Repurposing Natural Gas Lines:
The Hydrogen Opportunity
Author: Caroline Kenton and Ben Silton
Call it a crisis or call it an opportunity – but it’s clear that the gas supply chain faces strong winds in its future. The winners in the energy transition will be those who shift their sails early and catch the winds blown by shifting regulations, policies and customer preferences. If you’re curious how ADL can help you leverage innovation to stay ahead of this transition, fill out the form to the right.
In our previous article “Repurposing Natural Gas Lines: The CO2 Opportunity”, we discussed the enormity of natural gas pipelines across the U.S. and the opportunity to repurpose them to transport carbon for utilization and storage.
However, while carbon capture, utilization, and storage (CCUS) could play a key role by helping us manage our greenhouse gas emissions, it does little to help fill the gaping hole sure to be left by the energy provided by natural gas today. Enter hydrogen. For processes that today rely on fuels and are difficult to electrify – e.g. cement/steel manufacturing, shipping/freight/aviation, etc. – we can provide infrastructural support towards decarbonization by repurposing gas lines for hydrogen transport.
Hydrogen offers major strategic value for energy-intensive sectors and utilities alike: if we don’t continue using lines for energy transport, we will simply stop building them altogether as more and more authorities ban new gas infrastructure and as more consumer groups speak out against gas – and utilities perhaps could be forced to gradually begin to remove them (which could get ugly). Over time, one would expect decreasing natural gas volume over fixed line infrastructure to result in increasing gas prices, accelerating electrification, thereby restarting the cycle and perpetuating an existential threat for the whole gas supply chain.
So, the crux of the long-term battle here is not over the lines themselves – it’s over gas as a major energy resource altogether.
Disclaimer on H2
Before touting hydrogen as the key to a clean future, it’s critical to note that not all hydrogen is created equal. Natural gas is a hydrocarbon and therefore will always release carbon when combusted – but hydrogen can be carbon neutral. Hydrogen combustion releases only energy and water as byproducts (unless nitrogen is present, in which case the process can create harmful NOx as well). Unfortunately, hydrogen rarely is truly carbon-neutral today due to its production methods.
Most hydrogen production is lumped into four categories: green hydrogen, grey hydrogen, blue hydrogen, and turquoise hydrogen.
- Grey hydrogen is made through steam methane reforming, which requires the burning of natural gas. This creates “embedded carbon” in the hydrogen that could (and should) be accounted for at time of use. Unfortunately, the vast majority of hydrogen created today is grey.
- For those production methods that release greenhouse gases but at a lesser rate, you can have so-called “blue” and “turquoise” hydrogen:
- Blue hydrogen closely resembles grey hydrogen, but is coupled with CCUS to limit emissions.
- A new form of production, turquoise hydrogen, uses a high-temperature chemical pyrolysis to break down methane into hydrogen and solid carbon.
- Green hydrogen is generated using excess renewable energy to power the electrolysis of water, making it a truly clean energy source. The economics of this technology do not yet pencil out in most cases due to the low utilization of electrolyzers powered by wind and solar.
In summary, the emissions advantages of hydrogen use are highly dependent on its method of production. If our goal is to move away from natural gas, continuing to burn it to create grey hydrogen is counter-productive. Therefore, significant innovation needs to take place to make green(ish) hydrogen a viable and cost-effective industry.
Where are we today?
Investments and innovation are gradually making hydrogen cheaper, and while it’s not yet cost-competitive in most cases, there are some promising projects providing blueprints for future scaling.
UK gas distributor Cadent and energy giant Equinor are working together on the H21 North of England initiative to convert the North of England to hydrogen by 2035. This project – including a 12.15 GW hydrogen production facility – could be the first policy initiative for the UK government assuming the critical safety evidence is shown by 2023.
Germany has a similar program with GET H2 which aims to create a nationwide hydrogen program by generating green hydrogen from renewable sources via electrolysis and transporting it across the existing gas infrastructure.
Zooming out, the whole EU has a Hydrogen Strategy for a Climate-Neutral Europe which is part of the EU’s Green Deal to boost clean hydrogen production. Before 2024, they will install at least 6 GW of electrolyzers for up to 1 million tons of clean hydrogen, and, by 2030, their capacity will exceed 10 million tons. European experts have recognized that an efficient transition to carbon neutrality requires leaving natural gas behind in favor of a robust hydrogen system. How far behind will the US remain?
