permeation coefficient of hydrogen is 4 to 5 times greater than that of methane in the 

hydrogen/methane mixture, even if the hydrogen partial pressure is lower by an order of 

magnitude than that of methane in the mixture. 

The absolute values of methane loss calculated for three type of PE piping materials are far 

lower than the extrapolated data. 

The aging of the pipes seems to have no significant influence on the permeation coefficients 

in these experimental conditions. 

One type of PVC (PVC-CPE) was also included in this study, and the calculated hydrogen leakage 

rate from PE and PVC pipes at 2.9 psig (200 mbar) distributing 100% H2 are [8]: 

PE100: 5.0 liter/km/day, and 

PVC: 13.2 liter/km/day 

The leakage rate of methane and hydrogen calculated from PE disc samples under a mixture of 80% 

natural gas and 20% hydrogen at 58 psig (4 bar) are [8]: 

Methane: 1.1 liter/km/day, and 

Hydrogen: 2.3 liter/km/day
Page 17

Additional Information on Leakage Assessment 

In addition to the gas leakage study in NaturalHy project, GTI also reviewed the report from IEA 

Greenhouse Gas R&D Programme [11] and other relevant information [13, 18, 19, 29] about hydrogen 

leakage in natural gas distribution systems. 

Gas Leakage from Steel or Ductile Iron Systems [19]: 

The leakage in steel and ductile iron systems mainly passes through the threads or the mechanical 

joints. The leakage measurements carried out by GTI on gas distribution systems indicated that the 

volume leakage rate for hydrogen is about a factor of three higher than for natural gas. 

Gas Leakage from Plastic Pipes and Elastomers [11, 13, AGA handbook] 

Leakage Assessment by IEA Greenhouse Gas Programme [11] 

The permeation coefficient of hydrogen in several plastic pipes was determined by experimental 

measurements in this study. The experimental data and the literature data are summarized in Table 15

[11]. A calculation of the total loss of hydrogen was performed in this study based on the experimental 

data of a representative material from the Dutch grid. The estimated gas loss is 26×103

 m3 (918,182 Ft3) 

per year when 17% hydrogen is adding into this gas distribution system. This amount of gas loss only 

represents 0.0005% of the hydrogen transported. Thus the gas loss due to the hydrogen permeation is 

considered as negligible and will not create a significant problem.

Estimation of Gas Loss for US Distribution Network 

The majority of the plastic pipes used in US natural gas distribution systems are polyethylene pipes 

including medium density polyethylene (MDPE) and high density polyethylene (HDPE). There are also 

small percentage polyvinylchloride pipes. These materials are similar to those used in European natural 

gas distribution system, but with different material designation system. 

The permeation coefficient of hydrogen and methane in the typical plastic pipe and elastomeric 

materials that have been used in US distribution systems are summarized in Table 16 [13, 29]. The 

hydrogen permeation coefficient in the US grade plastic pipe materials are very close to those published 

by IEA’s study [11]. It appears the permeation coefficient of hydrogen is about 5 to 6 times of that of 

methane in the plastic pipes. The hydrogen permeation coefficient is even higher in elastomers, especially 

in natural rubber and Buna S, which are 26 and 21 times of that in HDPE. 

Because the plastic pipes have much larger surface area than the seals, the gas leakage rate is 

calculated with plastic pipes to estimate the amount of gas leakage in the entire gas distribution system. 

The gas leakage rate (V) through plastic pipes can be calculated using the permeation coefficient (P) [30]: 

V=P*(A/t)*∆p (3) 

A: the surface area of pipe 

t: pipe wall thickness 

p: the pressure difference between internal and external surface of pipe 

High density polyethylene is used as an example for this calculation with a pipe diameter of 1 and 

wall thickness of 0.1 which is a representative pipe dimension in the distribution system. Table 17 shows 

the calculated hydrogen and methane leakage rate at the typical distribution operating pressures (60 psig 

(4.1 bar), 3 psig (210 mbar), and 0.25 psig (17.2 mbar)) with various hydrogen concentrations of 

hydrogen/methane mixtures. The gas leakage data are also plotted vs. the hydrogen content at the 

operating pressures in Figure 9. The total volume of gas loss of hydrogen and natural gas increases by 

adding hydrogen due to the higher permeation rate of hydrogen. The total gas loss from a gas mixture 
Page 18

containing 20% hydrogen is about double the gas loss from a pure methane, but the amount of gas loss 

with this hydrogen content from a 1 HDPE pipe at low pressure (3 psig (210 mbar) and 0.25 psig (17.2 

mbar)) is not significant (5.3 ft3/mile/year and 0.4 ft3/mile/year at 3 psig and 0.25 psig respectively). 

Since the service lines normally operate at 3 psig (210 mbar) or 0.25 psig (17.2 mbar), the total gas loss 

from service lines is negligible compared to that from distribution mains which operate at 60 psig (4.1 

bar) or higher. The estimated total gas loss in the distribution systems at different hydrogen levels in the 

gas mixture is shown in Figure 10 using 60 psig (4.1 bar) as a representative operating pressure and the 

mileage for PE pipes with the size less than 2 diameter which accounts about 69% of the total plastic 

pipes in distribution system. The gas leakage rates obtained from experimental measurements in 

NaturalHy are also included in this plot. For pure methane, the gas loss calculated from NaturalHy 

experimental data is close to the calculation from AGA handbook. However, for the gas mixture 

containing 10% hydrogen, the gas loss calculated based on NaturalHy experimental data is only half of 

that based on the permeation coefficient from AGA handbook. The total gas loss for the gas mixture 

containing 20% hydrogen is about 40 million cubic feet per year, and it is about double the total gas loss 

from pure methane, but this amount is still not significant from the economy point of view. 

Summary and GTI’s Concluding Remarks on Gas Leakage 

It has been indicated by the research studies and literature data that hydrogen is more mobile than 

methane in many polymer materials including the plastic pipes and elastomeric seals used in natural gas 

distribution systems. There is almost zero lag time for hydrogen to penetrate the pipe wall, and the 

permeation rate of hydrogen is 4 to 5 times faster than methane through the typical pipes used in natural 

gas distribution. 

The permeation coefficient of hydrogen is even higher through most of the elastomeric sealing 

materials that are used in natural gas distribution systems. Natural rubber and Buna S (SBR) have less 

sealing ability to hydrogen compared to the other elastomers. 

Since plastic pipes have much larger surface area compared to the seals, a typical polyethylene pipe 

used in natural gas distribution system is used to estimate the gas loss through pipe wall at the general 

operating pressures. The calculation based on the literature data of the permeation coefficient of hydrogen 

and methane in the polyethylene pipe (PE 3608 or PE 4710) indicates that the majority of the gas loss is 

from the pipes in distribution mains which operate at 60 psig (4.1 bar) or higher. The gas loss from the 

total of 414,830 mile polyethylene pipes with the size less than 2 in the entire distribution mains is about 

40 million cubic feet per year if 20% hydrogen is added into natural gas pipeline system. Though this 

amount of gas loss is almost double the total gas loss when the systems deliver only natural gas, it is still 

considered insignificant from the economic point of view. In addition, adding hydrogen in natural gas can 

slightly reduce the leakage of methane into the environment which is beneficial for greenhouse gas 

reduction. 

The hydrogen permeation coefficient from literature data is higher than that from the experimental 

measurements in NaturalHy project, especially at lower pressure. This phenomenon is reasonable because 

the literature data is measured in pure hydrogen and thin polymer films. It is most likely that hydrogen is 

less mobile in a low concentration hydrogen/methane mixture because the activity of hydrogen is much 

lower compared to pure hydrogen. Further, the plastic pipe has a much thicker wall and denser structure 

than the thin film which will increase the resistance for hydrogen to penetrate. Thus, the gas loss based on 

literature data may over estimate the gas loss from a pipeline system containing low concentration of 

hydrogen, especially at low operating pressures, e.g. 3 psig (210 mbar) or 0.25 psig (17.2 mbar). In order 

to obtain a more accurate estimation of the gas loss in the distribution system, it is necessary to perform 

further investigations testing pipes under general distribution operating pressures and at hydrogen 

concentrations that are typical of what will be used for blending hydrogen into natural gas pipeline 

systems. 
Page 19

The amount of gas loss from service lines is negligible from the economic point of view, but gas 

leaking in a confined space may increase hydrogen concentrations to levels that may become a threat 

from the safety standpoint. This is the same for elastomeric seals which have higher permeation rates for 

hydrogen. The accumulation of leaked gas over time may present a safety concern in a confined space 

where there are many sealed joints. This issue has not been well studied in NaturalHy and the other 

investigations, and remains a gap for the risk assessment. 

It is important to obtain further understanding on hydrogen permeation behavior in plastic pipes and 

elastomeric materials under the expected operating conditions for hydrogen services. Further investigation 

should be performed on the existing pipe and seal materials as well as newly developed materials that can 

be used as a replacement for current materials. This will provide a basis to accurately estimate the gas 

leakage through pipes and seals, and in particular to determine if the leakage in a confined space over 

time will present a safety risk and if it is required to implement a leak detection/monitoring device. 
Page 20

Task 4.4 – Durability 

It is well known that hydrogen damage is one of the concerns for many metallic piping materials. The 

occurrence and the severity of hydrogen damage on metallic materials depend on the type of materials, 

hydrogen concentration and the operating parameters. It is crucial to understand the acceptable hydrogen 

level that can be blended into natural gas without negatively impacting the lifetime of the infrastructure. 

 Since hydrogen is the smallest element, it has a greater tendency than natural gas to leak through 

valves, seals, gaskets and pipes. The accumulation of hydrogen in a confined space may create safety 

concerns. Gas meters record the volumetric quantities of the gas supplied. Adding hydrogen into natural 

gas changes the gas properties. Therefore, it is necessary to quantify the deviation of the gas meter when 

measuring hydrogen/natural gas mixtures at various hydrogen levels. 

The above issues relate to material degradation. Leakage and meter accuracy were investigated in the 

NaturalHy Project-Work Package 3. The aim of this investigation was to develop sufficient knowledge 

for establishing hydrogen level in the blends, estimating the lifetime for different natural gas networks, 

identifying and removing bottlenecks for transporting hydrogen in the natural gas network and developing 

operational guidelines. The goal of the NaturalHy Project is to determine the feasible conditions under 

which hydrogen produced from a centralized production site can be injected into high pressure 

transmission pipelines and deliver to end users through distribution networks. Under this scenario, the 

durability of pipeline materials in distribution network is less of a concern than transmission pipelines 

because distribution pipelines operate at much lower pressure levels. Thus, hydrogen degradation of 

metallic components in natural gas distribution systems was not studied in the NaturalHy Project based on 

the hypothesis that the integrity of metallic components in low pressure distribution systems will not be 

significantly impacted at the hydrogen levels that are acceptable for high pressure transmission pipe. 

In view of the long term goal of the US to use hydrogen as a sustainable energy carrier, hydrogen 

produced from the satellite, local production sites, will play a role in the hydrogen economy, especially in 

utilizing renewable energy such as wind and solar. In this scenario, hydrogen is most likely to be blended

into natural gas distribution networks directly and the hydrogen level in natural gas determined from the 

pipeline materials and operating conditions for transmission pipelines could be conservative. A beneficial 

improvement can be made on the productivity of hydrogen delivery and recovery of hydrogen from gas 

mixture at end users if higher levels of hydrogen can be injected directly into natural gas distribution 

systems without adversely impacting pipeline integrity. 

