Economics

The hydrogen economy is growing and will play an important part in the energy transition and net-zero targets. While traditionally used in refining and chemical production, hydrogen is now poised for its use in energy storage, power generation, transport, heating, and heavy industry decarbonization. The Metharc wellbore methane reformation process has the potential to drive down the cost of producing low-carbon (Blue) hydrogen close to, or below, the cost of Grey hydrogen. This would accelerate the supply and increase the volumes of low-carbon hydrogen and maximize the value of methane reserves that risk becoming economically stranded due to climate restrictions.

The cost of hydrogen production is reducing, but Green hydrogen production costs are still much higher than for Grey (~3-4x) or Blue hydrogen (~2-2.5x). The cost of producing Blue hydrogen at surface with atmospheric CCS is at least 1.5 times that of Grey hydrogen production.

Lost Reserves

“Climate goals dictate that the majority of known, economic, strategic fossil fuel reserves will not be permitted to be used and will be left abandoned in the ground, if we adhere to the climate agreements and stop producing hydrocarbons to stay within the 1.5 or 2.0 deg C climate limitations. This is approximately 60%, or 40 years, of global oil & gas reserves”.

[Ref.: https://ourworldindata.org/]

Terminal Value Risk

Climate restrictions dictate that the majority of known, economic, fossil fuel reserves will not be permitted to be used. This value loss can be significantly reduced through the at-source gasification, or reforming, of oil and gas to generate hydrogen, with the simultaneous injection downhole of the generated CO₂.

Our Zero Carbon to Surface methodology would enable the continued exploitation of these otherwise stranded energy reserves, allowing for the re-classification of oil & gas resources to become branded as hydrogen reserves.

[Ref.: https://ourworldindata.org/grapher/years-of-fossil-fuel-reserves-left]

In 2050 (30 years on the graph), significant energy reserves could be abandoned, impacting the global economy. As an example, the Danish Climate Act gives 2050 as the cutoff date for all oil and gas extraction in Denmark.

[Ref. : https://en.kefm.dk/news/news-archive/2020/dec/denmark-introduces-cutoff-date-of-2050-for-oil-and- gas-extraction-in-the-north-sea-cancels-all-future-licensing-rounds]

Billion tonnes Carbon (GtC) [2013]

CCS CO₂ injection, combined with the downhole reformation of oil and gas to generate hydrogen, significantly reduces carbon release at point-source. This will provide access to the 63% of potentially stranded reserves, through a climate beneficial method, providing continued, secure, long-term energy.

[Ref. : https://ourworldindata.org/grapher/global-carbon-budget-for-a-two-degree-world? tab=chart&country=Global+Fossil+Fuel+Reserves~Carbon+Budget+for+2C]

Stranded Reserves

To allow for only a 50 per cent probability of limiting warming to 1.5 °C… by 2050 nearly 60 percent of oil [744 billion barrels] and fossil methane gas [92 trillion cubic meters], and 90 percent of coal [826 billion tonnes] must remain unextracted in order to keep within a 1.5 °C carbon budget. This is a large increase in the unextractable estimates for a 2 °C carbon budget, particularly for oil, for which an additional 25 percent of reserves must remain unextracted. Furthermore, it was estimated that oil and gas production must decline globally by 3 percent each year until 2050. This implies that most regions must reach peak production now, or during the next decade, rendering many operational and planned fossil fuel projects unviable. We probably present an underestimate of the production changes required, because a greater than 50 per cent probability of limiting warming to 1.5 °C requires more carbon to stay in the ground and because of uncertainties around the timely deployment of negative emission technologies at scale.

[Ref.: https://www.nature.com/articles/s41586-021-03821-8]

Geopolitics and Climate Change Economics

A critical item that delays international agreement to climate change policies and their subsequent global implementation is the relative effects that any new policy has on each nation’s energy security and economy (i.e., potential new benefits received by one national economy may hinder another). As nations manoeuvre to obtain maximum energy security and economic benefit, they are tempted to block those policies that do not benefit them. Our technology helps accelerate international climate policy agreement and implementation, as it does not hinder or benefit any specific economy beyond the current status quo; global energy providers remain so (albeit in a different form; hydrogen in place of oil & gas).

