Technical and Economic Assessment of Energy Efficiency of Electrification of Hydrocarbon Production Facilities in Underdeveloped Areas

Abstract

The relevance of the technical and economic evaluation of options for the optimization of electrification projects of hydrocarbon production facilities is due to the growing need for the development of new fields in undeveloped and hard-to-reach territories. Development of new fields requires the construction of large amounts of infrastructure energy facilities, new solutions to improve energy efficiency, reducing capital intensity of projects, solutions to improve the efficiency of resource use in the circular economy, and the use of renewable energy sources (RES). Analysis of the technological directions of electrification of hydrocarbon production facilities proves that the low level of application of RES for energy supply purposes is due to the lack of experimental data on the implementation of this kind of project. This study considers features of technological solutions, practical recommendations, and the main limitations of the application of a hybrid automated system based on RES for the electrification of gas production facilities located in poorly-developed territories. A comparative technical and economic analysis of electrification options using autonomous RES and construction of a power transmission line (PTL) to a remote section of an oil and gas condensate field located in the Arctic zone was carried out. In order to justify the implementation of the electrification project with the use of RES sources, the climatic potential of the region was assessed, and the calculation of energy supply needs and a comparison of alternatives on the basis of specific total capital and operating costs were provided. Assessment of the specific indicator of costs for the proposed variant of the autonomous energy complex based on wind generation indicated savings of RUB 2.24 per kilowatt-hour of energy used. The results of the study can be used in project planning and evaluation of proposed technological solutions based on the rational choice of energy sources and optimization of cost indicators for the construction and operation of energy supply systems.

1. Introduction

The vast majority of subsoil users, both globally and in Russia, use external resource sources of electrification for their production needs; that is, they connect production facilities to existing power nodes.

Against the background of the socio-economic upheavals of the past few years associated with the pandemic and the difficult geopolitical situation in the world, “green” trends in the development of production and the economy as a whole have gained momentum [1,2,3]. They have already had a significant impact on the activities of resource enterprises, regardless of their industry. Major international oil companies such as British Petroleum, Shell, Total, and Equinor have long positioned themselves as “integrated energy companies” in an effort to change consumer perceptions of themselves as purely extractive businesses. They are actively investing in the field of renewable energy sources and technologies to integrate them into their own production [4,5,6].

Recent studies by scientists note the actual opportunities of renewable energy sources to accelerate the production of hydrogen fuel, as well as the possibility of increasing the sustainable economic development of countries by realizing opportunities presented by the demographic dividend, the digital economy, and ensuring energy efficiency [7,8].

For Russian oil and gas producing companies, the tasks of energy efficiency become more complicated due to the geographical conditions of their resource potential, due to the location of fields in the Arctic zone, in the zone of the Russian shelf, where the infrastructure is poorly developed. At the same time, an extremely important aspect of oil and gas production is the uninterrupted and stable supply of production facilities with electricity at all stages of hydrocarbon production, from drilling wells to its processing and disposal [9,10,11].

The resource potential of the Arctic zone of the Russian Federation (AZRF), according to the Ministry of Energy, is more than 35 billion tons of oil and 210 trillion m³ of gas. The main problem of electrification of hydrocarbon production facilities in the Arctic is the technological isolation of a large part of these territories from the Unified Energy System of Russia (UES of Russia) [12]. The remoteness of such Arctic and Far Eastern regions from the existing large energy hubs makes it practically impossible to use the UES as the main source of electricity for the needs of oil and gas production. The use of large energy hubs in the Arctic and Far Eastern regions for the needs of oil and gas production is difficult. Therefore, at this stage of infrastructure development, the only possible way out of the situation is the use of autonomous power generation facilities [13,14].

The increasing need to develop new fields in undeveloped and inaccessible areas makes it necessary for mining companies to build large infrastructure facilities, including power transmission lines and transformer systems, because it is impossible to connect them to the unified power grid. Therefore, operating companies face the challenge of improving the energy efficiency of the entire enterprise and reducing the capital intensity of field development projects located in underdeveloped areas.

This paper proposes options for the alternative energy supply of certain hydrocarbon production facilities in the conditions of the far north. The main objective of the study was the development of two clusters of gas production wells in the oil and gas condensate field located in the north-eastern part of the Yamalo-Nenets Autonomous District of Russia, or Yamalo-Nenets Autonomous Okrug (YNAO). The study proposed and assessed options for the electrification of individual field facilities, due to their relative remoteness from the nearest energy hub, using autonomous renewable energy sources as an alternative to the construction of transmission lines.

The purpose of the work is to evaluate and justify electrification options for hydrocarbon production facilities, taking into account the current technological possibilities for the rational use of energy resources and the economic feasibility of design solutions.

Research objectives:

• A review of global experience in the application of modern technological directions of electrification of hydrocarbon production facilities, including the use of renewable energy sources, was carried out;
• We developed and justified the option of alternative technological solutions for the electrification of remote hydrocarbon production facilities on the basis of a hybrid automated system of renewable energy sources;
• The economic substantiation of alternative options for electrification projects, based on the assessment of the specific total capital and operating costs, was carried out.

The Section 2 describes the concept of ‘underdeveloped areas’ using the Russian Federation as an example. A review of the technological directions for the electrification of hydrocarbon production facilities is also included, which was further used to model the proposed project.

The Section 3 identifies the sources of information and provides a brief description of the study objectives. The stages of the study are reflected in the form of an algorithm for assessing the technological solution, which includes an analysis of the wind and solar potential of the area; an assessment of the generation mix based on a forecast calculation of electricity generation volume; calculation of the optimal storage capacity to balance the output capacity, increase the generating capacity utilization factor, and avoid gaps in energy supply to consumers; comparison of alternatives based on the specific total capital and operating costs.

Section 4 contains a justification of the design solution for the electrification of hydrocarbon production facilities, which implies the power supply of these facilities by an autonomous energy complex, functioning on the basis of a combination of wind and solar energy with storage batteries, as an alternative to the basic option of using the centralized scheme of power supply of production facilities from a gas turbine power plant (GTPP). The assessment of the economic efficiency of the proposed solutions on the basis of a comparative analysis of specific capital and operating costs of the options is presented.

