Blending Natural Gas and Hydrogen

M. SCHLEBACH, Emerson, Calgary, Alberta

Greenhouse gas (GHG) reduction has become a global endeavor. Initial efforts focused on methane (CH₄), nitrogen oxides (NO_x) and fluorinated gases due to their high global warming potential. Now attention has turned to carbon dioxide (CO₂) reduction due to the sheer volume of CO₂ emitted into the atmosphere. For example, CO₂ accounts for nearly 80% of GHG emissions in the U.S.

One relatively quick solution that offers immediate benefits for CO₂ reduction is hydrogen (H₂) blending with natural gas. H₂ combustion generates no CO₂ emissions, so every molecule of natural gas replaced with H₂ is one less molecule of CO₂ reaching the environment. This can create significant GHG reductions for natural gas-burning applications in industry, homes and the transportation sectors.

While the concept is simple, H₂ blending poses several chemical, logistic and control challenges. This article discusses the benefits and challenges associated with H₂ blending and provides process measurement solutions.

A burgeoning environmental problem. Global CO₂ emissions have been growing for decades, increasing average global temperatures and impacting weather patterns worldwide. A significant source of CO₂ emissions comes from burning coal and hydrocarbon fuels. The CO₂ generated is directly proportional to the amount of carbon in the fuel. Coal (C₁₃₇H₉₇O₉NS) and diesel (C₁₂H₂₃) have significant carbon content and generate prodigious quantities of CO₂ when burned. CH₄ is the main component in natural gas, and it has significantly less carbon and burns comparatively cleaner but still creates a CO₂ molecule for every CH₄ molecule consumed. H₂ offers the best fuel burning alternative, producing no CO₂ emissions.

Unfortunately, natural H₂ is in very short supply, and the gas is mostly created using industrial processes that can also produce significant GHG emissions. Green H₂ can be created through electrolysis powered by sustainable sources such as wind or solar, emitting no GHGs. Although many projects are seeking to expand green H₂ production, supplies remain expensive and in short supply.

An option is to use existing industrial processes such as steam methane reforming (SMR) or autothermal reforming (ATR) to make H₂ and capture and sequester the emitted CO₂. This blue H₂ produces significantly fewer GHG emissions and is more readily available in the short term since it utilizes existing industrial processes as a starting point.

As green or blue H₂ becomes available, an obvious source of CO₂ gas reduction can be immediately achieved by blending H₂ with natural gas for fuel combustion applications. As CH₄ is gradually replaced with H₂ in the fuel gas blend, CO₂ emissions are reduced (FIG. 1). CO₂ emissions reach zero as the H₂ concentration reaches 100%.

H₂ blending concept. Theoretically, H₂ blending offers an easily implemented strategy for reducing CO₂ emissions from burning natural gas. The existing natural gas transportation network is enormous, offering a ready-made means of transporting the cleaner burning fuel gas blend to existing users.

Ideally, existing natural gas combustion equipment (industrial boilers, heaters, gas-fired home appliances, etc.) could burn the cleaner-burning H₂ mix, reducing CO₂ emissions on a global scale. GHG emission reductions are tied directly to the concentration of H₂ in the mix, so as clean sources of H₂ become available, they could be used to increase the H₂ blend to as high as possible.

While this concept sounds promising, there are stark realities associated with H₂ blending that limit its implementation well below the theoretical maximums.

H₂ blending realities. The first challenge associated with H₂ blending is caused by H₂ itself. High concentrations of H₂ can defuse into the walls of metal pipelines, making them prone to cracking and stress corrosion. The rate of H₂ embrittlement depends on many factors, including the specific metals involved, the level of existing corrosion and stress in the pipe, the concentration of H₂ and the operating pipeline pressures.

The existing natural gas transportation network is vast and aging, so its ability to handle high concentrations of H₂ is difficult to predict. Overall, the long-term potential risk of pipeline failure appears to increase with increasing concentrations of H₂, but lower concentrations of H₂ seem to have little effect on the pipeline infrastructure.

Another challenge for H₂ blending stems from the differences in energy and physical density of H₂ vs. CH₄. H₂ combustion creates less energy than CH₄ (FIG. 2). In addition, the specific gravity of H₂ (2) is substantially less than that of CH₄ (16), so the resulting fuel gas blend has a lower density. Combining these two factors reduces the energy delivery capacity of a pipeline for a given operating pressure, and that reduction increases with H₂ concentration.

