Renowned geoscientist Arnout Everts, armed with a Ph.D. in Earth Sciences and over 30 years of experience in the oil and gas industry, delves into the potential of natural hydrogen in a new Energy News interview.
The conversation revolves around the emergence of hydrogen as a pivotal player in the ongoing energy transition.
Watch the full interview:
- What indicators suggest the emergence of abundant “white hydrogen” in the market, and can you elaborate on recent findings?
Compilation of reported rates of natural seepage worldwide by US Geological Survey and other workers (e.g., Zgonnik, 2020) suggest the earth’ crust emits significant quantities of hydrogen, possibly in the order of 23 Megaton per annum. However, most of these seeps are highly diffuse (=spread over large areas), low-rate flows that are extremely difficult to capture and/or harvest commercially. - Could you elaborate on the challenges and considerations in the research and exploration of natural hydrogen, and why it’s essential to add context?
For hydrogen exploration to scale up to material and commercial production output, key would be to confirm presence of “hydrogen fields” where hydrogen is trapped in porous and permeable reservoirs at excess pressure. Similar to the reservoir-trap-seal systems of most natural oil and gas fields. So far, the hypothesis of “hydrogen fields” with trapped H2 at high excess-pressure is merely speculative, no such fields have been conclusively proven to date. The hydrogen shows reported in Aragon (Spain) could prove a trapped accumulation but to verify this hypothesis, appraisal drilling must confirm significant overpressure in the sandstone reservoir (capped by thick salts) where hydrogen shows were first suggested.
Producing from natural “seeps” like those found in Mali may be possible but production rates will be low, possibly adequate for small local offtake but not for large-scale hydrogen supply (like feeding a large powerplant). Commerciality will stand or fall with the ability to drill very cheaply. Exploitation will be limited to sites with favourable geology (which are not abundant).
Production from hydrogen adsorbed in coals like those found in Lorraine basin (France) may be possible but exploitation would be a resource play similar to coalbed methane. With 100s or 1000s of wells, producing at low rates and initially producing large quantities of water that will have to be disposed in an environmentally acceptable way. Producing gas from coals deeper than about 700-800m will inevitably require some form of stimulation (i.e., fraccing). Producing gas from coals deeper than about 1km is technically very challenging and has never been done before. - How do the properties of hydrogen contribute to the scarcity of subsurface occurrences, and what role does binding with other elements play?
Hydrogen is a very small molecule and extremely reactive, much more than hydrocarbon oil and gas. Hydrogen tends to bind itself to other elements (for example, to oxygen resulting in water, or to carbon resulting in methane). Either during migration from a subsurface hydrogen source to a reservoir/trap, or in the reservoir itself. In petroleum systems, migration pathways from source to reservoir/trap are typically quite long and migration may take hundreds of thousands of years. If the same would be true for hydrogen systems, the risk of losing much or all of the hydrogen due to chemical reactions during migration, is very significant. - Can you explain the geological processes behind hydrothermal alteration of ultramafic rocks and its role in releasing hydrogen?
“Ultramafic” basement are rocks rich in iron- and magnesium-silicate minerals like olivine and pyroxene. “Hydrothermal alteration” means alteration due to contact with water. During a process called “serpentinization”, oxidization of iron-magnesium silicate minerals by contact with water releases hydrogen. “Ultramafic” rocks are most commonly formed along mid-oceanic ridges (which is where most sea-floor “serpentinization” occurs) but in rare cases they are also found on continents. For example, in the cores of mountain ranges that sometimes contain up-thrusted slabs of ocean floor rock, or in continental rift zones where plugs or sills of ultramafic volcanic rocks sometimes occur. - Are there alternative sources of subsurface hydrogen, such as radiolysis or degassing, and how significant are they compared to hydrothermal alteration?
• Hydrogen formation from Radiolysis of water is a process where gamma radiation emitted from decay of radioactive isotopes (e.g., from a Uranium-rich granite) is sufficient to split some formation-water molecules into hydrogen and oxygen. However, rocks with a level of natural radioactivity sufficient to induce radiolysis and release significant quantities of hydrogen are relatively rare;
• Hydrogen formation from mantle and lower crust degassing. The lower crust and mantle of the earth are believed to be enriched in hydrogen and degassing deeply buried rocks may release some of this hydrogen. Seepage into shallower, porous rocks and/or to surface may occur in rare locations where mantle rocks are very shallow, for example along major thrust zones such as the North Pyrenean fault zone in S. France.
I don’t believe we understand enough about the hydrogen “systems” operating on earth and haven’t found enough natural hydrogen to state which of the three main processes (serpentinization, radiolysis and crust degassing) is more important for the formation of natural hydrogen resources. - What challenges do geological settings associated with ultramafic rocks pose for commercial rates and recovery efficiencies?