The decarbonisation of oil and gas production at point-source could also allow for the continued exploration for new oil and gas reserves, if Zero Carbon to Surface becomes the default contractual criteria. A government’s terms and conditions for the approval of a production licence development plan (for oil and gas assets and their associated production of hydrogen to surface) would mandate that all CO₂ is simultaneously injected, and so the energy production becomes sustainable, and the climate advantages would be immediate. The global oil and gas market therefore converts to a hydrogen market.

We have purposefully designed our patented process as a Zero Carbon to Surface system. We hope this will encourage the political, energy and environmental lobbies to work together going forward, making energy a significantly net-negative carbon process together with a significantly net-positive climate and social impact. We hope this directly addresses and mitigates all arguments concerning potential damage to the climate from any future exploitation (not production) of oil and gas and leads to a more positive politically motivated focus on the sustainable use of our energy resources. The value of the wellbore decarbonisation of oil and gas is more than the sum of its’ parts, as the positive environmental and climate consequences downstream of the wellbore are far reaching within energy, agriculture, and health.

CO₂ Capital Costs

Commercial CO₂ separation technologies are expensive and lack durability. And there is a trade-off between building a new platform to cater to the separation unit or to retrofit to the existing platform. Both have considerable costs. Whether via pipelines or shipping enabled by cryogenic distillation technologies, the economics of CO₂ transport may not pay off, depending on distance to shore/customer.

…CO₂ demand for EOR is increasing rapidly, with an expected growth of 20% CAGR by 2024.

In terms of storage, not all developments have the luxury of depleted reservoirs in which to store CO₂, as do those in the North Sea, nor the ability to support the costs involved in CCS. In our research, we have seen a 16% reduction in CCS activity over the last eight years, with a clear pivot toward CCU.

 [Ref.: Arthur D Little, UNLOCKING HIGH CO₂ GAS FIELDS – CONTRIBUTING TO THE CARBON ECONOMY, Sept 2021 : https://www.adlittle.com/my-en/insights/viewpoints/unlocking-high-co2-gas-fields-%E2%80%93-contributing-carbon-economy]

Climate and Economic Benefits of Biogas-Geothermal

A common list of both the Climate and Economic benefits of the Geothermal value chain includes the following.

Long Term Energy Delivery & Price Stability

• Minimises fluctuations for long term energy delivery & price stability, reducing the influence of geopolitics (e.g., market pricing, international conflicts) and our dependence on oil & gas to supply our national energy requirements.
• Decentralises power production, reducing dependencies on the national grid.

Synergy between the power generation and agriculture industries

• Increase crop productivity and yields [CO₂ yields & Nutrient Availability].
• Lower NOx pollution improves crop yields by 10-25%. [Ref. (June 2022): https://news.stanford.edu/press/view/43874]
• Increase resource utilisation and efficiency to work the land.

Hydrogen generation close to the marketplace

• Delivers hydrogen at volume, converting the biogas’ methane downhole.
• Hydrogen as a source of water (irrigation).

Climate & Environmental Sustainability

• A circular Green Economy, with zero carbon returned to surface.
• Immediate reduction in carbon footprint via CCS.
• Reduces methane (CH₄, a potent GHG) transportation and distribution losses.
• No requirement for expensive capture of carbon emissions from the atmosphere, as wells produce no carbon.
• An ever-diminishing requirement for the recycling of old atmospheric carbon (via re-generation and use as synfuels) – which is expensive, energy intensive and environmentally harmful while the GHG transition through the atmosphere.
• a reduced requirement for rare earth metals when compared to green energy technologies.
• an improved social-economy and environment. The resulting cleaner air will reduce pollution-based cardiovascular and respiratory illnesses, which are a significant cost to the national economy through their demands on the national health services.

Future Proofing Biogas Production

• Allows for the continued use of biogas, generated from biomass processing to fertilizers, when the upgrading of biogas to biomethane is no longer a permitted option due to the CO₂ climate restrictions caused by methane combustion.

Long Term Energy Delivery & Price Stability

• Reduces fluctuations (e.g., oil & gas market pricing, international conflicts, geo-politics…)

Fast-track 2030 climate goals

• CCS, sustainable energy, cost reductions, and fossil free logistics.