In order to provide a comprehensive point of view on the impact from hydrogen on distribution 

pipeline materials, GTI included other literature sources on materials degradation, hydrogen leakage and 

gas meter accuracy with hydrogen/natural gas. In addition, GTI performed a thorough review of the 

pipeline materials using the distribution pipeline data published by DOT and the GTI literature sources. 

By integrating the literature information with the pipeline materials and operating conditions in the 

natural gas distribution system, GTI assessed the durability of the US natural gas distribution 

infrastructure for transporting hydrogen/natural gas mixtures. 

Durability (NaturalHy Projects-Work Package 3) [8, 17, 18] 

This investigation was led by GDF SUEZ, with participation by Commissariat à l’Energie Atomique, 

CMI, CSM, DBI-GUT, DEPA, Ecole Nationale des Ingénieurs de Metz, GASUNIE, Institut Français du 

Pétrole, IGDAS, ISQ, STATOIL, TNO, TOTAL and TUBITAK.

In this project, the effects of hydrogen on the durability of the materials and components used in the 

natural gas transmission and distribution network, as well as the end user devices were studied. 
Page 21

Hydrogen Affect on the Initiation and Growth of Defects in Transmission Pipelines 

This work focused on the hydrogen embrittlement of steel pipes used for high pressure natural gas 

transmission pipeline, and the crack growth from the existing defects, such as corrosion defects and sharp 

defects in the welds. It is concluded in this study that adding up to 50% hydrogen into the natural gas 

transmission pipelines may not cause catastrophic failure. The acceptable hydrogen level depends on the 

type of steel used for high pressure pipeline. 

Because distribution system operate at much lower pressure than transmission pipeline and are built 

with lower grade steels, no additional studies were performed in NaturalHy to evaluate the risk of 

hydrogen embrittlement on distribution steel and other metallic pipes. Additional review and evaluation 

by GTI on the integrity impact from adding hydrogen on distribution pipes are included in the next 

section. 

Hydrogen Permeation in Plastic Pipes in Distribution Network 

This work has been reviewed in Task 4.3, and the main conclusion is that permeation of hydrogen 

through the walls of PE pipes is 4-5 times faster than methane. Nonetheless, the gas permeation loss is 

still very small and acceptable from a safety, economy and environmental point of view. 

Aging of Plastic Pipes in Hydrogen/Natural Gas Blends 

Aging of PE pipe materials was tested with laboratory samples and it was concluded that aging effect 

of hydrogen on PE pipe materials is not significant. But aging of the other polymer materials such as 

PVC, ABS and the elastomeric sealing materials was not reported in this study. 

The Reliability of Gas Meters for Hydrogen Services 

Three gas meters with polymer membranes manufactured by Gallus (France), Dresser (Italy) and 

Elster (Germany) were tested with two gas mixtures (100% methane and 50% hydrogen and 50% 

methane). The test results on Dresser meter show a positive change, while the test results on Gallus and 

Elster meters show a negative change in 50% hydrogen/methane mixture compared to 100% methane. 

But the gaps are less than 2% for all the tested meters and they all decreases at lower flow rate. 

Additional Information for the Durability of Pipeline Materials under Hydrogen Services 

In addition to the durability studies published by the NaturalHy Project, GTI include additional 

literature sources related to the effect from hydrogen on pipeline materials and equipments. They are used 

as supplemental information to provide a comprehensive point of view in terms of the impact from 

hydrogen on the distribution systems and the basis to assess the potential risks imposed to the system in 

the presence of different levels of hydrogen in natural gas. 

Hydrogen Damage of Metals 

Hydrogen damage is a form of environmentally assisted failure that results most often from the 

combined action of hydrogen and residual or applied tensile stress. The failure includes cracking, 

blistering, hydride formation and loss in tensile ductility and it has been generally called hydrogen 

embrittlement (ASM Vol. 13a). In general, the hydrogen damage occurs at a stress level below those 

typically experienced for a particular metal in an environment without hydrogen. It is affected by 

hydrogen pressure, purity, temperature, stress level, strain rate, and material microstructure and strength. 

The specific types of hydrogen damage have been categorized in ASM Handbook Vol. 13A, see 

Table 18. This table includes the materials that are susceptible to hydrogen damage, the various types of 

hydrogen damage, the source of hydrogen and the typical conditions for the occurrence of failure. The 

first three classes are grouped together and designated hydrogen embrittlement. It appears that the 

conditions for hydrogen damage on iron or copper do not apply to natural gas distribution system, thus 

there should be no concern of hydrogen damage on iron and copper pipes in the distribution system. 

Though hydrogen embrittlement is a potential concern for steel pipe, this effect varies with the steels. In 
Page 22

general, high-strength steel (>100 ksi yield strength) are more susceptible to hydrogen induced cracking, 

while low-strength steel is only subjected to loss in tensile ductility. 

Hydrogen Impact on Steel Linepipe 

Hydrogen Embrittlement of Steel Pipe [11] 

Many steels are prone to hydrogen embrittlement, which is the type of brittle fracture at a sustained 

load below the yield strength when materials are exposed to hydrogen. High pressure transmission steel 

pipeline is more of a concern due to the higher stress from the operating pressure and the higher strength 

of pipeline material, especially the new natural gas pipeline construction. Hydrogen concentration and 

operating pressure are the most critical factors to cause hydrogen embrittlement. 

The steel grades (API 5L A, B, X42 and X46) used in natural gas distribution pipeline are relatively 

low strength steels. The predominant hydrogen damage for low strength steels is loss of tensile ductility 

or blistering, but they usually fail in a ductile mode instead of catastrophic brittle fracture in hydrogen 

environment. The severity of the hydrogen damage depends significantly on the hydrogen concentration 

and operating pressure. 

Hydrogen Assisted Fatigue [13] 

Carbon and low alloy steels show accelerated fatigue crack growth and degradation in fatigue 

endurance limits when expose to hydrogen even at relatively low pressures. The accelerated fatigue crack 

growth is more pronounced at ambient temperatures and becomes less severe at elevated temperatures. 

The presence of hydrogen reduces the threshold cyclic stress intensity factor ( Kth) as well as fatigue 

life, thus fatigue cracking will be a concern if the pipeline experiences pressure fluctuations. 

Enhanced Crack Growth on Existing Defects [11] 

Crack growth from existing defects may be enhanced by the addition of hydrogen due to the reduced 

ductility of steel, and fluctuation of the operating pressure in the pipeline may accelerate this effect. 

At low and medium pressures (< 290 psig (20 bar)) in distribution systems, the pipeline will be far 

less susceptible to hydrogen enhanced crack growth due to the relatively low operating tensile strength 

compared to the design strength. There is a long history of the successful transportation of “pure” 

hydrogen at pressures below 290 psig (20 bar) across the world, no operational problems occurring over 

many decades. Town gas, which contains hydrogen, also has been transported historically in gas 

distribution pipelines. 

Welding Requirements for Hydrogen Services [13] 

The welds should be defect free and the weld heat affected zones must match the mechanical and 

toughness properties of the linepipe. The hardness levels in the weld and weld heat affected zone must be 

controlled to avoid hard spots to ensure the adequate toughness for hydrogen containing environment. 

Hydrogen Impact on Non-Metallic Materials 

Compatibility of Polymer Materials with Hydrogen [13] 

The degradation of polymer materials in normal environmental conditions includes UV irradiation, 

chemical attack and thermal breakdown. With respect to the investigation of the polyethylene pipeline for 

hydrogen service, no degradation by pure hydrogen has been reported. Little or no interaction between 

hydrogen gas (or any non-polar gas) and polyethylene should be expected [30]. In addition, hydrogen 

alone does not provide radicals that can cause polymer breakdown. Most of the elastomers are also 

compatible with hydrogen. Table 19 lists the major plastic and elastomeric materials used in natural gas 

pipeline and their compatibility to hydrogen. 

Though pure hydrogen dose not promote the degradation of polymer materials, some contaminants in 
Page 23

hydrogen gas may be harmful to pipeline materials, and the degradation depends on their concentration. 

Hydrogen Permeability in Plastics [11] 

This has been reviewed in Task 4.3. In plastic pipe systems, hydrogen diffuses faster than methane 

through the plastic pipe wall, but the total loss of hydrogen is considered insignificant from the economic

standpoint. 

Impact of Hydrogen on the Durability of Gas Meters [11] 

The influence of hydrogen addition was measured for leather and plastic diaphragm gas meters in 

Polman’s study [11]. The deviations in gas metering were determined with natural gas and 17% 

hydrogen/natural gas mixture at five different flows from 0.013 to 5 m3/h. For the two types of gas 

meters, the deviations observed were lower than 0.1%. This deviation can be regarded as negligible 

considering the calibration standards stating a maximum deviation of 4% for recalibration and 

repeatability within 0.2%. 

This study also examined the required capacity of gas meters for measuring hydrogen/natural gas 

mixtures. The results indicated that for mixtures up to 17%, the required capacity is not affected by 

adding hydrogen in natural gas. 

It is concluded in this study that the gas meters used in natural gas distribution systems are not 

expected to be changed. 

Summary and GTI’s Concluding Remarks on Durability 

Impact of Hydrogen on the Durability of Metallic Pipes in Distribution Systems 

The metallic pipes in US distribution systems are primarily made of relatively low strength steel, 

typically API 5L A, B, X42 and X46 in distribution mains. The major hydrogen damage of these steels in 

a hydrogen containing environment is loss of tensile strength or blistering which strongly depends on the 

hydrogen content in the environment. They normally fail in ductile mode, and are not the type of steels 

that are susceptible to hydrogen induced brittle cracking. 

In addition, the operating pressure in distribution system is normally less than 250 psig (17.2 bar), 

and the stress level in most of the steel pipes, generated by operating pressure, is less than 20% SMYS. 

Under this stress level, the potential risks for the low strength steel pipes in distribution system are low 

considering the failures by hydrogen (hydrogen induced stress cracking, hydrogen enhanced fatigue 

cracking or hydrogen enhanced crack growth from the existing defects) which are the major integrity 

concerns for high pressure transmission pipelines transporting hydrogen. 

For the other metallic pipes, including ductile iron, cast and wrought iron, and copper pipes, there is 

no concern of hydrogen damage under general operating conditions in natural gas distribution systems. 

Impact of Hydrogen on the Durability of Plastic Pipes and Elastomers in Distribution Systems 

There is no major concern on the hydrogen aging effect on PE or PVC pipe materials. Most of the 

elastomeric materials used in distribution system are also compatible with hydrogen. There is very small 

amount of ABS pipes in distribution mains (0.2%) and service lines (0.02%). No investigation on the 

aging and permeability of this pipe material has been performed. Since this material only takes very small 

portion in the distribution pipes, and also it is not the pipe material to be used for new construction, the 

unknown performance from ABS will not significantly affect the overall performance for the plastic pipes 

in distribution system. If ABS is of direct concern, targeted testing could be conducted. Therefore, it can 

be concluded that material aging by hydrogen is not a major concern on the durability of the polymer 

materials in natural gas distribution systems. 
Page 24

One remaining durability gap that needs to be addressed is the potential contaminants in hydrogen gas 

that may be introduced into the network. The specification for the purity level of the hydrogen gas to be 

transported by natural gas pipelines has not been determined. 