Ultramafic rocks themselves are extremely “tight” (non-porous and impermeable, like any other igneous rock). Moreover, settings where ultramafic rocks are common are typically deepwater ocean floors where extensive porous reservoirs (such as thick and continuous sandstone layers) are uncommon. In other words, the favourable co-location of large volumes of “serpentinizing” basement rocks and extensive porous reservoirs within reasonable migration distance (the closer the better) to trap the released hydrogen, appears rather implausible. - Why is there a lack of information on flow rates in recent hydrogen finds in Mali and Nebraska, and how crucial are these rates for assessing viability?
Flowrates are very important for a commercial development of gas (be it natural gas or hydrogen). The reason being, commercial buyers of gas (e.g., a power station or a steel plant) want to secure delivery of material supply volumes for a reasonable stretch of time. Similarly, investors in a gas development-project are looking for materiality when they decide on large investments in wells and infrastructure (pipelines, compressors etc). If flowrates per well are very low, the only way to achieve material offtake from a project is to drill many wells (100s or even 1000s of wells like in a CBM resource play).
The Bougou-1 well in Mali, the only producing hydrogen well in the world, has a very low flowrate (1,500m3/day or 135kg/day, feeding a power generator in a nearby village; Maiga et al 2023). In oil terms, this translates to about 3BOE/d (barrels of oil-equivalent per day). Orders of magnitude less than a typical natural gas well.
In energy terms, 1,500m3/day is about 17GigaJoule per day and (assuming well production rate is constant) a power equivalent of about 200kiloWatt. In comparison, a modern onshore wind turbine has a power output of about 3,200kiloWatt (https://www.energy.gov/eere/articles/wind-turbines-bigger-better).
Another comparison: to run on hydrogen instead of coal, a steel plant requires 50kg of hydrogen per ton of steel (https://www.azocleantech.com/article.aspx?ArticleID=1606). A “typical” steel plant (1.5 million ton steel per annum) would need about 75,000 ton of hydrogen per annum. Equivalent to 1,500 Bougou-1 wells.
Upscaling flowrates from hydrogen finds to rates high enough to materially contribute to decarbonization targets and to justify material sales contracts (which attract higher product prices) is going to be the main hurdle towards commercialization. - How does the 15% size difference in subsurface hydrogen traps impact their feasibility and economics?
It simply means that a hydrogen accumulation of the same areal extent, reservoir property (porosity, gas saturation) and trapping pressure would have 15% less heating value compared to a natural gas. - In what ways does the lower compressibility of hydrogen affect the design and operation of subsurface traps and recovery efficiency?
Lower compressibility of H2 compared to CH4 (methane) means less gas expansion during production and pressure withdrawal and hence, lower “reservoir energy” and possibly lower Recovery factor. However, the first challenge for now is to conclusively prove the existence of “hydrogen fields” with H2 trapped at excess pressure like in a conventional gas field. - How does the lower Heating Value of hydrogen impact energy yield and the economic viability of subsurface hydrogen fields?
Lower heating value of hydrogen compared to natural gas in theory would mean lower pricing but in practice, this effect may be (more than) offset by other factors such as the positive environmental attributes of hydrogen compared to methane. A commercial energy analyst would be better placed to comment on this. - Are there ongoing technological developments addressing the challenges in exploiting subsurface hydrogen, and what advancements have been made?
The main advancement made is increased awareness of “white hydrogen” occurrences. It is true that exploration and appraisal drilling for oil and gas typically makes use of mudlogging suites that cannot detect molecular hydrogen. The lack of hydrogen reports from exploration drilling around the world to date is therefore likely an underestimate. I anticipate that mudgas logging suites that can detect presence of H2 are being or will be developed and as these become available for deployment, more H2 shows may get reported from exploration efforts globally. - How do regulatory frameworks influence the exploration and exploitation of subsurface hydrogen, and their impact on commercial viability?
I am not sure but it might be that in many places, natural hydrogen is not covered by existing regulations for subsurface exploration (because it is not a petroleum gas nor a mining product). Government incentives towards hydrogen exploration (such as accelerated cost recovery and tax/royalty waivers) could help attract commercial interest. - What potential geopolitical and environmental implications are associated with widespread hydrogen exploitation, considering its impact on energy markets and emissions?
Environmental concerns: considering in what settings “white hydrogen” has been noted to date, exploitation of it (if commercially viable) may bring about concerns similar to those applying to other resource plays such as shale gas and coal-bed methane. Production of “white hydrogen” adsorbed in coals (like in Lorraine, France) will likely come with significant amounts of water (likely saline and possibly with traces of hydrocarbons and drilling fluids) which need to be disposed of in an acceptable manner. Same for production of “white hydrogen” dissolved in water (like the deeper finds in Mali).
Production of hydrogen from poor-quality reservoirs or from deeper-buried coals, may require fracking or other forms of well stimulation that bring about environmental concerns.