Geothermal Sustainability

• More revenue streams; biogas, CO₂ CCS, district heating, power, H₂, water.
• Improved economics accelerates the growth of Geothermal energy projects, and enables development of marginal Geothermal projects
• CO₂ injection enhances the energy efficiency of the geothermal power fluid.
• CO₂ injection is a solvent at the wellbore supercritical condition, eliminating process permeability loss in the reservoir by dissolving potential biofilm deposits.
• Continued investment = security and utilisation of resources ‘under our feet’.

Natural Gas Sustainability

• More revenue streams; CO₂ CCS, power, H₂, water.
• Improved reserve recovery and utilisation through CO₂ injection, for Enhance Oil Recovery (EOR) to make more wellbore hydrogen.
• Better economics; adapt and re-use infrastructure, no high-cost CO₂
• Enables development of marginal or Brownfield projects.
• Continued investment = security and utilisation of resources ‘under our feet’.

Future Proofing Against Terminal Value Risk (TVR)

• Allows continued exploitation of known oil and gas reserves.
• Oil companies would no longer require to negotiate with governments about compensation for any oil and gas assets that would become stranded prior to production licence end.
• Governments would no longer require to account for the loss of value pools in specific parts of the economy.
• Through a value driven philosophy incorporating both CCS and hydrogen generation, this terminal oil and gas value loss is minimised, and direct value is gained through hydrogen sales, CCS, the motivation of corporations to mitigation of carbon taxes, collection of carbon credits (through CO₂ or CH₄ injection) and increased recovery of oil & gas reserves through enhanced CO₂ injection sweep efficiencies (EOR) providing more oil and gas for conversion to wellbore hydrogen.

Less Oil & Gas Refineries Required – the Merits of Wellbore Hydrogen

• Financial headlines that have stated the “US needs more refineries” or an “era of expensive oil is here to stay”, point to the lack of oil and gas processing capacity and the need for more oil and gas as an energy source. The long lead-times to refinery construction, high costs and local pollution associated with building refineries are well documented. Our patent pending technology can be compared to a mini refinery placed in each wellbore. After the oil and gas wellbore gasification, or reformation, only pure hydrogen, at pressure, would be delivered to surface. All exhaust (i.e., CO₂ plus trace compounds) is re-injected downhole. A true Zero Carbon to Surface system, delivering low cost H₂ production, replacing oil & gas, without any further need to refine the hydrogen. Call it a circular argument, a domino effect or a self-fulling prophecy, but with our wellbore refinery methodology the requirement for large, onshore oil & gas refinery upgrades (or new builds) for increased capacity reduces, as additional capacity is no longer required with diminishing oil and gas demand. As the hydrogen economy grows, a lower demand for oil & gas develops. As more wellbore hydrogen is produced (e.g., for power generation & transport), so less oil & gas volumes are produced to surface (being systematically replaced with more hydrogen), further reducing the need for oil & gas refinery capacity (saving huge upgrade or new-build time & costs). The knock-on effect is a continual reduction cycle of CO₂ production from not burning oil and gas for either power or transportation. There will still be a requirement for some finite refinery capacity for waxes, plastics and oils, but at ever reducing volumes as we also begin to phase out plastics.

The Economics of Blue Hydrogen

These overall life cycle cost reductions plus the multiple revenue streams from this multifaceted wellbore process makes this a business model profit-multiplier. By prohibiting any CO₂ from exiting the wellbore all downstream carbon capture costs and their associated process energy, finance and commodity requirements are subsequently reduced – with significant savings. The carbon footprint reduction is also immediate, as no carbon is produced to surface. This therefore provides longevity to oil and gas assets, future proofing them in an environmentally responsible way.

The full value of the wellbore decarbonisation of oil and gas is more than the sum of its’ parts, as the positive environmental and climate consequences downstream of the wellbore are far reaching within energy, agriculture, and health.

As with all things, the term economic depends largely on market, demand & subsequent price structures imposed.

The reality is that, unfortunately, Energy is not simply a commercial business, it is also largely a socio- economic and geopolitical necessity. When adding to this our environmental & climate necessities, with their associated short timelines, we begin to appreciate the very complex definition of economic.