The Section 5 considers the features of the technological solution, the practical recommendations, and the main limitations for the application of a hybrid automated system based on RES for the electrification of gas production facilities in underdeveloped areas.

2. Literature Review

2.1. An Overview of the Characteristics of Underdeveloped Areas in Russia

The state and operators of oil and gas projects are facing new organizational and managerial challenges, whose solution should increase the sustainability of hydrocarbon field development, ensuring the economic efficiency of all project participants, considering social factors of territorial development, ecological equilibrium, and technological development [15,16].

Within the context of this paper, an underdeveloped area is understood as a territory of economically underdeveloped regions. They differ from underdeveloped areas by a comparatively low level of infrastructure and economic and demographic density under high natural-resource potential [17]. As a rule, the development of such territories is considerably affected by extreme natural conditions and the specificity of their geographical and geopolitical position. The territorial organization of the economy of underdeveloped regions has its own peculiarities. The main of which is the presence of an already established support base for further socio-economic and demographic development, but subsequent development is extremely slow [18,19,20].

The level of economic development of particular territories in Russia is directly related to historical aspects. The resource potential of the vast territories of Western and Eastern Siberia and the Far East was discovered relatively recently, around the beginning of the last century [21]. Since then, the level of development of these territories has made a significant leap forward, but harsh climatic conditions and considerable remoteness from the main economic and energy hubs have severely hampered further development. Apart from the obvious problem of the complete or partial lack of industrial (and in some cases also communal) infrastructure, which is the basis of sustainable economic and social development, socio-economically underdeveloped areas are now facing a situation that is considerably more difficult to solve. Due to the need to make significant investments in the economy of these regions, the creation of economic infrastructure on a specific production scale often falls on the owner of the production in question. The reasons for this current situation are not the subject of this paper but are certainly important for further research.

Within the framework of oil and gas production, due to its specificity of being strictly tied to a certain geographical location, the problem of creating or maintaining and developing already existing infrastructure elements is particularly acute. The Arctic zone of the Russian Federation should be singled out as a separate region, consisting almost entirely of underdeveloped territories of various constituent entities of the Russian Federation, as it is currently of major strategic interest to Russia due to its enormous resource potential [22,23,24].

The advantage and the challenge of developing the Arctic is the great potential for the development of the resource sector in a context where the continental base is gradually being depleted (the Arctic accounts for approximately 25% of the world’s undiscovered reserves) [25] and the creation of new transport and logistics systems would provide a direct route to the northern seas, paving alternative transit routes and redirecting the flow of global trade in a new way [26,27].

At the moment, the maximum interest of major oil and gas-producing companies is focused on the Nenets (#3), Vorkuta (#4), Yamalo-Nenets (#5), and Taimyr-Turukhan (#6) strongholds It is in these Arctic territories that the oil and gas industry is now the most developed compared to others. Gradually, interest in the production and resource potential of the North-Yakutian (#7) support zone is beginning to grow. However, at the moment, the development of the oil and gas industry in the area is hampered, firstly, by the lack of full-fledged industrial infrastructure elements, and secondly, by a lack of exploration data due to the small amount of research being carried out [26]. According to Rosneft [28], major discoveries are expected in the northern regions of Western Siberia and in the western part of the Yenisei-Khatanga Trough, adjacent areas of the Irkutsk Region and Yakutia. Here, over the past few years, there has been a multiple increase in the success rate of exploratory drilling.

The resource potential of the Arctic zone, according to the Russian Ministry of Energy [29], is more than 35 billion tons of oil and 210 trillion cubic meters of gas. According to the Ministry for the Development of the Far East and the Arctic for 2020, the AZRF contributes approximately 10% of Russia’s GDP (gross domestic product) from oil and gas production and 10% of total investment and also has a high rate of labor productivity growth. At the same time, the region is home to 1.5% of the country’s population. Overall, the regions of the Arctic and the Far East have considerable resource potential, which makes them a focus for both state and oil and gas interests.

2.2. Main Problems of Electrification of Hydrocarbon Production Facilities in Underdeveloped Areas

The main problem in the electrification of hydrocarbon production facilities in underdeveloped areas, as mentioned above, is the low level of coverage of these areas by the Unified Energy System. The remoteness of the Arctic and Far Eastern regions from the existing large energy hubs makes it practically impossible to use the UES as the main source of electric power for the needs of oil and gas production. Therefore, at this stage of infrastructure development, the only possible way out is the use of autonomous power generation facilities [30,31]. However, the design and installation of such facilities are also a separate problem.

Power generation is usually associated with the generation of a huge amount of thermal energy; additional engineering surveys are required to deal with permafrost soils prevailing in the areas in question. When building on permafrost soils, depending on the design and technological features of buildings and structures, engineering and geocryological conditions, and the possibility of purposeful change of foundation soil properties, one of the following principles of using permafrost soils as a foundation for structures is applied [32]:

• Principle I—permafrost soils are used in a frozen or freezing state, preserved during construction and throughout the operation of the structure;
• Principle II—permafrost soils are used in a thawed or thawing state (with preliminary thawing to the design depth prior to the construction of the structure or with the assumption of their thawing during the operation of the structure).

When using permafrost soils as bases for structures under Principle I, in order to preserve the frozen state of the foundation soils and ensure their thermal design regime, the following must be included in the designs of foundations and bases: ventilated basements or cold ground floors of buildings, laying ventilated pipes, channels or using ventilated foundations in the foundation of structures, installation of seasonally operating cooling devices of liquid or steam-liquid type, as well as implementing other measures (heat shields, etc.) to eliminate or reduce the thermal impact of the structure on the frozen soils of the base.

When designing bases and foundations for buildings and structures erected using permafrost soils according to Principle II, measures to reduce foundation deformation or measures to adapt the structure to absorb uneven foundation deformation should be envisaged and determined based on the results of the foundation deformation calculation.

In addition to permafrost, difficult climatic conditions, in general, are a significant obstacle to any engineering work. The selection of the required equipment, materials for its construction, and the choice of design features must be tailored to the operating conditions. It has to be taken into account that maintenance of complex engineering structures will also potentially be difficult due to the seasonality of transport in the region.

