4. Infrastructure and transport of renewable and low-carbon gases

4.1 Increasing grid injection of biomethane

About 90% of biomethane plants in the EU are connected to the gas grid. About 20 TWh/yr of biomethane was injected in and transported through gas grids in Europe in 2018 (approximately 0.4% of transported gas). Large differences exist between countries regarding the connection profile.

Biomethane is similar to natural gas (LHV 36 MJ/m3),9 allowing it to be injected into the natural gas transmission or distribution grids with the appropriate purity and quality standards. Biomethane can be blended with natural gas without requiring any gas grid modifications.2 Biomethane is often produced in small-to-medium installations located close to gas grids.2 About 20 TWh of biomethane was injected in and transported through gas grids in Europe in 2018 (about approximately 0.4% of transported gas), with higher ratios in some countries.2 In the EU, about 90% of biomethane plants were connected to the gas grid in 2019, either at the distribution or transmission level (Figure 4.2).

Biomethane grid connection types vary by country (Figure 4.3). Germany had almost only grid-connected installations in 2019; Sweden had predominantly non-grid connected installations (~79%); Denmark (96%) and France (89%) had mostly distribution grid-connected installations; and Italy mainly had transmission grid-connected installations (75%).

Biomethane grid injection volume in Europe has increased from around 5.5 TWh to approximately 20 TWh per year over the last decade. This share is expected to increase to 5%-8%, on average, by 2030 based on European and national targets, with differing shares among EU member states.2

EU biomethane production and injection in gas distribution and transmission grids is increasing because of European and national policies, such as the RED II, the Gas Directive, the Innovation Fund, and CEN standards. The biomethane injection volume in the EU has increased from around 5.5 TWh/yr in 2010 to around 20 TWh/yr in 2018. The share of biomethane plants without a grid connection in the EU has gradually decreased to about 12% of biomethane plants in 2019 (Figure 4.4). The share of biomethane injected into the EU gas grid is expected to increase from 0.4% to 5%-8%, on average, by 2030 based on targets on European and national levels, with differing shares among member states.2

France is paving the way for a regional biomethane planning framework to map high potential zones that aim to increase and coordinate biomethane production and grid injection.

EU member states are starting to establish issuing bodies for end-consumer disclosure (so-called GoO) according to RED II, Article 19.80 For example, France used the transposition of the RED II to introduce a binding mandate for 10% biomethane in the French gas grid by 2030.2 To facilitate this, France is developing a national biomethane planning framework to map the high potential zones for biomethane production and grid injection (see showcase projects in section 4.3). Several other European countries are also developing innovative concepts to further scale-up biomethane gas grid injection; these are highlighted through the showcase projects.

Showcase projects

4.2 Early commercial deployment of biogas pooling and reverse flow

Biogas pooling is in an early development stage, with two main projects in Europe: one in Bitburg, Germany and the other in Twente, the Netherlands.

Biogas production installations are often small or medium in size. In Europe, about 16 bcm of produced biogas is currently not upgraded to biomethane, which can be injected into the gas grid. This biogas is largely used for local baseload heat and electricity production.2 To increase injection volumes of biomethane into the gas grid, biogas needs to be upgraded to the desired quality and purity standards through a costly upgrading process.

Biomethane grid connection costs can be significant when multiple smaller biomethane plants individually connect to gas grids. Biogas pooling is a way to upgrade existing dispersed biogas production in a large, centralised biomethane upgrading facility located close to the gas grid. Produced biogas at multiple dispersed installations can be transported through biogas pipelines to the centralised upgrading facility. In this way, pooling enables existing dispersed biogas production plants to increase efficiency and share the costs to upgrade biogas to biomethane.2 This concept does not require each biogas installation to individually invest in an upgrading facility; instead, it allows for dynamic adaptation to fluctuating raw gas compositions and provides flexibility for baseload electricity production through the centralised production of biomethane.

Pooling concepts are in the early stages of development, with two main projects: one in Bitburg, Germany (biogaspartner) and the other in Twente, the Netherlands (biogasnetwork). Another example project includes the Stadtwerke Schwäbisch Hall, where a regional biogas grid was developed to transport biogas from rural and regional areas to CHP plants in the nearby urban region. The local energy supplier has the flexibility to use the biogas for heat generation purposes or to upgrade it to biomethane.

