**1. Introduction**

Despite the existing trends of transition to renewable energy, a complete elimination of hydrocarbon raw materials is not possible in a near perspective because of constant growth of energy consumption. Simultaneously, the problem of climate change, especially in Arctic and other ecologically fragile regions, starts to be more and more acute [1,2].

Therefore, use of hydrogen starts to attract attention as an alternative way to reduce greenhouse gas emissions [3]. The European Union (EU) prognosis to create a hydrogen economy recognizes the limits in satisfying the EU's demand for low-carbon hydrogen on the basis of its own renewable energy resources [4]. Therefore, supply from external sources is considered to be a viable option. On the other hand, according to Energy Strategy of the Russian Federation for the period up to 2035, it is planned to export 0.2 million tons by 2024, and by 2035, 2 million tons of hydrogen [5].

The growing interest in the use of hydrogen has attracted attention to a need of classification of its origin and production methods. It is motivated by the fact that different methods of hydrogen production have their own specific carbon and toxic footprint. One of the attempts to build a taxonomy is the color classification [6]. The following colors of hydrogen are identified:

Green hydrogen—produced by electrolysis of water, while electrolysis uses only electricity from renewable energy sources. Regardless of the electrolysis technology chosen, the production of hydrogen has no carbon footprint, as 100% of the energy must come from renewable sources.

Gray hydrogen—produced from fossil fuels, typically natural gas. It produces waste gases containing CO2 and increases the global greenhouse effect. The production of one ton of hydrogen in this way produces about 10 tons of CO2.

Blue hydrogen—like gray hydrogen, but during the production process CO2 must be separated and buried (Carbon Capture and Storage, CCS) or used for the production of fuels or chemical raw materials (Carbon Capture and Utilization, CCU) [7,8].

Turquoise hydrogen—produced by the thermal decomposition of natural gas (methane pyrolysis). Instead of CO2, the process releases solid carbon (soot). At the same time, the use of renewable energy for the operation of a high-temperature reactor, as well as the long-term binding or storage of solid carbon, is a necessary condition for the CO2-neutrality of the process.

In the future, gray hydrogen will not be used at all due to its highest carbon footprint. The potential for obtaining green hydrogen is limited due to high energy consumption in the process of water electrolysis.

The cost of turquoise hydrogen obtained by pyrolysis of methane, according to experts in the field of simulation and computer modeling, is much lower than that of hydrogen produced by electrolysis of water (green hydrogen). This is due to the fact that part of the energy is lost due to the efficiency of the electrolyzer 70–80%. Whereas pyrolysis of methane requires several times less energy than electrolysis. In addition, water used in electrolysis has no free energy, whereas methane has the potential to release energy during oxidation. When separating a methane molecule, hydrogen has a greater energy potential for further oxidation than that the energy spent on pyrolysis. In this case, the cost of hydrogen will depend on the cost of gas, which is minimal in the places of its production. According to our preliminary estimates, the cost of turquoise hydrogen may be lower than the cost of hydrogen produced by traditional steam reforming of natural gas with the capture of greenhouse gases (blue hydrogen). This is due to the fact that there is no need to build and maintain a CSS and CCU infrastructure for turquoise hydrogen.

The growing demand of European countries for hydrogen could create an opportunity for hydrogen production in the Russian Arctic region and its transport using new trunk pipelines. However, it should be noted that building trunk pipelines for transportation of pure hydrogen is economically unprofitable due to the high capital (use of special types of steels and coatings) and operating costs of installing and maintaining the infrastructure. The use of the existing gas transportation infrastructure is possible only when natural gas is transported with the addition of maximum 20% of hydrogen. These circumstances require the rebuilding of existing gas transportation infrastructure or the use of other means of transport [9].

The above-mentioned limitations related to production and transport of hydrogen lead to the idea of situating hydrogen production in an area with a nearby well-established transport system, and not to build transport infrastructure of remote green field. The Northern Sea Route for transportation of the Russian Federation production to the countries of Western Europe and the Asia-Pacific region, Figure 1, is considered as a perspective due to the following factors [10]:


**Figure 1.** Product transportation routes of the Arctic zone of the Russian Federation to the countries of the European Union and the Asia-Pacific region.

In consideration of the foregoing, the task of considering new concepts for the production, storage and transport of hydrogen at the facilities of the Arctic region corresponds to actual global needs.

For this, the article attempts to revise the existing approaches to the development of Arctic oil, gas and gas condensate fields in order to focus on the emerging markets for low-carbon products.

First of all, we will consider promising methods of hydrogen production that can be integrated into Arctic industrial production.

#### **2. Promising Methods of Hydrogen Production**

More than 100 existing and proposed technologies for the production of hydrogen are described [11,12]. More than 80% of the described technologies are based on the steam conversion of fossil fuels and over 70% among them on the conversion of natural gas. However, to reduce carbon dioxide emissions from remote Arctic oil and gas facilities, a broader range of hydrogen production technologies needs to be considered, including methane pyrolysis and seawater electrolysis using renewable energy sources.