All of the lithological and climatic features of the Russian Arctic, as mentioned above, lead to a significant increase in the cost of any capital construction in the area. For the electricity supply sector, a significant share of investment, in addition to the cost of constructing and operating power sources (power plants), is in the construction of the electricity distribution network (transmission lines and transformer converters). For example, the average cost of tenders for the construction of transmission lines and related installation works in the Yamalo-Nenets Autonomous District is higher than in the neighboring, more southern Khanty-Mansi Autonomous District by approximately 19% and compared to the even more southern Tomsk Region by almost 28% (see

Table 1. Data on cost and number of tenders for transmission line construction and related installation works.

Subject of the Russian Federation	Number of Tenders (from January 2020 to May 2022)	Total Amount, Million Rubles	Average Cost, Million Rubles per Tender
Yamalo-Nenets Autonomous District	28	1544.485	55.160
Khanty-Mansi Autonomous District	34	1524.515	44.839
Tomsk Region	21	830.944	39.569

Source: compiled by the author on the basis of data [33].

, Figure 1).

Therefore, when conducting a feasibility study for a project to electrify oil production facilities in underdeveloped areas of the Arctic zone of the Russian Federation, preference should be given to technological solutions that minimize the capital costs of building the entire power supply system, as well as the ongoing costs of its maintenance.

2.3. An Overview of Modern Technologies for the Electrification of Hydrocarbon Production Facilities in Poorly Developed or Hard-to-Reach Areas

Many researchers [34,35,36] note the importance of effective infrastructure planning and cost optimization at the project initiation stage. The main problem here is to take into account as complete a set of information as possible about the oil and gas production facilities in operation, from the required capacity for energy consumers to the properties of the produced hydrocarbons. There are many different tools and methods aimed at its solution [31,37,38]. In our previous study [39], the authors identified the current global trends of electrification and power supply and identified the specifics of using modern technologies for the electrification of hydrocarbon production facilities in poorly developed or hard-to-reach territories of Russia.

In our previous work [30,39], the current level of scientific and technological development and environmental requirements in terms of electrification of hydrocarbon production facilities allows the following directions: the use of power units based on gas fuel (natural gas or associated petroleum gas (APG)); integration of RES and their combinations with traditional types of power supply; the association of several facilities (offshore platforms) into a single power network and the creation of additional power centers.

The main advantage of using APG, the internal power source, as the main fuel cell over similar diesel plants is that there is no need to organize regular fuel supply chains. This has a significant impact on the cost-effectiveness of electrification projects when the production facilities are located remotely [40,41,42].

Associated petroleum gas, or APG, is a mixture of various gaseous hydrocarbons dissolved in oil, released during its production and treatment. The main problem with associated gas, which greatly complicates its use as a marketable extraction product, is its component composition. APG consists essentially of methane and ethane but also has a large proportion of propane, butane, and vapors of heavier hydrocarbons. A separate problem is the presence of a high-molecular-weight liquid in different phase states.

Due to the high cost of APG treatment and processing equipment, which, due to the previously mentioned characteristics of the feedstock, must be tailored on a case-by-case basis to the specific gas composition, until recently, the main method of APG utilization was simply flaring in unlimited quantities. Other reasons for flaring a valuable hydrocarbon resource include the need to build separate gas pipeline systems to transport it and the lack of a gas consumer as such for a number of oil fields.

A turning point in the beneficial use of APG came with the adoption of the so-called Kyoto Protocol. The signatories to the protocol made quantitative commitments to reduce emissions of six greenhouse gases: carbon dioxide (CO₂), methane (CH₄), nitrous oxide (N₂O), hydrofluorocarbons (HFCs), perfluorocarbons (PFCs), and sulphur hexafluoride (SF₆). The first three are part of associated petroleum gas and its products of combustion, and according to some researchers [43], they are the ones that have the greatest impact on the greenhouse effect.

Over the last 10 years, the level of utilization of associated petroleum gas has largely determined the development efficiency of the entire oil and gas complex of a country. The use of APG is a marker for government and business in terms of integrated subsoil development, utilization of raw materials, and environmental safety [44].

Statistics on the use of APG in the world in 2020 according to the International Energy Agency show that the main leaders in the processing and use of APG are in North America, and the worst situation is in Africa [45,46].

In Russia, the need to control APG flaring was raised just over 10 years ago. In 1995, the volume of associated petroleum gas produced in the Russian Federation was 25 billion cubic meters; in 2007, it was 48.6 billion cubic meters. With the increase in volumes, combustion volumes and, consequently, harmful emissions into the atmosphere have increased. In 2010, only 30% of associated gas was sent for processing; the remaining 70% was flared by Russian oil companies [47]. According to the Ministry of Energy [48], the industry-wide utilization of associated petroleum gas in the Russian Federation increased by 1.1 p.p. to 82.6% in 2020 compared to the previous year (see Figure 2). Two types of APG-fired power plants are currently used in the oil and gas industry in Russia and worldwide: gas turbine power plants and gas piston units (GPU). More often, when companies need to create a so-called internal source of power, it is the gas turbine power plant that is used, as the cost of the plant for equal power output is somewhat lower than that of its piston counterpart, as well as the sensitivity of turbines to the composition of the fuel used, which in the case of APG is a critical indicator [44].

There are many scientific papers and publications on the efficiency of energy supply for oil and gas field facilities using associated petroleum gas as an energy carrier [49,50,51]. At the moment, GTPP is actively and successfully used at remote enterprises from the main nodes of the unified energy system of the Russian Federation. However, in the last few years, research papers devoted to the improvement of existing autonomous power supply systems based on APG, as well as solving a number of problems of their operation in accordance with the accumulated experience, have naturally started to appear. For example, one of these problems is the dependence of GTPP efficiency on ambient temperature [52,53,54]. Some researchers also point to the high level of CO₂ emissions during operation as the main problem of GTPPs [31,55,56].

