A review of challenges with using the natural gas system for hydrogen

Hydrogen, as an energy carrier, is attractive to many stakeholders based on the assumption that the extensive global network of natural gas infrastructure can be repurposed to transport hydrogen as part of a zero ‐ carbon energy future. Therefore, utility companies and governments are rapidly advancing efforts to pilot blending low ‐ carbon hydrogen into existing natural gas systems, many with the goal of eventually shifting to pure hydrogen. However, hydrogen has fundamentally different physical and chemical properties to natural gas, with major consequences for safety, energy supply, climate, and cost. We evaluate the suitability of using existing natural gas infrastructure for distribution of hydrogen. We summarize differences between hydrogen and natural gas, assess the latest science and engineering of each component of the natural gas value chain for hydrogen distribution, and discuss proposed solutions for building an effective hydrogen value chain. We find that every value chain component is challenged by reuse. Hydrogen blending can circumvent many challenges but offers only a small reduction in greenhouse gas emissions due to hydrogen's low volumetric energy density. Furthermore, a transition to pure hydrogen is not possible without significant retrofits

responsible for around 75% of today's gross warming relative to the beginning of the industrial revolution. 4hereas experts suggest that we have the technologies available to cut CH 4 emissions from oil and gas operations by 75%, 3 a transition away from fossil fuels and their combustion, including natural gas, is needed to achieve climate goals. 5Therefore, an obvious way to maintain beneficial use of the extensive and valuable global network of natural gas infrastructure during the impending energy transition would require switching to a gas/gas mixture that does not generate greenhouse gas (GHG) emissions when combusted.
Hydrogen (H 2 ) has emerged as a natural gas replacement, because it can release energy without associated carbon dioxide emissions.The chemical energy stored in the hydrogen to hydrogen bond can be converted to either heat through combustion or electricity in a fuel cell with no CO 2 emissions: processes that humans have been employing for more than 100 years. 6 2 cannot currently be considered an energy source like natural gas, because it is being produced through methods such as electrolysis or steam reforming. 7There are numerous techniques available to manufacture hydrogen from feedstock molecules, including natural gas but also water.Currently, 99% of dedicated H 2 production relies on fossil fuels without carbon capture, 3 emitting over 900 million metric tonnes of CO 2 into the atmosphere annually. 3There are more than a 1000 proposed projects aimed at scaling up zero-and low-carbon hydrogen production processes globally. 80][11][12] For example, renewable energy displacement or high methane emissions can make hydrogen applications worse for the climate in the near-term than the fossil fuel systems they are replacing. 13lthough reusing natural gas infrastructure for hydrogen is an appealing proposition, its feasibility rests on the suitability of the existing gas network for hydrogen gas.Decades ago, gas mixtures made by gasification of either coal or petroleum-known as "town gas"contained high concentrations (up to 50% by volume) of H 2 , 14 and were piped into homes.Therefore, the distribution infrastructure could technically tolerate high levels of hydrogen.Although gas produced by gasification of petroleum naphtha and natural gas is still used in locations like Singapore and Hong Kong, this method has been abandoned in most of the world for safer options (natural gas), which do not contain toxic carbon monoxide.Therefore, most gas networks today are almost entirely designed for fossil gas mixtures that are primarily comprising methane (75% to 90%+ by volume, containing very little if any H 2 ).Material selection, system attributes, storage systems, appliances and device design, and so on were designed, tested, and optimized specifically for the characteristics of natural gas and not for those of H 2 .The fundamental differences in physical and chemical properties of H 2 and CH 4 are quite large, leading to challenges with respect to safety, energy supply, climate impacts, and cost.
In the following sections, we address the practicality, risks, and remaining data gaps of using H 2 in existing natural gas infrastructure by (1) contrasting physical and chemical properties between H 2 and CH 4 ; (2) describing how these differences affect each component of the existing natural gas system value chain; (3) discussing potential strategies to mitigate issues; and (4) the challenges associated with implementing such solutions.