As an example, it’s now economic to ship CO₂ across the planet in specialist pressurised CO₂ shipping, build specialised CO₂ harbours to dock these ships at, and invest in yet more CO₂ infrastructure to capture & use CO₂ [CO₂ pipelines and dedicated CO₂ injection wells are being commissioned and planned for newly licenced and yet to be explored aquifers]. Who’d have thought it, CO₂, and it’s not even an energy source its landfill.

Yes, government subsidies are perhaps a very important part of these project’s economics, but even the oil & gas industry has been receiving government subsidies and incentives of various kinds for many decades.

While we still continue to burn natural gas as efficiently as we can, the transition to a greener energy will nevertheless involve converting some of that same methane to Blue hydrogen in surface reformation factories; but this is yet more energy input to an additional process. However, we can instead reform and decarbonised the methane at source, subsurface, within its’ own wellbores. The process energy required would then be supplemented by natures free geological temperatures & pressures, reducing the baseline energy input requirements for reformation. This will then go towards reducing the life cycle process energy consumption for hydrogen generation & improve the financial incentives of a Blue hydrogen based future.

If, in addition, all the carbon from the wellbore process is also immediately captured subsurface (from within the same wellbore) and re-injected into the surrounding geology, this improves economics further with earned carbon credits. With at-source carbon capture (CCS), there is now no requirement for the capture of that same unit of carbon from the atmosphere, or to ship CO₂ or CH₄ anymore, just the hydrogen. This consequently reduces (or in some cases eliminating) these greenhouse gas (GHG) emissions and transportation losses, together with downstream carbon capture costs (CCS), while improving hydrogen life cycle economics significantly.

To start a Blue hydrogen economy, we don’t need a 100% new infrastructure, we can adapt and repurpose the natural gas networks that we have already to a large extent, minimising or offsetting the costs and commodities required to build the energy transition.

It’s not a perfect solution but, with all things being equal, perhaps it’s a more sustainable and climate beneficial way to continue to utilise our oil and gas energy resources going forward into the energy transition. Natural gas is the most productive way to create the hydrogen volumes at the scale required by the hydrogen economy – even though methane is a finite resource – while we continue, in parallel, to use and improve upon other greener technologies.

The Hydrogen Shot

The U.S. Department of Energy’s (DOE’s) Energy Earthshot Initiative aims to accelerate breakthroughs of more abundant, affordable, and reliable clean energy solutions within the decade. The first Energy Earthshot, launched June 7, 2021—Hydrogen Shot—seeks to reduce the cost of clean hydrogen by 80% to $1 per 1 kilogram in 1 decade (“1 1 1“). Currently, hydrogen from renewable energy costs about $5 per kilogram. If the Hydrogen Shot goals are achieved, scenarios show the opportunity for at least a 5-fold increase in clean hydrogen use. A U.S. industry estimate shows the potential for 16% carbon dioxide emission reduction by 2050 as well as $140 billion in revenues and 700,000 jobs by 2030.

[Ref. US Department of Energy: https://www.energy.gov/eere/fuelcells/hydrogen-shot]

The Enhanced Geothermal Shot

The Enhanced Geothermal Shot is a DOE research, development, and demonstration effort. Their goal is to reduce the cost of EGS by 90%, to $45 per megawatt-hour (MWh) by 2035.

There is enough technical EGS potential in the United States to meet the electricity needs of the entire world. Capturing even a small fraction of this resource via wide scale commercial deployment could affordably power more than 40 million American homes and businesses. Investments in EGS will also exponentially increase opportunities for geothermal heating and cooling solutions nationwide.

[Ref. Earth Energy Shots – Enhanced Geothermal (U.S. Department of Energy) : https://www.energy.gov/eere/geothermal/enhanced-geothermal-shot ]

Verification & Feasibility Study

Metharc ApS commissioned an Independent Verification & Feasibility Study to be conducted by The University of Manchester. The purpose was to analyse Proof-of-Concept and investigate both the technical and economic feasibility of Metharc’s patented process. Their analysis concluded that our natural gas process has the potential to achieve the U.S. DOE ‘Hydrogen Shot’. Their study also used the economic template from the NREL H2A analysis for hydrogen production, and the resulting cost estimates ranged from under $1 per 1 kilogram for a 3-well scenario to ~$2 per 1 kilogram for a single-well scenario. Based on their comparative cost analyses, it is estimated that the Metharc process could produce hydrogen consistently below $1 per 1 kilogram for a multi-well scenario with CCS.