Promising ideas in this direction seem to be the use of thermal energy in the cooling system for energy distribution in accordance with workloads and the needs of consumers, as well as a more specific technology for creating cogeneration plants with a binary cycle of electricity generation and trigeneration systems, involving the use not only of thermal energy in the GTPP but also the energy of exhaust gas in the GPU to improve its efficiency through the regulation of the temperature regime [30,48].

According to the new energy strategy of the Russian Federation (RF), the use of primary energy in electricity generation for the needs of industrial enterprises should be reduced through the use of secondary energy resources [29]. In the context of oil and gas production, such secondary energy resources are not only APG but also GPU waste gas and thermal energy generated by these units during operation.

Against the backdrop of the social and economic upheaval of the past few years due to the pandemic and the complex geopolitical environment in the world, ideas of a new energy transition and the so-called ‘green’ trends in production and overall economic development have gained momentum [57]. This trend has already had a significant impact on resource companies regardless of their industry.

In the upstream oil and gas sector, large corporate actors are actively demonstrating their commitment to supporting action on climate change and energy sustainability [5,58]. As a demonstration of this position, oil and gas corporations are resorting to measures such as the overall reduction of emissions through modernization and upgrading of existing equipment, improving the energy efficiency of production, as well as conducting numerous studies and introducing new technological solutions aimed directly at the environmental reorientation of production cycles [1,4].

The main problem with renewable energy sources is their high relative cost compared to conventional sources. Although there has been a downward trend in the cost per MWh of electricity from renewables over the past 10 years, the oil and gas industry is wary of actively integrating green technologies into production [59].

The most promising areas for the use of RES as energy sources in hydrocarbon production facilities are wind power generation and the use of solar photovoltaic cells.

Many researchers [31,60,61] point out that a significant problem with the use of RES is the fact that their stand-alone use cannot guarantee the necessary amount of electricity without an additional power source at all times. The amount of electricity will vary over time with an arbitrary character, and its qualitative characteristics, such as amplitude, frequency, and voltage curve shape, will also be unstable due to environmental factors that directly determine the performance of PV cells and wind turbine generators.

A solution, which has already proven to be cost-effective [31], is to combine wind generation technologies with solar power and to supply the structure with additional power sources in the form of batteries [62,63]. It has been proven that the territories of northern Eastern Siberia, where the main actively developed oil and gas clusters are now located, represent an area with unique climatic conditions for the integration of these RESs. Industry leaders, represented by Gazprom and Rosneft, have already announced the creation of a large wind power generation hub to serve the Vankor cluster and the recently discovered large gas field in Taimyr [64].

A separate promising area is the use of gas production automation complexes with integrated RES in northern fields [61]. The main advantage of this technology is the possibility of transferring the power source directly to the well, thereby significantly reducing the amount of capital expenditure on infrastructure. As mentioned earlier, for all the specifics of construction processes in the Arctic zone, a solution that allows us to avoid the creation of additional power lines is required.

Principles of creation, management, and economics of power complexes based on renewable energy sources for decentralized power supply, as well as materials and technologies used in the production of equipment for power generation systems operating in harsh climatic conditions, including in northern regions, were considered in the works of authors from St. Petersburg Polytechnic University [65,66] and other authors [67]. It is also worth noting that many international studies aimed at developing autonomous power supply systems in the isolated mode for reliable power supply from renewable sources and a combination of energy types, depending on the required installed capacity and geographical location of power consumption facilities [68,69,70].

Based on the above, we can conclude that there is a need for the modernization of power supply systems of remote power consumption facilities, including oil and gas production facilities located in the underdeveloped area in the Arctic regions, using modern energy-efficient technologies, including power plants based on renewable energy sources. Therefore, the development of hybrid automated systems based on RES and technologies and measures aimed at adaptation to such conditions is an important task for the sustainable development of energy supply systems based on renewable energy sources.

3. Materials and Methods

During the research, open materials of scientific monographs and articles by Russian and foreign scientists were used and were dedicated to theoretical and practical issues of electrification of hydrocarbon production objects using different power units and technical and economic analysis of power supply projects.

The literature review includes a review of the features of poorly developed territories using the example of Russian territories, the main problems of electrification of hydrocarbon production facilities in poorly developed territories, and a review of modern technologies for the electrification of hydrocarbon production facilities in poorly developed or hard-to-reach areas. The analysis of this information makes it possible to systematize knowledge in the field of electrification technology for oil and gas facilities and to identify features and opportunities in the field of electrification of hydrocarbon production facilities in poorly developed territories.

The object of this study was an oil and gas condensate field located in the north-east of the Yamalo-Nenets Autonomous District. This RF subject is located within the Arctic zone, belongs to the poorly developed regions of the RF, and the largest energy consumers in the region are oil and gas production companies. Although the region is partially connected to the UES, most of the oil and gas production facilities in its territory have autonomous sources of electricity. As of the beginning of 2020, there were 93 thermal power plants with a total capacity of 2357 MW in the YNAO; 12 power plants with a total capacity of 1032.7 MW are connected to the Unified energy system of Russia [71]. Energy districts of YNAO, which operate in isolation from the UES of Russia, cover the territory of eight municipalities. Electricity is generated mainly by gas pistons, gas turbines, and diesel power plants using hydrocarbon fuel (see Figure 3).

Several hydrocarbon fields are currently in the first or second stages of development in the subject area, i.e., in a state of active production build-up by expanding the scale of production drilling and the development of production facilities. The oil and gas condensate field in question is one such field. At present, the main work on the capital construction of the production stock at the field has been completed, but local drilling and well construction projects aimed at increasing the coverage of the field by development are still being implemented. Part of one such local development project is the construction of two gas production well clusters in the north-eastern part of the field. The main source of electricity in the field is an existing 80 MW gas turbine power plant, with 10.5 kW generating voltage, fueled by produced APG. The nearest power supply point to these hydrocarbon production facilities is a transformer substation located approximately 10 km away. According to the project documents, in order to supply power to these clusters, an additional approximately 6 km of the transmission line from the existing line will need to be constructed. The total electrical loads under the project are 179.57 kW, and the annual electricity consumption is 787.65 thousand kWh/year.