Impact of Hydrogen on the Durability of Gas Meters 

The deviation of a gas meter with hydrogen/methane mixtures varies with the manufacture’s detail of 

the meter design, e.g., Dresser meter show a positive change while those from Gallus and Elser show a 

negative change. Nonetheless, the deviation is acceptable based on the requirement for recalibration 

(<4%) when they are measuring a gas mixture containing less than 50% hydrogen. The meters may not 

need to be “tuned” under the potential hydrogen levels (<50%) in natural gas pipeline that are 

transporting hydrogen/natural gas mixtures. 
Page 25

Task 4.5 - Integrity 

There are always existing defects in the pipe materials or welds. The current integrity management 

for natural gas pipeline systems is based on the operating conditions for transporting natural gas. Adding 

hydrogen into the pipeline network changes the pipeline operating environment, which may accelerate 

crack propagation or fatigue failures from the existing defects, and thus adversely impacts pipeline 

integrity. There may be certain defects which are acceptable under current integrity management criteria 

which will become critical due to the material property change in hydrogen containing environments. 

In the US, the Pipeline and Hazardous Materials Safety Administration (PHMSA) has implemented 

integrity management requirements for hazardous liquid and gas transmission pipelines, but no similar 

requirements currently exist for gas distribution pipelines. In 2009, PHMSA published the final rule 

effective on Feb. 12, 2010 to establish integrity management requirements for gas distribution pipeline 

systems. The operators are given until August. 2, 2011 to write and implement the integrity program for 

distribution pipeline systems. 

 The investigations of the suitability of current integrity programs for hydrogen services have been 

focused on the natural gas transmission pipelines. The integrity concern in the medium to low pressure 

distribution system is considered a lower risk compared to high pressure transmission pipeline assuming 

that the hydrogen level that is acceptable to high pressure transmission pipeline will not create a 

significant threat to distribution systems which operate at much lower pressures. 

Because the natural gas distribution systems are different from transmission pipelines and they are 

constructed with a large variety of materials and operated with varied pressures and other conditions, it is 

not appropriate to simply apply the integrity program for transmission pipelines to distribution systems. In 

order to assess the potential risks of adding hydrogen to the distribution systems, GTI performed a review 

on the natural gas distribution systems (see the section “Overview-Natural Gas Distribution System in 

US”) and the potential fourteen threats in the distribution systems which have been identified by the 

American Gas Foundation through the survey of a group of utility operators [27]. Each of the threats has 

been reevaluated by GTI for the conditions under which the systems transport hydrogen/natural gas 

mixtures. The integrity investigation from the NaturalHy Project is used as a basis to identify the risk to 

the integrity of distribution systems. 

Integrity Management Program for Transporting Hydrogen/Natural Gas Mixtures [4,5,6] 

The needs to upgrade current Integrity Management Program (IMP) for transporting 

hydrogen/natural gas mixtures were investigated in “NaturalHy Project Work Package 4”. The aim of this 

project is to provide a specification for an Integrity Management Tool (IMT) that allows the operator to 

modify the existing IMP for hydrogen service. The cost of the new IMP was also evaluated in this study. 

This work was led by DBI-GUT, with participation by TNO Science & Industry, Computational 

Mechanics BEASY, GDF SUEZ, PII Ltd., Istanbul Gas Distribution Co. Inc. (IGDAS), N.V. Nederlandse 

Gasunie, Instituto de Soldadura e Qualidade (ISQ), Turkish Scientific and Technical Research Council 

(TUBITAK), StatoilHydro and Total. 

Defects in Natural Gas Pipeline Systems and the Potential Impact by Hydrogen 

The acceptable defects in the natural gas pipeline systems are defined in the current integrity 

program by the number, type, distribution and the shape of the defects. The aspects to be concerned with 

for hydrogen services is the stress generated at a defect and the rate at which the defect can propagate if 

the stress is over the critical value for crack propagation. Blunt defects, like corrosion, will not generate 

relatively large stresses. However, sharp defects, like cracks, can cause significant stress and under typical 

pipeline fatigue loads hydrogen can accelerate crack growth. In general, crack and crack like defects are 

considered to be more critical than corrosion defects when hydrogen is introduced. 
Page 26

Impact of Hydrogen on the Defect Criticality 

A clear impact on the acceptable initial crack size was observed especially for axial defects. The 

critical size of the defects can be back calculated with an assumed design life based on the knowledge of 

crack growth rate in a specific environment. The effect of hydrogen on the defect criticality is minor 

under the selected assumptions in the hydrogen/natural gas mixtures with up to 50% hydrogen. A tool 

was developed to calculate the probability that a pipeline will fail or a defect will lead to a pipeline failure 

and the failure rate. 

Inspection/Monitoring Tools and Inspection Intervals 

The current inspection tools were investigated for their abilities to identify the critical defects under 

hydrogen services. The modified pipeline inspection tools (MFL, TRIAX, and EMAT) can be applied to 

find critical defects when transporting hydrogen/natural gas. The inspection interval can be determined 

for different hydrogen concentrations, loads and geometries of pipeline and defects based on the in-line 

inspection and probability of failure (POF) calculation results. The expected inspection intervals will be 

shortened for transporting hydrogen/natural gas mixture, especially for higher hydrogen concentrations. 

Improvement of the in-line inspection tools of their reliability and sensitivity to identify critical cracks 

will be beneficial to lowering the probability of failure. 

Cathodic Protection (CP) Integrity Management 

A prototype of an integrated remote monitoring system has been proven feasible for coated 

pipelines. This system includes data collection system and a modeling tool to provide a real time display 

of the CP protection levels along the pipeline. The benefit of using this remote monitoring system is to 

manage the pipeline integrity in the presence of hydrogen with reduced cost. 

Repair Methods 

Three currently applied repair procedures have been investigated to determine if they can be used for 

pipeline repair under hydrogen service. The focus was on the pipeline load and the effect of hydrogen on 

welding activities. Clock Spring, Metallic Sleeve and Weld Deposit can be used to repair the pipelines 

that co-transport hydrogen and natural gas, but the performance will be slightly reduced in some cases. 

Cost of the Integrity Management for Hydrogen Service 

The cost of the integrity management is strongly dependent on the individual circumstances 

including hydrogen concentration, defect distribution, material properties, loads and integrity targets. The 

potential increase of the total cost will be less than 10% for the inspection and repair costs on corrosion 

and cracks if: (a) the hydrogen concentration is less than 50% of the natural gas blend, (b) with the 

maximum operation pressure of 957 psig (66 bars), and (c) the design life of the system is 50 years or 

less. 

Additional Information for Distribution Pipeline Integrity under Hydrogen Services 

Major Threats to Distribution Infrastructure 

The threats are classified in ASME Standard B31.8S (Managing System Integrity of Gas Pipelines) as: 

1) Time Dependent Threat 

External corrosion 

Internal corrosion 

Stress corrosion cracking (SCC) 

2) Stable Threat 

Manufacturing related (e.g., defective pipe seam or defective pipe) 
Page 27

Construction related (e.g., defective pipe girth weld, wrinkle bend or buckle, etc.) 

Equipment related (e.g., gasket or O-ring failure, control/relief equipment malfunction, etc.) 

3) Time Independent 

Third party/Mechanical damage 

Incorrect operations (incorrect operation procedure) 

Weather related/outside force (cold weather, lightening, heavy rains or floods, earth 

movements) 

The above threats are defined primarily for natural gas transmission system which operate at high 

pressure and are constructed predominantly with high strength steels which are coated, wrapped or bare. 

The materials found in distribution pipeline systems are predominantly steel or polyethylene, with some 

cast iron, wrought iron, other plastics and copper. Some of the threats to transmission pipelines are not 

applicable to distribution systems. For example, the threat of stress corrosion cracking is not typically a 

threat to the distribution infrastructure because it is the cracking of a pipeline from the combined 

influence of tensile stress, a corrosive environment, and a susceptible material. The distribution pipelines 

do not operate at pressures high enough to produce the stress necessary to create an environment that 

could include stress corrosion cracking. 

With the different materials taken into account, and in view of the incident causes, the nine threats 

defined for transmission pipelines were expanded to the following fourteen categories of threats for 

distribution systems which are prioritized in Table 20 [27]. Unlike transmission pipelines, the top two 

threats to distribution pipelines are the weather-related outside force damage on cast iron and 

excavation/mechanical damage instead of the time dependent threats from corrosion (external corrosion, 

internal corrosion or stress corrosion cracking) posed to transmission pipelines. This is because the 

distribution pipelines are mostly buried in the highly populated area and are frequently subjected to 

outside force damage. 

For the fourteen threats present for natural gas distribution systems, the likelihood of any threat will 

not be significantly affected by having hydrogen added in the system, but the severity of the hazard may 

be increased by hydrogen in the case leaking occurs as a result of an incident. 

The integrity program may need to be tightened in the future when hydrogen is added to the 

distribution system. For example, one may need to shorten the inspection intervals to minimize the 

possibility of pipeline failure, or to implement leak detection or monitoring device for hydrogen. 

Currently there is no available odorant for hydrogen, and this may require the development of a new 

odorant. This may lead to a potentially increase of the maintenance cost for the utilities. Since there is no 

existing integrity program for distribution system (DIMP is just being introduced in the U.S.), the affect 

on maintenance cost by adding hydrogen cannot be determined. 

Summary and GTI’s Concluding Remarks on the Integrity under Hydrogen Services

Conclusions in NaturalHy Project on Transmission Pipeline Integrity 

The studies on integrity in NaturalHy project is focused on high pressure transportation pipelines. 

This study concludes that hydrogen can be transported by the existing natural gas pipeline with small 

adaptations of the current Integrity Management Program. The necessary adaptations depend on the 

hydrogen concentration and the operating conditions of the individual pipeline. The modifications of 

current integrity program is considered insignificant if hydrogen in the pipeline is less than 50%, but it 

requires a detailed investigation for each case and corresponding modification on the upper limitation of 

hydrogen concentration. 
Page 28

GTI’s Comments on Distribution Integrity

The threat of hydrogen addition on distribution integrity has been considered smaller when 

compared to transmission pipelines. It should be noted that the natural gas distribution systems are very 

different from transmission pipelines, and it is not possible to simply apply the integrity program for 

transmission pipeline to distribution systems. One of the important differences of distribution systems 

from transmission pipelines is the locations, i.e., the distribution pipelines are in populated areas. The 

level of hydrogen that is acceptable for transmission pipeline may need to be reassessed for distribution 

systems in terms of the frequency and severity of fire or explosion in the populated area. In addition, the 

gas leakage in a distribution system is more severe than transmission pipeline, especially in a confined 

service area. The integrity management for distribution systems under hydrogen services may require the 

implementation of leak detecting/monitoring devices or sensors. Currently, there is no available odorant 

for hydrogen, and this becomes an area for further investigation. 

It is likely that the maintenance cost for distribution system under hydrogen service will be increased 

due to the need for increasing inspection frequency and leak detection. 
Page 29

Task 4.6 - End Use-Hydrogen Separation 

One of the challenge for using the existing natural gas network to distribute hydrogen is to separate 

hydrogen from the mixtures at the end use. Currently, pressure swing adsorption (PSA) is the mature 

technology used in refineries to produce high purity hydrogen. However, this technology requires large 

scale units which work best with high levels (normally larger than 50%) hydrogen in the mixtures. A 

smaller scale separation is desired to extract hydrogen from the hydrogen-natural gas mixtures which 

contains lower levels of hydrogen (mostly likely below 25%) under typical natural gas pipeline 

conditions. In addition, the purity of the hydrogen extracted from hydrogen-natural gas mixtures has to 

match the requirements in the specific application. 