An similar comparative techno-economic analysis, using the same NREL H2A template, for the Metharc biogas-geothermal process estimated hydrogen generation costs at between $2-3 per kilogram with CCS. This revenue is supplemental to geothermal power production and does not include any power fluid thermal benefits from the hydrogen production process.

For comparison, the IEA regional hydrogen production costs analysis (below), USD/kg of H₂ , show the cost breakdown for Natural Gas (green), Opex (dark blue) and Capex (light blue).

The wellbore decarbonisation of natural gas offers a free biproduct of carbon capture (CCS), as part of a net hydrogen energy generation process, eliminating the Opex and Capex associated with a CCUS process.

[Ref. : IEA, Hydrogen production costs using natural gas in selected regions, 2018, IEA, Paris https://www.iea.org/data-and-statistics/charts/hydrogen-production-costs-using-natural-gas-in-selected- regions-2018-2 , IEA.]

The hydrogen application map (below) illustrates the differences in attitude between industry and consumer, with respect to our environmental need versus our willingness to pay the market for hydrogen.

Through the wellbore decarbonisation of methane to hydrogen, manufacturing cost reductions to under $2/kg can be achieved. However, the high volumes of scale necessary for the hydrogen economy can only be delivered by the oil & gas companies via Blue hydrogen.

[Ref.: AVL List GmbH, 2023. https://www.avl.com/en]

Additional Revenues Streams & Cost Reductions

Additional cost reductions and revenues streams can be achieved through our multifaceted process. It is highly anticipated that the Earthshot targeted $1 per 1 kilogram can be further reduced, by including the revenues and cost saving as listed below. The amount of additional cost savings and revenues will of course largely depend on the owner’s specific facility (i.e., number of wells, their average well flow rates etc…, and the location and scale of the project (e.g., whether onshore or offshore)).

Metharc’s aim is not field development of an oil & gas or geothermal reservoir, but to enable the asset holders to change and enhance their energy production process within their own, existing facilities, through the utilisation of a new downhole tool – a well workover/recompletion is all that would be initially required.