As a design option, it is proposed to consider a RES-based electrification scheme, such as the use of a combination of solar panels and a wind turbine together with backup batteries. A typical scheme of an autonomous energy complex has been designed by the Vympel Group. The main advantage of such a facility is that it can be located directly at the production site (a cluster or a single well site). In addition to the capital costs, this autonomous complex can potentially reduce operating costs because it allows you to install automatic telemechanics to control wells, thereby reducing the need for personnel presence on the site. Vympel is actively implementing projects to introduce this automated system in conjunction with Gazprom subsidiaries. More than 50 units are successfully operating in the fields of Gazprom Dobycha Yamburg [72].

The algorithm for assessing and justifying the option of alternative technological solution for the electrification of remote hydrocarbon production field facilities based on a hybrid automated renewable sources system includes:

• Assessment of the wind potential of the territory;
• Assessment of solar insolation level;
• Assessment of generation mix based on projected wind and solar power generation;
• Calculating the optimum storage capacity for balancing the output, increasing the generating capacity utilization factor, and eliminating power dips in the consumer’s supply;
• Minimizing the cost of the solution on the basis of specific total capital and operating costs.

The input climate data for the calculations were the GIS “Renewable Energy Sources of Russia” [73] and the corresponding climatological database for the Russian Federation, in turn, created on the basis of NASA SSE (space-based measurements) [74] and RETScreen (ground-based measurements) (RETScreen Exprt, Ottawa, Canada) [75].

The study area is located in the Arctic climate zone. A characteristic feature of the climate is the predominance of cyclonic weather throughout the year, especially during transitional periods. The average annual air temperature is minus 8.8 °C. The absolute minimum is minus 52.6 °C, and the absolute maximum is 33 °C. The average temperature of the heating period is minus 13.9 °C, and the duration of the heating period is 297 days. Precipitation is abundant in the area. The highest monthly amount of precipitation is in August and is 58 mm, and the lowest amount is in February and is 22 mm. The average number of days with stable snow cover in the area is 232.

According to the climatological database for the territory of the Russian Federation [73], the average monthly characteristics of atmospheric air in the study area are as follows (see Figure 4 and Figure 5). Figure 6 shows the number of windless days by month during the year, with the period of windless days during the polar night highlighted in orange (total for two months—13 days).

As a result of the analysis of the average monthly characteristics of atmospheric air for the area of the Vostochno-Messoyakhskoye field location, it is clear that the greatest risk of disturbance of stable operation of the power unit is possible in the winter period since, in the period from November to the end of February, the polar night and the amount of solar radiation sharply decreases and can reach zero values. It is in December–February that the average number of windless days increases and reaches 19–21% (6 days) per month, while the peak of windless days is observed during January–February and their total duration may reach 13 days.

A feature of the proposed electrification scheme is that the bulk of the electricity is generated by the wind turbine. The function of the solar panels remains to recharge the integrated batteries in case the wind turbine stops. Therefore, the equipment for the wind turbine generator must be selected in such a way that its generation capacity is fully sufficient for the operation of the hydrocarbon production facilities.

4. Result

4.1. Natural Factors Assessment

According to these data [59,73], the gross wind potential at the field location is approximately 422 MWh/year (see Figure 6).

The average annual solar insolation level for the horizontal surface averages 2.3 kWh/m² per day and 4.8 kWh/m² for the summer period on average (see Figure 7).

In an area of 1 m², the amount of solar energy generated per year is:

2.3 × 365 = 0.839 (MWh/year).

(1)

It is understood that, based on the known level of solar insolation (2.3 kWh per 1 m² per day) and the number of sunny days per year in the region (365 days), it is possible to generate the same amount of energy on the solar cells proposed by the authors for implementation to provide energy for gas well clusters of the considered field, namely—0.839 MWh/year for 1 m² of solar cells.

The total potential of solar and wind energy for the power supply of clusters of gas wells of the considered field satisfies the criterion of necessary energy volume of objects of cluster No. 1 and cluster No. 2—380.98 MWh/year and 393.31 MWh/year, respectively (Appendix A,

Table A1. Power consumption of electrical consumers of well pads.

Consumer	Components of Design Capacity			Annual Consumption Electricity, Thousand kWh
	Pr, kW	Qr, kWAr	Sr, kWA
Well cluster No. 1. CTS 10/0.4 kW 2 × 100 kWA
Radio communication	10.53	3.718	11.18	18.98
Incineration system for gas utilization	24	2	24.5	160
Flow line connectors	2.4	0.7	2.5	9.6
APCS equipment	36.0	14.6	39.7	140.0
Wellhead valve electric drive	13.1	6.0	14.4	52.4
Total for CTS without compensation, taking into account Kt = 0.8; Kr = 1; tgφ = 0.63:	86.03	27.018	92.28	380.98
Reactive power compensation at CTS:		−19
Total for CTS with compensation, taking into account Kt = 0.8; Kr = 1; tgφ = 0.13:	86.03	8.018	79.4	380.98
Well cluster No. 2. CTS 10/0.4 kW 2 × 100 kWA
Radio communication	14.04	4.96	14.91	18.98
Incineration system for gas utilization	24.0	2.0	24.5	160.0
Flow line connectors	2.4	0.7	2.5	12.8
APCS equipment	40.0	15.0	42.7	146.0
Wellhead valve electric drive	13.1	6.0	14.4	69.87
Total for CTS without compensation, taking into account Kt = 0.8; Kr = 1; tgφ = 0.63:	93.54	28.66	99.01	407.65
Reactive power compensation at CTS:		−23
Total for CTS with compensation, taking into account Kt = 0.8; Kr = 1; tgφ = 0.13:	93.54	5.66	84.17	407.65
Total for the project, taking into account reactive power compensation:	179.57	13.678	163.57	787.65

):

380.98 MWh/year < 407.65 MWh/year < (422 + 0.839) MWh/year.

(2)

Calculation of the main parameters and characteristics of the equipment, the number of wind turbines and solar panels, is presented in Appendix A,

Table A2. Calculation of parameters and number of windmills and solar panels of an autonomous energy complex.

