Supply Chains for Hydrogen and Carbon Dioxide for Sustainable Production of Base Chemicals

Abstract

In pursuit of global climate goals, the emergence of a hydrogen economy is a promising avenue, emphasizing the environmentally friendly production and versatile applications of hydrogen as an energy carrier, raw material, and cornerstone for energy-intensive sectors such as power, transportation, and especially the chemical industry. This evolution requires profound changes in the supply chain, ranging from the establishment of a robust hydrogen infrastructure to the realization of efficient transportation, distribution, and storage mechanisms. Amidst a plethora of potential hydrogen supply modalities, determining the path to a carbon-neutral hydrogen economy presents complex challenges. This chapter explores these transition complexities in the context of sustainable technology development. It also critically assesses the symbiosis between this transition and emerging carbon supply chains, particularly those aiming for closed carbon cycles, and presents a holistic vision for future sustainable frameworks in the chemical sector.

1. Introduction

With its vast array of products and intricate processes, the chemical industry is one of the influential sectors of the global economy. At the heart is a progressively branching, yet mostly linear, supply chain originating from fossil resources (Figure 1) that ensures the seamless flow of raw materials, intermediates, and finished products across continents and markets. This supply chain, honed over decades, is the silent engine that powers our modern world, from the materials to the chemicals and fuels we use in our daily lives. In this chapter, we will analyze today’s chemical supply chain to understand its intricacies, challenges, and the innovations [1] that are driving their evolution in a rapidly changing global landscape.

Figure 1.

Schematic representation of the linear fossil-based supply chain and the amendments needed to make the supply chain sustainable.

As our collective awareness of the fragility of the planet grows, the concept of sustainability has evolved from a niche concern to a global imperative. For industry, including the chemical sector, the call for sustainability is not only a moral obligation, but also an economic and strategic necessity. Traditional paradigms that emphasized efficiency and output are now converging with environmental protection, resource conservation, and social responsibility. The pressing challenges of climate change, resource depletion, and environmental degradation underscore the need for sustainable transformation in chemical supply chains [2]. This chapter explores emerging sustainable amendments to the supply chain (Figure 1) and how these changes are reshaping the very fabric of chemical production, distribution, and consumption.

In the midst of this transformative shift, the world is eyeing the contours of a sustainable hydrogen economy as an indispensable part of a clean energy supply. Hydrogen stands out not only as an energy vector, but as a keystone for the sustainable evolution of the chemical industry. At the same time, the push toward closed carbon cycles [3] promises a breakthrough solution to some of the world’s greatest environmental challenges. By capturing and reusing carbon dioxide (CO₂), we can forge supply chains that significantly reduce carbon footprints [4] and ensure a circular economy (Figure 1). As we navigate the complex realm of possibilities, it is critical to merge these two paradigms—building an infrastructure that promotes hydrogen while optimizing the sustainable use of carbon. The goal of this chapter is to demonstrate the synergies between a sustainable hydrogen economy and a closed-loop carbon supply chain, with the aim of outlining a blueprint for sustainable production in the chemical industry.

1.1 Sustainable hydrogen economy

One promising strategy to meet global climate objectives is transitioning to the so-called “hydrogen economy” [5]. This concept is based on producing hydrogen in a climate-friendly manner and then using it as an energy source, raw material, and feedstock in energy-intensive sectors such as power generation, transportation, and the chemical industry [6, 7]. In 2020, global hydrogen production was about 120 million tons per annum (t/a) [8]. Hydrogen is used for oil refining and as important feedstock in the chemical industry (39 million t/a), for methanol production and the production of platform and high-value chemicals (14 million t/a) as well as ammonia synthesis (32 million t/a) [9]. Hydrogen plays roles in steel production by the direct reduced iron process (5 million t/a) and in the generation of electricity and heat (30 million t/a) [8]. By 2050, once a hydrogen economy takes shape, the worldwide demand of hydrogen could rise to about 530 million t/a [10]. Transitioning to this hydrogen economy requires fundamental changes in the supply chain including establishing new technologies for hydrogen production and a suitable hydrogen infrastructure. This comprises creating new transport, distribution, and storage systems. Given the diverse methods available for hydrogen supply, determining the best way to provide hydrogen sustainably in the future hydrogen economy needs to be carefully analyzed.

2. Sustainable supply chains for hydrogen

An overview of various hydrogen production technologies, distinguishing between those derived from fossil fuels and those derived from renewable resources, is given in Table 1. The technologies are classified according to the primary feedstock. A notable advance in reducing the process-related CO₂ emissions of conventional hydrogen production is the incorporation of Carbon Capture Utilization and Storage (CCUS) technologies. While relying on the same fossil resources and production process, these methods focus on capturing a significant part of the arising CO₂. After capture, this CO₂ can either be reused (termed as “Carbon Capture and Utilization” or CCU) or stored (known as “Carbon Capture and Storage” or CCS) [11].

Technologies based on fossil resources				Technologies based on sustainable resources
	Natural gas	Oil	Coal	Biomass	Water
Steam reforming	X			Dark fermentation	Electrolysis
Autothermal reforming	X	X		Photofermentation	Thermolysis
Partial oxidation	X	X		Bio-photolysis	Photolysis
Pyrolysis	X	X		X
Gasification		X	X	X

Table 1.

Hydrogen production technologies categorized according to the primary feedstock.

Hydrogen production technologies vary significantly in their development stage, the raw materials or feedstocks they employ (e.g., natural gas, oil, coal, biomass, water), the utilities they require, and their associated Greenhouse Gas (GHG) emissions. To facilitate differentiation, common color-based terms are used to categorize these technologies. For example, the colors “gray,” “blue,” “turquoise,” and “green” often refer to conventional low-CO₂, CO₂-free, and carbon-free production pathways, respectively (Figure 2) [12, 13]. Several other color descriptors, such as “yellow,” “purple,” “pink,” “brown,” and “black,” have been introduced to classify hydrogen production technologies [14].

Figure 2.

Hydrogen production pathways and frequently associated colors, adapted from Ref. [12].

Hydrogen produced from fossil resources is commonly termed “gray” or conventional hydrogen. The most common technology for producing hydrogen is through steam reforming of natural gas. This is often combined with two other fossil-based technologies that are widely used on an industrial scale, autothermal reforming, and partial oxidation [13]. The carbon dioxide resulting from these processes is emitted into the atmosphere, contributing to GHG emissions and, consequently, to global warming [15, 16].

“Blue” hydrogen, often referred to as low-CO₂ hydrogen, uses the same process technologies as “gray” hydrogen [12]. The key difference is how the off-gases from hydrogen production are managed. Before these gases are released into the atmosphere, they are treated to capture most of the resultant CO₂. This captured CO₂ is then stored in geological formations. For a process to earn the “low-CO₂” label, it is essential to ensure that the CO₂ is stored safely. Over time, the CO₂ gradually reacts with the surrounding rock. It is worth noting that there is no universally accepted definition specifying the minimum percentage of CO₂ that must be captured and stored to qualify for this classification [13].

“Turquoise” hydrogen is produced through methane pyrolysis (MP) [12], a process that cleaves methane into gaseous hydrogen and solid carbon. Notably, this process results in no direct CO₂ emissions, earning it the “CO₂-free” label. Similar to the captured CO₂ in “blue” hydrogen production [12], the solid carbon byproduct from MP requires long-term storage to keep it out of the atmospheric carbon cycle [3]. It is also important to note that for the process to be truly CO₂-free, the heat required for the process must be generated without the burning of fossil fuels and the associated release of CO₂ into the atmosphere [15, 17].

“Green” hydrogen is classified as such when its production is based entirely on renewable resources [12]. One notable method of producing “green” hydrogen is water electrolysis powered by electricity derived from renewable primary energy sources. This process does not involve any carbon-based feedstocks. Furthermore, neither the upstream value chain of electricity generation nor the operation of the electrolysis system produces CO₂ emissions, except for those associated with the construction and eventual disposal of the necessary plants and infrastructure. As a result, water electrolysis is often labeled as “carbon-free” [15, 17]. However, similar to the classification of “blue” hydrogen, the label for “green” hydrogen can be ambiguous [12]. There may be instances where the electricity used in the electrolysis cells is supplied by a mix that includes fossil-based primary energy sources [13]. Such a mix might be needed to maintain a high utilization of the electrolysis cells, given the intrinsically fluctuating availability of renewable primary energy sources [18].