Political implications: not sure. - In terms of environmental impact, how does the extraction and use of white hydrogen compare to traditional methods such as gasifying coal or reforming methane?
Production of hydrogen from natural gas (steam reforming) is very energy intense and produces significant CO2 emissions. The conversion efficiency of electrolysis is relatively poor (60-70% at best) which means very significant amounts of energy are lost in the conversion to hydrogen (and conversion back into electricity).
In comparison, production of natural hydrogen requires some energy upfront to drill the well(s) but theoretically, once a well is drilled and onstream it will produce hydrogen for a substantial amount of time with minimal additional energy requirement. Not enough is known about the “white hydrogen” occurrences to date to firmly state whether replenishment (if any) happens on a timeline short enough to consider white hydrogen a “renewable resource”. For the Bougou-1 well in Mali, it has been reported that pressure has not declined despite years of hydrogen production (Maiga et al 2023) but production rates from this well are very small and pressure was low to begin with. - Considering the significant quantities of white hydrogen found in France and Switzerland, are there ongoing efforts to assess the global potential of natural hydrogen deposits, and how might this impact the energy landscape?
I do not think the hydrogen reported recently from Lorraine (France) will prove an easily exploitable discovery for the following reasons. Lorraine is an old mining district and the hydrogen shows were reported from a coal-bed-methane test well (Folschviller-1). These tests were not done as part of a dedicated hydrogen exploration efforts but to look at the viability of coalbed methane development (Regalor project). Based on the reported depths of gas shows quoted in the press release versus information about the well published before (EGL press release 2006; Allouti et al, 2023), I inferred that hydrogen shows must be from coal beds which occur sandwiched in between tight sandstones and shales. Coals can adsorb significant quantities of gas: they preferentially adsorb methane but they can also adsorb hydrogen (e.g., Iglaurer et al, 2021).
Given that the reported percentage of hydrogen in gas shows from the well is very low (1-20%) whilst the bulk of the gas is methane, commercial viability would hinge on sales value of the methane and on whether a coalbed methane development of the area could get regulatory approval (considering the various environmental concerns pertaining to CMB).
Typical coalbed methane wells achieve a peak production of about 300,000scf/d (standard cubic feet of gas per day). Considering that on average, for the coals in Lorraine shallower than 1km (which have better permeability) H2 content is around 8% average, some 24,000scf/d of this would be hydrogen. Assuming H2 vs CH4 separation can be done with minimal losses, we are talking H2 production rates the same order of magnitude as the Bougou-1 well in Mali: 10 wells to equal the power output of an onshore wind turbine, 1,500 wells to deliver the H2 required to decarbonize a single steel plant. - There are mentions that the Earth has locations where conditions co-exist to naturally produce and accumulate hydrogen. Could you provide examples of other regions where such conditions might be present?
Indeed, in some specific settings with favourable geology and conditions, natural hydrogen may be trapped or seeped in concentrations enough to be exploitable. Such settings include:
• Reservoir-trap-seal systems similar to those trapping oil and gas. These are locations where hydrogen generated from basement rocks migrated up into a trapping configuration of porous and permeable reservoir sealed by a caprock. Theoretically such trapping could result in high hydrogen saturations and significant excess pressure which, in turn, will allow wells to produce at high rates. To trap material columns of hydrogen, caprocks will have to be of high sealing quality because of the small molecular size of hydrogen compared to oil and gas.
To date, no reservoir-trap occurrences of hydrogen have conclusively been proven although the hydrogen shows reported from the Ebro basin in Spain (in Triassic sandstones sealed by salt; ongoing exploration by Helios) may eventually prove an example (pending further drilling success).
Reservoir pressure, reservoir quality and connectivity (= hydrogen volumes assessable per well) will be key factors that determine how much hydrogen might be extractable from a reservoir-trap-seal system. Exploitation of deep, low-porosity reservoirs like the Triassic in Aragon may require advanced drilling techniques (horizontal wells) and stimulation (fraccing);
• Focus areas of natural seepage where streams of seeped hydrogen generated by hydrothermal basement alteration or mantle degassing over a larger area, are somehow funnelled into a major fault/fracture zone. The Mali hydrogen find is an example of such a setting. Natural seeps lack pressure support hence well flowrates will inevitably be low.
How much hydrogen may be extractable from a “focused seep” setting will depend on the density of drilling. Cheap wells and proximity to market will be a key enablers to commerciality.
• ”Coalbed hydrogen“ settings i.e., hydrogen adsorbed in coals. Coals are known to have high adsorption capacity for methane (coalbed methane also known as “mine gas”) but they can also adsorb significant quantities of hydrogen. As adsorption capacity increases with pressure, the drawdown of pressure (drilling a well and pumping off pore fluids, or bringing coal samples to surface) will recover hydrogen from the coal. The hydrogen shows reported in Lorraine, France (a mining district, hydrogen shows were reported in a coal-bed-methane test well) are an example of a “coalbed hydrogen” play.