Reverse flow plants are in early commercial deployment, with several plants installed in France (two in 2019), Germany (more than six in 2020), and the Netherlands (one in 2019).

Medium- and larger-scale biomethane plants feeding into low pressure (<4 bar or between 4 and 6 bar depending on the country160) gas distribution pipes in areas with little local gas demand might lead to local oversupply—for example, during summer months with low gas demand.161 Local oversupply could be mitigated by allowing biomethane to flow upwards towards medium or even high pressure grids using a solution called reverse flow technology.2 A reverse flow unit is a facility that allows gas transfer from the distribution system to the upstream transmission system using a decentralised gas compression mechanism that increases pressure.162 The reverse flow concept allows the biomethane injected at the distribution level to be transported to different regions and across borders through transmission grids (bidirectional transport).2, 163

This solution fundamentally changes grid flows compared to the current downward flows from high to medium to low pressure. Reverse flow technology is being implemented and generally requires limited investments. The cost of a reverse flowinstallation,however,dependsonthehoursof operation and the pressure on the transport network (compressioncosts).Theoperatingcostofareverse flow installation could, in some cases, be higher than a direct connection to the transport network.

Reverse flow plants are in early commercial deployment. The first two reverse flow plants in France were commissioned in 2019.164 One reverse flow plant was installed in the Netherlands in 2019.165 In 2020, more than six reverse flow plants were installed in Germany.166

Showcase projects

4.3 Research and pilot projects on increasing hydrogen blending levels

Blending is in an early commercial stage, with several pilot projects ongoing across Europe. Hydrogen blending tolerances in the gas distribution grid could range between 5% and 20%.

Hydrogen blending in the existing gas grid is identified under the pathway as a way to quickly scale-up hydrogen supply, while limiting the need for hydrogen pipeline and end-user investments.2 Certain levels of blending hydrogen with natural gas are achievable without major upgrades or adaptations to appliances and gas infrastructure.46 Studies report blending percentages of between 5% and 20% of volume to be technically feasible in current gas distribution grids with minimal investments.167

However, the actual feasibility of blending levels depends on the hydrogen tolerance of end users and in appliances, including the ability to deal with varying blends. When moving to higher blending percentages, changes might need to be made to the infrastructure and to the end-user equipment and appliances (e.g. different burners). In general, building appliances have a higher tolerance for hydrogen admixing than industrial applications. The maximum concentration depends strongly on the type of end user and their specific gas demand (Figure 4.5). Blending is in the early commercial stage with several pilot projects ongoing, including the Thyga project.168 Avacon Netz and the German Gas and Water Association (DVGW) are also examining up to 20% hydrogen in natural gas blends in the Avacon distribution network in Saxony-Anhalt.169

Using pure hydrogen, in contrast, requires significant upgrades to appliances and infrastructure but at a lower cost than full electrification.46 End-use appliances also require conversions and adaptation to use hydrogen as an energy carrier. The City of Leeds H21 project, for example, estimates the cost and effort required for boiler and cook top replacements.170

At a distribution grid level, situations can arise where a relatively homogenous group of end users is connected to a branch of the grid, such as building owners. Homogenous end users will allow more easy blending of hydrogen than in situations where also some industrial users are connected. On a transmission grid level, many different users are connected to the grid. A possible technical solution to safeguard low tolerance end users, such as gas turbines, would be a downstream separation of the hydrogen from the blended gas stream through separation membranes (de-blending).2 Pilot projects are underway to test technoeconomic aspects of hydrogen separation, including the HIGGS project171 and the membrane separation pilot project in Prenzlau.172

Taking into account constraints in hydrogen tolerance in the grid and at the end users, EU member states have set specific limits on the amount of hydrogen that can be blended into natural gas grids (Figure 4.6). Various projects are ongoing to develop a better understanding of the maximum concentration with which hydrogen can be blended (see showcase projects in section 4.6).

Showcase projects

4.4 Early deployment of dedicated hydrogen infrastructure and storage

A gas pipeline typically transports hydrogen between the production facility and usage; truck transport is used for smaller volumes. Hydrogen can be blended with natural gas or dedicated hydrogen infrastructure can be developed. The FCH JU states in its Hydrogen Roadmap for Europe that around 66 hydrogen blending and pure hydrogen projects are under development in Europe.