• The oil & gas industry has a clear, natural energy advantage when utilising the geological temperature and pressure of an oil & gas reservoir. This ‘free energy’ gain gives commercial benefit through reduced baseline energy input costs when compared to the surface-based hydrogen industries that incorporate either methane reformation or electrolysis. Far less feedstock would therefore be consumed for power generation, with more available to generate additional hydrogen.
• Natural gas in an SMR process is both a fuel and a feedstock (together with water). Typically, 30–40% of it is combusted to fuel the process, while the rest of it is split by the process into hydrogen.
  [Ref.: The Future of Hydrogen, page 39. Report prepared by the IEA for the G20, Japan, June 2019. [Ref.: https://www.capenergies.fr/wp-content/uploads/2019/07/the_future_of_hydrogen.pdf]
• In addition to this, the oil & gas industry has a clear feedstock advantage, as the oil and gas is produced from their own reservoirs and not purchased on the open market at a higher price. Production volume is also a very significant driver at reducing costs. Industrial oil and gas reformation for hydrogen generation uses mature, well-established technologies, but their industry energy costs are very high. Commercial hydrogen is predominantly made through oil and gas-based reactions, using oil and gas purchased from the oil & gas industry.
• The production cost of SMR hydrogen from natural gas is influenced by a range of technical and economic factors, with gas prices and capital expenditures being the two most important. Fuel costs are the largest cost component, accounting for between 45% and 75% of production costs.
  [Ref.: International Energy Agency, June 2019 – https://www.iea.org/reports/the-future-of-hydrogen]
• Through the direct production of Blue hydrogen from wellbores, the oil & gas industry would essentially be cutting out the middleman, increasing profit margins.
• As a consequence of hydrogen production at-source, there would be an immediate reduction in CH₄ transportation to the industrial methane reformation market. This would significantly reduce methane transportation losses (currently estimated at ~15% link) and therefore have a direct impact on carbon emissions, reducing carbon footprint. Minimising losses also has the knock-on effect of increasing your energy reserves by this same amount.
• Producing no carbon (due to the simultaneous capture of the generated carbon) during the downhole wellbore gasification, eliminates or reduces carbon taxes, increasing profitability.
  [Ref.: 115th United States Congress, the Section 45Q tax credits (enacted in 2018). Section 45Q tax credits incentivizing CCS allots $50 per ton CO2 in tax credits for the permanent sequestration of CO2 in saline geological formations, as well as $35 per ton CO2 for EOR applications of CCS]
• Producing no carbon reduces the volume, and therefore the cost, of externally sourced CO₂ shipments (as generated CO₂ is injected at-source). This would cut the capital cost for new-build CO₂ shipment (estimated as $50m-$60m per ship), multiplied by the numerous CO₂ ships required, together with port modification costs and compression costs. This is a huge cost reduction through the reduced requirement for CO₂ shipping transport to the injection point, together with the ship’s operational & fuel costs and the fuel’s emissions.
  [Ref. Shipping CO2 – UK Cost Estimation Study by ElementEnergy (Nov 2018), for UK Government, Business, Energy & Industrial Strategy Department (BEIS) : https://assets.publishing.service.gov.uk/government/uploads/system/uploads/attachment_data/file/761 762/BEIS_Shipping_CO2.pdf]
• Producing no carbon removes, or reduces, the need for newly tendered field acreage to inject imported CO₂
  No more costs or geological risk related to tendering, exploring and identifying acreage, cost of Regional Geological Evaluation and Site Characterization, Permitting and Operations, Post Injection Site Care & Site Closure, or new surface process equipment to capture CO₂ (e.g., pipelines, compression & injection equipment, etc.).
  Note: All these costs were already included in the original, existing, oil & gas field production licence economics
• For existing oil & gas fields, including the CCS injection of externally sourced CO₂ together with wellbore hydrogen production provides an additional revenue stream (increased carbon credits), and further reduces cost and simultaneously the carbon footprint. This CO₂ could come from outside the oil & gas Industry; for example, the CO₂ produced during the making of cement, or the CO₂ and CH₄ content within biogas from Agriculture and biowaste (landfill or sewage), future-proofing these CO₂ and CH₄
• The injection of both the externally sourced and generated CO₂ can improve Enhance Oil Recovery (EOR), increasing the per centage of reserve recovery for more hydrogen generation, giving infrastructure longevity to existing production licences while elevating profits.
• Reservoir depth, wellbore reformation to generate Blue hydrogen can use existing oil & gas infrastructure without capital cost increases, and currently allows ~20% or more hydrogen to be mixed in existing natural gas pipelines (link to 4.4).This means there is no increased requirement for surface space or significant additional capital costs (e.g. energy islands, far-offshore wind cables, electrolyser platform space etc..), until hydrogen volumes exceed this magnitude.
• As the Metharc process uses a downhole wellbore tool, the hydrogen is separated and purified at downhole pressure and so significantly reduces the need for hydrogen surface compression or purification requirements together with their high associated costs and energy consumption.
• Scaling can be achieved by the systematic conversion of the energy industry’s wells; from producing oil & gas or geothermal energy to producing hydrogen.
• The adaptation of geothermal wells to include hydrogen production with CCS (by using their geothermal energy to process the surface injected biogas deep within the wellbore) will accelerate geothermal marketplace growth, enabling significant climate and clean energy gains.
• By using the natural synergy to also incorporate the storage of CO₂ together with producing hydrogen in these geothermal wells, generates more revenues streams.
• In addition, incorporating the use of CO₂ as the geothermal power fluid (e.g., our CIGG holistic well design) improves energy efficiency and cost effectiveness. While part of the CO₂ is recycled as power fluid, part is captured within the reservoir.
• Part of the recycled CO₂ and water within the geothermal power fluid can also be diverted to local greenhouses, significantly increasing crop yields by having higher CO₂ ppm and temperatures held within the greenhouses.
• Conversion of post-production, retired, oil & gas wells into geothermal wells also reduces capital costs and defers abandonment (P&A) costs, breathing life back into the energy infrastructure.