Investment and innovation
Investments in the hydrogen transition need to come from all angles:
|Production (Supply)||Storage & Transport||Consumption (Demand)|
|Make it cheaper|
Make it cleaner
|Make it safer|
Make it efficient
|Make it hydrogen-friendly (i.e. fuel-flexible!)|
Much of today’s hydrogen investments come from oil & gas giants like Shell and bp. Only time will tell how much of this is greenwashing – but arguably no one else is truly better positioned to lead the hydrogen transition. Oil & gas majors have all the engineering expertise, all the logistics and operations learning, the patience, and all the incentive to get and stay ahead in the supply-side turf war. And assuming pipeline operators and gas utilities hold their ground, the physical skeleton of hydrogen infrastructure will likely resemble that of natural gas today – centered around industrial ports and major pipeline routes connecting large population hubs.
One important shift, though, is that while today’s natural gas supply comes from large-scale, concentrated sources (underground wells), hydrogen will be produced (and used) in a more distributed manner. For the foreseeable future, electrolyzers will be on the order of kW or MW, not GW, and hydrogen fuel cells are unlikely to ever reach a GW scale for grid use (and probably not for transportation). For this reason, it’s conceivable that the new gas lines of the future may be smaller in diameter – thereby carrying higher CapEx and O&M per cubic foot of transported gas.
One major wild card could be hydrogen’s market share in transportation applications. Batteries have a strong head start on hydrogen in the passenger vehicle space, and if innovation continues, batteries will gradually overcome limitations on energy density (its biggest drawback today relative to fuel cells) as well as charging speed and useful life. Hydrogen will come down in cost, but it will always require the extra step of electrolysis – and if we continue the battery-electric vehicle (BEV) transition with urgency, the hydrogen players may not have enough time to achieve any appreciable market share before BEV infrastructure fully permeates our transportation network and edges fuel cell OEMs out of the market. In other words, hydrogen could end up playing a larger role in industries like aviation, ocean freight, and Class 8 trucks (where energy density matters more), but otherwise its dollars may be best spent on decarbonizing our grid (so that BEVs run on power that is actually low-carbon!).
So how would a transition work?
- Many experts suggest that hydrogen can be blended into natural gas at a rate of up to 20% without causing problems in transport, storage, and most end-use applications. Scaling up to 20% as soon as possible lets us build a robust supply chain, bringing down costs and pulling new innovations into the supply market.
- In the meantime, we need to make our transportation and storage infrastructure capable of safely handling higher levels of hydrogen, which causes safety issues like embrittlement and decarburization. This includes things like updating our pipelines with hydrogen-safe coatings and components; better leak prevention, identification, and repair mechanisms; better operational methods for gas blending, state, and flow management; and distributed monitoring solutions to reduce maintenance costs and mitigate safety hazards.
- Also in the meantime, we need to transition our end-use equipment, both big (e.g. industrial high-heat-process machinery) and small (e.g. gas stoves) run safely on hydrogen blends above 20% (ideally, up to 100%), given its wide flammability limits and higher flame speed – or otherwise electrify altogether. Remember that the open-air combustion of hydrogen creates NOx, so this is not a trivial effort (no one wants NOx filling grandma’s kitchen).
- Only once those transitional hurdles are surmounted can we further ramp up hydrogen blending beyond 20% into our natural gas networks. It’s unclear where this blending rate will eventually settle, as technologies decarbonizing natural gas itself such as renewable natural gas (RNG) through methods like anaerobic digestion and power-to-gas are in some cases already an efficient and cost-effective use of capital in a decarbonization effort.
In any case, it’s becoming clear that we need to transition today’s gas infrastructure to become capable of integrating appreciable levels of hydrogen. If you’re still reading this article, you probably want to know how that could be done in pipelines.
Challenges of H2 Pipelines
It will be far cheaper to adapt and repurpose our existing pipelines than to build new ones altogether; Siemens has quoted pipeline retrofit costs at an estimated 10-15% of the cost of new construction, assuming all required innovations (e.g. embrittlement management) become commercially available. At ADL we speak with enough experts to know that this will happen; the question is how.
Before we go and pump our natural gas pipelines full of hydrogen, we have to better understand the chemical challenges that hydrogen brings with it.
Hydrogen and natural gas have different physical properties that make their handling unique. For starters, H2 is a small molecule about 8 times lighter in mass than methane, making it leak faster and through smaller pores. Also, while natural gas is still lighter than tropospheric air, it tends to have odorants added in production to make leaks more obvious; hydrogen would need similar odorants to enable leak detection without impacting its use. Further, both hydrogen and natural gas have auto-ignition temperatures over 1000℉, but hydrogen has a much larger range of flammability and extremely low energy requirement for ignition. Under peak conditions, which is just a 29% hydrogen-to-air volume ratio, hydrogen will easily ignite with something as small as a single spark.