Hydrogen-selective membranes are commonly seen as the promising technology for the recovery of 

hydrogen from the feed stream with a low (<30%) hydrogen concentration. The NaturalHy project has 

focused on developing advanced hydrogen selective membranes for the separation of hydrogen from 

natural gas/hydrogen mixtures in “Work Package 5 (Task 5.3-5.7)”. 

This work was led by University of Oxford, and with participation by the Norwegian University of 

Science and Technology (NTNU) and Compagnie Europeenne des Technologies del’Hydrogene (CETE).

The objects of this work include: 

Developing membranes to recover hydrogen from hydrogen/natural gas mixtures; 

Investigating the physical properties of the remaining stream and methods to re-establish the 

gas quality; and 

Performing a cost analysis of the membrane system vs. the commercial PSA systems. 

In general, membranes are classified into two major types: dense membranes (e.g., metallic 

membranes) and microporous membranes (e.g., carbon molecular sieves). Both types of membranes have 

been investigated in NaturalHy project. 

Development of High Selectivity Palladium-Based Membranes 

Palladium membranes are the most used technology to recover hydrogen from gas streams with a low 

hydrogen concentration. In order for these membranes to function efficiently, the entire gas feed stream 

must be heated to temperatures higher than 350oC. Currently, the commercially available palladium 

membranes are conventionally “thick” tubular membranes and are very expensive. The object of 

NaturalHy project is to develop ultra-thin palladium-alloy membranes supported on porous ceramic 

substrates to achieve coherent, defect-free membranes. One of the processes that can produce a three 

micrometer thick membrane is electroless plating of palladium onto a porous alumina substrate. The other 

technology is to deposit thin palladium/silver alloy membranes onto smooth uniform substrates. These 

membranes operate at 300oC with good hydrogen flux, high recovery and 100% selectivity for hydrogen. 

The results from this investigation indicate: 

Electroless plating of palladium onto a porous alumina substrate can produce the membranes 

that meet or exceed 2010 US DOE targets for membrane hydrogen flux at 400oC. 

Depositing thin palladium alloyed with silver and copper is not successful because the 

manufacturing defects in the ceramic support give rise to pin-hole leaks and mechanical 

problems. 

Magnetron vacuum sputtering is a potential alternative technique, but the challenge is to use 

perfectly smooth surfaces such as silicon wafers and polymers as the forming surface and 

then remove of the deposited membrane. 

Development of Carbon-Based Membranes 

Though palladium membranes are promising for recovery of hydrogen from feed streams with a low 

(<30%) hydrogen, these membranes have to be heated to temperatures higher than 350oC in order to 
Page 30

function efficiently. This temperature requirement increases the cost and energy input. Carbon-based 

membranes are able to separate hydrogen at lower or ambient temperature, however the efficiency with 

respect to flux and selectivity vary depending on temperature and pressure. 

Two types of new carbon-based membrane materials suitable for the recovery of hydrogen from 

hydrogen/natural gas mixtures have been investigated in this project. 

Carbon Molecular Sieves (CMS) 

Carbon molecular sieves are formed by carbonization (pyrolysis) of a polymeric precursor at 

temperatures between 400 and 800oC. This is usually preformed under vacuum or an inert gas such as 

nitrogen using cellulose derived from plentiful wood pulp which is cheap and abundant. 

Periodical regeneration of carbon membranes can recover hydrogen permeation properties and is 

beneficial to improve long-term performance of the membranes. A regeneration technique that can be 

applied on-stream while the membrane is in operation has been developed. 

The results from this investigation indicate that the CMS sieves can effectively recover hydrogen 

from the pipeline networks that transport hydrogen/natural gas blends. It provides a greater permeability 

and better selectivity (up to 98%) than conventional polymer membranes and operates at temperatures 

between 30oC and 90oC. Further development is ongoing to develop larger scale membrane modules and 

perform lifetime testing. 

A Mixed Matrix (MM) Material 

The development of the MM-membrane did not provide successful results and the development of 

this membrane was terminated in this project. 

Development of Hybrid Membrane Separation System 

It is most likely that the beneficial characteristics from metallic and carbon based membranes can be 

combined by producing a hybrid membranes to provide an increase in efficiency and flexibility together 

with lower cost. A carbon based membrane can be used as at the first stage to achieve higher hydrogen 

content (up to 98%) at almost room temperature and then followed by a palladium membrane for final 

purification of hydrogen. A hybrid separation system is proposed for further development, see Figure 11. 

Summary on Hydrogen Separation Technologies 

Electroless plating of palladium and carbon molecular sieves are the two technologies that can be 

further developed for hydrogen separation from hydrogen/natural gas blends transported by a natural gas 

pipeline network. A Palladium membrane can provide high purity hydrogen, but is expensive and has to 

operate at 300oC. A CMS membrane is low cost and can operate at temperature between 30oC and 90oC, 

but the maximum hydrogen content obtained using a CMS membrane is 98%. 

The most promising technique in the future would be a hybrid separation system. This could be 

constructed by combining palladium and CMS membrane technology. The cost analysis performed in this 

study indicates that the hybrid system including ancillaries is potentially cheaper than separation by PSA. 

Small scale PSA systems are under development, but it is problematic for PSA to separate hydrogen from 

streams with hydrogen content less than 40%, an additional PSA or a CMS membrane can be used in the 

first stage to concentrate the hydrogen level in the feed. 

The analysis performed in this study also shows that the downstream gas quality will not be adversely 

affected since the Wobbe index and heating value will not be outside the statutory requirements. 
Page 31

Task 4.7 – Impacts (Environmental and Macroeconomic Benefits) 

The impact from adding hydrogen into natural gas systems was assessed in “NaturalHy Project Work 

Package 1”. The review of this study by GTI is included in Task 4.1, and below is a summary of the 

major impacts on environmental and macroeconomic benefits from adding hydrogen in natural gas: 

1) Significant reduction of greenhouse gas emissions if hydrogen is produced from biomass, wind 

power, and nuclear power. 

2) Some advantage on greenhouse gas emissions with hydrogen production from fossil fuels with 

CCS, but no benefits for decreasing primary energy demand or energy resource depletion. 

3) Potential benefits of selective extraction of hydrogen (this depend on the performance of the 

separation technology and the subsequent use of the hydrogen and the residual gas). 

4) Potential benefits on improving air quality by reducing sulfur dioxide, oxides of nitrogen and 

particulate emissions if hydrogen is used in transportation and displaces conventional diesel fuel. 

5) Potential benefit on “greening” natural gas if the hydrogen/natural gas mixture is used directly in 

existing appliances for heat production and electricity generation. 
Page 32

Conclusions 

GTI reviewed the studies performed by the NaturalHy Project on using natural gas network for 

hydrogen services. The scope of this review covers the seven aspects that have been investigated in 

NaturalHy including “Life Cycle Assessment”, “Safety”, “Leakage Assessment”, “Durability”, 

“Integrity”, “End Use” and “Environmental and Macroeconomic Impacts”. In addition to the reports and 

publications from the NaturalHy Project, GTI included the report published by the Greenhouse Gas R&D 

Programme sponsored by International Energy Agency (IEA) and other related publications in this review 

to develop a comprehensive understanding of the major benefits and limitation of using the existing 

natural gas network for transporting hydrogen. 

The aim of this review was to provide a scientific basis and engineering assessment of the potential 

impact from hydrogen on the US natural gas distribution infrastructure when hydrogen is blended into the 

natural gas network. The conclusions of this review not only include the summary of the findings and 

conclusions from the research investigations, but also include GTI’s comments made for US distribution 

system by integrating the research findings with the particular conditions for the distribution 

infrastructure. The main conclusions of the seven tasks are summarized below: 

1) Task 4.1 Life Cycle Assessment 

The life cycle assessment in the NaturalHy project supports the beneficial effects on the 

environment by adding hydrogen to natural gas, which include the reduction of greenhouse emission 

and improving the air quality. However, there is not enough information in this study to support that 

there is a benefit from the standpoint of economy and employment. No concluding remarks were 

made in this aspect. 

2) Task 4.2 Safety 

The research findings indicate that the probability of ignition and the severity of explosion of 

pipeline systems are increased by adding hydrogen. The risk increased by blending hydrogen into 

natural gas pipeline systems is related to the hydrogen levels in the gas mixtures, and the increase is 

slight for hydrogen addition up to 20%. 

GTI performed a quantitative risk assessment on US natural gas distribution systems for carrying 

hydrogen containing natural gas. Compared to the current situation with natural gas, the risks in

natural gas distribution systems are increased by adding hydrogen into the system. The assessment 

results indicate that the risks in distribution mains and service lines are different, especially at higher 

levels of hydrogen in the system. 

If less than 20% hydrogen is introduced into distribution system, the overall risk is not significant 

for both distribution mains and service lines, but the service lines are more impacted than mains 

because they are mostly in confined spaces. 

If the hydrogen level in natural gas increases beyond 20%, the overall risk in service lines can 

significantly increase and the potential hazards can become severe, while the overall risk in 

distribution mains still can be moderate at up to 50% hydrogen. 

For hydrogen level above 50% in natural gas, the risks in both distribution mains and service 

lines significantly increase compared to the situation with natural gas, and the overall risk in 

distribution system becomes severe. 

3) Task 4.3 Leakage 

Hydrogen is more mobile than methane in many polymer materials including the plastic pipes and 

elastomeric seals used in natural gas distribution system. The permeation coefficient of hydrogen is 

higher through most of the elastomeric sealing materials vs. plastic pipe materials. But the plastic 
Page 33

pipes have much larger surface area compared to the seals. Therefore, the leaks through pipe walls 

accounts for the major gas loss in the systems. 

A calculation based on the literature data for the permeation coefficient of hydrogen and methane 

in the polyethylene indicates that the majority of the gas loss is from the pipes (pipe wall) in 

distribution mains which operate at 60 psig (4.1 bar) or higher. The gas loss from the total of 414,830 

miles of polyethylene pipes with the sizes less than 2 in the entire distribution mains is about 40 

million cubic feet per year if 20% hydrogen is added into natural gas pipeline system. Though this 

amount of gas loss is almost double the total gas loss when the systems deliver only natural gas, it is 

still considered insignificant from the economic point of view. Furthermore, this calculation may 

over estimate the gas loss because the permeation coefficient in the literature is considered larger than 

the experimental measurements using pipe test under actual operating pressures, especially at lower 

pressure. Further investigation may be necessary for accurately quantifying the gas loss. 

The amount of gas loss from service lines is negligible from the economy point of view, but the 

gas loss into a confined space may increase hydrogen concentration to levels that may become a 

threat from the safety standpoint. In addition, the gas leak from the elastomeric seals at the joints in 

service lines may increase the risk in confined spaces. 

Further investigation on the pipe and seal materials can provide a basis to accurately estimate the 

gas leakage through pipes and seals in order to determine if the leakage in a confined space, over 

time, will present a safety risk and if it is required to implement a leak detection/monitoring device. 