Technologies that are poised for large-scale hydrogen production in the near to midterm future are characterized by their reliance on feedstocks with the established, extensive distribution networks and a high Technology Readiness Level (TRL).

2.1 Hydrogen production by steam methane reforming

Today, hydrogen production relies primarily on fossil hydrocarbons as the primary feedstock. The annual production of 70 million t/a of hydrogen is based mostly on the reforming and gasification of natural gas (76%) and coal (23%) [9]. The leading processes are steam reforming, partial oxidation, and autothermal reforming. The remainder of global hydrogen production is attributed to electrolysis, with chlor-alkali electrolysis being the predominant process [9].

Steam reforming [19] is a process that typically uses natural gas as a hydrocarbon feedstock. Methane (CH₄) is the major constituent of natural gas with a molar fraction of 75 to 99% [20]. Therefore, steam reforming is mostly termed Steam Methane Reforming (SMR). However, natural gas also contains varying quantities of higher alkanes. Additionally, it comprises inert gases such as nitrogen and helium, and acidic “sour” gases, predominantly carbon dioxide and hydrogen sulfide [20]. It is worth noting that hydrogen sulfide, when present in hydrogen, can be harmful for downstream processes. This is because sulfur compounds can poison catalysts by chemisorbing to the metal centers that form the active sites of the catalysts [21]. Therefore, it is critical to remove hydrogen sulfide from the hydrocarbon feed [22]. This removal is typically accomplished by hydrotreating or by reaction with activated zinc oxide [15].

The main process steps in SMR are depicted in Figure 3. Initially, methane undergoes catalytic cleavage, forming carbon monoxide (CO) and hydrogen (H₂). This reaction takes place in the presence of steam (H₂O) at temperatures ranging from 700 to 900°C [24] and pressures between 3 and 35 bar [6, 25]. Commonly used heterogeneous catalysts for this process include nickel sponges [15], as well as metal-supported catalysts like nickel/aluminum oxide (Ni/Al₂O₃) [26, 27] or ruthenium/zirconium dioxide (Ru/ZrO₂) [28].

Figure 3.

Main process steps in hydrogen production by steam methane reforming and options for carbon capture, adapted from Ref. [23].

Reacting hydrocarbons with water (as shown in Eqs. (1) and (2)) is highly endothermic that requires substantial external heat supply [19]. The necessary reaction temperatures depend on the hydrocarbon feedstock and typically fall within the 700 to 900°C range [24]. Specifically, for methane, hydrogen formation commences at temperatures above 750°C [24, 25]. The required heat is usually supplied through superheated steam, external reactor heating, or both. Natural gas and off-gases from hydrogen purification are frequently used as fuels for this purpose [6]. In addition, the subsequent step in the SMR process chain, the exothermic Water-Gas-Shift (WGS) reaction (as detailed in Eq. (3)), can be harnessed to contribute to heat integration [19].

$${\mathrm{C}}_{\mathit{n}}{\mathrm{H}}_{\mathit{m}}+n{\mathrm{H}}_2\mathrm{O}\to n\mathrm{CO}+\left(n+\frac{m}{2}\right){\mathrm{H}}_2$$E1

$${\mathrm{CH}}_4+{\mathrm{H}}_2\mathrm{O}\rightleftharpoons \mathrm{CO}+3{\mathrm{H}}_2{\mathrm{\Delta }H}_{\mathrm{R}}^0=+206.3\mathrm{kJ}/\mathrm{mol}$$E2

$$\mathrm{CO}+{\mathrm{H}}_2\mathrm{O}\rightleftharpoons {\mathrm{CO}}_2+{\mathrm{H}}_2{\mathrm{\Delta }H}_{\mathrm{R}}^0=-41.2\mathrm{kJ}/\mathrm{mol}$$E3

After the reforming step, the resulting hydrogen stream contains more than 10 vol.% CO [28]. The WGS reaction addresses this aspect by converting CO and water to CO₂ and H₂, enhancing the hydrogen yield (Eq. (3)). There are two distinct WGS methods, characterized by their operating temperature ranges and catalyst types:

• High-temperature shift WGS: This operates at temperatures between 310 and 500°C and at pressures between 25 and 35 bar. The catalysts used are iron/chromium (Fe/Cr) [29, 30] or cobalt/molybdenum (Co/Mo) [28].

• Low-temperature shift WGS: This operates at temperatures between 190 and 280°C. The catalysts used are copper oxide/zinc oxide (CuO/ZnO) [29] or brass-type catalysts [28].

Typically, a two-stage reactor is used combining these WGS conversion steps. After the dual-step WGS conversion, the carbon monoxide content in the product stream is reduced to about 1% [28]. Carbon dioxide is removed by physical absorption in gas scrubbers. If the hydrogen is destined for ammonia production, residual traces of carbon oxides are methanized, since methane does inhibit ammonia formation. For the generation of high-purity hydrogen, further purification is augmented by methods such as freezing, selective catalytic oxidation, Pressure Swing Adsorption (PSA), hydride storage, and membrane diffusion [6, 15, 25].

Steam Methane Reforming’s (SMR’s) performance is influenced by several factors. According to the Le Chatelier principle, higher temperatures and lower pressures enhance the process [25]. Introducing excess steam avoids coke formation, which is represented by the steam-to-carbon ratio. Typically, this ratio ranges between 2 [19] and 5 [24, 25]. For a balance between hydrogen yield, efficiency, and compact plant dimensions, a ratio between 2.5 [31] and 3.5 [19] is often deemed optimal. Current developments in SMR focus on elevating energy efficiency, particularly in steam preheating. This aims to reduce fuel consumption and increase the reformer’s outlet temperature [32].

Steam Methane Reforming is a mature, well-established technology with a TRL of 9 [25, 27]. Some of the largest SMR plants have capacities of up to 120,000 Nm³/h of hydrogen, primarily to serve the downstream production of ammonia (NH₃) [33]. When evaluating the overall process efficiency based on a Higher Heating Value (HHV), SMR operates at about 65 to 70% [34, 35]. Any excess heat—for instance, steam [36] from cooling of the flue gas or from intermediate product stream cooling—can be repurposed. The steam can either be used to supply adjacent industrial facilities or to produce electricity in steam turbines. The theoretical efficiency limit of SMR stands between 88.9 and 90.7% on a HHV basis [36]. A significant drawback of SMR is its notable process-related CO₂ emissions. With annual emissions currently at 530 million t/a, SMR contributes considerably to exacerbating climate change [9].

2.2 Hydrogen production by partial oxidation

Partial oxidation is currently the second most prevalent method for hydrogen production [9]. While SMR mostly utilizes natural gas, partial oxidation primarily processes higher hydrocarbons [22, 25]. A major advantage of partial oxidation is its flexibility with regard to feedstock quality [37]. In fact, a wide range of carbonaceous materials, ranging from heavy oil and coal to biomass and waste, can serve as potential feedstocks for partial oxidation [38]. The chemical equations of the partial oxidation of hydrocarbons and, specifically, of methane are given in Eqs. (4) and (5), respectively.

$${\mathrm{C}}_{\mathit{n}}{\mathrm{H}}_{\mathit{m}}+\frac{n}{2}{\mathrm{O}}_2\to \mathit{n}\mathrm{CO}+\frac{m}{2}{\mathrm{H}}_2$$E4

$${\mathrm{CH}}_4+\frac{1}{2}{\mathrm{O}}_2\rightleftharpoons \mathrm{CO}+2{\mathrm{H}}_2{\mathrm{\Delta }H}_{\mathrm{R}}^0=-35.6\mathrm{kJ}/\mathrm{mol}$$E5

Partial oxidation can operate without the need for a catalyst, depending on the chosen feedstock [25]. This non-catalytic approach, also known as thermal partial oxidation, is especially advantageous, when processing sulfur-rich feedstocks such as crude oil or coal [37]. Compared to SMR, the thermal partial oxidation process is carried out at higher temperatures ranging from 1200 to 1500°C [38] and elevated pressures between 20 and 100 bar [6, 25].