| CONSTRASTING PROPERTIES OF HYDROGEN AND NATURAL GAS
Although both colorless and odorless gases at standard temperature and pressure, H 2 and CH 4 are very different gases both physically and chemically (see Table 1).These differences present many challenges when considering the use of natural gas infrastructure for H 2 , which are further discussed in Section 3. In addition, while CH 4 in the atmosphere absorbs radiation whereas H 2 does not, both can be oxidized leading to perturbations to atmospheric chemistry in ways that lead to increases in other GHGs.

| Physical
There are two key physical differences between H 2 and CH 4 that relate to their molecular sizes and liquid phase temperatures.First, hydrogen is the smallest and lightest element on the periodic table.A molecule of hydrogenconsisting of two hydrogen atoms-is therefore the smallest and lightest molecule.H 2 's weight and density is one-eighth that of CH 4 and its diffusivity in air is around three times higher (see Table 1).This means that H 2 can more rapidly leak from infrastructure, permeate through materials, and rise and accumulate at high points in enclosed spaces. 15econd, the temperatures at which H 2 and CH 4 can be converted into a liquid, which can be useful as a storage and transport mechanism, are −253°C and −162°C at atmospheric pressure, respectively.Thus, much more energy is needed to convert H 2 gas into a liquid and it is more likely to incur H 2 losses through evaporation given the high temperature difference between the liquid and the surrounding environment.
T A B L E 1 Characteristics of hydrogen compared to natural gas (methane) and their implications.Second, the ignition properties of H 2 relative to CH 4 make it more flammable.Hydrogen has a much wider range between lower and upper flammability limits than natural gas (4%-75% for H 2 vs. 5.3%-15% for CH 4 and 5%-15.6%for natural gas). 16,17H 2 leakage is, therefore, more likely to reach a potential source of ignition within the range of ignitable mixture concentrations than similarly sized leaks of natural gas.H 2 also has a considerably lower ignition energy than CH 4 , meaning that it is considerably easier to ignite accidentally via arcs and sparks from electrical devices. 17hird, H 2 's flame properties make it more dangerous than CH 4 .H 2 's laminar flame speed is about eight times that of CH 4 . 18Flame speed affects flame stability in burners, the risk of flashback, and overpressure, which may be encountered during a deflagration event such as the ignition of gas leaked into a confined space.Flames of pure H 2 are also very low in visible light emissions, making flame detection more difficult.Finally, H 2 's adiabatic flame temperature is higher than that of CH 4 .This gives it the potential to generate more nitrogen oxides (NO x ) for given combustion conditions. 17,19ourth, H 2 has a very high energy density per unit mass, but per unit volume, its energy density is about one-third that of a typical pipeline gas.This means that much less energy is transmitted, distributed, and stored in the same volume of H 2 versus natural gas.

| Atmospheric
CH 4 is an infrared-absorbing GHG, whereas H 2 is not.However, both gases react with hydroxyl radicals in the atmosphere, leading to increased concentrations of other GHGs and, therefore, indirectly causing warming.For CH 4 , the main sink of emissions is atmospheric oxidation with the hydroxyl radical that on average takes about a decade, leading to the formation of the GHGs tropospheric ozone, stratospheric water vapor, and carbon dioxide. 20For H 2 , ~70% is taken up by microbial communities in the soil and the remaining ~30% take about 2 years to be oxidized by the hydroxyl radical, leading to the formation of tropospheric ozone and stratospheric water vapor. 21,22An additional warming effect from H 2 emitted to the atmosphere is that less hydroxyl is available to react with CH 4 , thereby increasing its residence time in the atmosphere.Consequently, current assessments of hydrogen's global warming potential suggest that H 2 can cause around ~12 times more warming than carbon dioxide (CO 2 ) over a 100-year period following emissions of equal mass, and ~37 times more warming over a 20-year period. 21CH 4 's warming potency (from direct and indirect warming effects) is around ~30 and ~80 times that of CO 2 over 100 and 20 years, respectively. 4

| IMPLICATIONS ACROSS THE NATURAL GAS VALUE CHAIN
The physical and chemical differences between H 2 and CH 4 are critical to the suitability of using several components of existing natural gas infrastructure for H 2 , and contribute to safety, energy supply, climate, and cost risks (see Figure 1).Although there are solutions to mitigate some of these risks, they too are often associated with new risks and challenges.