How much hydrogen can be extracted from a “coalbed hydrogen” will depend on the permeability of the coal and on hydrogen saturation (relative to adsorption capacity). Since coals are low permeability, well flowrates will be low and well drainage areas will be small. Dense drilling of cheap wells will be key to commerciality. Disposal of produced water may be a significant issue. Production from deeper coals may require well stimulation (e.g., fraccing). - Given the ongoing exploration and discovery of white hydrogen deposits, how close are we to developing commercially viable methods for extracting and utilizing this resource on a larger scale?
I believe we are still a long way from commercial exploitation of “white hydrogen” on a large scale. To begin with, none of the “white hydrogen” occurrences reported to date can firmly be considered commercially viable. The Bougou-1 well in Mali, the only producing hydrogen well in the world, has a very low flowrate (1,500m3/day equivalent to 3 Barrels-of-Oil-Equivalent per day or BOE/d). It would be very difficult to anchor a material development project for hydrogen (e.g., selling hydrogen to a steelplant or a large power station) around wells with such a low rate
Generally, the steps involved in assessing commerciality of a hydrogen find would be no different from an oil and gas project. More or less in sequence, these are:
– Flow-testing of one or more wells to demonstrate technical feasibility of recovering hydrogen at material flowrates. A flow-test could be done over a longer period in the form of a “pilot project”.
– Appraise the field. This may include additional drilling and other activities such as seismic, to firm up the areal and vertical extent of the Resource and to reduce the uncertainty in Resource volume to a level where development planning can be undertaken;
– Commercial/market surveys to identify potential buyers for the hydrogen and determine a range in potential gas-sales prices;
– Economic viability assessment i.e., determine whether or not development of the Resource can be done economically, based on a preliminary range of production forecasts, product prices and cost assumptions;
– Conceptual development planning where different “development concepts” (=assumptions on the number of drill sites, type and number of wells, surface facilities, production rate, etc.) are evaluated on their technical and economic merits and risks, to arrive at an “optimum development concept” and issue a “Field Development Plan” (FDP);
– Obtain stakeholder and regulatory approvals for the FDP, including environmental and HSE aspects;
– Firm up sales contracts for the hydrogen with one or more buyers, including contract pricing and contract period;
– Perform detailed engineering studies for surface facilities, wells etc. Firm up cost estimates and project economics;
– Take Final Investment Decision. Only at this stage, Resource quantities will mature to “Reserve” class;
– Execute and operate the project.
Looking at this list and considering the information available in open domain, it looks like all of the white hydrogen “projects” flagged in the media are in the early exploration stage and only just considering or preparing for step 1) (flow testing). Which means that all of the subsequent steps still would have to follow. Projects can stall due to unfavourable findings at any of these steps. - Considering the lack of technology to monitor hydrogen leaks, do you believe this poses a significant challenge to the industry’s growth, and what steps are being taken to address this issue?
I believe the lack of technology to monitor H2 leaks is more an issue for H2 storage projects than it would be for future “white hydrogen” exploitation. However, advancements in technology on this front may still come to the benefit of future “white H2” developments, e.g., to improve the HSE of surface operations (wellsites, pipelines etc). - The logistics of transporting and storing hydrogen are highlighted as challenges. Are there innovative solutions or technologies being developed to overcome these obstacles, especially in terms of efficiency and safety?
Not sure, I am sure this is being looked into as part of “green hydrogen” subsurface storage (e.g., in salt domes or depleted gas fields). I know that the need for excessive cooling during transport and high boiling-off losses are technical challenges that hamper surface transport and storage. On the subsurface storage side, I know that options to minimize losses during repeated storage-withdrawal cycles such as the use of CO2 as a “cushion gas”, are being studied. - Given the potential environmental benefits of white hydrogen, do you see it playing a role in achieving broader climate targets, and how might it complement other renewable energy sources?
Producing from natural hydrogen “seeps” like those found in Mali may be possible but production rates will be low, possibly adequate for small local offtake but not for large-scale hydrogen supply (like feeding a large powerplant). Commerciality will stand or fall with the ability to drill very cheaply. Exploitation will be limited to sites with favourable geology (which are not abundant).
Production from “hydrogen fields” (similar to natural gas fields, with H2 gas trapped in a reservoir at significant excess pressure) has the largest decarbonization potential but the existence of such fields in nature needs to be proven first.
Production from hydrogen adsorbed in coals like those found in Lorraine basin (France) may be possible but would be an challenge due to environmental and other concerns similar to those applicable to CBM resource plays (e.g., high well densities, groundwater lowering, produced water handling, fraccing).