To enhance the hydrogen yield and facilitate the use of reduced process temperatures in the range of 800–900°C [15, 19, 38], a catalyst can be introduced. Both, noble metals (such as Pt, Rh, Ir, Pd) and non-noble metals (like Ni, Co), are commonly used as heterogeneous catalysts for partial oxidation [38]. For catalytic partial oxidation to be effective, the sulfur content of the feed must, however, be below 50 ppm to prevent catalyst poisoning [38]. If the feed has higher sulfur contents, the non-catalytic partial oxidation is preferable. Otherwise, similar to SMR, there is a prerequisite to desulfurize the feedstock [38].

After any necessary pre-treatment, the hydrocarbon feedstock undergoes partial oxidation. This is achieved by adding less than the stoichiometrically required amount of an oxidant [38]. While air, oxygen, and oxygen-enriched air can be used [38], pure oxygen is the preferred choice. Using pure oxygen avoids the reaction of nitrogen and hydrogen, leading to a cleaner, more concentrated product stream [25].

As in SMR, hydrogen and carbon monoxide are the main products. Moreover, the use of sulfur-containing feedstocks results in the formation of hydrogen sulfide and a small amount of carbonyl sulfide as by-products [25]. The raw product gas may also contain particles such as soot. To remove these unwanted contaminants, the hydrogen stream must be cleaned, for example, by a gas scrubber [28, 39]. For feedstocks with relatively high sulfur contents above 3–4 wt.%, elemental sulfur can be recovered as a marketable byproduct [40].

The subsequent process steps resemble those of the SMR process [25]. The WGS reaction (Eq. (3)) is carried out to further increase the hydrogen yield, followed by the final purification of the product stream.

The concept of partial oxidation surpasses that of SMR in terms of a more compact process design and higher reaction rates [41]. In addition, no external heat is required as sufficient energy is recovered from the exothermic oxidation reaction [41, 42]. A disadvantage of partial oxidation is the need for pure oxygen as oxidant. Oxygen is usually provided by a cryogenic air separation unit [15], which is typically the most expensive part of the plant [25, 43]. In the future, however, sample amounts of pure oxygen may be available from water electrolysis plants, as this technology becomes widely available.

2.3 Hydrogen production by autothermal reforming

Autothermal reforming [44] is a process that combines steam reforming and non-catalytic partial oxidation in a single reactor to take advantage of both technologies [22, 37, 38, 43]. The reactor is configured in two successive sections: In the first section, called the combustion zone, the partial oxidation takes place. The heated gas is then passed to a fixed bed catalytic section where the reforming reactions take place [45]. After syngas production, as in SMR and partial oxidation, the WGS reaction is performed to further increase the hydrogen yield [22, 46].

Gaseous and liquid hydrocarbon feedstocks can be processed. At a process temperature of 850°C, a crude product gas with about 60 to 65% hydrogen is obtained [28]. As with the individual processes, it is advantageous to operate the autothermal reforming process with an excess of steam, high process temperatures, and pure oxygen as the oxidant. These measures prevent the formation of solid carbon particles such as coke in the reactor [6, 28, 39]. Assuming methane as feedstock, the net enthalpy is ${\mathrm{\Delta }H}_{\mathrm{R}}^0=+170\mathrm{kJ}/\mathrm{mol}$. Noteworthy, the process can be operated as an exothermic, endothermic, and thermoneutral type depending on the selected ratio of hydrocarbon feedstock, oxygen, and steam supply [45].

By integrating the excess heat of exothermic partial oxidation (Eqs. (4) and (5)) for endothermic steam reforming (Eq. (1)), the combined autothermal reforming process results in higher thermal efficiencies than the individual processes [47]. Furthermore, autothermal reforming shows higher feedstock flexibility [45] and entails a lower risk of coking than SMR [31]. Autothermal reforming is considered to be suited for relatively small production plants [28, 39] and producing syngas with a low hydrogen/carbon monoxide (H₂/CO) ratio [38, 48].

2.4 Hydrogen production by methane pyrolysis

In MP, methane (CH₄) is cleaved into gaseous hydrogen (H₂) and elemental carbon (C) [49, 50], as given by Eq. (6).

$${\mathrm{CH}}_4\rightleftharpoons \mathrm{C}+2{\mathrm{H}}_2{\mathrm{\Delta }H}_{\mathrm{R}}^0=+74.9\mathrm{kJ}/\mathrm{mol}$$E6

In the MP process, methane is primarily sourced from natural gas, a fossil hydrocarbon feedstock. As shown in Figure 4, the main process steps in MP include the actual cleavage of methane into gaseous hydrogen and solid carbon, the removal of the solid carbon from the product stream, and the purification of the hydrogen produced [44]. MP requires greater amounts of methane for hydrogen production, given that the molar ratio of H₂ product to CH₄ feedstock is 2:1, compared to 4:1 for SMR. A notable advantage of MP over SMR is its reduced environmental impact [12]: MP does not result in direct CO₂ emissions. Therefore, hydrogen produced by MP is frequently labeled as “turquoise” or CO₂-free hydrogen [12, 13]. Because of this environmental advantage, MP is regarded as a potential bridging technology for more climate-friendly hydrogen production [51].

Figure 4.

Main process steps of hydrogen production by methane pyrolysis.

As methane is chemically very stable and MP an endothermal reaction, high temperatures are necessary to trigger the chemical conversion [52]. MP technologies are classified according to the characteristic temperature range, into catalytic, non-catalytic thermal, and plasma-based processes (Figure 5). By using a suitable catalyst, the methane conversion can be achieved at temperatures as low as 500°C [54]. It should be noted that the reaction rate increases with temperature [50, 55]. In contrast, the thermal, non-catalytic conversion of methane necessitates temperatures of at least 700°C [54]. Plasma technologies are particularly suitable for achieving the high temperatures required for thermal MP. To achieve practical space-time yields in industrial applications, anticipated temperatures are above 800°C for catalytic processes, 1000°C for non-catalytic processes, and up to 2000°C for plasma-based processes [53, 56, 57]. Significant research is currently underway to determine the optimal choice of catalyst for MP, to understand the kinetics of the reaction, and to elucidate the underlying reaction mechanism. This research is aimed at developing a robust and scalable process concept [58].

Figure 5.

Classification of methane pyrolysis concepts adapted from Ref. [53].

Numerous reactor concepts have been proposed for MP. These include plasma [59, 60, 61], packed bed [62], (circulating) fluidized bed [63, 64, 65], monolithic [66, 67], liquid bubble column [49, 68, 69, 70, 71, 72], and moving bed reactors [53]. Most of these concepts, however, are still in the early stages of development, predominantly explored at the laboratory scale (TRL 3–4) [53]. Scaling up MP for commercial hydrogen production presents several challenges [53] that must be overcome:

1. Meeting the significant heat demand to achieve practical space-time yields.

2. Managing the deposition of coke and solid carbon on the catalyst surface and within the reactor.

3. Use of natural gas, as opposed to pure methane, as a feedstock. This requires understanding the effects of a more complex gas composition on both process performance and product gas purity.

4. Effective processing and finding commercial applications for the resulting solid carbon that is obtained as a byproduct.

Catalysts play a pivotal role in MP. Various metals, especially nickel [73, 74, 75], iron [76, 77], and cobalt [78, 79], as well as carbonaceous materials [63, 80, 81, 82, 83] have been investigated as potential catalysts. Molten media [70, 71, 72, 84, 85] have been tested to enhance methane conversion and hydrogen selectivity at lower temperatures.