| Production
Natural gas is produced from wells and fed via gathering lines to processing plants, where a gas mixture meeting pipeline specifications is produced.Purification processes vary by gas composition but often include removal in part or in total of gaseous higher-carbon hydrocarbons, butane, propane, ethane, in addition to sulfur compounds, mercury, carbon dioxide, water, and rarely, helium.Sometimes, nitrogen is added to reduce the energy content.Some natural gas production can be expected in a decarbonized future, for use in producing chemicals like ethylene and propylene.However, given that most gas is burned rather than used as a chemical feedstock, 23 most natural gas wells, gathering lines, and processing plant infrastructure would only have very limited use in a decarbonized world as peaking capacity to complement renewable power and storage (see Figure 2).Reuse of some components may be possible, with scraps taken and repurposed.Therefore, new infrastructure would be required to scale up hydrogen production facilities and then transport the hydrogen to the natural gas F I G U R E 1 Challenges and risks with using existing natural gas system for pure hydrogen service.
MARTIN ET AL. transmission infrastructure.However, although natural gas processing plants are not designed for H 2 , it is possible that some parts may be salvaged and relocated.

| Long-distance transport
Natural gas from processing plants is often transported long distances via transmission pipelines or transported in its liquified form, when crossing oceans.Transmission pipelines typically operate at considerable pressure (50-150 bar or 5-15 MPa); are constructed from high yield strength grades of carbon/low alloy steel; have exterior coatings and electrochemical protection to reduce pipe corrosion; and are often buried (or subsea) for physical protection. 24Interior linings are sometimes used.The pipes are sized for pressure drops on the order of 5 psi per mile (20 kPa/km), with compressor stations at regular intervals to maintain pressure.These compressors often use centrifugal-type or reciprocating-type machines and are powered by gas turbines or engines fueled by the gas in the pipeline, and in some cases electric motor-driven. 24,251][32] In high-yield strength steels commonly used in gas transmission pipelines, exposure to molecular hydrogen combined with cyclic stress, initiated at manufacturing or welding flaws or corrosion points in the piping system, increases the growth rate of cracks.The process, known as HAFC, occurs because hydrogen atoms diffuse into the steel. 33he cracks may ultimately extend through the wall of the pipe, causing it to leak or burst. 34The hydrogen atoms can also recombine into molecular hydrogen gas at defects in the steel. 35Low-yield-strength steel pipes are not particularly susceptible to fatigue cracking unless both temperature and the partial pressure of hydrogen are quite high. 30,36ecent, extensive testing of typical pipeline materials in Europe demonstrates both acceleration of fatigue cracking and reduction in fracture toughness when hydrogen is used, but the impacts vary widely depending on the material. 36Welds and their heat-affected zones, as well as manufacturing or fabrication defects in the pipe increase vulnerability by serving as crack initiation sites. 37This issue has been known for decades.
9][40] Because natural gas pipes are usually buried, external inspections are difficult and internal inspections are largely relied upon to verify the integrity of the pipe material.Consequently, there is a considerable risk of premature failure if natural gas pipes are re-purposed for H 2 service.There are, however, several solutions that have been suggested, but none are without additional challenges.
First, hydrogen could be "blended" with natural gas below a certain threshold so that the partial pressure of hydrogen is limited and HAFC risk is reduced. 41However, this significantly limits the decarbonization potential of using hydrogen, because it is not safe to pursue higher blending rates without undertaking retrofits or complete replacement of pipes.Even with small percentage admixtures of molecular hydrogen in high pressure natural gas pipes made of high-yield strength carbon steels it is expected that considerable acceleration of fatigue cracking, by as much as 30-fold, will occur with fracture resistance of the piping material reduced by as much as 50%. 34econd, it is sometimes possible to install a liner or coating into a natural gas pipe to protect it against F I G U R E 2 Existing natural gas production system suitability for pure hydrogen.