If the pipeline infrastructure can handle higher pressures, raising the operating pressure and delivering the same net energy is possible, but this increases compression costs. One option to address these issues is injecting H₂ closer to the point of use. This limits pipeline exposure and compression issues, but each injection station will have associated CAPEX and OPEX, increasing the blending net cost considerably.

There are other challenges associated with H₂ blending. Higher concentrations of H₂ affect flame formation and stability, and H₂ concentrations higher than 30% have a different electrical classification, raising equipment costs.

For all these reasons, lower blended concentrations of H₂ are a much more viable option in the immediate future. The potential CO₂ emission reduction of the resulting blend is less dramatic, but the numerous challenges associated with high H₂ concentrations are largely eliminated. Several global pilot studies suggest a H₂ blend of 20%–25% can be safely implemented within the existing natural gas distribution network, while performing well with existing combustion equipment.

Blended H₂ metering. Extensive studies have investigated the flow measurement of natural gas/H₂ blends. Coriolis meters are often the best solution for mass flow metering, and they can handle the full range of H₂ blends from 0%–100% concentration (FIG. 3). Coriolis meters are usually limited in size (16” or less) but alternative solutions are available for larger line sizes.

As mentioned, Coriolis meters are not usually used for larger bore pipe natural gas metering due to line size limitations, but they are an excellent choice for the smaller, pure H₂ flowmeter injections required in most H₂ blending applications.

Differential pressure transmitters are another option for natural gas pipelines, but the measurements must be compensated for component density, as well as temperature and pressure effects, and the pressure drop created by the orifice plate results in additional operating costs due to line loss.

Therefore, most natural gas metering applications use multipath ultrasonic flowmeters (FIG. 4). These meters cost less than Coriolis meters in larger line sizes, have virtually no pressure drop and are available in line sizes up to 42”.

Multipath technology improves flow measurement accuracy and reliability by making multiple measurements across many areas of the pipe to compensate for fluid dynamics and inconsistent flow profiles. Performance testing of these meters under real world conditions suggests these meters can measure blends of H₂ up to 25%, with minimal loss in accuracy.

Blended H₂ controls. A typical H₂ blending station is shown in FIG. 5 and includes a full-bore ultrasonic flowmeter to measure the incoming gas flow, a Coriolis meter and control valve to measure and control the H₂ addition, and a downstream gas chromatograph to confirm the resulting blend.

Both flowmeters should be pressure and temperature compensated for maximum accuracy, and an industrial chromatograph should be used to measure incoming and exit gas quality to confirm the resulting blended gas meets specifications.

Blended H₂ case studies. Several countries and organizations have implemented pilot studies to better understand the pros, cons, limitations and benefits of H₂ blending in real-life applications. The UK implemented a HyDeploy trial at Keele University to blend H₂ gas into the local natural gas grid to supply residential halls, student facilities and offices. The project proved that 20% H₂ could be blended with natural gas in the existing natural gas infrastructure, with virtually no modification to the transportation infrastructure or the fuel-burning equipment.

The U.S. Department of Energy (DOE) started the HyBlend initiative to study the feasibility of H₂ blending in the U.S. This multi-faceted project is investigating the impact of H₂ blending on existing pipeline materials of construction and the optimization of H₂ production and fuel cell facilities, and it is creating lifecycle emission models for various alternate fuel pathways. That project is ongoing, but early results look promising.

Takeaways. Using the existing natural gas transmission infrastructure, H₂ blending with natural gas can yield significant and immediate GHG reductions. While higher H₂ blend concentrations may be feasible for specific applications, 20%–25% blends can be implemented with existing transportation pipelines and fuel-burning equipment, with little to no modification.

Existing multipath ultrasonic meters can handle this level of blending with minimal impact on accuracy, and research is ongoing to create modified meters to handle a much broader range of H₂ blending. Coriolis flowmeters can be used for pure H₂ flow measurement in H₂ blending applications. Industrialized gas chromatographs are well suited to measure incoming and outgoing gas streams to confirm product quality, and to adjust the ratio controls as necessary to keep the blend on specification.

Based on the available research, it is likely that H₂ blending will be employed as clean H₂ sources become available and price competitive. If specified correctly, existing instrumentation and controls are available for these applications, and ongoing research may yield improved options.

NOTES

^a Emerson’s Rosemount^™ 3418 meter

About the author

MARTIN SCHLEBACH is a senior business development director and flow consultant for Emerson. He has more than 35 yr of measurement experience, focused mainly on ultrasonics. Schlebach is an active and contributing member of several industry committees, including AGA TMC, PRCI MTC and API COPM. He earned a degree in electronic engineering from SAIT Polytechnic in Calgary, Alberta.