Among the metals tested, nickel showed the highest catalytic activities [86, 87], followed by cobalt and iron [88]. Nickel-based catalysts, in particular, suffer from rapid deactivation [89, 90, 91]. The deposition of coke on the active sites of the catalysts and in the reactor results in catalyst deactivation [92], decreased heat transfer [93], and reactor plugging [55, 94]. This progressively slows the chemical conversion and leads to a decline in the hydrogen yield. As a result, the catalyst must be periodically regenerated [58]. Suitable methods for removing the accumulated carbon are oxidation of the carbon and gasification with steam. However, both methods lead to the unwanted formation of CO or CO₂ and are contrary to the purpose of producing high-purity hydrogen [55, 69, 85]. In addition, the carbon byproduct may contain catalyst residues [58]. Nickel-based catalysts are relatively costly [95]. Cobalt-based catalysts have lower activity than Ni-based catalysts [79, 96], and their use raises toxicity concerns [74, 97]. In contrast, iron-based catalysts often show greater resistance to carbon accumulation [98, 99], and result in lower costs [95] and fewer environmental concerns [100, 101]. However, iron-based catalysts are less active and provide incomplete methane conversion at moderate temperatures [96].

Carbonaceous materials, such as activated carbon [102], carbon black [103], or graphite [104], combine many desirable properties for use as catalysts in MP, including resistance to high temperatures [52, 105], low cost [81], non-toxicity [58], and tolerance to sulfur compounds [82]. In addition, there is no need to regenerate the carbon catalyst [81], thus avoiding the unwanted formation of CO₂. However, the carbon catalysts require high reaction temperatures to provide reasonable hydrogen yields [106].

Certain metals (Ti, Pb, Sn) [49, 50, 68, 69], metal alloys (Ni-Bi, Cu-Bi) [72, 84], and salts (KBr, NaBr, NaCl, NaF, MnCl₂, KCl) [70, 71] have been proposed to catalyze the thermal cleavage of methane in the form of molten media [85]. In a bubble column reactor methane is introduced at the bottom of the melt, forming bubbles that rise to the surface. Methane cleavage occurs at the interface between the gas bubbles and the molten medium. The rapid physical motion of the gas-liquid mixture results in constant recirculation of gas bubbles and prevents the accumulation of carbon at the interphase [107]. Molten tin has been found to be a suitable medium, allowing operating temperatures up to 1200°C [69, 94]. Laboratory-scale tests of this technology have shown that hydrogen can be produced for many hours without reactor plugging [50, 69].

The bubbles are buoyant according to Archimedes’ principle and rise to the surface of the melt. Since two moles of gaseous hydrogen are formed for each mole of methane, the amount of gas contained in the bubbles increases, resulting in an increasing buoyancy. As a result, the bubbles rise progressively faster until they burst open at the top of the melt. Gaseous hydrogen and residual methane escape upward often entraining some of the solid carbon that separates from the molten medium [85, 94]. Carbon floating on the surface of the melt can be removed and collected [69]. Carbon particles entrained in the gas stream are removed by a filtration system. Hydrogen is then separated from the product gas stream by PSA or by the use of metallic membranes [51, 94, 108]. Unconverted methane is recycled to the reactor.

Industrial applications of MP currently would be based on the use of natural gas. At a later stage, methane from biogas plants may also be used as a feedstock [44]. Few studies have addressed the influence of trace components in the feed gas on critical process parameters such as selectivity, product quality, and conversion [53, 58]. Nickel- and iron-based catalysts are progressively deactivated by contact with hydrogen sulfide [82]. Small amounts of higher alkanes may reduce the deactivation of carbon catalysts [80, 109]. Consequently, feed conditioning may be required. Natural gas components other than CH₄ can trigger the formation of undesirable byproducts such as (un-)saturated hydrocarbons and (poly-)cyclic aromatic compounds [57, 110, 111].

On a mass basis, MP yields a hydrogen-to-carbon ratio of 1:3, which means that only 25% of the product mass is attributable to the primary target product hydrogen [53]. Consequently, the utilization of the carbon byproduct will be critical to the economic feasibility and environmental performance of the process. Highly dispersed amorpous carbon with small particle sizes is currently marketed as carbon black [112]. Carbon black is primarily used as a reinforcing filler in tires and other rubber products, and as a black pigment in plastics, paints, coatings, and printing inks [94, 113]. Minor applications include the manufacture of dry cells and electrodes, and the enhancement of antistatic and conductive properties of polymers and resins [114]. Each application requires a different grade of carbon black with narrow specifications for physical and chemical properties [115].

Depending on the process and the feedstock, furnace black, gas black, channel black, lamp black, acetylene black, and thermal black are distinguished [112]. The internally heated furnace black process, based on petroleum and coal tar oil feedstocks, is most widely used today due to a wide range of accessible carbon black grades and economic viability [116]. The thermal black process provides carbon blacks specialized for high filler mechanical rubber goods. Mainly for economic reasons, industrial plants for example, by the company Monolith Materials have been decommissioned and production has been focused on carbon black [116].

A disadvantage of MP is that it produces two economically valuable products at the same time [53, 59, 117]. The existing carbon black market is of insufficient size considering the sheer scale of a potential future hydrogen production by MP [118, 119, 120]. Global annual carbon black consumption is projected to exceed 15 million t/a [113] in 2025. In comparison, meeting the current annual demand for pure H₂ of approximately 70 million t/a [9] by MP would result in approximately 210 million t/a of carbon [44], exceeding the estimated market demand for carbon black by a factor of 14.

The mismatch between supply and demand is even greater when considering the expected increase in hydrogen demand in the future. It is unlikely that the full range of carbon black grades can be produced by MP alone. Finally, increased material use of the carbon, for example, as a filler in polymeric materials, would result in renewed CO₂ emissions at a later stage of the life cycle. To achieve truly CO₂-free hydrogen production from MP, the carbon must be permanently removed from the atmosphere [44]. While storage does not add value, the use of carbon fillers in concrete and for other construction purposes could meet the criteria for long-term removal of the carbon from the atmosphere. Carbon-reinforced cement could also contribute to material savings and reduced energy demand [121, 122, 123].

2.5 Hydrogen production by water electrolysis

Water electrolysis [44] is the electrochemical cleavage of water (H₂O) into hydrogen (H₂) and oxygen (O₂), Eq. (7). Unlike other hydrogen production technologies, water electrolysis does not rely on fossil resources. As a result, hydrogen from water electrolysis is often referred to as “green” or carbon-free hydrogen [13]. Nevertheless, there may be significant climate change impacts from equipment manufacturing, infrastructure development, and the underlying water and electricity supply chains [44].

$${\mathrm{H}}_2\mathrm{O}\rightleftharpoons {\mathrm{H}}_2+\mathrm{½}{\mathrm{O}}_2{\mathrm{\Delta }H}_{\mathrm{R}}^0=+285.9\mathrm{kJ}/\mathrm{mol}$$E7

Water electrolysis [44] is based on an electrolysis cell, which consists of two electrodes that are spatially and electrically separated from one another by a an ion-conducting electrolyte [124]. Electricity is supplied in the form of a direct current to create a difference in electrical potential between the electrodes [124]. When a sufficiently high electric potential is applied, an endothermic ($\mathrm{\Delta }{H}_{\mathrm{R}}>0$), non-spontaneous ($\mathrm{\Delta }{G}_{\mathrm{R}}>0$) redox reaction is initiated [126]. At one of the electrodes, water is electrochemically converted to either O₂ and positively charged ions (cations) by oxidation, or H₂ and negatively charged ions (anions) by reduction [124]. The ions then migrate through the electrolyte to the other electrode, attracted by its opposite charge [127]. At the second electrode, the second part of the redox reaction takes place, forming either H₂ by reduction at the cathode, or O₂ by oxidation at the anode [128].