corrosion and erosion, leading some to suggest that liners or coatings may provide a means to protect existing gas pipelines against HAFC associated with H 2 . 33,42,43However, this can be challenging both technically and logistically.Furthermore, H 2 permeates through nonmetallic materials and, over time, even permeates through intact metallic materials. 44Thus, the suite of hydrogenimpermeable materials to choose from is extremely limited.Moreover, installing a liner in an existing buried line is very difficult to undertake effectively and would require shutting down the pipe for an extended period of time.
Because permeation is likely inevitable, the space between the liner and the inner diameter of the pipe would need to be vented at numerous points along the pipeline, or else the cracking risk would not be prevented.The resulting H 2 leakage/venting also represents a flammability hazard and emits climate-warming H 2 into the atmosphere.Research into suitable options for the interior protection of gas pipelines against H 2 -induced damage is underway, with recent developments identifying graphene and MXene as promising. 43However, liners are difficult to install, control, and inspect regardless of material.
F I G U R E 3 Existing natural gas transmission system suitability for pure hydrogen.
Third, cyclic stress amplitude can be reduced and HAFC might be delayed by operating piping systems at constant pressure, but practically it may not be possible, and other cyclic stresses (from vibration, soil movements, thermal expansion, and so on) will continue to pose a risk of fatigue cracking.Repurposing existing gas pipelines to carry H 2 would also often require de-rating the design pressure to as little as half to one-third of the original due to design codes and standards (see Supporting Information for details). 42A reduction in design pressure of this magnitude represents a very significant reduction in pipeline energy-carrying capacity and also diminishes the "line pack" (i.e., the energy stored in the form of gas compressed above its delivery pressure in the gas network; discussed further in Section 3.4).
There are safe materials available for construction of new, purpose-built H 2 pipelines. 30,45Purpose-built industrial hydrogen pipelines made from mild steels, lower strength steels or high yield strength steels that were designed and fabricated for use with hydrogen have been operating for decades. 45,46The key is design pressure determinations, materials selection, nondestructive examinations, welding methods, and testing all focused on H 2 applications.These pipelines are operated differently than natural gas pipelines, operating at low and near constant pressures (less than about 65 bar(g) or 6.5 MPa).
Regardless of potential modifications and replacement, an additional transmission challenge for hydrogen is pipeline capacity.With H 2 's energy density per unit volume at one-third that of a typical natural gas and the desirability of operating hydrogen pipelines at low pressure, the ability to move large amounts of hydrogen using existing pipelines is limited.For example, the amount of energy that can be transmitted by hydrogen compared to natural gas would be one ninth if derating pressure by on third and having one-third of the calorific value.
][49] The mechanical energy to compress one gas relative to another is roughly inversely proportional to its molecular weight, which at constant temperature and pressure is proportional to the volumetric flow at a given compression ratio (see Supporting Information).Given that H 2 would need to flow in piping at roughly three times the volumetric flowrate of natural gas to deliver the same amount of energy, hydrogen compressors would require at least three times as much energy as those used for natural gas.Compression energy requirements would be increased further if the design pressure of the piping must also be reduced; a line operating at reduced pressure would have reduced energy carrying capacity, and the pressure loss per unit length would require compression to a greater compression ratio at each compressor station.This would require proportionately more compressor input energy per delivered joule of heat energy in the transmitted gas, thus, undercutting the net climate benefits of delivered hydrogen.(See calculations in Supporting Information.) Although the energy efficiency impact and cost may be significant, the need to replace all compressors in existing transmission systems with larger machines of considerably higher power and suction displacement would require a significant investment and the capacity to provide such compressors.Existing compressors are often made of materials of construction (high strength steels, and so on) and can have seals, and so on, incompatible with H 2 , and any engines previously running on gas would need replacement or significant modification to operate with pure H 2 . 50In the absence of valve replacement hydrogen can leak from existing closed valves, packings, and so on, which leads to safety hazards, lost product, and climatewarming emissions. 50,51