Index	Formula
Converting wind speed to tower height	$v_i=v_m{\left(\frac{H_T}{H_m}\right)}^{\gamma }$	(A1)
	$v_i$—wind speed at tower height, m/c; Hm—height at which measurements were taken, m; $v_m$—measured wind speed at altitude Hm, m/c; HT—tower height, m; $\gamma \approx 0.2$—coefficient depending on the location of the object under study [73].
Power of wind flow	$N_{WF}={\rho }_{air}\cdot S_b\cdot \frac{v_i^3}{2}$	(A2)
	${\rho }_{air}\approx 1.225$—air density (standard value at a temperature of +15 °C and a pressure of 760 mm Hg), kg/m3; Sb—rotor swept area, m2. Taking into account that the rotor swept area is almost equal to the area of the circle, which is described by the edges of the wind turbine blades, which are the most distant from the axis of rotation when moving, we take:
	$S_b=\pi \cdot \frac{d_{}^2}{4}$	(A3)
	where d—wind wheel diameter, m.
Power generated by wind turbines	$N_{WT}=N_{WF}\cdot \xi$	(A4)
	where NWF—power of wind flow, W; $\xi$—wind energy utilization factor (depends on the characteristics of a particular wind generator), fractions of units. Taking into account Formulas (A2) and (A3), we have:
	$N_{WT}={\rho }_{air}\cdot \pi \cdot \frac{d_{}^2\cdot v_i^3}{8}\cdot \xi$	(A5)
Calculation of wind speed and wind flow power	Starting speed of the installation rotor—3.4 m/c [79]. According to climate data, in February, the wind speed can be below this mark. Therefore, the height of the wind turbine tower must be at least 15 m:
	$v_{i.feb}=3.19{\left(\frac{15}{10}\right)}^{0.2}\approx 3.46$(m/c).	(A6)
	Taking into account the given height of the tower, the most optimal diameter of the rotor blades d is 2 m. As an example of the calculation, we determine the power of the wind flow for February:
	$N_{WTfeb}=1.225·3.14·\frac{2^2·{3.46}^3}{8}·0.15\approx 43\left(\mathrm{kWh}\right).$	(A7)
Calculation of the required battery capacity	$Q=P\cdot t/U\cdot k$	(A8)
	where P—available load, W; U—battery voltage, V; t—reservation time, h; k = 0.7—battery capacity utilization factor. Thus, the required battery capacity for two gas production facilities:
	$Q_{K-5}=12.08·312/2·0.7\approx 1319.22$ (A·h);	(A9)
	$Q_{K-4}=12.93·312/2·0.7\approx 1411.57$ (A·h).	(A10)
	To increase the reliability of the system, we take batteries with an additional 20% capacity margin. $Q_{K-5}=1583.06$ A·h; $Q_{K-4}=1693.88$ A·h.
Energy of solar panels to install	$E_{SP}=E_{ins}\cdot P_{SP}/P_{ins}\cdot k$	(A11)
	where Eins—average monthly insolation level, kW·h/m2 per day; PSP—installed capacity of solar panels, W; Pins—insolation power on the earth’s surface per square meter (1000 W/m2); k = 1.2—loss factor per charge–discharge of batteries, conversion of direct voltage into alternating voltage.
Installed power for solar panels of this installation at a temperature of 25 °C	$P_{SP}=180\cdot n$	(A12)
	where n = 2…10—number of solar panels in the installation, pcs.
	$E_{SP}=W_B$	(A13)
	where $W_B=Q_B\cdot U$—energy generated by the battery, W·h. As a result, based on Formulas (A11)–(A13), we obtain:
	$W_B\cdot k_{safe}=E_{ins}\cdot \left(180\cdot n\right)/P_{ins}\cdot k\Rightarrow n_i=\frac{Q_i\cdot U\cdot k_{safe}\cdot P_{ins}\cdot k}{E_{ins}\cdot 180}$	(A14)
	$n_{K-5}=\frac{1583.06·2·1.3·29.21·1.2}{75.72·180}\approx 9$ (pcs).	(A15)
Change in the average annual power of the panels	$P_{SC}=P_0\left(1+\beta \Delta t\right)$,	(A16)
	where PSC—solar cell power, W; P0 = 180—solar cell power at 25 °C, W; $\beta \approx -0.4$—thermal power factor, °C−1; $\Delta t$—temperature change, °C.
	$P_{SC}=180\left(1+\left(-0.004\right)·\left(-7.8-25\right)\right)\approx 203.62$ (B)	(A17)
Total number of solar panels for well clusters K-5 (gas) и K-4 (gas)	$n_{K-5}=\frac{1583.06·2·1.3·29.21·1.2}{75.72·203.62}\approx 8$ (pcs)	(A18)
	$n_{K-4}=\frac{1693.88·2·1.3·29.21·1.2}{75.72·203.62}\approx 9$ (pcs)	(A19)

, including characteristics of the equipment for the autonomous power complex (see

Table 2. Composition and characteristics of equipment for autonomous energy complexes. Source: compiled by the authors using typical power supply schemes for oil and gas well production installations [76,77,78]; data on loads and the required amount of voltage were selected conditionally.

Composition and Characteristics	Cluster No. 1	Cluster No. 2
Wind turbine:
- Tower height, m	15	15
- Diameter of rotor blades, m	2	2
- Generated energy, MWh/year	661.39	661.39
Solar panels:
- Quantity, pcs.	8	9
- Maximum power, W	203.62	203.62
Batteries:
- Capacity, Ah	1583.06	1693.88
- Voltage, V	2	2

).

It should be noted that a wind speed of 10 m is not sufficient to generate electricity from a wind turbine. This speed corresponds to the minimum requirement for power generation. In such a situation, the wind turbine generates several times less power than the nominal capacity. In order to determine the number of solar panels required, the capacity of the backup battery must be estimated. Based on the average monthly number of windless days per year, the standby power unit should be able to operate the gas production systems for 13 days (the number of windless days in January and February), as this is the period when polar nights are in effect in the area where the production facilities are located.

4.2. Economic Justification of Alternative Electrification Projects

The base case for the two clusters (No. 1 and No. 2) of gas production wells involved the construction of 6 km of transmission line from the existing line to the gas turbine power plant (Figure A1, Appendix A).