The FCH JU states in its Hydrogen Roadmap for Europe that around 66 hydrogen blending and pure hydrogen projects are under development in Europe.46 For hydrogen users, a dedicated hydrogen pipeline or gas grid connection will be more cost- effective than an electricity grid connection to produce green hydrogen via electrolysis onsite.2

(Grey) hydrogen-dedicated pipeline infrastructures are already in place, connecting merchant producers to users. These pipelines are generally distribution pipes that operate at low pressures (10- 20 bar) and are operated by hydrogen producers.175 In the EU, 613 km of pipelines were installed in Belgium in 2016, 376 km in Germany, 303 km in France, and 237 km in the Netherlands, among others.176 These infrastructures are generally point- to-point, although some regional grids exist that transport hydrogen between industrial hubs, such as the Air Liquide grid-connecting industrial hubs in the North of France and the ports of Antwerp and Rotterdam in Belgium.177

Dedicated hydrogen infrastructure development is gaining momentum through conversion and repurposing of gas infrastructure as well as the early development of hydrogen networks, such as the European Hydrogen Backbone.

While new hydrogen infrastructure can be developed, it will be more cost-effective to convert existing pipelines for dedicated hydrogen transport. Existing natural gas infrastructure can undergo repurposing to noncorrosive and nonpermeable material to transport 100% hydrogen depending on the type of steel used for the infrastructure and the pipe pressure.2, 46 Repurposing mainly incurs costs to replace the compressor stations, valves, and metering stations; costs vary based on the local gas grid characteristics.2 The exact requirements for network upgrading to use 100% hydrogen are being investigated in multiple pilot projects, such as in the City of Leeds H21 project and the SGN Hydrogen 100 project.178

Retrofitting existing gas infrastructure to transport 100% hydrogen has only been tested on a pilot scale. Based on an estimation in the European Hydrogen Backbone study,179 investment costs to refurbish natural gas transmission pipelines are estimated at 10%-35% of new build pipelines; investment costs for new dedicated hydrogen pipelines range between 110% and 150% of the investment cost of a new natural gas pipeline with a similar diameter.180 The levelised costs for hydrogen transmission for refurbished natural gas infrastructure are estimated to be between €0.07 and €0.15/kg/1,000km.179 The levelised costs for hydrogen transmission for new hydrogen infrastructure, in contrast, are estimated to range between €0.16 and €0.23/kg/1,000km.179

The Dutch TSO Gasunie has already converted a 12 km natural gas pipeline into a hydrogen pipeline to transport by-product hydrogen from DOW to be used as feedstock by Yara in Zeeland, the Netherlands.181 Multiple other projects are exploring how existing natural gas pipelines can optimally be converted to transport hydrogen. In July 2020, the European Hydrogen Backbone initiative was launched, illustrating how a pan- European hydrogen transmission infrastructure can be developed by 2040 by building on existing gas infrastructure (Figure 4.7). About 75% of the future hydrogen backbone can consist of converted, existing natural gas pipelines, and only 25% will need to be new-built dedicated hydrogen pipelines.179

In Europe, early projects are exploring the use and potential of hydrogen storage in salt caverns to match future supply and demand.

The natural gas grid has a large intrinsic storage capacity (line packing), which is further enhanced by underground gas storage—for instance in salt caverns and depleted natural gas fields. Such large- scale storage can match seasonal demand and supply fluctuations. About 15%-20% of the total gas consumption is stored to balance gas production and consumption.182 Storage of future green hydrogen production allows intermittent renewable electricity production to be decoupled from demand. Across the EU, several projects are being developed that explore this power-to-gas-to-power cycle and the required storage capabilities.

Hydrogen storage in salt caverns is one of the most promising ways to store large volumes of hydrogen. In a typical salt cavern, storage capacity at 200 bar is around 6,000 tons of hydrogen or about 240 GWh. Storing energy in the form of hydrogen in salt caverns is estimated to cost around €100 million for a single salt cavern, which is at least a factor of 100 cheaper than storing that amount of energy in an electric battery.182 Estimations are that there is sufficient potential capacity in European salt caverns to store large amounts of hydrogen in many EU countries (Figure 4.8).183 The current gas demand in the EU is around 4,577 TWh (as of 2018),184 suggesting the technical H2 storage potential in the EU is sufficient to support a resilient future hydrogen energy system.