First, a little bit of color theory. The hydrogen obtained by steam reforming of methane is said to be gray. It emits about 10 kg of CO2 for each kg of hydrogen produced. To produce low carbon hydrogen, different industrial solutions exist:

  • Capture the carbon emitted by the vapor-reforming of methane: in this case, the hydrogen is said to be blue;
  • Electrolysis of water using electricity from renewable sources: this method produces hydrogen qualified as green;
  • Electrolysis using nuclear electricity: the hydrogen turns yellow;
  • Pyrolysis of methane with solid CO2 capture: hydrogen turns turquoise.

Many countries are promoting low-carbon hydrogen as one of the instruments to be favored in the fight to limit the aggravation of climate change. For the oil & gas sector, already a producer and user of hydrogen, the creation of a low-carbon hydrogen market opens up new prospects, including for their R&I (Research and Innovation) function. Here we ask ourselves three questions to better understand these new prospects:

  • How is the oil & gas sector approaching the energy transition?
  • What is the immediate interest of blue hydrogen in this context?
  • What systemic role can blue hydrogen play in the longer term in the oil & gas sector’s energy transition?


The existential challenge of the oil & gas energy transition

As the oil & gas business is directly based on the extraction of fossil fuels, determining a technological roadmap for energy transition is an existential challenge. If we take a step back in history, however, this transition is not the first in the history of mankind. In the space of a few centuries, several changes in the energy system have taken place, from traditional biofuels to coal, then oil, then natural gas. The difference in our current transition lies in the fact that its main determinant is no longer only energy density, but also what could be called environmental density. Moreover, as Laurent Poncet, Lead Originator Hydrogen Corporate Development at Equinor recently reminded us:

“the return on exploration activities is declining, with a current ratio of two barrels found for every ten used”.1

This is despite the impact of digital transformation on exploration, through the application of artificial intelligence methods to the analysis of satellite images.

Some aspects of the transition are relatively straightforward. For example, the substitution of natural gas for coal allows power plants to reduce their emissions at an acceptable cost. Only the type of power plant changes, the infrastructures, and the economic model remains the same. However, since it involves the construction of new types of infrastructure, the energy transition also involves factors of uncertainty.

In a previous article, we saw that the industrial starting point of the energy transition is in green power generation technologies. Indeed, these technologies benefit from an attractive regulatory framework aimed at providing a guaranteed return to investors. The shift to a larger scale of production has also made it possible to reduce the cost of these technologies and to anchor the energy transition in two decades in a strategy of massive electrification.

From the point of view of the oil & gas sector, in view of its historical business, it is a question of diversifying the activity within a broader perspective of energy supply. As no one in this sector is currently thinking of converting 100% to renewables, such diversification would not be enough to solve the existential challenge of the transition.


The blue hydrogen

This is where technologies for capturing and sequestering the carbon emitted during industrial processes, or through the centralized production of electricity from fossil fuels, come into play. Evaluating the economic performance of this technology benefits from the fact that the costs of its deployment are known. Putting aside the thorny issue of the reliability of long-term sequestration, industry players consider it a technology that can be deployed on a large scale.

Does this mean that it is all about the cost of carbon? In the case of the production of blue hydrogen from natural gas, no. Indeed, if demand for hydrogen increases due to the growth of its new industrial and energy applications, the price of blue hydrogen could be another determinant in the equation. The overall outlook for this new market currently appears favourable in both Europe and Asia.

However, long-term sequestration on the seabed or underground is not self-evident. Laurent Poncet drew our attention to the fact that attitudes towards sequestration are more favourable in Northern European countries used to directly manage the exploitation of fossil energy resource deposits. Carbon sequestration does not meet strong societal resistance there, and it is these countries that are leading the way in current major capture projects, such as the Northern Lights project. Laurent Poncet summarises the situation as follows:

  • “All the European CCS projects that I have seen so far are offshore, some land-based caverns can be used for storage but I believe that capture tanks are overwhelmingly offshore.
  • In France, Total has a CCS project in Dunkirk and its test facility in Lacq. In Italy, ENI has its CCS project in Ravenna, where it involves reconverting old gas reservoirs into CO2 traps. Projects continue to be concentrated in Northern Europe in O&G producing countries.
  • Carbon sequestration there meets less societal resistance.
  • For Japan (and for the EU), the current priority is to bring down the price of hydrogen, to accelerate the market penetration of fuel cells (especially on mobility) and to stimulate the demand and consumption of hydrogen, even if in the short term it remains mainly grey”.


Beyond decarbonization: towards the new industrial synergies of circular carbon

Carbon capture can be combined with industrial use of the captured carbon. Such a circular approach is an interesting way to neutralize emissions, and not only for oil & gas players. Decarbonated hydrogen is expected to play a central role in these future synergies, which could prove indispensable for the decarbonization of aviation.

The case of a project led by a consortium of Danish players illustrates this perspective. On a site near Copenhagen, the initial aim is to produce hydrogen by electrolysis, supplied with electricity from renewable sources. In the second phase, the aim is to deploy carbon capture from adjacent industrial activities. Finally, in a third phase, the aim is to combine hydrogen and carbon to produce renewable liquid fuels for aviation.

Beyond this project, liquid renewable fuels are expected to develop because of their energy density and low storage cost. Their major drawback lies in their low energy efficiency (around 13%). But where the need for liquid fuels is unavoidable, the aim will be to produce these synthetic fuels using low-cost energy sources, while working to increase efficiency.



Blue hydrogen is thus destined to play a major role in the energy transition of the oil & gas sector – all the more so as the scope of responsibility of its players is vast. If this responsibility goes as far as including the emissions produced by oil users, then hydrogen and the renewable fuels it enables are unavoidable. An industrial carbon cycle would then be added to the natural carbon cycle and would make it possible to limit the extent of ongoing climate change. In a longer perspective, this cycle would also take over from the exploitation of fossil resources, when the cost of this exploitation becomes too high.

There is no reason to assume that the need for hydrocarbon-based fuels will disappear in the near future. The only thing likely to change is the origin of the molecules of these fuels. Once an industrial carbon cycle has been set up to cap the natural cycle, the energy horizon will be set according to a rule of equilibrium in the renewal of resources. Who will be the builders of this horizon? Go to the Synergy Factory of Presans to learn more!


  1. Referring to an analysis published by Rystad Energy, in 2019, according to which the resource replacement rate for conventional oil was 16% (or 1.6 bbl found per 10 of products, cf.

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