The design option (alternative to the baseline option) for these cluster gas production facilities involved the use of an autonomous renewable energy complex (Figure 8).

The capital costs of the project are defined by the following main areas: purchase of equipment; payment for transportation services (delivery of equipment to the site of installation); cost of construction site preparation; payment for construction and installation works, adjustment, testing, commissioning, etc.; costs of environmental protection measures; other costs. To estimate capital costs, data from design and estimate documentation, as well as data from object-analogues, were used. Calculations of operating costs were made in the context of the following cost items: current costs of facility maintenance (at least once every 3 months) and capital repairs (at least once every 8 years); property tax (2.2% of average annual property value); depreciation charges (for main production assets) calculated using the straight-line method; depreciation rate is 10%; decommissioning costs (in the last year of the field operation, they were 10% of the book value of assets).

The results of the capital and operating cost calculations of the two options for the hydrocarbon production facilities electrification project in an underdeveloped area are shown in Figure 9.

The total investment cost of the combined heat and power (CHP) project is approximately 70.5% (just under a factor of three) lower than the baseline option of electrifying the facilities by building a transmission line from an existing energy source—GTPP. At the same time, the capital cost of the project is approximately 47.2% lower than the base case (a little less than half). The main cost item in the base case of the electrification project is the purchase of equipment and materials for the construction of the transmission line (steel structures, wires, and components for pile foundations), as well as the costs of delivering materials to the installation site and the preparation of the construction site are also significant in the capital cost estimates. An electrification project involving the installation of an electricity generation source in close proximity to the extraction sites avoids a number of these costs altogether.

The unit cost per kWh of energy is taken as an additional indicator for comparing the options:

$$K_s=\frac{CAPEX+OPEX}{W_{gen}},$$

(3)

where W_gen is the amount of energy consumed by hydrocarbon production facilities over the lifetime of the project, kWh.

For the base case of the electrification project, this indicator would be:

K_s.base = (56,486,220 + 54,894,870)/(787,650 × 30) = 4.18 (rub./kWh).

(4)

For the alternative:

K_s.alt = (29,837,320 + 16,202,049)/(787,650 × 30) = 1.94 (rub./kWh).

(5)

Equations (4) and (5) in the numerator are the capital costs of the project, calculated in

Table A3. Capital costs of the basic option for the development of two clusters (K-4 and K-5) of gas production wells based on the construction of a power transmission line from the existing line to the gas turbine power plant per thousand RUB.

Index	Cost
1. Basic metal structures	29,556.217
2. Equipment and materials for linear facilities	3842.31
3. Logistics (services for the delivery of equipment and materials)	3852
4. Preparation of the construction site	1100.76
5. Construction work (costs of transport and units)	2908.3
Piling installation	1608.98
Installation of pile foundations	1709
Installation of power transmission towers	5055
6. Construction, installation and commissioning	4729.432
7. Environmental measures (including installation of bird protection devices)	590.90
8. Other expenses	1533.318
TOTAL	56,486.22

and

Table A4. Capital costs of the design option for the development of two clusters (K-4 and K-5) of gas production wells based on an autonomous energy complex using renewable energy sources per thousand RUB.

Index	Quantity	Unit Price	Cost
1. Equipment (selection services)			964.6
Wind monitor	2	285.71	571.43
Wind generator (rotor + blades)	2	2512.63	5025.26
Tower (15 m)	2	300.72	601.44
Energy module	2	482.262	964.52
Mounting module with battery pack	2	664.26	1328.52
Maintenance Trestle	2	120.78	241.56
Mounting module with electronics module	2	613.59	1227.19
Solar modules	17	220.59	3750.13
Mounting support for solar modules	4	150.65	602.62
Well piping technology module	7	1018.58	7130.06
2. Transport and delivery services			1389
3. Site preparation			300
Foundation for mounting modules	2	97.38	194.76
Pile foundation for a wind turbine tower	8	28.4	227.2
Piles under the wind turbine tower	8	7.06	56.48
4. Construction and installation works			2312.7
5. Commissioning works			1484.53
6. Environmental measures			153.07
Bird scaring devices	4	30	120
7. Other expenses			1192.254
TOTAL	29,837.32

of Appendix A, and operating cost calculations. Their ratios are visualized in Figure 10. In the denominators of Equations (4) and (5), we show the annual power consumption by the electrical consumers of the well pads, including the reactive power compensation, calculated in Table A1 of Appendix A (787.65 thousand kWh), and the battery life.

Thus, based on the calculation of the specific index for each of the two options, it can be concluded that the use of an autonomous energy complex based on wind generation as an alternative to standard electrification provides savings of RUB 2.24 for each kWh of energy used. As previously mentioned, this saving arises primarily from a significant reduction in the capital costs for the construction of production facilities, as well as from a reduction in the running costs of their maintenance.

In our study, we looked for a solution to the urgent problem of the energy supply of the underdeveloped regions because the reason for their underdevelopment lies precisely in the lack of energy supply: they are remote from the country’s energy system and lack any infrastructure.

We have proven that our proposed solution can be effective even in permafrost areas, provided there is sufficient wind and solar potential.

Moreover, it will be effective for regions where climatic conditions are more favorable. In this case, the energy supply of such territories will be much cheaper and even more profitable: CAPEX and OPEX, in this case, will be much smaller.

The study focused on underdeveloped areas since it is for them that the problems of energy supply are especially relevant; without energy supply, the development of these regions is almost impossible.

The introduction of RES is relevant, especially in the current geopolitical situation. It is technologically possible and economically feasible in regions with different climates; the main condition is sufficient potential for wind and solar energy. In the northern regions, CAPEX and OPEX for the introduction of RES will be quite high, and the introduction of RES will be economically feasible, subject to a full assessment of construction cost factors, taking into account the use of special steel grades, hydrophobic coating, and additional insulation of windmill structures, as well as taking into account the growth in costs for construction technologies in frozen ground conditions. In areas with a more favorable, warm climate, CAPEX and OPEX will be much less with the introduction of RES, which also determines the effectiveness of the introduction of the considered autonomous energy sources.