4) Task 4.4 Durability 

The metallic pipes in US distribution systems are primarily made of low strength steel, typically 

API 5L A, B, X42 and X46 in distribution mains. They are not the type of steels that are susceptible 

to hydrogen induced brittle cracking. In addition, at the stress level generated in natural gas 

distribution system, hydrogen induced failures are not major integrity concerns for the steel pipes in 

distribution system. 

For the other metallic pipes including ductile iron, cast and wrought iron, and copper pipes, there 

is no concern of hydrogen damage under general operating conditions in natural gas distribution 

systems.

There is no major concern on the hydrogen aging effect on PE or PVC pipe materials. Most of the 

elastomeric materials used in distribution system are also compatible with hydrogen. 

The deviation of a gas meter with hydrogen/methane mixtures varies with the manufacture’s 

detail of the meter design. Nonetheless, the deviation is acceptable based on the requirement for 

recalibration (<4%) when they are measuring a gas mixture containing less than 50% hydrogen. The 

meters may not need to be tuned under the potential hydrogen levels (<50%) in natural gas pipeline 

that are transporting hydrogen/natural gas blends. 

One of the remaining gaps needs to be addressed for the durability issues is the potential 

contaminants in hydrogen gas that may be introduced into the network. 

5) Task 4.5 Integrity 

In the NaturalHy Project and some other research programs, the focus on the integrity issues has 

been on the transmission pipelines because of the concerns of high operating pressures (up to 2000 

psig (138 bar)) and the pipeline steels that are subject to hydrogen induced cracking. It is concluded 

in the NaturalHy Project that hydrogen can be transported by the existing natural gas pipeline with 

small adaptations of the current Integrity Management Program. The necessary adaptations depend on 

the hydrogen concentration and the operating conditions of the individual pipeline. The necessary 

modifications are not significant with up to 50% hydrogen addition, but a detailed investigation for 
Page 34

every case is mandatory and the upper limitation on hydrogen concentration may be reduced. 

It should be noted that the natural gas distribution systems are very different from transmission 

pipelines, and it is not possible to simply apply the integrity program for transmission pipelines to 

distribution systems. One of the important differences of distribution systems from transmission 

pipeline is the locations of these systems. The level of hydrogen that is acceptable for transmission 

pipeline may need to be reassessed for distribution systems in terms of the frequency and severity of 

fire or explosion in a highly populated area. 

In addition, the hazards arising from gas leakage in a distribution system may be more severe 

than in transmission pipelines, especially in a confined service area. The integrity management for 

distribution systems under hydrogen services may require the implementation of leak detecting or a 

monitoring device or sensor. Currently, there is no available odorant for hydrogen, and this becomes 

an area for further investigation. 

It is likely that the maintenance cost for distribution systems under hydrogen service will be 

increased due to the need for increasing inspection frequency and implementing leak detection. 

6) Task 4.6 End Use Hydrogen Separation 

Electroless plating of palladium membranes and carbon molecular sieves are the two technologies 

that can be further developed for hydrogen separation from hydrogen/natural gas blends transported 

by a natural gas pipeline. Palladium membranes can provide high purity hydrogen, but they are 

expensive and have to operate at 300oC. CMS membranes are low cost and can operate at temperature 

between 30oC and 90oC, but the maximum hydrogen concentration obtained using CMS membranes 

is 98%. 

The most promising technique is to making a hybrid separation system by combining palladium 

and CMS membranes. The cost analysis performed in this study indicates that the hybrid system, 

including ancillaries, is potentially cheaper than separation by PSA. 

Small scale PSA systems are also under developments that include an additional PSA or a CMS 

membrane in the first stage to concentrate the hydrogen level in the feed. 

Downstream gas quality will not be adversely affected since the Wobbe index and heating value 

will not be outside the statutory requirements. 

7) Task 4.7 Environmental Impact 

Adding hydrogen in natural gas can significantly reduce greenhouse gas emissions if hydrogen is 

produced from biomass, wind power and or nuclear power. There are also some advantages related to 

greenhouse gas emissions with hydrogen production from fossil fuels with CCS, but hydrogen from 

this source has no benefits for decreasing primary energy demand or energy resource depletion. 

Adding hydrogen in natural gas also has the potential benefits of improving air quality by 

reducing sulfur dioxide, oxides of nitrogen and particulate emissions if hydrogen is used in 

transportation and displaces conventional diesel fuels. It could also green natural gas if the 

hydrogen/natural gas mixture is used directly in existing appliances for heat production and electricity 

generation. 

END OF REPORT 
Page 35

Figure 1. Schematic of the Natural Gas Delivery Pipeline Infrastructure* 

Note: 

*: Figure from AGF report “Safety Performance and Integrity of the Natural Gas Distribution Infrastructure” [27].
Page 36

Figure 2. Piping Materials of Mains and Service Lines in Distribution Systems* 

Note: 

*: Original data from DOT 2007 Annual Report [25] 

Steel/Unprotected/Bare

4.31%

Steel/Unprotected/Coated

1.58%

Steel/Cathodically 

Protected/Bare

1.15%

Steel/Cathodically 

Protected/Coated

39.55%

Plastic Pipe

50.10%

Cast Iron, Wrought Iron

3.14%

Ductile Iron

0.08%

Copper

0.003%

Other(1)

0.07%

Other(2)

0.03%

Miles of Main by Material 2007

Source: PHMSA 

Distribution Annuals Reports 

Steel/Unprotected/Bare, 

5.84%

Steel/Unprotected/Coated

2.57%

Steel/Cathodically 

Protected/Bare, 0.68%

Steel/Cathodically 

Protected/Coated, 

23.65%

Plastic Pipe, 63.43%

Cast Iron, Wrought Iron, 

0.17%

Ductile Iron, 0.001%

Copper, 1.73%

Other(1), 1.79%

Other(2), 0.12%

Number of Services by Material, 2007

Source: PHMSA 

Distribution Annuals Reports 
Page 37

Figure 3. The Distribution of Pipe Size of Steel and PE Pipes in Distribution Mains* 

Note: 

*: Original data from DOT 2007 Annual Report [25] 

unknown

0.01%

< 2"

49.30%

2" to 4"

27.91%

4" to 8"

18.11%

8" to 12"

3.45%

>12"

1.23%

Steel Main

unknown

0.22%

< 2"

71.78%

2" to 4"

22.51%

4" to 8"

5.38%

8" to 12"

0.11% >12"

0.01%

PE Main
Page 38

Figure 4. The Distribution of Pipe Size of Steel and PE Pipes in Service Lines* 

Note: 

*: Original data from DOT 2007 Annual Report [25] 

unknown

2.30%

< 2"

70.62%

2" to 4"

26.23%

4" to 8"

0.78%

8" to 12"

0.07%

>12"

0.005%

Steel Service

unknown

0.24%

< 2"

88.56%

2" to 4"

10.85%

4" to 8"

0.33%

8" to 12"

0.03% >12"

0.002%

PE Service
Page 39

Figure 5. Statistical Data for Leak Incidents in Distribution Mains and Service Lines* 

Note: 

*: Original data from DOT 2007 Annual Report [25] 

Corrosion

36.42%

Material Defect

6.98%

Natural Force

8.47%

Excavation

15.39%

Other outside 

force

1.86%

Equipment

6.75%

Operation

2.53%

Other

21.60%

Mains

Corrosion

21.64%

Material Defect

11.16%

Natural Force

Excavation 3.40%

24.90%

Other outside 

force

3.95%

Equipment

12.71%

Operation

2.57%

Other

19.66%

Service Lines
Page 40

Figure 6. Incidents by Part of the Distribution System* 

Note: 

*: Plot from AGF report “Safety Performance and Integrity of the Natural Gas Distribution Infrastructure” [27].
Page 41

Figure 7. Serious Incidents by Construction Materials of Mains* 

Note: 

*: Plot from AGF report “Safety Performance and Integrity of the Natural Gas Distribution Infrastructure” [27].
Page 42

Figure 8. Serious Incidents in Steel and Polyethylene Service Lines by Cause* 

Note: 

*: Plot from AGF report “Safety Performance and Integrity of the Natural Gas Distribution Infrastructure” [27].
Page 43

Figure 9. The Calculated Gas Loss Rate vs. Hydrogen Concentration in Hydrogen/Methane 

Mixtures at the Typical Distribution Operating Pressures (60 psig (4.1 bar), 3 psig (210 mbar) and 

0.25 psig (17.2 mbar))*

Note: 

*: The data are calculated by Equation (2) using the permeation coefficient data in Table 16 from AGA Handbook 

“Plastic Pipe Manual for Gas Service” [29].

0

50

100

150

200

250

300

350

0% 10% 20% 50% 100%

Gas Loss Rate (Ft3/Mile/Yr)

Hydrogen Content (%)

Methane (AGA Data)

Hydrogen (AGA Data)

60 psig

0

5

10

15

20

0% 10% 20% 50% 100%

Gas Loss Rate (Ft3/Mile/Yr)

Hydrogen Content (%)

Methane (AGA Data)

Hydrogen (AGA Data)

3 psig

0

0.2

0.4

0.6

0.8

1

1.2

1.4

1.6

0% 10% 20% 50% 100%

Gas Loss Rate (Ft3/Mile/Yr)

Hydrogen Content (%)

Methane (AGA Data)

Hydrogen (AGA Data)

0.25 psig
Page 44

Figure 10. The Calculated Gas Loss from the Gas Mixtures Containing Different Levels of 

Hydrogen in Distribution System at 60 psig (4.1 bar) Operating Pressure 

Note: 

a: AGA Data: The data are calculated by Equation (2) using the permeation coefficient data in Table 16 from AGA 

Handbook “Plastic Pipe Manual for Gas Service” [29].

b: The original data are from the experimental test results in the paper of “Evaluation of the Permeability to CH4 and 

H2 of PE Currently Used in Gas Distribution Networks” [18], and are converted to the English unit.

