Decarbonisation Technology - November 2021

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, CO 2 is at the core of carbon emissions, but other greenhouse gases like methane, nitrous oxide (N 2 O), hydrofluorocarbons (HFCs), perflurocarbons (PFCs), and others are also within the boundary. Therefore,

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

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