The thermodynamics of water cleavage is described by Eq. (8) in combination with Eq. (9) [129]. The minimal voltage ($U_{\min }$) for a water electrolysis cell to operate can be derived by considering the electrons transferred per mol of water ($n=2$) and the Faraday constant ($\mathrm{F}=96485\mathrm{C}/\mathrm{mol})$ [129, 130].

$$\mathrm{\Delta }{H}_{\mathrm{R}}=\mathrm{\Delta }{G}_{\mathrm{R}}+\mathrm{\Delta }{S}_{\mathrm{R}}\times T$$E8

$$\mathrm{\Delta }{G}_{\mathrm{R}}=U_{\min }\times n\times \mathrm{F}$$E9

At a standard temperature of 25°C and pressure of 1 bar, the thermodynamic changes associated with water cleavage are as follows: ${\mathrm{\Delta }G}_{\mathrm{R}}^0=237.21\mathit{kJ}{\mathit{mol}}^{-1}$, ${\mathrm{\Delta }S}_{\mathrm{R}}^0=0.1631\mathit{kJ}{\left(\mathit{mol}K\right)}^{-1}$, and ${\mathrm{\Delta }H}_{\mathrm{R}}^0=285.84\mathit{kJ}{\mathit{mol}}^{-1}$ [131]. When the entire process heat is supplied externally, the minimum cell voltage for water splitting, called the “reversible” cell voltage, is 1.23 V [126, 129, 130]. In many cases, both the electrical energy and the thermal energy are supplied electrically, resulting in a thermo neutral cell voltage of 1.48 V [126, 129, 130]. It is important to note that the actual cell voltage ($U_{\text{cell}}$) in practice is higher due to the cell overpotential, which results from activation losses at the electrodes, mass transport limitations, and ohmic resistances [130]. As described by Eq. (10), these factors contribute to a reduced efficiency (${\eta }_U$) of the electrolysis cell, defined as the ratio of the minimal to the actual cell voltage [129].

$${\eta }_U=\frac{U_{\min }}{U_{\text{cell}}}$$E10

The efficiency of electrolyzers is given by the ratio of the energy content of the hydrogen produced to the electricity consumed ($E_{\mathrm{el}}$) [132]. Taking into account the energy demand of the entire process chain, the metrics used for calculating the efficiency is based on the Lower Heating Value (LHV, 3.00 kWh/Nm³), as given in Eq. (11), or on the HHV value (3.54 kWh/Nm³) of hydrogen, as shown in Eq. (12) [129]. The choice depends on the aggregate state of the supplied water, specifically whether the water is in a liquid or vapor state. When liquid water is introduced into the electrolyzer, the HHV value is used for calculations. However, when steam is supplied, the LHV value is selected because the energy for water evaporation has been accounted for before the water enters the electrolyzer. In addition, the choice between HHV and LHV depends on the intended use of the produced hydrogen: chemical applications prefer HHV, while energy-related applications favor LHV. Consideration is also given to whether the oxygen byproduct will be further used [132].

$${\eta }_{\mathrm{LHV}}=\frac{\mathrm{LHV}}{E_{\mathrm{el}}}$$E11

$${\eta }_{\mathrm{HHV}}=\frac{\mathrm{HHV}}{E_{\mathrm{el}}}$$E12

2.6 Water electrolysis technologies

The primary technologies for hydrogen production by water electrolysis [44] are Alkaline Electrolysis (AEL) [133], Polymer Electrolyte Membrane electrolysis (PEM) [134], and high-temperature electrolysis with Solid Oxide Electrolysis Cells (SOECs) [135]. These technologies differ in their stage of development, choice of electrolyte and charge carrier, operating conditions, and suitability for dynamic operation, especially when powered by intermittent renewable energy sources [124]. Commercial systems are available for both AEL and PEM, with AEL being the most advanced and dominant commercial technology [136]. Its leading position largely arises from the knowledge and experience acquired from chlor-alkali electrolysis, the main technology used for the production of chlorine and caustic soda [137]. In contrast, SOEC is still under development and has yet to gain a foothold in the industry [138, 139, 140]. Each electrolysis technology has its own set of advantages and disadvantages. The following is a brief overview of the three main technologies.

2.6.1 Alkaline water electrolysis

In AEL, a diaphragm that is permeable to OH⁻ ions separates the electrodes (Figure 6). Conventional AEL systems employ an alkaline solution, typically 20–40 wt.% aqueous potassium hydroxide, as the electrolyte [141, 142]. In the newer, advanced AEL concept, the electrodes are separated only by a gas-tight barrier, eliminating any spatial gap. This innovative “zero-gap” technology [143] achieves superior efficiencies compared to conventional AEL systems.

Figure 6.

Schematic representation of an alkaline water electrolysis cell for producing hydrogen adapted from Ref. [12].

In the AEL process, deionized water is supplied in liquid form to the cathode. When an electric potential is applied to the electrodes, this water is cleaved into hydrogen gas and OH⁻ ions (Eq. (13)). The OH⁻ ions migrate through the electrolyte, pass through the diaphragm, and reach the anode, where they are converted to form water and oxygen (Eq. (14)).

$$\mathrm{\text{Cathode reaction}}2{\mathrm{H}}_2\mathrm{O}+2{\mathrm{e}}^{-}\rightleftharpoons {\mathrm{H}}_2+2{\mathrm{OH}}^{-}$$E13

$$\mathrm{\text{Anode reaction}}2{\mathrm{OH}}^{-}\rightleftharpoons \mathrm{½}{\mathrm{O}}_2+{\mathrm{H}}_2\mathrm{O}+2{\mathrm{e}}^{-}$$E14

Alkaline electrolyzers typically operate at temperatures between 40 and 90°C, and pressures between 10 and 30 bar [130, 132]. Their current densities range from 0.13 [32] to 0.5 A/cm² [128], with cell voltages ranging from 1.80 [32, 132, 144] to 2.4 V [132, 144]. This results in stack efficiencies of 62 to 82% in modern commercial systems [144, 145].

Alkaline electrolysis is the most mature water electrolysis technology [132, 141, 144, 146], having reached the industrial scale (TRL 9) for several decades [126, 133]. Notably, the world’s largest AEL plant, with a capacity of 156 MW, is situated at the Aswan Reservoir in Egypt. This plant, operating at ambient pressure, can produce up to 33,000 Nm³/h of hydrogen per hour [132]. This maturity offers notable benefits. AEL electrolyzers tend to have lower capital costs [126, 136, 141, 144, 147] and are well suited for large-scale applications [126, 141, 144]. Their durability exceeds that of other water electrolysis technologies [126, 136, 141, 144]. The use of non-precious catalysts makes AEL even more attractive [144]. However, AEL also has its drawbacks. Conventional AEL systems are limited in terms of current densities [130, 136, 144, 146, 147] and operating pressures [144]. Consequently, the dimensions of AEL electrolyzers are significantly larger than those of PEM electrolyzers of equivalent capacity [133]. Their partial load range is limited [130, 132, 136, 141, 144, 146], and there is a risk of gas crossover at low loads [144]. This not only compromises the purity of the hydrogen gas produced but may also raises safety concerns.

2.6.2 Polymer electrolyte membrane water electrolysis

The main components of a PEM cell are shown in Figure 7. A typical PEM cell comprises a solid polymer electrolyte sandwiched between two electrodes, an anode and a cathode, both coated with noble metal catalysts. Adjacent to these electrodes are two porous transport layers, flanked by two bipolar plates [134, 148].

Figure 7.

Schematic representation of a polymer electrolyte membrane water electrolysis cell for producing hydrogen adapted from Ref. [12].

The electrolyte in a PEM cell is a proton-conducting membrane made of porous polymer materials, often either Nafion™ [134] or fumapem™ [144]. This membrane, which has a thickness varying between 60 [148] and 200 μm [130], promotes the flow of current and facilitates transport of water and gas.

Electrodes, with a thickness of about 10 μm [148], are coated directly onto the membrane, a design aimed at minimizing ohmic resistances [130]. These electrodes are decorated with noble metal catalysts: typically, iridium for the anode and platinum for the cathode [144, 149]. The need for rare and costly materials, including platinum, iridium, and titanium, is a challenge. Their use is necessary, given the resilience to high potentials at the anode and the corrosive acidic environment due to the proton-conducting ionomer [150]. Current research aims to achieve higher current densities, reduce catalyst loading, and minimize the use of rare materials [148].

Surrounding the membrane and electrodes is porous transport layers, measuring approximately 280 μm thick [151]. The transport layer for the cathode is made of carbon paper, while that for the anode is made of sintered titanium foam or felt. Firmly attached to these transport layers are bipolar plates, typically made of titanium [130, 152]. These plates have engraved flow channels that facilitate the transport of water and hydrogen gas [132], and ensure a uniform current distribution over the entire surface [152]. For industrial-scale capacities, multiple electrolysis cells are commonly linked in series to form a single electrolyzer stack, a practice seen across all electrolysis processes [134].