Though the physical differences between natural gas and hydrogen are well understood, the risks for repurposing pipelines are not as simple. In addition to the general considerations we previously offered for transporting CO2 (e.g. differences in temperature, pressure, etc.), we’ll add a few more here:
|Brittleness of Materials and Seals||Hydrogen is highly diffusive due to its low density. Seals and seams must stay tight to limit losses and minimize explosion risk. Further, hydrogen aggressively attacks mild steels, causing decarburization and embrittlement.|
|Incompatibility of Pump Lubrication||From existing H2 pipelines, we know that H2 and natural gas pumps require different lubricants.|
|Probability of Accumulation||Accumulation of H2 poses a significant explosion risk that could be catastrophic.|
|Long-term Pipe Corrosion||This is a two-part challenge: how can we understand the corrosion pipelines have already suffered from natural gas, and how will a transition to carrying hydrogen affect life expectancy?|
This table demonstrates that there are significant risks to be addressed prior to ramping up hydrogen blending appreciably – and we’re likely facing years of careful engineering studies and pilot projects. But if we pull it off, the payoff is massive.
Using Existing Lines for Transporting Hydrogen - and Storing Electricity
Today, the gas and electric grids function largely independently, with one key exception: electricity generation from gas, typically in massive power plants. But what if we could seamlessly convert one into the other – even at the city, building, or even household level?
In a future where renewables and green hydrogen technologies are cheap, today’s gas line network could essentially function as a giant, connected battery. When electric demand is low, cheap power can drive hydrogen electrolysis and power-to-gas processes followed by pipeline injection; in other times, when electricity demand is high, gas can be pulled out of lines to create electricity with fuel cells, linear generators, or emissions-controlled combustion, all of which could run on gas blends. These conversions will all be subject to imperfect efficiencies, and thus there will always be some net loss in a round-trip conversion, but the benefits of supply flexibility cannot be understated in the high-renewables grid of the future.
To accomplish this, the gas network will need access to flexible pockets of hydrogen-friendly storage in order to maintain safe pressure levels – for example, on super sunny and windy days with a ton of excess renewable electricity, we won’t want to pump pipelines full of gas until they pop! Salt caverns could prove to be an early example of successful gas storage at scale. Operators of those storage facilities and of the pipelines themselves must be nimble enough to maintain safe pressure, temperature, and blending with shifting demands in real-time.
Blending also becomes a critical issue in this scenario. If point source inputs are feeding homogeneous gas (e.g. electrolyzers would feed hydrogen, anaerobic digesters would feed methane, etc.), but all end-use equipment components that convert gas to electricity (or heat) are designed to run on some methane/hydrogen blend level range, then either gas must be effectively and promptly blended after pipeline injection or the range of acceptable blends has to be extremely flexible. Some critical level of blending will be required, though, due to the varying temperatures and pressures required to handle hydrogen and methane as described above.
Once these hurdles are cleared, though, this vision of interwoven electricity and gas networks – with transitional gatekeepers such as reversible fuel cells – unlocks functionally complete renewables penetration on the electricity grid, consistently utilizes otherwise curtailed intermittent renewable power, and yet preserves the critical role of gas infrastructure.
In this way, hydrogen-friendly gas line infrastructure could not only clear a path to full decarbonization but could also increase the flexibility of the entire electric grid system.
As the hydrogen supply chain continues to mature, we need to spend more time thinking about how it’s going to re-shape our energy grid beyond the applications it serves today. As entrepreneurs and innovators, we need to acknowledge the challenges, but understand the immense opportunity hydrogen could offer as a clean fuel and storage medium. Repurposing natural gas pipelines is a critical piece of this transition, and we need both bodies and minds working on this effort.
ADL will be launching a Gas Line Innovation Challenge to solicit novel solutions from the entrepreneurial ecosystem for repurposing natural gas pipes to transport carbon, hydrogen, or other materials. We’d love to chat with any innovators, experts, and infrastructure managers at gas utilities, gas majors, or other industry groups about how to make this challenge as impactful as possible. Get in touch or request more information on the challenge by clicking the “Schedule a Conversation” button below.
Upcoming Gas Line Innovation Challenge: Learn More!
In our upcoming ProblemSpace Gas Line Innovation Challenge, ADL will work with gas utilities and other partners to solicit innovations in areas that may include 1) Transition Enablement, 2) Gas Line Hardening, and 3) Gas Leak Management.