By Yuan-Sheng Yu, Lux Research

Natural gas is widely viewed as a transition fuel as we move from today’s fossil fuel-dominated energy system towards a largely renewable energy system of the future.

In many parts of the world, the capacity for natural gas is being ramped up as coal-fired power plants are phased out, but in the longer-term natural gas is expected to be replaced by hydrogen as the bulk energy carrier.

However, that shift from natural gas to hydrogen is neither simple nor straightforward. With an existing natural gas infrastructure and more than US$1 trillion of additional pipeline projects around the world due to be completed in the coming years, natural gas pipelines appear to be ideal to transport and distribute hydrogen.

But the complexity of the natural gas infrastructure makes it difficult to judge how easily and inexpensively it can be switched over to hydrogen. Hydrogen compatibility in existing natural gas infrastructure depends on factors including operational pressure, hydrogen concentration, and the technology of the metals used.

Getting the mix right

Hydrogen blended with natural gas may be permitted for up to 10% or 20% of capacity, depending on the system. However, that upper limit is largely determined by turbines, compressors, and end-use appliances, rather than just pipelines.

Operating with 100% hydrogen may be technically possible, but low-strength steels less susceptible to hydrogen embrittlement would need to be used. Or the system should be operated at reduced pressure.

Bearing in mind the trade-offs required, it is not immediately clear how the natural gas grid can be adapted to integrate hydrogen. There are four distinct strategies to tackle this:

1. Reform natural gas downstream to produce hydrogen

This is the most obvious approach to delivering hydrogen using the gas grid. Hydrogen produced from natural gas through a process of steam methane reforming (SMR) is injected into the low-pressure distribution network, eliminating the need to adapt either the upstream transmission pipeline or the downstream distribution network. However, small-scale SMR is economically challenged, losing much of its benefits from economies of scale that currently make it the low-cost, dominant form of hydrogen production. To exacerbate the issue, carbon capture and sequestration costs are also considerable on a small scale if a zero-carbon hydrogen stream is desired.

2. Build dedicated new hydrogen pipelines

There are currently around 4,500 km of dedicated hydrogen pipelines around the world, though nearly all are short-distance pipelines. To meet the needs of long-distance hydrogen delivery, new hydrogen pipelines would need to be built with the appropriate steel grades and compressor station technologies. While new pipelines address the compatibility question, they come at a high price.

3. Retrofit compressor stations for hydrogen

Pipelines themselves are very expensive, costing millions of US dollars per kilometer. Instead of building a brand-new pipeline, an existing natural gas pipeline could be switched to hydrogen use and the compressor stations that maintain gas flow upgraded to hydrogen compressors. Depending on steel grade, the pipeline operating pressure may need to be reduced to lessen the risk of hydrogen embrittlement.

4. Blend hydrogen with natural gas

This is a near-term step that gas system operators can take to introduce hydrogen and decarbonise the gas grid. Hydrogen-natural gas blends can be reasonably tolerated up to 10% or 20% of capacity, which – given the sheer size of the natural gas system – is an extremely high limit from a hydrogen supply perspective. A typical natural gas transmission pipeline will require hundreds of megawatts of electrolysis to produce enough hydrogen to reach that limit. Should pure hydrogen be required downstream, pressure swing adsorption (PSA) technology can be used to separate the hydrogen from the natural gas feed, yielding a high-purity hydrogen stream and a separate natural gas stream.

Currently several countries, corporations, and innovators are looking at ways to tackle the challenges of integrating hydrogen into the existing natural gas infrastructure. The following are key developments, projects, and proof-of-concept demonstrations taking place globally: 

• The H21 Projects in the United Kingdom (UK): A consortium of UK regional gas distribution operators in 2015 investigated the feasibility of converting the entire UK natural gas distribution network to hydrogen, and converting all UK household gas consumption to hydrogen. H21 is a foundational element of the UK’s hydrogen strategy launched in 2021. The key findings from the flagship Leeds City Gate Project concluded in 2016 showed the transition would be technically feasible, would cost approximately US$5.4 billion, and would result in an average 7% increase in household gas bills.

• HyDeploy in the UK: In 2021, the HyDeploy initiative blended up to 20% hydrogen in a closed gas network that serviced 130 residential and commercial buildings and concluded that no modifications to downstream appliances were necessary. While it is generally known that 20% hydrogen blending in the natural gas grid is technically feasible, the project provided an additional real-world data point as countries continue to look towards decarbonising their heating network with hydrogen.

• HYPOS in Germany: The HYPOS project in Germany explores the idea of transporting hydrogen through an existing 511,000 km natural gas grid, among other approaches. At the point of use, hydrogen will be separated using an ultrathin carbon membrane developed by German research organisation Fraunhofer-Gesellschaft with pores smaller than a nanometer, allowing for the selective passage of hydrogen molecules. While transporting hydrogen in various blended rates in natural gas grids is an attractive option, the downstream separation for pure hydrogen remains a key challenge that has yet to be addressed.

• Mitsubishi Power in the United States: Mitsubishi Power and El Paso Electric are developing a hydrogen roadmap to support El Paso Electric’s goal of an 80% carbon-free resource mix by 2035 and 100% by 2045. The first step in the project is to convert El Paso Electric’s Newman Power Station’s newest unit from 100% natural gas to a 30% hydrogen blend, with a target of 100% hydrogen by 2045. Mitsubishi Power continues to establish its position as a leading hydrogen turbine supplier and is also involved in projects with Entergy and the Intermountain Power Project. Switching to hydrogen presents a technically feasible pathway for utility companies to reduce their carbon footprint while utilising existing assets.

• CLP Holdings in Australia and Hong Kong: Supported by an agreement with the Government of New South Wales, CLP's subsidiary EnergyAustralia has begun preparation works on Tallawarra B, a net-zero emissions power plant designed to use a blend of green hydrogen and natural gas. It is scheduled to go into operation in time for the 2023-24 Australia summer, and EnergyAustralia will offer to buy 200,000kg of green hydrogen per year from 2025. In Hong Kong, the two new gas-fired power generation units at Black Point Power Station could be re-purposed and retrofitted to use 100% hydrogen in future. CLP is also working with GE to jointly develop a decarbonisation roadmap for the other eight units at the plant and explore the feasibility of burning a variable blend of natural gas and hydrogen up to a possible ceiling of 100% hydrogen, supporting CLP’s goal to reduce the emissions of its generation facilities. 

Considerable operational challenges remain over how and when hydrogen should be blended with natural gas, and how natural gas networks can be switched to hydrogen without disrupting entire systems.

Retrofitting compressors may be an economical strategy, but it would take months to replace compressors on the half dozen stations on a 500 km pipeline, while it is relatively easy to build a steam methane reforming (SMR) facility parallel to a pipeline.

The optimal solution to repurposing infrastructure to accelerate the hydrogen economy will ultimately depend heavily on the specifics of the assets. But now is the time to evaluate options and apply ingenuity as we plot a course towards a sustainable energy future.