In PEM, deionized water is supplied in liquid form to the anode side [153, 154], where the application of an electric potential initiates the oxidation of water to O₂ and protons (Eq. (15)). The byproduct oxygen leaves the system in gaseous form. The protons travel through the membrane to the cathode, where they combine with electrons to form hydrogen (Eq. (16)), which is also removed in gaseous form [134].

$$\mathrm{\text{Anode reaction}}{\mathrm{H}}_2\mathrm{O}\rightleftharpoons 2{\mathrm{H}}^{+}+\mathrm{½}{\mathrm{O}}_2+2{\mathrm{e}}^{-}$$E15

$$\mathrm{\text{Cathode reaction}}2{\mathrm{H}}^{+}+2{\mathrm{e}}^{-}\rightleftharpoons {\mathrm{H}}_2$$E16

Typical operating conditions for PEM cells are temperatures of 20 [130, 132] to 150°C [32] and pressures of up to 200 bar [134]. To date, electrolyzers with pressures greater than 30 bar have only been tested on a small scale [126]. At current densities of up to 4.0 A/cm² [32] and cell voltages of 1.4 [32] to 2.2 V [132, 144], the energy efficiency of PEM stacks is 67–82% [132, 144].

Polymer Electrolyte Membrane electrolysis is well suited for dynamic operation, seamlessly aligning with the fluctuating availability of electricity generated from intermittent renewable primary energy sources [146, 155]. In this context, PEM has several coveted traits: short response, startup, and shutdown times; low degradation; energy-efficient standby operation; and a wide partial load range, all without compromising the purity of the hydrogen gas produced [130, 132, 136, 144, 147]. Other merits of PEM include its high current densities, compact system design, and the ability to operate safely at high pressures, the latter eliminating the need for post-compression [130, 136, 144, 147].

While PEM systems offer several advantages, they are not without drawbacks. One concern is their dependence on critical, scarce, and expensive materials, a necessity due to their corrosive acidic environment [144]. Their lifetime is compromised by high degradation rates [126, 136, 142]. Financially, they have higher investment costs compared to AEL systems [126, 136, 142, 144]. However, it is important to highlight that there is significant potential for cost reduction through economy of scale [136].

Polymer Electrolyte Membrane electrolysis development began in the 1960s [156]. Although PEM is not as frequently used as AEL [132], PEM electrolyzers are now commercially available (TRL 9) [146]. In 2020, the world’s largest hydrogen production plant using PEM technology commenced commercial operation in Québec, Canada [157]. Powered by four 5 MW electrolyzers, the plant has a total capacity of 20 MW and produces about 3000 t/a of H₂ annually. Notably, both the hydrogen [147] and oxygen [158] produced are of high purity and are used directly without any further purification.

2.6.3 Solid oxide water electrolysis

In SOEC [44], the anode and cathode are separated by an electrolyte composed of oxygen-conducting solid oxides or ceramics, such as yttrium-stabilized zirconia (Figure 8) [144]. This gas-tight electrolyte becomes permeable to O²⁻ ions at high temperatures [138].

Figure 8.

Schematic comparison of a solid oxide electrolysis cell for generating hydrogen adapted from Ref. [12].

Unlike the other electrolysis technologies, SOEC uses superheated steam instead of liquid water, which is supplied to the cathode. When an electric potential is applied to the electrodes, the water is cleaved into hydrogen and O²⁻ ions (Eq. (17)). The hydrogen produced is then removed from the system. Meanwhile, the O²⁻ ions migrate through the solid oxide electrolyte membrane to the anode, where they are oxidized to oxygen (Eq. (18)) [126, 132].

$$\mathrm{\text{Cathode reaction}}{\mathrm{H}}_2\mathrm{O}+2{\mathrm{e}}^{-}\rightleftharpoons {\mathrm{H}}_2+{\mathrm{O}}^{2-}$$E17

$$\mathrm{\text{Anode reaction}}2{\mathrm{O}}^{2-}\rightleftharpoons \mathrm{½}{\mathrm{O}}_2+2{\mathrm{e}}^{-}$$E18

In SOEC stacks, operating temperatures range from 600°C [126, 159] to 1000°C [32, 130, 132, 143], markedly higher than those applied in other electrolyzer types [160, 161, 162, 163]. Unlike other processes that use liquid water, SOEC uses steam, a feature that contributes to high efficiencies that can exceed 80% [32]. In terms of performance, the system typically operates at current densities range between 0.3 [32, 138, 141] and 2.0 A/cm² [138, 141], resulting in cell voltages of 0.7–1.5 V [138].

Solid oxide electrolysis cell is at an early development stage and has yet to be adopted by the industry [138, 139, 140]. Extensive research is needed to make the transition to industrial application, particularly in developing cost-effective, durable, and heat-resistant ceramic materials [126, 132, 136], achieving higher current densities [136], and reducing investment costs [136, 146].

Solid oxide electrolysis cell is emerging as a technology with significant potential for the future [144]. One of its major advantages is the use of steam instead of liquid water, which results in significantly lower operating potentials [132, 135, 136, 146]. This choice affects two thermodynamic properties. First, as the process temperature increases, the thermal component of the reaction enthalpy ${\mathrm{\Delta }H}_{\mathrm{R}}^0$ (as seen in Eq. (8)) also increases. Conversely, the energy required for electrochemical water cleavage, represented by ${\mathrm{\Delta }G}_{\mathrm{R}}^0$ (see Eq. (9)), decreases substantially. This improved efficiency stems from the fact that the use of steam eliminates the energy otherwise required for the phase change during electrolysis [132]. Interestingly, under certain conditions, where steam is supplied at extremely high temperatures, the efficiency can theoretically surpass 100% [144]. Overall thermal efficiency can also benefit from the use of waste heat sources, such as otherwise unused excess heat from nearby industrial facilities [126, 132, 146].

Another advantage of SOEC is its flexibility: Many solid oxide cells can function as either electrolytic cells or fuel cells [126], meaning that they can also use hydrogen as a fuel to generate electricity. This duality allows plant operators to store surplus energy for times when demand exceeds supply [18]. With its ability to buffer fluctuations in power supply and the resulting increase in plant operating hours, SOEC is attractive when combined with renewable power generation technologies [135]. However, in order to respond quickly to load changes, the cell must maintain a consistently high temperature due to its long cold start time. Therefore, a continuous and readily available source of (excess) heat is critical.

3. Sustainable supply chains for carbon dioxide

In the evolving narrative of global sustainability, carbon dioxide (CO₂) plays a central role, not only as an environmental concern, but also as a valuable resource. As industries move to utilize CO₂ in various applications, the focus is now on creating sustainable supply chains dedicated to its management and utilization. These supply chains must holistically address the capture, transportation, storage, and end-use of CO₂, ensuring that each step is optimized for environmental and economic viability. As we enter this arena, we will take a deep dive into understanding the intricacies and imperatives of building and maintaining a sustainable carbon supply chain, setting the stage for a future where carbon management is seamlessly integrated into our industrial fabric.

3.1 Carbon capture

Three technologies are used primarily for CO₂ capture: pre-combustion, oxyfuel combustion, and post-combustion [164, 165]:

• Pre-combustion: In this upstream process, the carbon in the fuel is converted to CO₂ prior to combustion. The CO₂ is then captured using techniques such as physicochemical absorption in aqueous amine scrubbing solutions, or physical absorption with solvents such as polyethylene glycol dimethyl ether (Selexol™) and cold methanol (Rectisol™) [166, 167].

• Oxyfuel combustion: This industrial-scale combustion method uses pure oxygen for combustion. This results in a CO₂-enriched flue gas stream, facilitating CO₂ sequestration.

• Post-combustion: Here, CO₂ is captured from the post-combustion flue gas stream in a downstream process. Technologies used for CO₂ capture include absorption by Monoethanolamine (MEA), adsorption on solid sorbents, cryogenic separation, and pressure swing adsorption [165, 168].