| Local distribution
Once delivered to the "city gate," natural gas is distributed to individual users via an extensive network of buried piping operating at medium to low pressures.These pipelines are made of a variety of materials ranging from mild steel to cast iron to high-density polyethylene (HDPE).
The lower pressure in the distribution network, the operation of piping farther away from their yield strength, and the infrequent use of high-yield strength steels in construction reduces the risk of HAFC.The major concerns in the gas distribution network for re-use with H 2 are not primarily associated with metallurgy, but rather with leakage and permeation and associated climate warming and fire/explosion risk (see Figure 4). 26,28,29,52ydrogen permeates through intact HDPE and other "soft goods" (polymeric and elastomeric materials used in gaskets, seals, and so on) at an appreciable rate. 53The H 2 molecule's considerably smaller molecular diameter and high diffusivity relative to CH 4 lead to faster permeation, that is, more molecules of H 2 will permeate per unit time than molecules of CH 4 at a given pressure.There is also an overall tendency for H 2 to leak to a greater extent than that of natural gas. 53Theory suggests that H 2 will leak at 1.3-3 times the rate of CH 4 . 54easurements confirm the increased H 2 leakage rate through plastic piping of four to five times that of natural gas. 24,55However, there are some limited lab experiments that indicate that hydrogen may leak at the same rate 56 or faster than methane 57

depending on flow regimes.
There is also some evidence of material property changes in HDPE piping after exposure to hydrogen, and additional research is warranted to understand a safe lifetime for HDPE pipes used in the distribution of hydrogen.There doesn't appear to be any safety concern related to premature failure arising from hydrogen exposure. 55However, elastomeric materials exposed to hydrogen show reduction in tensile strength due to permeation, increasing the risk of larger leaks. 24he use of liners to reduce permeability may provide a partial solution, but more research is required. 42lternatively, blending hydrogen into the gas network for transport is another option to mitigate issues of transporting hydrogen, although it provides limited decarbonization potential.Some have raised the potential of de-blending when pure H 2 is required.Methods including pressure-or temperature-swing adsorption and selective membranes have been examined in detail. 24,55he result would be a significant additional cost and energy demand per kilogram of pure hydrogen recovered. 24Methane and hydrogen emissions associated with the separation process would also be of concern.
Gas meters in the distribution network would likely need significant retrofit or replacement. 26,58Not only might they be required to measure gas volumetric flows three times as high as those required for fossil gas (to deliver same energy content to consumers), but diaphragm-type meters using large elastomeric or polymeric components have been known to under-report flowrate when fed gas mixtures containing hydrogen. 59