Scaling the Application of Metharc Technology

In the U.S. alone, oil production reached 11.6 million b/d, and natural gas natural gas production reached 118.7 Bcf/d in December 2021. The number of producing wells in the United States was just under 1 million (916,934) wells in 2021.
[Ref.: https://www.eia.gov/petroleum/wells/]

Just 6% of global Natural Gas production is used in the making of almost the entire 70 million tonnes per year (MtH₂/yr) Hydrogen.
[Ref.: The Future of Hydrogen (page 17). Report prepared by the IEA for the G20, Japan, June 2019. https://www.capenergies.fr/wp-content/uploads/2019/07/the_future_of_hydrogen.pdf]

By 2020 there were approximately 1,200 geothermal wells worldwide. There is therefore increasing opportunity to improve commerciality with the injection of biogas and drive forward the future expansion of the geothermal energy sector in tandem.
[Ref. Oct 2021: https://www.geothermal-energy.org/pdf/IGAstandard/WGC/2020/01017.pdf]

Global Geothermal power production capacity will rise from 16 GW at the end of 2020 to 24 GW in 2025, a Rystad Energy analysis shows, unlocking total investments of US$25 billion in the next five years.
[Ref. Oct 2020 : https://www.energyglobal.com/other-renewables/14102020/rystad-energy-geothermal- power-on-the-rise/]

New Licence Rounds versus Climate Neutrality

The UK North Sea Transition Authority (NSTA) is encouraging applications for new licence rounds designed especially for the Southern North Sea where oil and gas are close to existing infrastructure allowing for swift development.
[Ref. : https://www.nstauthority.co.uk/careers/about-the-nsta/hot-topics/the-move-to-net-zero-carbon/ ]

Meanwhile, the Danish Climate Act gives 2050 as the cutoff date for all oil & gas extraction in Denmark.
[Ref. : https://en.kefm.dk/news/news-archive/2020/dec/denmark-introduces-cutoff-date-of-2050-for-oil-and- gas-extraction-in-the-north-sea-cancels-all-future-licensing-rounds ]

As an illustration, let us assume that any new oil and gas licence awarded will need a minimum of 5 years to reach its’ first production (i.e. includes time for seismic mapping & interpretation, exploration drilling, government development plan approval (i.e., once oil or gas reserves are discovered), development drilling, platform construction). If we then include a minimum of a 20-yr production licence to be economic, then a production cut-off deadline of 2050 prior to the start abandonment operations would mean the finalisation of any oil and gas licence activities by latest 2025.

Our best opportunity for a hydrogen economy lies with the implementation of an environmentally robust and sustainable solution to the exploitation and reformation of oil and gas.

An example of offshore licence areas, from the Danish sector of the North Sea, is shown below.

[Ref. Courtesy of Danish Energy Agency: https://ens.dk/en/our-responsibilities/oil-gas/licensing-rounds]

Geothermal Economic Subsidies Make Economic Sense

Governments can choose to accelerate the growth of geothermal energy, utilising the skills and resources within the oil & gas industry. By subsidising geothermal energy in a similar way to the subsidies previously and currently given for the Wave, Wind and Solar energy sectors, this would maintain employment and therefore also the employee tax base. With geothermal wells lasting typically 20 – 30 years, it is a cost-effective way to secure long term energy supply within national borders.

The advantages of utilising geothermal wells as a local, de-centralised CO₂ collection point are obvious, both economically and technically, and addresses one of the major root-causes of greenhouses gases directly, namely oil and gas. Incorporating the capture of the CO₂ at point-source provides for immediate net-negative, greenhouse gas (GHG) removal, while simultaneously lowering both the net energy and costs of hydrogen generation. The hydrogen generated (together with potentially additional, externally supplied, CO₂ for capture via injection) makes the geothermal process both far more economically self-sustainable and a GHG net-negative impact multiplier.

In addition, there are processes which capture CO₂ direct from the atmosphere to create synthetic hydrocarbon fuels. Unfortunately, this then focuses the climate debate on a ‘post-burn’ narrative; where these synfuels are subsequently re-burnt, re-releasing this same CO₂ greenhouse gas back to the atmosphere in a costly and energy intensive, self-perpetuating, net-zero, CO₂ neutral cycle which could and should be avoided.

There are, of course, evolving hydrogen generation industries (e.g., PtX, electrolysis, wind) which utilise the intermittent supply of power from green energy sources when there is an excess in power availability.

However, these will not generate the significant hydrogen volumes required for a national or global hydrogen economy. Replacing the daily national (and global) production of methane directly with hydrogen production will directly provide an increase in hydrogen supply volumes by several orders of magnitude.