In the context of SMR, pre-combustion CO₂ capture from the shifted syngas by chemical absorption with aqueous Methyldiethanolamine (MDEA) is recognized as the standard practice [44]. This preference is largely due to the high partial pressure of CO₂ in the syngas stream (16 vol.% CO₂ at 25 bar) at this stage of the process [169]. Capturing CO₂ from the tail gas has often been viewed as less economically viable due to the lower CO₂ partial pressure (51 vol.% at 2 bar) [169], but remains an area of research [23]. For the post-combustion stages, CO₂ capture from the flue gas stream, which contains 21 vol.% CO₂ at 1 bar [169], is primarily accomplished by chemical absorption, typically using MEA scrubbing [170, 171, 172].

In the CO₂ absorption process, the gas stream is contacted with a solvent, commonly aqueous MEA or MDEA, in an absorption column [44]. This step effectively extracts CO₂ from the gas stream. Once saturated with CO₂, the solvent is regenerated by heating it in a stripper unit, releasing the CO₂ for subsequent use. A continuous solvent make-up stream is required to compensate for evaporation losses and degradation [171].

The efficiency of CO₂ capture varies, ranging from 53 to 95%. While it is technically possible to capture a larger fraction of the CO₂, this requires greater energy consumption [170, 171, 172, 173]. Integrating carbon capture technologies into SMR plants results in a 5–14% reduction in their efficiency [168]. Often, the site where CO₂ is captured is spatially separated from the site where the CO₂ is used (CCU) or stored (CCS). Therefore, CCUS strategies involve require not only CO₂ capture, but also the transportation of CO₂—whether by pipeline, ship, or other means—to its intended destination. This often requires significant investment to develop the appropriate transportation infrastructure [173].

3.2 Carbon dioxide transport

To achieve a transport density that is both technically manageable and economically feasible, carbon dioxide (CO₂) may need to be compressed, liquefied, or solidified. Some key properties of CO₂ include its condensation at 57.28 bar at ambient temperature (20°C) [174], a critical point at 31.04°C and 73.83 bar [174], and its freezing point at −78.46°C at standard pressure (1 bar) [174]. CO₂ can be transported in various forms, including as a compressed gas, in liquid or supercritical state or even in its solid form [175, 176].

• Compressed state: Pipelines, due to their energy and economic efficiency, are commonly preferred for transporting large quantities of CO₂ over long distances [175, 177]. Maintaining a high density of CO₂ is critical for economical transport, which in turn minimizes the energy required for compression along the transport route [177, 178].

• Liquid and supercritical state: CO₂ can be easily liquefied, although this requires a significant energy input of 0.11 kWh/kg CO₂ [179]. Supercritical CO₂, which combines the density of a liquid with the low viscosity of a gas [180], is especially suitable for transportation [176, 178]. To ensure that CO₂ remains in this supercritical state [181, 182], pipelines typically operate at temperatures between 13 and 44°C and pressures between 85 and 150 bar [183, 184, 185].

• Solid state (dry ice): CO₂ can be converted to “dry ice,” its solid form. This option requires substantial energy to cool the CO₂ to temperatures below −78.0°C [174]. Because dry ice sublimes continuously, even in well-insulated containers, it is typically produced on demand.

Ultimately, the optimal method of transporting CO₂ depends on factors such as distance, quantity, and the infrastructure available.

3.3 Carbon dioxide storage

Physical storage of CO₂ in salt caverns is suitable for temporary storage of large quantities [168]. For longer-term storage, especially in the context of CCS, CO₂ must be injected into suitable geological formations [11]. These include aquifers, depleted oil and gas reservoirs, and coal seams [186]. Typically, CO₂ is compressed and injected under supercritical conditions into these geological formations [170]. One notable monitoring project took place in the Williston Basin, a geological formation in Canada and the US. As part of the International Energy Agency Greenhouse Gas (IEAGHG) research program from 2000 to 2012, this study found no evidence of CO₂ leakage from the geologic storage site [187]. Estimates of annual leakage rates vary, ranging from 0.00001 to 1%, based primarily on the permeability of the rock formation [165]. Over time in the geological reservoirs, CO₂ undergoes chemical transformation with the adjacent rock formations [188, 189]. Silicates, for example, in the reservoir slowly react with CO₂ to form carbonates and silica, as exemplified by Eq. (19).

$${\left(\mathrm{Mg},\mathrm{Mn},\mathrm{Fe}\right)}_2\left[{\mathrm{SiO}}_4\right]+2{\mathrm{CO}}_2\to 2\left(\mathrm{Mg},\mathrm{Mn},\mathrm{Fe}\right)\left[{\mathrm{CO}}_3\right]+{\mathrm{SiO}}_2$$E19

To meet the Paris Agreement’s goal of limiting global warming to 1.5°C [190], the amount of CO₂ that must be sequestered through CCS varies across different scenarios [191]. On a global scale, projections for annual CO₂ capture in the twenty-first century range widely, from none at all to over 1200 Gt/a per year [191]. Within Europe, the expected capture could reach up to 300 million t/a annually by 2050 [191].

The estimated global storage capacity for CO₂ spans from 3900 to 55,000 Gt of CO₂ [191, 192]. However, it should be noted that potential hazards associated with storage could lead to social or regulatory restrictions. After accounting for such constraints, Europe’s CO₂ storage capacity is estimated at 134 Gt of CO₂ [193], which would last for about 400 years based on current emission rates [11].

The first CCS plant was commissioned in the US in 1972 as part of an Enhanced Oil Recovery (EOR) project [194]. EOR involves the injection of gaseous CO₂ into mature oil reservoirs. The dissolution of CO₂ in the oil reduces the oil’s viscosity and interfacial tension, causing it to swell and restore the declining oil production rates [194]. Turning to Europe, the Sleipner oil field in Norway is home to the first permanent, dedicated CO₂ storage facility and has been in operation since 1996 [11]. Globally, there are now 26 commercial CCS facilities in operation, with a combined annual CO₂ capture of 40 million t/a [194]. Of these, six facilities are designed for dedicated geological storage, while the other 20 facilities use the CO₂ for EOR or Enhanced Gas Recovery (EGR) as a revenue-generating mechanism [194]. In addition, 34 pilot and demonstration facilities are either operational or in the development phase [194]. Given the maturity of the technologies involved throughout the value chain, the SMR-CCS approach is considered to be verified at an industrial scale, achieving a TRL of 8-9 [11].

3.4 Physical utilization of carbon dioxide

There are many possibilities for the industrial use of CO₂. In general, CO₂ can either be used directly in its physical form or it can be chemically converted into value-added products. Direct utilization technologies take advantage of the unique physicochemical properties of CO₂. At ambient conditions, CO₂ is an inert, non-flammable, and non-toxic gas.

Several applications make use of gaseous CO₂. For instance, it is used in fire extinguishers [174, 195] and acts as an economical shielding gas in arc welding [195, 196]. It also plays a role in food preservation [2, 174].

Carbon dioxide (CO₂) is readily soluble in a variety of liquids, including water. When dissolved in water, CO₂ forms carbonic acid. This reaction is harnessed by the beverage industry to produce carbonated beverages, such as soda and sparkling water [174]. The formation of carbonic acid plays a role in adjusting the pH of aqueous solutions applications in several industries [180], including the production of hydrogen peroxide by the reaction of hydrogen and oxygen [197, 198], bleaching in the textile and paper industries [199], and the treatment of alkaline wastewaters [200].

An intriguing characteristic of CO₂ near the critical point is its responsiveness to small changes in temperature and pressure. These small changes significantly alter the properties of CO₂, including its density, viscosity, miscibility and solubilizing power, and polarity. As a result, CO₂ is advantageous for tweaking the properties of switchable solvents, surfactants, and other materials. This adaptability promotes energy-efficient separation processes [201].

Its supercritical point at 31.1°C and 73.8 bar allows CO₂ to become supercritical under mild conditions [174]. Supercritical CO₂ is widely used across industries, acting as a reaction medium for catalysis [202], extractant in coffee decaffeination [203], and aiding the textile industry in dyeing and impregnating [204] fibers and polymers [205]. Its role also extends to other industrial processes, including dispersion polymerization [206, 207], fractionation, and powder polymer formation [208, 209]. One of its outstanding properties is its low heat of vaporization, which makes it an easily recoverable solvent, and suggests its potential as a substitute for other more harmful solvents [210]. In the context of sustainability, supercritical CO₂ stands out as an environmentally friendly substitute for more harmful and hazardous refrigerants, especially in refrigeration cycles [211].