0

20

40

60

80

100

120

140

160

Gas Leakage (Million Ft3/yr)

Hydorgen Content (%)

Methane Hydrogen

0% 10% 20% 50% 100% Naturalhy Data Naturalhy Data 

b

AGA Data 

a

AGA Data 

a

AGA Data 

a

AGA Data 

a

AGA Data 

a
Page 45

Figure 11. A Hybrid Separation Membrane System for Hydrogen Recovery*

Note: 

*: Plot from NaturalHy “Interim Report on Membrane Development for Hydrogen Separation” [7]. 
Page 46

Table 1. Regulation Mandated Inspection of Gas Pipeline Facilities* 

Note: 

*: Table from AGF report “Safety Performance and Integrity of the Natural Gas Distribution Infrastructure” [27].
Page 47

Table 1. Regulation Mandated Inspection of Gas Pipeline Facilities [27] (Continued) 

Note: 

*: Table from AGF report “Safety Performance and Integrity of the Natural Gas Distribution Infrastructure” [27].
Page 48

Table 2. Pipe Sizes and Materials in Distribution Systems* 

Type Size Quantity Steel Ductile

Iron Copper Wrought/Cast Iron PVC PE ABS Other Total by Size

Mains

Unknown

Miles 44 0 0 3 88 1290 234 9 1667

% 0.00 0.00 0.00 0.00 0.01 0.11 0.02 0.00 0.14

< 2"

Miles 275599 0 33 1199 18061 414831 2268 530 712520

% 22.95 0.00 0.00 0.10 1.50 34.54 0.19 0.04 59.33

2" to 4"

Miles 156023 214 3 15424 3444 130091 251 157 305609

% 12.99 0.02 0.00 1.28 0.29 10.83 0.02 0.01 25.45

4" to 8"

Miles 101239 470 1 15913 366 31077 4 29 149099

% 8.43 0.04 0.00 1.32 0.03 2.59 0.00 0.00 12.41

8" to 12"

Miles 19273 70 0 3146 0 625 0 5 23119

% 1.60 0.01 0.00 0.26 0.00 0.05 0.00 0.00 1.93

>12"

Miles 6875 73 0 1985 0 37 0 2 8973

% 0.57 0.01 0.00 0.17 0.00 0.00 0.00 0.00 0.75

Total

by Materials

Miles 559053 828 36 37670 21959 577950 2757 732 1200987

% 46.55 0.07 0.00 3.14 1.83 48.12 0.23 0.06 100.00

Services

Unknown

Numbers 486667 0 70 52 918 97283 453 487767 1073210

% 0.75 0.00 0.00 0.00 0.00 0.15 0.00 0.75 1.66

< 1"

Numbers 14953056 0 703688 96381 224150 36183571 9870 723781 52894497

% 23.07 0.00 1.09 0.15 0.35 55.84 0.02 1.12 81.62

1" to 2"

Numbers 5554217 0 416609 10881 32866 4431757 642 60707 10507679

% 8.57 0.00 0.64 0.02 0.05 6.84 0.00 0.09 16.21

2" to 4"

Numbers 164653 0 582 621 244 132842 130 525 299597

% 0.25 0.00 0.00 0.00 0.00 0.20 0.00 0.00 0.46

4" to 8"

Numbers 15260 332 15 236 7 11066 0 80 26996

% 0.02 0.00 0.00 0.00 0.00 0.02 0.00 0.00 0.04

>8"

Numbers 1050 46 0 12 0 839 0 1 1948

% 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

Total

by Materials

Numbers 21174903 378 1120964 108183 258185 40857358 11095 1272861 64803927

% 32.68 0.00 1.73 0.17 0.40 63.05 0.02 1.96 100.00

Note: 

*: Original data from DOT 2007 Annual Report [25] 
Page 49

Table 3. Steel Grades for Distribution Pipelines and Their Material Properties* 

API 5L Min

Yield Strength

Min Ultimate

Tensile Strength

Min

Elongation

Grade ksi MPa ksi MPa %

A 30 207 48 331 -

B 35 241 60 413 22.5

X42 42 289 60 413 22.5

X46 46 317 63 434 21.5

Note: 

*: Table from CTC report “Existing Natural Gas Pipeline Materials and Associated Operational Characteristics 

(Hydrogen Regional Infrastructure Program in Pennsylvania)” [10]
Page 50

Table 4. Elastomers in Natural Gas Distribution System* 

Material Name Other Names Type Acronym

1 Butadiene-Styrene Buna-S; GR-S Styrene-butadiene Rubber SBR

2 Butadiene-Acrylonitrile Buna-N; Nitrile; Perbunan; Nytek Acrylonitrile-butadiene Rubber NBR

3 Natural Rubber Gum Natural Rubber NR

4 Polychloroprene Neoprene; Bayprene; Chloroprene Synthetic Rubber CR

5 Ethylene-Propylene Nordel; Royalene; Dutral Synthetic Rubber EPM & EPDM

6 Polyamide (11 and 12) Rilsan; Vydyne; Plaskin; Nylon PA11 & PA12 Elastomer PA11 & PA12

7 Silicone and Fluorosilicone Polysiloxanes; Cohrlastic; Green-Sil; Parshiled; 

Baysilone; Blue-Sil Silicone Rubber/Polysiloxane SI &FSI

8 Fluoroelastomer Viton; Fluorel; Technoflon High Performance Synthetic Rubber FKM

9 Perfluoroelastomer Kalrez; Chemraz; Kel-F High Performance Synthetic Rubber FPM

10 Polypropylene PP Thermoplastic/Polyolefin PP

11 Polytetrafluoroethylene Teflon, Halon Fully Fluorinated Thermoplastic PTFE &FTE

Note: 

*: GTI internal data source
Page 51

Table 5. Number of Leak Incidences by Causes for Distribution Mains and Services* 

Mains Services

Number % number %

Corrosion 55553 36.42 71963 21.64

Material Defect 10645 6.98 37124 11.16

Natural Force 12924 8.47 11305 3.40

Excavation 23475 15.39 82814 24.90

Other outside force 2834 1.86 13141 3.95

Equipment 10293 6.75 42279 12.71

Operation 3866 2.53 8557 2.57

Other 32956 21.60 65386 19.66

Total 152546 100.00 332569 100.00

Note: 

*: Original data from DOT 2007 Annual Report [25] 
Page 52

Table 6. The cause of Transmission and Distribution Incidents* 

Pipeline Safety Record 

Transmission and Distribution 

1990-2002

Incidents by Cause

Corrosion

Outside Force

Construction/Operating Error

Accidently Caused by Operator

Other

No Data

Total

Distribution

# of 

Incidents

Total

Incident 59 954 97 84 378 7 1579

Serious 

Incident 39 280 59 59 160 4 601

% of 

Incidents

Total

Incident 3.7 60.4 6.1 5.3 23.9 0.4 100

Serious 

Incident 6.5 46.6 9.8 9.8 26.6 0.7 100

Transmission

# of 

Incidents

Total

Incident 224 381 139 0 213 0 957

Serious 

Incident 7 38 11 0 47 0 103

% of 

Incidents

Total

Incident 23.4 39.8 14.5 0.0 22.3 0.0 100

Serious 

Incident 6.8 36.9 10.7 0.0 45.6 0.0 100

Note: 

*: The data are from AGF report “Safety Performance and Integrity of the Natural Gas Distribution Infrastructure” 

[27].
Page 53

Table 7. Coverage of Technology Areas in the Literature Database* 

Technology Area # of References # of Reviews

Electrical Power-Coal 22 14

Electrical Power-Natural Gas 21 13

Electrical Power-Nuclear Power 10 7

Electrical Power-Oil 14 7

Electrical Power-Renewables 47 35

Electrical Power-Transmission and Distribution 9 9

Hydrogen-Network 13 14

Hydrogen-Production 48 60

Hydrogen-Utilization 11 9

Miscellaneous 6 5

Natural Gas Production, Network and Utilization 46 42

Natural Gas/Hydrogen Network and Utilization 5 3

Oil Production and Processing 13 6

Transport-Using Electricity 10 11

Transport-Using Hydrogen 32 33

Transport-Using Natural Gas 16 16

Transport-Using Oil 17 16

Transport-Using Renewable Energy 12 13

Note: 

*: Table from NaturalHy Report “Literature Review Report on Life Cycle and Socio-Economic Assessment Aspects 

[1].
Page 54

Table 8. Effect of Hydrogen Addition in Natural Gas on Gas Properties and Hazards* 

Properties/Phenomena Effect of Hydrogen 

Addition

Main Hazardous Hazards

Rupture

Explosion

Fire

Burns

Suffocation

Poisoning

Density Lower x

Viscosity Lower x

Velocity of Dispersion About the same x x x

Hydrogen Component Higher x x

Household Gas Pipe Leak Rate Higher x + x

Lower flammability limit About the same level x x

Higher Flammability Limit Higher +

Flammability Range Wider x

Detonability Range Wider x

Explosive Energy/Volume Lower x x

Explosive Energy/Mass Higher x x

Minimum Energy for Ignition Lower x x

Auto Ignition Temperature Lower x +

Uncontrolled Ignition Easier x x

Severity of Explosive Damage Lower x

Explosion Risk in Confined Room Higher +

Explosion Risk in unconfined 

Room Lower -

Note: 

*: Table from IEA report “Reduction of CO2 Emissions by Adding Hydrogen to Natural Gas” [11]

×: hazard exists but unchanged by presence of hydrogen up to 15% 

+: hazard increases by presence of hydrogen 

-: hazard reduces by presence of hydrogen
Page 55

Table 9. Ranking of the Hazards in Natural Gas Distribution Systems* 

Significance of Hazard Ranking Assigned

Severe 50

Moderate to Severe 40

Moderate 30

Minor to Moderate 20

Minor 10

None 0

Note: 

*: The severity of the hazards is ranked with the numerical system generally used for risk assessment.
Page 56

Table 10. The Risk Factor a for Pipe Material Categories and the Overall Risk Factor b at Each 

Failure Modes in Distribution Mains 

Failure Mode

Pipe Material Categories and Their Percentage in Distribution Mains

Steel Cast Iron PE Other Plastics Other Overall Risk 

Factor 46.55% 3.14% 48.12% 2.06% 0.13%

Corrosion 50 40 0 0 10 24.54

Material Defect 30 10 40 30 10 34.16

Natural Force 30 50 20 20 10 25.58

Excavation 50 50 50 50 50 50.00

Other Outside Force 10 10 10 10 10 10.00

Equipment 30 30 30 30 30 30.00

Operation 30 30 30 30 30 30.00

Other 10 10 10 10 10 10.00

Total 240 230 190 180 160 214

Note: 

a: The hazard severity for each pipe material category was assessed at each failure mode by GTI based on the 

engineering experiences and the reported incident data in natural gas distribution system from 1990 to 2002 in AGF 

report “Safety Performance and Integrity of the Natural Gas Distribution Infrastructure” [27]. The risk factor for 

each material category in this table is assigned with the numerical definition of the hazard severity defined in Table 

9. 

b: The overall risk factor for each failure mode is calculated by the sum of the risk factor of each material category 

times the percentage of this material in distribution mains, see Equation (2).
Page 57

Table 11. The Risk Factor a for Pipe Material Categories and the Overall Risk Factor b at Each 

Failure Modes in Service Lines 

Failure Type

Pipe Material Categories and Their Percentage in Service Lines

Steel Cast Iron PE Other Plastics Other Overall Risk 

Factor

32.68% 0.17% 63.05% 0.42% 3.69%

Corrosion 50 40 0 0 10 16.77

Material Defect 30 10 40 30 10 35.53

Natural Force 30 50 20 20 10 22.95

Excavation 50 50 50 50 50 50.00

Other Outside Force 10 10 10 10 10 10.00

Equipment 30 30 30 30 30 30.00

Operation 30 30 30 30 30 30.00

Other 10 10 10 10 10 10.00

Total 240 230 190 180 160 205

Note: 

a: The hazard severity for each pipe material category was assessed at each failure mode by GTI based on the 

engineering experiences and the reported incident data in natural gas distribution system from 1990 to 2002 in AGF 

report “Safety Performance and Integrity of the Natural Gas Distribution Infrastructure” [27]. The risk factor for 

each material category in this table is assigned with the numerical definition of the hazard severity defined in Table 

9. 

b: The overall risk factor for each failure mode is calculated by the sum of the risk factor of each material category 

times the percentage of this material in service lines, see Equation (2). 
Page 58

Table 12. Risk Assessment for Distribution Mains at Three Hydrogen Levels 

Failure Mode Probability a

(%)