5. Discussion

The main barrier to the use of renewable energy technologies in oil and gas production is their relatively low power output, with the need for complex process equipment and significant design and maintenance costs. However, the energy consumption of gas production facilities is about 80% lower than that of oil production facilities (see Figure 10), where the bulk of the energy is used to power a submersible electric motor for an electric centrifugal pump. Therefore, the use of renewable energy technologies to power gas production facilities, even with a small generation capacity, may be more economically viable than connecting such facilities to the existing utility grid.

The average value of energy consumption was determined by us per one well; it was obtained from the analysis of equipment energy consumption data for several wells (for a cluster of wells). The observation period was a calendar year, taking into account summer and winter periods of power generation and consumption. Thus, the average power consumption of one gas well was 185 kW and one oil well was 987 kW, of which 570 kW was used to power the submersible electric motor for the electric centrifugal pump.

The main advantage of RES over other sources of electricity is mobility and the ability to locate an electricity generator in close proximity to the electricity consumer. Integration of RES into the electricity supply system of oil and gas production facilities will, in some cases, make it possible to eliminate the construction of transmission lines, which will optimize the capital costs of the development project.

A more detailed study of the projects proves that wind speed and icing factors can have a significant impact on project variation and should therefore be taken into account in the risk analysis. It is worth noting that the impact of these factors is greatly increased during winter operation, especially between January and February, because in addition to the extreme temperatures during this period, the area where the generating set is potentially located experiences the phenomenon of polar night, which significantly reduces the reliability of the entire system due to the dysfunctionality of the solar energy elements. The main methods of adapting wind turbine equipment to the arctic climate and managing the risk of icing and wind speed changes include the following technological solutions: using special grades of steel with low sensitivity to negative temperatures in the manufacture of blades and towers, which should increase the durability of the structure; using a hydrophobic coating to prevent ice formation on the rotor and other parts; using additional insulation to reduce heat loss and emergency shutdown system [24].

The value of the study lies in modeling options for the electrification of hydrocarbon production facilities, taking into account modern technology and optimization and rational use of energy resources at production facilities in underdeveloped and remote regions.

The theoretical significance of the study lies in the systematization of knowledge in the field of electrification technologies for oil and gas facilities; in identifying problems, features and opportunities in the field of electrification of hydrocarbon production facilities in poorly developed territories can be determined.

The results obtained in the “Review of Literature” section (technologies, features, and possibilities of electrifying oil and gas objects in the poorly mastered territories) are the basis for modeling the proposed electrification options.

The practical significance of the study lies in the fact that the results of the study can be used by Russian gas and oil companies for pre-project planning to select and justify such technological solutions.

The proposed approach makes it possible to evaluate the project by taking into account the rational choice of the power source for remote deposits; optimal composition of equipment and arrangement of elements of power supply systems, construction schedule; estimates of indicators of the cost of construction and operation of energy supply systems.

Automation of power supply to production facilities in the Far North conditions is a complex technical task. The proposed power supply system has a number of advantages: it operates in a wide range of ambient air temperatures (from +50 °C to −60 °C) and does not require electrification of field sites and maintenance.

This system can be applied to provide:

• Safe transportation of liquid hydrocarbons through continuous monitoring of process parameters of the pipeline system and control of actuators on pipelines;
• Detection of possible leaks for the prompt shutdown of emergency sections;
• Control of scheduled technological operations for cleaning and diagnostics of pipelines;
• Control of the cathodic protection system;
• Power supply to controlled telemechanics points and connected equipment.

The study confirms the technical and economic feasibility of the practical application of a hybrid automated system based on renewable energy sources in the Arctic.

6. Conclusions

The study has proved that there are several directions of electrification of hydrocarbon production facilities, including the use of gas-fueled power plants (natural gas or APG), integration of RES and their combinations with traditional types of power supply, and integration of several facilities into a single power grid and creation of additional power centres. The main difficulty in the use of these directions is that most technological options for the electrification of hydrocarbon production facilities are presented at the conceptual level without implementation results or experimental data. In this work, we attempted to fill the gap of knowledge between theoretical and practical research in the given area on the basis of the comparative technical and economic analysis of variants of electrification of objects of hydrocarbonic extraction, taking into account modern technological possibilities of rational use of power resources and economic feasibility of design decisions.

It has been substantiated that projects for the introduction of RES in the northern fields are of particular interest against the increasing trends of circular economy in the development of alternative energy sources and minimization of CO₂ emissions. Considerable popularity in recent years has been gained by the projects that involve the use of solar energy based on photovoltaic cells, wind generation, and their combination options. However, the efficiency of alternative sources in the conditions of poorly developed northern territories requires individual research and feasibility study since each individual field is characterized by exceptional technological factors of extraction, difficult climatic conditions, and the need to work with permafrost soils during construction, transport seasonality, and high cost of capital construction. Failure to take these factors into account increases the risk of project cost changes during the planning and implementation phase and limits the feasibility of implementing RES.

A design solution for the electrification of hydrocarbon production facilities has been proposed, which implies the power supply of some oil and gas condensate field facilities through an autonomous energy complex, functioning on the basis of combining wind and solar energy with storage batteries, as an alternative to the basic option of centralized power supply scheme from a gas turbine power plant.

The article reflects the algorithm of comparative analysis of electrification options, where the location of the object is evaluated, a preliminary analysis of wind potential on open sources is made, an evaluation of solar potential, logistics, and the equipment of the installation is determined, taking into account the optimal ratio of wind power plants, solar panels, storage units, and diesel generators, and calculation of capital and operating costs for comparison options is performed.

It has been proved that the use of RES is technologically possible provided the sufficient potential of the wind and solar energy and economically feasible subject to a full assessment of construction cost factors taking into account the use of special steel grades, hydrophobic coating, and additional insulation of wind turbine structures, as well as taking into account the increase in costs of construction technologies in frozen ground conditions. A comparison of the options proves that the use of an autonomous energy complex based on wind generation as an alternative to standard electrification reduces costs by RUB 2.24 per kWh of energy used (−60%), which is due to lower capital costs for construction of production facilities and lower current costs for their maintenance RES facilities compared with the transmission line.