| Storage
Natural gas systems contain both large storage elements for management of seasonal variation in gas use and smaller storage elements that manage daily variations in flow.The storage afforded by virtue of the volume of gas held up in the transmission and gas distribution network itself is referred to as "line pack."Line pack storage, in the form of the difference in pressure between nominal and minimum operating pressure for the gas system in question, can represent many hours of system demand.Such storage, absent from electrical distribution systems, is a critical tool for maintaining gas grid operational stability against fluctuations in demand and supply and against interruptions in service due to equipment failures or maintenance. 60witching the gas system to pure H 2 , with an energy density per unit volume roughly one-third that of a typical pipeline gas; therefore, would result in a reduction in "line pack" storage to one-third of the present value if storage pressure and volume are kept constant (Figure 5). 49If pipeline design pressures must be de-rated to accommodate the added risks associated with hydrogen to the pipeline materials of construction (as discussed in Section 3.2), a further reduction in the line pack would be expected.This would either represent a reduction in reliability and peak flow handling capacity, F I G U R E 4 Existing natural gas distribution system suitability for pure hydrogen.
or a need to install new dedicated storage not currently required on the network.
In most heating climates where gas use is much higher in winter than summer, additional gas storage is often incorporated into the gas network to provide a seasonal buffer.The volumes of gas involved are large, such that the use of above-ground storage facilities (such as the gas-o-meters previously used in the age of town gas) has largely been rendered impractical.Subsurface gas storage in depleted gas reservoirs, constructed salt caverns, and aquifers will be required to balance the system if there is variation in demand, yet H 2 is both geologically and biologically reactive. 61Storing H 2 in depleted reservoirs formerly containing natural gas is possible but will likely result in depleted product. 55,62,63urthermore, uses such as fuel cells that require high purity hydrogen may be impaired if hydrogen has been contaminated due to storage in a former gas reservoir. 64n the other hand, using salt caverns for hydrogen storage should not compromise the integrity of hydrogen as it should not react with salt, and salt caverns are used today for natural gas storage. 65,66However, suitable geology may not be available where storage capacity is required and not all salt domes are pure salt.Given the difficulties associated with using depleted natural gas reservoirs to store hydrogen, construction of "salt dome" storage facilities could represent a significant additional cost. 14

| End use
Equipment (appliances, devices, and so on) designed to burn or derive energy from a gas mixture is optimized around the properties of that gas mixture.The tolerance for variations in gas properties, notably energy density per unit volume, flame speed, adiabatic flame temperature, explosive range, and the Wobbe index (an indicator of the interchangeability of fuel gases in combustion equipment) varies with the type of device.][69][70][71] However, very few appliances or end-user devices designed to use fossil gas mixtures are suitable for use with pure H 2 without significant modification or replacement. 72atural gas devices and appliances are incompatible with pure H 2 because of the physical and chemical differences between CH 4 and H 2 (Table 1).Hydrogen's smaller size allows it to escape more easily and permeate through materials, risking explosive-level concentrations and climate-warming emissions. 15Hydrogen's lower density also causes it to rise and accumulate at high points in enclosed spaces.Although the difference in buoyancy is somewhat offset by hydrogen's greater diffusivity, the greater diffusivity can lead to more rapid leakage.
F I G U R E 5 Existing natural gas storage system suitability for pure hydrogen.
H 2 is also more explosive, ignitable, burns hotter, and the flame is faster with lower visibility than CH 4 ; these characteristics yield higher safety risks.The significant differences in properties between typical natural gas mixtures and H 2 , therefore, necessitate changes in the design of burners and burner management systems to achieve comparative levels of safety, which must then be certified (Figure 6). 17,67For example, all H 2 burner appliances require flame failure detection apparatus such as that used in the burners for ovens and broilers that shuts off the flow of gas when ignition does not result in a rise in gas temperature within a few seconds of the gas valve opening.
A quantitative risk assessment (QRA) was carried out in advance of a planned trial of pure H 2 in a residential gas distribution system in the UK. 18The report concluded that even if the homes were fitted with appliances designed and certified for use with H 2 , the risk of damage and injury due to fires and explosions would increase in frequency and severity.The report recommended that in addition to a leak testing program, excess flow devices of dissimilar type be installed in every home operating with H 2 (something, i.e., not currently done for natural gas supplies).One such device would be a conventional excess flow valve, which closes when flow through the valve greatly exceeds the maximum expected flow (due to, for instance, damage to a downstream pipe).Another would be a "smart meter," with an automated valve interlocked to close when the gas meter reported gas flow greater than the expected maximum.However, these devices were only expected to reduce the severity of fires and explosions, but not the frequency-therefore, the QRA asserted that injuries and deaths would be approximately the same as those encountered with existing gas use, even though events would be more frequent fires and explosions.The report also recommended that each room containing a gas appliance be fitted with a 10 × 10 cm nonclosing vent within 1.5 m of the ceiling, connected to the outdoors, to serve to vent any H 2 accumulating during a leakage event.Such vents would create a significant loss of heat and decreased comfort due to drafts, and therefore increased heating fuel use for the residents.
An additional safety challenge is the use of stenching agents, which are added to gas in the low-pressure distribution system to aid in leakage detection.Conventional sulfur-containing stenching agents, such as mercaptan used in the natural gas systems, are powerful fuel cell catalyst poisons. 64However, they can be used as long as fuel cells are not deployed or are fitted with adsorbents to remove the stenching agent at the point of use, but this risks fuel cell failure. 73Some previous research that has tested promising odorants compatible with fuel cells, but none appear commercially available. 74,75nally, although H 2 combustion would eliminate the toxic risk of carbon monoxide-a consequence of natural gas combustion-it would not eliminate NO x emissions that all fuels generate when burned in air, by virtue of the reaction of atmospheric nitrogen with oxygen.The hotter hydrogen flame could yield more NO x emissions than natural gas. 71,72,76,77Hydrogen combustion produces NO, which rapidly oxidizes to form NO 2 , a pollutant regulated globally.NO 2 is a major health risk and is linked to childhood asthma among other ailments. 780][81] For devices with an enclosed flue (furnaces, boilers, and so on), catalytic NO x reduction is possible but is expensive and high-maintenance, because a reducing agent is required which must be replenished.