Risk Factor Overall Risk

NG b< 20% H2

c

20 to 50% H2

c

>50% H2

c NG b

<20% H2

c

20 to 50% H2 

c

>50% H2

c

Corrosion 36.42 24.54 29.54 29.54 44.54 8.94 10.76 10.76 16.22

Material Defect 6.98 34.16 39.16 39.16 54.16 2.38 2.73 2.73 3.78

Natural Force 8.47 25.58 35.58 35.58 45.58 2.17 3.01 3.01 3.86

Excavation 15.39 50.00 60.00 70.00 70.00 7.69 9.23 10.77 10.77

Other Outside Force 1.86 10.00 15.00 15.00 30.00 0.19 0.28 0.28 0.56

Equipment 6.75 30.00 35.00 35.00 50.00 2.02 2.36 2.36 3.37

Operation 2.53 30.00 35.00 35.00 50.00 0.76 0.89 0.89 1.27

Other 21.60 10.00 15.00 15.00 30.00 2.16 3.24 3.24 6.48

Total 100.00 214 264 274 374 26 33 34 46

Note: The calculation of “Risk Factor” was performed by GTI

a: The probability of each failure mode is the statistical data of the leak incidents in distribution mains from DOT 2007 annual report [25], see Table 5. 

b: The baseline risk factor for each failure mode in natural gas distribution mains, see Table 10. 

c: The risk was assessed by GTI for each failure mode at different hydrogen levels in natural gas distribution mains compared with the baseline risk with natural 

gas. The risk factor at each level of hydrogen is calculated by adding the baseline risk factor with the increase of risk factor ( RF) at this hydrogen level, which is 

defined as below: 

RF=5: minor increase 

RF=10: minor to moderate increase 

RF=20: moderate to significant increase 
Page 59

Table 13. Risk Assessment for Distribution Services at Three Hydrogen Levels 

Failure Mode Probability a

(%)

Risk Factor Overall Risk

NG b< 20% H2

c

20 to 50% H2

c

>50% H2 

c NG b

< 20% H2

c

20 to 50% H2

c

>50% H2 

c

Corrosion 21.64 16.77 26.77 26.77 36.77 6.11 9.75 9.75 13.39

Material Defect 11.16 35.53 45.53 45.53 55.53 2.48 3.18 3.18 3.88

Natural Force 3.40 22.95 42.95 42.95 42.95 1.94 3.64 3.64 3.64

Excavation 24.90 50.00 70.00 90.00 100.00 7.69 10.77 13.85 15.39

Other Outside Force 3.95 10.00 20.00 20.00 30.00 0.19 0.37 0.37 0.56

Equipment 12.71 30.00 40.00 40.00 50.00 2.02 2.70 2.70 3.37

Operation 2.57 30.00 40.00 40.00 50.00 0.76 1.01 1.01 1.27

Other 19.66 10.00 20.00 20.00 30.00 2.16 4.32 4.32 6.48

Total 100.00 205 305 325 395 23 36 39 48

Note: The calculation of “Risk Factor” was performed by GTI

a: The probability of each failure mode is the statistical data of the leak incidents in service lines from DOT 2007 annual report [25], see Table 5 

b: The baseline risk factor for each failure mode in natural gas service lines, see Table 11.

c: the risk was assessed by GTI for each failure mode at different hydrogen levels in natural gas service lines compared with the baseline risk with natural gas. 

The risk factor at each level of hydrogen is calculated by adding the baseline risk factor with the increase of risk factor ( RF) at this hydrogen level, which is 

defined as below: 

RF=5: minor increase 

RF=10: minor to moderate increase 

RF=20: moderate to significant increase 

RF=40: significant increase 

RF=50: significant increase at higher degree 
Page 60

Table 14. The Permeation Coefficient and the Calculated Gas Loss from a 32 mm (1.26 ) PE80 Pipe 

Under the Pressures of (58 psig (4 bar), 116 psig (8 bar) and 174 psig (12 bar))* 

Gas Pressure

(psig)

Time-Lag 

(day)

Permeation Coefficient

(×10-3 ft3-mil/ft2/day/psig)

Gas Loss

(ft3/mile/year)

CH4 H2 CH4 H2 CH4 H2 Total

Pure CH4 58 6.46 NA 0.18 0 54.07 NA 54.07

90% CH4

+

10% H2

58 4.31 0 0.09 0.34 25.90 10.59 36.49

116 6.39 0 0.12 0.50 67.03 31.04 98.07

174 5.69 0 0.12 0.52 101.91 48.54 150.45

Note: 

*: The original data in this table are from the experimental test results in the paper of “Evaluation of the 

Permeability to CH4 and H2 of PE Currently Used in Gas Distribution Networks” [18], and are converted to the 

English unit. 
Page 61

Table 15. Permeation Coefficient (10-3×ft3-mil/ft/day/psig) of Hydrogen Gas for Plastic Pipe 

Materials at 20 C* 

Material Experiment Literature

PE80 1.50 1.99

MDPE 1.63 1.10

PE100 1.46 0.00

PEXa 3.37 0.00

PVC 0.91 0.69

Ductile PVC 0.97 0.00

Note: 

*: The original data in this table are from IEA report “Reduction of CO2 Emissions by Adding Hydrogen to 

Natural Gas” [11], and they are converted to the English unit.
Page 62

Table 16. Permeation Coefficient (10-3×ft3-mil/ft/day/psig) of Hydrogen in Plastic Pipe and 

Elastomeric Materials 

Material Hydrogen Methane

MDPE (PE2708)

a

1.43 0.29

HDPE (PE3608)

a

1.09 0.16

HDPE (PE4710)

a

1.09 0.16

PVC a0.95 NA

Natural Rubber b28.39 NA

Butyl Rubber b4.27 NA

Buna S (SBR) b23.02 NA

Neoprene (CR) b7.67 NA

Buna N (NBR) b9.12 NA

Note: 

a: Data are from “AGA Handbook: Plastic Pipe Manual for Gas Service” [29]

b: Data are from EIA report “Hydrogen Transportation Pipeline” [13] 
Page 63

Table 17. The Calculated Gas Loss Rate (ft3/mile/year) Based on Literature Data for HDPE Pipes 

at the Operating Pressures of 60 psig, 3 psig and 0.25 psig* 

Hydrogen 

Content

At 60 psig At 3 psig At 0.25 psig

H2 CH4 Total H2 CH4 Total H2 CH4 Total

0% 0.0 49.4 49.4 0.0 2.5 2.5 0.0 0.2 0.2

10% 32.9 44.5 77.4 1.6 2.2 3.9 0.1 0.2 0.3

20% 65.9 39.5 105.4 3.3 2.0 5.3 0.3 0.2 0.4

50% 164.7 24.7 189.4 8.2 1.2 9.5 0.7 0.1 0.8

100% 329.3 0.0 329.3 16.5 0.0 16.5 1.4 0.0 1.4

Note: The calculation was performed by GTI. 

*: The data in this table are calculated by Equation (2) using the permeation coefficient data in Table 16 from “AGA 

Handbook: Plastic Pipe Manual for Gas Service” [29].
Page 64

Table 18. Classification of Hydrogen Degradation of Metals* 

Type of 

Damage

Hydrogen Embrittlement Hydrogen 

Attack Blistering

Environment Embrittlement Stress Cracking Loss in Tensile Ductility

Typical 

Materials

Steels, nickel-base alloys, 

metastable stainless steel,

titanium alloys

Carbon and low-alloy steels

Steels, nickel-base alloys, 

Be-Cu bronze, aluminum 

alloys

Carbon and lowalloy steelsSteels, copper, 

aluminum

Hydrogen 

Source Gaseous H2

Thermal processing, 

electrolysis, corrosion

Gaseous H2, internal 

hydrogen from 

electrochemical charging

Gaseous

Hydrogen sulfide 

corrosion, 

electrolytic charging, 

gaseous

Typical 

Conditions

10-10 to 104gas pressure

0.1 to 10 ppm total 

hydrogen content

0.1 to 10 ppm H2 of gas 

pressure exposure

Up to 15 ksi

Hydrogen activity 

equivalent to 3-15 

ksi

Observed at -150 to 1290°F

Most severe at 70°F

Observed at -150 to 210°F

Most severe near 70°F

Observed at -150 to 

1290°F 400-1100°F 30-300°F

More severe at low strain rate More severe at low strain 

rate Strain rate important

Type of 

Damage

Shatter Cracks, 

Flakes, Fisheyes Micro-Perforation Degradation in Flow 

Properties Metal Hydride Formation

Typical 

Materials Steels (forgings and castings) Steels (compressors) Iron, steels, nickel-base 

alloys

Vanadium, Niobium, Tantalum, 

Titanium, Zirconium, Uranium

Hydrogen 

Source

Water vapor reacting with 

molten steel Gaseous hydrogen Gaseous or internal hydrogen

Internal hydrogen from melt; corrosion, 

electrolytic charging, welding

Typical 

Conditions

Precipitation of dissolved 

ingot 30-125 ksi

1-10 ppm hydrogen 

content at 70°F for iron or 

steels

15-15,000 psig gas pressure

Cooling 70-210°F

Up to 15 ksi gaseous 

hydrogen at T > 0.5 

melting point for various 

metals

Hydrogen activity must exceed solubility 

limit near 70°F

Note: 

*: Table from ASM Handbook Vol. 13A (Hydrogen Damage) [28]
Page 65

Table 19. Hydrogen Compatibility of the Plastics and Elastomers Used in Natural Gas Pipeline* 

Polymers Compatibility

Polyethylene Good

Polyvinyl Chloride Good

Natural Rubber Fair

Butyl Rubber Good

Silicone Rubber Fair

Neoprene (CR) Good

Buna S (SBR) Good

Viton Good

Buna N (NBR) Good

Note: 

*: Data from EIA report “Hydrogen Transportation Pipelines” [13] and PPI report “Chemical Resistance of Thermoplastics Piping Materials” [31]
Page 66

Table 20. Operator Perceptions on Threat Significance* 

Threat Priority Threat % of Respondent

1 Outside Force/Weather Cast Iron Pipe 90

2 Excavation/Mechanical Damage 87

3 External Corrosion Bare Steel Pipe 86

4 External Corrosion (Graphitization) Cast Iron Pipe 71

5 External Corrosion Coated & Wrapped Pipe 69

6 Construction-Related Defects Plastic Pipe 57

7 Outside Force/Weather Steel Pipe 49

8 Construction-Related Defects Steel Pipe 48

9 Incorrect Operations & Operator Error 35

10 Equipment Malfunction 35

11 Manufacture-Related Defects Plastic Pipe 30

12 Outside Force/Weather Plastic Pipe 26

13 Internal Corrosion 22

14 Manufacture-Related Defects Plastic Pipe 22

Note: 

*: Table from AGF report “Safety Performance and Integrity of the Natural Gas Distribution Infrastructure” [27].

The identified threats in natural gas distribution systems are prioritized in this table according to the response from 

the survey performed by AGF with the utility operators. The higher priority is given to the threat accepted by more 

respondents. 
Page 67

References 

Ref # Outline Pub. Yr Task # Author and Affiliation

Natural

Hy Report

1

Literature Review Report on Life Cycle and Socio-Economic 

Assessment Aspects

Compare the current energy system, transition natural 

gas/hydrogen system, and future complete hydrogen system in 

terms of:

1. Primary energy inputs vs. energy resource depletion

2. Environmental impact:

Greenhouse gas emissions associated with climate 

change,

Other gases: NOx, SO2, PM10, etc.,

Liquid and solid emissions associated to acidification, 

ozone depletion and eutrophication,

3. Direct and indirect job creation and maintenance, and

4. Economic costs.

2004 4.1

4.7

1. N. D. Mortimer and R. E. Horne

U. of Warwick, UK

2. K. A. Adamson

Technical U., Germany

3. T. Bouquet, S. Minett and S. 

Craenen, COGEN Europe, Belgium

4. A. de Groot, ISQ, Portugal

5. T. Feck, K. Stolzenburg and R. 

Steinberger-Wilckens

Energy Research Centre of the 

Netherlands

6. P. Helb, SAVIKO Consultants ApS, 

Denmark

2

What are the Life Cycle Analysis and Socio-Economic Issues

(final presentation)

Identify the issues related to using hydrogen as primary energy 

source:

Emissions,

Employment, and 

Cost

2009 4.1

4.7

Nigel Mortimer

Loughborough University, UK

3

Adding Hydrogen to the Natural Gas Infra-Structure -

Assessing the Risk to the Public (final presentation)

1. Consequences of accidental releases (large scale 

experiments and mathematical models):

Gas buildup,

Fire, and

Explosion.

