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Nov-2021

First principles of energy transition - Part 2

Part 2 focuses on the application of hydrogen as a potential solution, then reviews Scope 1, 2, and 3 emissions

Jean-Gaël Le Floc’h, Mel Larson, Darren York and Robert Ohmes
Becht

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Article Summary

Energy transition: where do we go from here? In part one of this two-part series, we examined the sheer magnitude of the energy transition change and how it will impact every part of our lives and economies. From there, we outlined some of the unintended consequences as well as the growth and expansion requirements within metals extraction, battery production, and overall electrical infrastructure to meet the shift away from traditional fossil fuels for transportation and power usage. In part two, we will focus on the application of hydrogen as a potential solution, along with the associated challenges, and review Scope 1, 2, and 3 emissions to understand what these mean for the energy industry and front-line consumer. Finally, we will close this series with some focal areas that the energy providers should consider as they develop their strategic, tactical, and operational plans to achieve their defined strategy.

Hydrogen: the gas that solves all our problems?
In these early days of energy transition, hydrogen has emerged as a lead option for addressing decarbonisation, as it is a key building block and has many diverse applications within the energy sector. Currently, most hydrogen is produced by steam methane reforming or partial oxidation of natural gas, refinery off-gases, LPG, and light naphtha (C5s and C6s). Both processes produce carbon monoxide and carbon dioxide that is sent to the atmosphere, resulting in these types of hydrogen being labelled as grey hydrogen. These production methods are being replaced by multiple alternatives that meet GHG emission reduction targets.

Presently, the bulk of hydrogen produced is used in the industrial sector, with a key consumer being refiners who utilise hydrogen to remove sulphur and nitrogen and increase the qualities of transportation fuels while also converting heavy hydrocarbons to more valuable products. The future vision is to utilise hydrogen in alternate ways — as a direct transportation fuel, as a source for heating and cooking, as a way to produce ‘green’ transportation fuels, and as a way to store energy as well as generate electricity.

While hydrogen does have a key advantage that, when it is combusted, it does not produce carbon-based emissions (only water), hydrogen itself does have several challenges. For the sake of brevity, the use of hydrogen for fuel cells is reserved for a future discussion. Instead, we will focus on simple replacement of natural gas as a source of energy via combustion for electricity generation, cooking, and home heating uses. One challenge is that the energy density of hydrogen on a mass basis is quite high but is one-third of natural gas heat value on a volume basis (~975 BTU/scf for typical natural gas and 273 BTU/scf for hydrogen). To demonstrate, let us take a typical natural gas pipeline that supplies fuel to front-line consumers. Most conventional burners can handle 10 to 15% hydrogen before they require modification to manage operating pressure and combustion profile (think of the home grill that can be run on propane or natural gas but requires different burners and regulator). If 15 mol% hydrogen is used to replace natural gas within the pipeline, a few interesting shifts occur.

To deliver the same net BTUs out of the pipeline, the volume of gas must increase by around 12%, which may seem simple enough. However, the pipeline already exists and replacing that pipeline to handle this increase is not only capital intensive but also may require months of regulatory permits. In addition, the operating pressure of the pipeline must be increased, which may require re-rating and other modifications, additional compression stations may be required, and additional compression power is needed, to the tune of around 16%. Assuming this power is generated by green sources, additional power supply and infrastructure may be needed, and the pipeline compressors will need to be modified. In the extreme example, the pipeline with 100% hydrogen will require over four times the compression horsepower to meet the same energy delivery.

Hydrogen will certainly be part of the mix to meet energy demands and shows great promise. However, technical hurdles like these just touch the surface of what the energy industry must address. Hydrogen refuelling stations will require extensive infrastructure installation, and transportation, storage, and shipping of hydrogen presents metallurgical, operating pressure, and process safety challenges. Conversion of hydrogen to high energy density liquid streams, such as ammonia, allows for re-use of existing combustion systems, especially in the shipping industry, but presents its own handling issues. Also, this option has its own challenges, for the same energy release as a fossil equivalent, 2.4 times as much ammonia is necessary, and pure ammonia burning typically exceeds current NOx emissions allowances. Leveraging of existing offshore infrastructure to convert wind energy to green hydrogen and using the gas lines to onshore infrastructure shows promise. Hydrogen, as a core building block, presents many opportunities for consideration as a solution for our energy needs.

What are Scope 1, 2, and 3 emissions and how does one impact them?
Over the last several years, the terms of Scope 1, 2, and 3 emissions are used regularly within the energy production and consumption industries, but their definitions may not be clearly understood. As a brief history, the World Resources Institute (WRI) and World Business Council for Sustainable Development (WBCSD) first released a corporate standard in 2001 and, over the years, have continued to enhance and revise this standard as well as provide guidelines and tools for corporations, cities, countries, and energy sectors. Details can be found at ghgprotocol.org.

To understand these definitions, let us first start with outlining which emissions are included. As expected, CO2 is at the core of carbon emissions, but other greenhouse gases like methane, nitrous oxide (N2O), hydrofluorocarbons (HFCs), perflurocarbons (PFCs), and others are also within the boundary. Therefore, when preparing balances for a given entity or looking for improvement opportunities, each of these areas should be explored.

The figure opposite summarises the definition and boundaries for Scope 1, 2, and 3 emissions.
Scope 1 and 2 are the emissions that most entities have a clearer understanding of accounting on, as they are often required for tracking and filing by regulatory entities and corporate mandates. These are the emissions that are created by the fuel and power that is consumed or purchased by a given entity to convert their raw materials to a final product for either processing by another entity or use by the final consumer. Therefore, whether it be the purchased electricity from the local power grid, use of natural gas or coal for steam and power generation by the plant directly, or the gasoline and diesel used by the vehicles associated with the entity, all these combine into the Scope 1 and 2 emissions.

Scope 3 emissions are more challenging to account for, as they relate to the entire energy required to produce and transport the raw material, as well as the raw material itself, and then the emissions created by the next processing entity through to the final product. To track, understand, and identify improvement opportunities, the entity must have a clear understanding of their entire value chain and the associated carbon footprint, which is no small feat. The trend continues to increase of those entities that are required to track and report these emissions.

Most energy companies and firms are beginning the process of identifying ways to improve and reduce Scope 1 and 2 emissions, especially those who have set substantial reduction targets by 2030 to 2035, as well as tracking and understanding their upstream and downstream Scope 3 emissions. To begin the process, a multi-layer and bi-directional process is recommended (see figure above). As with any entity, underlying performance starts at the equipment level. Therefore, measuring and tracking energy usage and identifying improvements must start here. Once the consumers and producers are clearly understood, one can move out several levels to the unit, intra-unit, and site-wide levels. For some organisations, these distinct levels may not exist, but within the modern refinery, petrochemical plant, or factory, multiple units must work together to produce the final product slate and having a clear understanding of their integration, both in process and energy, will illuminate improvement areas. Finally, with these levels and associated integration defined, the entity can evolve to examine the entire value chain to address Scope 3 emissions, both actual and potential improvement.


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