| DISCUSSION AND CONCLUSION
Replacing natural gas with zero-and low-carbon hydrogen is viewed by many as an attractive decarbonization tool, because it can potentially re-use expensive infrastructure of considerable economic value.However, this paper has shown that there are numerous unresolved challenges with using hydrogen in the existing natural gas infrastructure due to its differing physical and chemical qualities compared to methane, the main component of natural gas.These differences have major implications for the entire natural gas value chainencompassing production, long-distance transport, local distribution, storage, to end use.The existing infrastructure is mostly unusable without de-rating to lower pressures (with consequently much decreased energy flow rates) or substantial investments, which often rely on unproven solutions.In addition, end-use appliances need replacement, and even then, they would still have safety and health challenges that would need to be overcome with new solutions.
Although many of the concerns associated with deploying pure hydrogen energy systems can be mitigated by blending hydrogen with natural gas, doing so will not help decarbonize the economy as it does not facilitate a gradual transition to pure hydrogen, and it only offers a small reduction in GHG emissions.The benefits from reduced GHG emissions are limited due to the greatly lower volumetric energy density of hydrogen relative to the gas it displaces.For example, a mixture of 20% hydrogen (by volume) into natural gas is only about 7% hydrogen in terms of energy content and, in the best case, represents only a 7% reduction in carbon dioxide emissions per joule of heat generated by its combustion.Furthermore, blending hydrogen with natural gas still has safety and climate risks from leakage and NO x emissions.
Overall, while repurposing the natural gas system for use with hydrogen may, at first, seem appealing, the limited practicality, risks, and data gaps strongly suggest that like-for-like gas substitution provides limited benefits for increased risks, even if major technical and economic hurdles are overcome.
That said, continuing to rely on natural gas is also not a viable option for addressing the climate crisis.Considering its physical and chemical properties, hydrogen is not an effective decarbonization tool for use in homes and buildings.For any decarbonization strategy, it is critical to determine if a fuel is in fact needed, and to compare with F I G U R E 6 Existing natural gas end use system suitability for pure hydrogen.
potentially more effective options such as direct electrification using renewably generated electricity.