2. Failure frequency and ignition probability (engineering 

judgment and information for durability and integrity work 

packages).

3. Assess risk to public:

Transmission pipeline failures, and 

Explosions in domestic properties.

2009 4.2

4.3

Barbara Lowesmith

Loughborough University, UK
Page 68

Ref # Outline Pub. Yr Task # Author and Affiliation

Natural

Hy Report

4

Assessment of Repair and Rehabilitation Technologies Relating to the Transport 

of Hythane:

1. Assess the suitability of the existing repair and rehabilitation technologies for 

distribution and transmission pipelines:

Operation pressure within 10 bars

50% hydrogen in hythane

2. Consequences of repair technologies:

Technological

Economical.

2006 4.5

Jens Huttenrauch and 

Gert Muller-Syring

DBI-GUT 

5

How Does the Presence of Hydrogen Effect Pipeline Integrity and What Can We 

Do About It? (final presentation)

When and how to inspect and repair

Specification for an integrity management tool

Software development to calculate probability of failure (POF)

Cost of integrity management by hydrogen addition.

2009 4.5 Gert Müller-Syring, 

DBI-GUT

6

Principles of Resource Allocation Relating to Pipeline Integrity Management (for 

transmission pipeline). 2008 4.5 Lise Lanarde

GDF SUEZ, France

7

Interim Report on Membrane Development for Hydrogen Separation:

Specifications and target for membrane development

Pd based membrane development (Interim)

Carbon based membrane development (Interim).

2007 4.6 D. F. Uoxf

NTUN, CETH

8

To What Extend Can Existing Pipelines Accommodate Hydrogen? (final 

presentation)

1. Assess the impact of H2 on transmission pipelines

2. Assess the impact of H2 on distribution network

Permeability of PE and PVC

Aging of PE

Reliability of domestic gas meters.

2009 4.4 Isabelle Alliat

GDF SUEZ

9

Decision Support Tool (final presentation)

Provide the assessment and suitability of adding hydrogen to NG systems in the 

Netherlands

The results and conclusions of this task are not included in this presentation.

2009 Go/no go

decision

Peter Bartlam

ISO, Portugal
Page 69

Ref # Outline Pub. Yr Task # Author and Affiliation

CTC Report

10

Existing Natural Gas Pipeline Materials and Associated Operational 

Characteristics (hydrogen regional infrastructure program in 

Pennsylvania):

Compare the natural gas pipelines in the U.S. and PA and assess the 

feasibility of co-transporting hydrogen and natural gas in terms of:

Pipeline materials

Operating conditions

Piping components

Losses and leakage

Pipeline security.

2005

4.2

4.3

4.4

4.6

Concurrent Technologies Corp., 

PA, US

IEA Green House Gas 

R&D Program

11

Reduction of CO2 Emissions by Adding Hydrogen to Natural Gas:

1. Review the effect of adding hydrogen in natural gas on the safety, 

economy, environment and the requirement for upgrades to the 

natural gas network and end user appliances.

2. Review the percentage of hydrogen in NG/H2 blends and the 

potential for a three step sequence to phase hydrogen into natural 

gas pipeline.

3. Review the potential non-technical barriers from the standpoint of 

economy, psychology or emotion that may hinder the introduction 

of hydrogen as a substantial energy carrier.

2003 4.1-4.7

E. A. Polman, J.C. de Laat, M. 

Crowther et al.

GASTEC Technology BV, 

Netherlands

12

Present Status of Hydrogen Transport Systems-Using Existing 

Natural Gas Supply Infrastructures in Europe and the USA

A review on the worldwide hydrogen infrastructure-related projects and the 

status as related to transporting hydrogen using existing natural gas 

networks.

2005 4.1-4.7

Takeo Suzuki, Shin-ichiro 

Kawabata, Tetsuji Tomita, 

Institute of Energy Economics, 

Japan (IEEJ)

13

Hydrogen Transportation Pipelines

A document on design, construction, and operational requirements for 

hydrogen transportation pipelines.

2004 4.4 European Industrial Gases 

Association
Page 70

Ref # Outline Pub. Yr Task # Author and Affiliation

EET Project

14

Mixing and Transportation of H2 via the NG Network in 

Rozenburg

Study of the bottlenecks and advantages/disadvantages of mixing 

and transporting hydrogen via the existing natural gas infrastructure 

from technical, institutional, and economical aspects of Rozenburg. 

2008

4.3

4.4

4.7

Anish Patil

Delft U. of Technology, 

Netherlands

15

The Use of the Natural Gas Pipeline Infrastructure for Hydrogen 

Transport in a Changing Market Structure

Discusses the energetic and material aspects of hydrogen transport 

through existing natural gas pipeline.

2006 4.4

4.7

Dries Haeseldoncks, William 

D'haeselleer, U. of Leuven, 

Belgium

Naturalhy Project

16

Assess the Durability and Integrity of Natural Gas Infrastructure 

for Hydrogen and Natural Gas Blends

1. Discusses the durability of steel, PE, and gas meters with H2:

H2 embrittlement and its effect on toughness and fatigue,

Permeability of H2 in PE and aging of PE in H2, and

Accuracy of gas meter (polymer membrane), leakage, 

and durability.

2. Integrity Management for H2/natural gas mixture:

Defect criticality may change with H2 content,

Development of inspection tools,

Development of repair strategies, and

Development of integrity management tool.

2005 4.4

4.5

Isabelle Alliat, J. Heerings, GAZ 

De France, France

Naturalhy 

Project

17

The Value of the Existing Natural Gas System for Hydrogen:

1. Overview of NaturalHy projects,

2. Durability of steel, PE and gas meters with H2, 

3. Integrity management for H2/natural gas mixture, and

4. Risks with H2 in natural gas pipeline.

2006

4.2

4.3

4.4

4.5

1. O Florisson, Gasunie 

Engineering & Technology, 

Netherlands

2. Isabelle Alliat, GAZ De 

France, France

Naturalhy 

Project

18

Evaluation of the Permeability to CH4 and CH4+H2 of PE 

Currently Used in Gas Distribution Networks.

Experimental evaluation of the permeability of CH4 and CH4+10%H2

in PE 63, PE80, and PE100 under operating temperatures and 

pressures.

2008 4.3

4.4

1. D. Gueugnaut, and Denise 

rousselot, GAZ De France, 

France

2. G. Tari, Degaz, Hungary

3. A. Drdöhelyi, Szeged U., 

Hungary
Page 71

Ref # Outline Pub. Yr Task # Author and Affiliation

19

Study of the Behavior of Gas Distribution Equipment in 

Hydrogen Service-Phase II

Leakage measurements with hydrogen/natural gas mixtures on 

natural gas distribution system

1980 4.3 Walter J. Jasionowski, GTI, 

USA

20

Pathways to a Hydrogen Society

The diffusion coefficients of hydrogen in Polyethylene (medium 

density, high density, PE100, crosslinked polyethylene) and Polyvinyl 

Chloride from literatures and laboratory measurements

2002 4.3

E.A. Polman, A. van Wingerden, 

M. Wolters

GASTEC Technology BV, 

Netherlands

21 ASME B31.8-2007

Gas Transmission and Distribution Piping Systems 2007 4.2

4.5

The American Society of 

Mechanical Engineers

22 API 5L (API Specification for Line Pipe) 2004 4.4 American Petroleum Institute

23 ASME B31.12-2008

Hydrogen Piping and Pipeline 2008 4.4 The American Society of 

Mechanical Engineers

24

49 CFR Part 192

Pipeline Safety: Integrity Management Program for Gas 

Distribution Pipelines (Final Rule)

2009 4.2

4.5

Department of Transportation

Pipeline and Hazardous 

Materials Safety Administration

25 DOT 2007 Annual Distribution Data 2007

4.2

4.3

4.5

Department of Transportation

Pipeline and Hazardous 

Materials Safety Administration

26 Integrity Management for Gas Distribution 

(Report of Phase 1 Investigation) 2005 4.2

4.5

Department of Transportation

Pipeline and Hazardous 

Materials Safety Administration

27 Safety Performance and Integrity of the Natural Gas Distribution 

Infrastructure 2005 4.2

4.5

URS Corporation

American Gas Foundation 

28 ASM Handbook Vol. 13A (Hydrogen Damage) 2003 4.4 ASM International

29 Plastic Pipe Manual for Gas Service (8th edition) 2006 4.3 American Gas Association

30 Permeation, Solubility and Interaction of Hydrogen in PolymersAn Assessment of Materials for Hydrogen Transport 2008 4.4 Savannah River National Lab

31 Chemical Resistance of Thermoplastics Piping Materials 2007 4.5 Plastic Pipe Institute
Page 72

List of Acronyms 

Acronym Description

ABS Acrylonitrile Butadiene Styrene

AGA American Gas Association

AGF American Gas Foundation

API American Petroleum Institute

ASM American Society for Metals

ASME American Society of Mechanical Engineers

CCS Carbon Capture Storage

CETE Compagnie Europeenne des Technologies del’Hydrogene

CFD Computational Fluid Dynamic

CFR Code of Federal Regulations

CI Cast Iron

CMS Carbon Molecular Sieves

CP Cathodic Protection

CTC Concurrent Technology Corporation

DCC Dutch Corrosion Center

DDT Deflagration to Detonation Transition

DIMP Distribution Integrity Management Program

DIMP Distribution Integrity Management Program

DOE Department of Energy

DOT Department of Transportation

ECN The Energy Research Center

EET Dutch Economy, Ecology and Technology

GTI Gas Technology Institute

HDPE High Density Polyethylene

IEEJ Institute of Energy Economics Japan

IMT Integrity Management Tool

IEA International Energy Agency
Page 73 

List of Acronyms 

Acronym Description

IMP Integrity Management Program

ISQ Instituto de Soldadura e Qualidade

LDCs Local Distribution Companies

LNG Liquefied Natural Gas

MDPE Medium Density Polyethylene

MM Mixed Matrix

NBR Butadiene-Acrylonitrile

NREL National Renewable Energy Laboratory 

NTNU Norwegian University of Science and Technology

OPS Office of Pipeline Safety

PE Polyethylene

PHMSA Pipeline and Hazardous Materials Safety Administration

POF Probability of Failure

PSA Pressure Swing Adsorption

PVC Polyvinyl Chloride

SBR Butadiene-Styrene

SCC Stress Corrosion Cracking

SMYS Specified Minimum Yield Strength

UV Ultraviolet

VCE Vapor Cloud Explosion

WI Wrought Iron

END OF TABLE