In its solid form, CO₂ is known and marketed as dry ice, available in compressed blocks or pellets. Notably, below its triple point of −56.57°C and 5.18 bar [174], CO₂ sublimates, transitioning directly from its solid to its gaseous state without becoming a liquid. This property makes dry ice an attractive, residue-free, non-toxic, and lightweight refrigerant, commonly used in applications such as food preservation [195].

It is important to underscore that the physical applications of CO₂ do not result in its permanent removal from the atmospheric carbon cycle [3]. Instead, the captured CO₂ is emitted back into the atmosphere shortly after its use. As a result, its role in mitigating climate change is marginal [212].

3.5 Chemical utilization of hydrogen and carbon dioxide

Chemical utilization of CO₂ [213] provides a pathway [195] to transform the captured CO₂ into value-added products [2, 214], either integrating them into anthropogenic carbon cycles [3] or permanently removing the carbon [215]. Due to CO₂ being the most oxidized form with carbon in oxidation state +IV, it possesses a low-energy level making it thermodynamically stable [3]. This means CO₂ does easily engage in chemical conversions at low temperatures, given its inherent stability [216]. To promote chemical reactions involving CO₂ one of the following strategies is generally employed [2, 213, 217]:

1. Using energy-rich co-reactants such as hydrogen and epoxides.

2. Applying external energy sources, whether electrical, thermal, radiant, or other forms.

3. Adjusting variables like reaction temperatures, concentrations, and pressures to sway the chemical equilibrium, based on the Le Chatelier principle.

4. Aiming for low-energy target products.

Using an appropriate catalyst for CO₂ conversion can introduce alternative reaction pathways with a lower activation energy, accelerating the reaction rate and improving selectivities [218]. Reactions for converting CO₂ comprise redox reactions and carbonylation and carboxylation reactions [213]. This chapter will not delve further into the latter as they do not involve the use of hydrogen.

Catalytic hydrogenation, which employs hydrogen (H₂) as the reducing agent, is the predominant method for providing the energy required for CO₂ reduction [219]. CO₂ hydrogenation gives access to value-added products [124], with methane [220], methanol [221], formic acid [222], carbon monoxide [223], and syngas [224] being the primary focus of current research. These products are promising because they serve as important platform chemicals. Currently, their large-scale production in the chemical industry is energy intensive and results in significant GHG emissions. Their climate-friendly production (see, e.g., [225]) could significantly mitigate global warming [41, 226].

The integration of these novel chemical processes into the chemical industry could occur seamlessly at an early stage of the value chains without requiring significant changes to the existing downstream production chains. Hence, CO₂ hydrogenation holds the promise not only to utilize vast quantities of CO₂ as a renewable carbon source, but also to position H₂ as a key feedstock for manufacturing high-demand platform chemicals. This could further amplify the already significant demand for H₂ in the (petro)chemical sector. Nevertheless, for these hydrogenation-based CO₂ utilization techniques to reach their full environmental potential, an environmentally sound supply of both CO₂ and H₂ is essential [226, 227].

Chemical CO₂ utilization technologies represent a promising avenue, not only for utilizing CO₂ captured from flue gases that would otherwise be released to the atmosphere, but also as a means to transition away from fossil carbon-based, energy-intensive feedstocks [2, 228]. As such, CCU technologies have the potential to reduce the industry’s impact on fossil resource depletion and global warming [212, 216].

However, it is important to recognize that the CO₂ used in these methods will eventually be released once the product’s lifetime concludes. While this temporary carbon storage does not avoid the resulting climate change impacts, delaying its release may still bear environmental benefits [229]. Notably, contemporary assessment methods do not account for such temporary CO₂ storage [230], and there is ongoing discussion about accounting for it [213]. One possible solution is to assess time-corrected global warming potentials [230, 231]. Current guidelines suggest reporting the amount and duration of stored carbon independently [232, 233]. Ultimately, anthropogenic carbon cycles [3] need to be established (Figure 9).

Figure 9.

Anthropogenic carbon cycles, adapted from Ref. [3].

Evaluating the environmental impact of CCU technologies presents unique challenges. One primary concern is the inherently temporary nature of CO₂ storage. Incorporating CCU technologies into existing production chains often leads to multifunctional systems producing multiple valuable products. While methods exist to account for these coproducts in life cycle assessments, meticulous attention is essential when setting the system boundaries and the functional unit [44]. This becomes especially pertinent in studies comparing alternative technologies for a singular product. The multitude of potential uses for captured CO₂ complicates the selection of a specific product or a technology. Emphasis should be on those technologies that promise longer storage durations of captured CO₂, aiming for its permanent removal from the atmospheric carbon cycle [3].

4. Conclusions

In summary, we have navigated the intricate landscape of CO₂ utilization in its varied forms—gaseous, supercritical, and solid. We have explored its diverse applications spanning several industries and the potential of CO₂ as an indispensable element in the modern industrial ecosystem. Direct utilization, while beneficial in specific contexts, merely offers a transitory solution to the broader challenges of atmospheric CO₂ accumulation. In contrast, the chemical utilization of CO₂, despite its challenges, presents a more sustainable and promising avenue. These processes, while thermodynamically demanding, require specific reactants and often confront complexities in life cycle assessments, especially when integrated into current production chains. The widespread adoption and scaling of CO₂ utilization technologies will undoubtedly have profound implications for global supply chains. As these technologies become more integrated into industries, several shifts can be foreseen:

• Focus on sustainability: With a heightened emphasis on CO₂ utilization, supply chains will evolve to become more sustainable, significantly reducing the carbon footprint associated with manufacturing and distribution.

• Demand for new reactants: An increased demand for co-reactants, most notably hydrogen, will stimulate the growth of related industries, consequently reshaping supply chain dynamics.

• Hydrogen supply chain: As CO₂ hydrogenation processes become more prevalent, the importance of a robust and sustainable hydrogen supply chain becomes paramount. This implies sourcing hydrogen from green methods, efficient storage, and transportation solutions, and ensuring that the hydrogen infrastructure is equipped to handle the increased demand.

• Integration: Incorporating CCU technologies into existing supply chains will pose require thorough integration, especially when processes yield multiple products.

• Temporary CO₂ storage: While CO₂ utilization offers a brief reprieve, it does extend a valuable timeframe in our battle against climate change. The integration of these processes into supply chains for carbon-based industrial feedstock is a pivotal consideration.

In the future, supply chains will need to be more resilient and adaptive. As CO₂ utilization technologies advance, industries must brace for a shift toward environmentally conscious and sustainable production methods. The path is laden with challenges, but with collective efforts, technological breakthroughs, and a steadfast commitment to sustainability, global supply chains stand poised to lead the way in our fight against climate change.

Acknowledgments

This contribution was made possible by funding of the state of North Rhine-Westphalia, grant number IRR-2018-1, RWE Power AG, and the Faculty of Mechanical Engineering of Ruhr-Universität Bochum as part of the endowed chair CSC. Also, the financial support of the Bundesministerium für Bildung und Forschung (BMBF) for the project “Production of Ethene from Recycling Streams and Renewable Carbon Sources as a Sustainable and Economic Route to Basic Building Materials for the Chemical Industry” (Syngas2Ethene, grant number 01LJ2107A) is acknowledged. TEM would like to thank Prof. M. Dröscher for the lively scientific discussions on the subjects of raw material and energy supply to the chemical industry.

Conflict of interest

The authors declare no conflict of interest.

Acronyms and abbreviations

AEL	alkaline electrolysis
CCS	carbon capture and storage
CCU	carbon capture and utilization
CCUS	carbon capture utilization and storage
EGR	enhanced gas recovery
EOR	enhanced oil recovery
GHG	greenhouse gas
HHV	higher heating value
MP	methane pyrolysis
MDEA	methyldiethanolamine
MEA	monoethanolamine
LCA	life-cycle-assessment
LHV	lower heating value
PEM	polymer electrolyte membrane electrolysis
PSA	pressure swing adsorption
SOEC	solid oxide electrolysis cells
SMR	steam methane reforming
TRL	technology readiness level
WGS	water-gas-shift