Low-Carbon Production of Iron & Steel: Technology Options, Economic Assessment, and Policy

Abstract

Given increased urgency to transition the global economy to net-zero CO2 emission, governments and industry have increased focus on decarbonizing hard-to-abate sectors, including steel making, which contributes roughly 6% of global CO2 emission and 8% of energy related emission (including power consumption emission). This paper reviews current global iron and steel production and assesses available decarbonization technologies, including hydrogen injection, solid biomass substitution, zero-carbon electricity substitution, carbon capture and storage (CCS) retrofit and combinations of these decarbonization approaches. Blast furnace – basic oxygen furnace (BF-BOF) dominates production (71%) and is particularly stubborn to any decarbonization technology. Direct reduced iron to electric arc furnace (DRI-EAF) production is 5% and growing, it appears to have better decarbonization potential to move towards net-zero. Secondary steel production using mainly steel scrap in electric arc furnace (EAF-scrap) is 24% of global production and has both the lowest energy consumption and is technically simplest to decarbonize through electrification, but is limited in market share to recycled steel capacity. Of the options assessed, blue hydrogen, carbon neutral biomass, and CCS appear to have the lowest cost and highest technical maturity. However, no single approach today can deliver deep decarbonization to the iron and steel industry and all approaches lead to substantial production cost increase. No uniform ideal solution exists and different geographies, infrastructure, and economies will determine the local optimum solution with viability and cost. Policy measures will be required to provide financial incentives for decarbonization and to avoid unwelcome outcomes such as emissions leakage or job loss.

Introduction

A core challenge in the energy transition and deep decarbonization is the growing demand for primary energy services. It is widely understood that man-made climate change is chiefly caused by greenhouse gas emissions, especially CO2, and that the consequences of global warming will be profound, widespread and destructive [(IPCC,2018]]. Nonetheless, global emissions have risen more or less continuously for the past 25 years and have increased each of the last three years [(UNEP,2019]]. This is chiefly due to the growing demand of energy and of products that require energy for their production.

Nowhere is this challenge more evident than in the industrial sector, which has grown profoundly and rapidly over the last 20 years [(IEA,2020)]. Steel, a major sector from a commercial and emissions standpoint, is an essential material for the modern world and is a key component of many national economies (figure 1). It is used in construction, military and defense, and manufacturing (e.g., automobiles). A globally traded commodity, iron and steel production has tripled production since 2000, with 2018 seeing $2.5 trillion in sales [(Worldsteel Association, 2019)]. It is also an enormous source of greenhouse gases: today’s iron and steel industry generates roughly 6% of global CO2 emissions (see table 2).

From a technical perspective, the challenge of decarbonization involves two processes: chemical reduction for iron ore refining (process emission), commonly with metallurgical coal and coke, and from the high temperature heat sourced required to operate BF and other production reactors [(Friedmann et al., 2019)].

Unlike the power sector, there are relatively few technical options to manage these challenges. From a non-technical perspective, challenges include the globally traded nature of the commodity, national dependencies for both security and economic well-being, the small margins of most producers, and labor politics [(ICEF,2019]]. Moreover, operating assets have long capital lives and are expected to operate for many decades, limiting the rate and range of options to substitute for existing facilities and thereby reduce emissions [(Friedmann, 2019)].

This paper examines near-term options to rapidly reduce greenhouse gas (GHG) emissions in steel production and seeks to identify and explain near-term pathways to reduce GHG emissions of hot metal (HM). We examine technical options in terms of cost, viability, readiness, and ability to scale. In addition, we assess key aspects of current commercial markets and potential policy options to accelerate a transition to low-emissions production of steel.

Overview of iron and steel production

World crude steel production exceeded 1808 million tons in 2018 with a 4.5% growth compared to the 2017 level [(Worldsteel Association, 2019]]. Three dominant production processes contributed to 99.6% of steel HM production (Figure 2):

Blast Furnace – Basic Oxygen Furnace (BF-BOF): This is the dominant steel production route in the iron and steel industry, involving the reduction of iron ore to pig iron in the blast furnace. BF-BOF operation relies almost entirely on coal products, emitting ~70% of CO2 in the integrated plant (BF iron making). Hot iron is then charged to BOF to make steel HM (BOF steel making). An integrated BF-BOF production plant also include process plants for coking, pelletizing, sinter, finishing, and associated power production.
Electric Arc Furnace (EAF): This steel making process using electric arc to heat charged materials such as pig iron, steel scraps, and DRI product (also referred as sponge iron) with electricity as the only energy source. Today, EAF is the dominant approach for steel recycling (i.e., secondary steel production) and also contributes to primary steel production by upgrading or refining DRI sponge iron. EAF steel production operates in batch mode instead of continuous like a BF-BOF plant.
Direct Reduced Iron (DRI): This iron production process directly reduces iron ore in solid-state with the reaction temperature below the melting point of iron. Reducing gases are produced from natural gas (gas-based DRI) or coal (coal-based DRI) called syngas, a mixture of H2 and CO. Although DRI production is more energy efficient than pig iron production from BF, additional processing (typically EAF) is needed to upgrade DRI sponge iron for market.

These processes operate with different feedstocks. The BF-BOF pathway converts raw iron ore to pig iron and then to steel HM – while EAF converts both steel scrap and sponge iron to steel HM. DRI converts raw iron ore to sponge iron, a porous, permeable, and highly reactive product that requires treatment with EAF before selling to market. One of the well known hard-to-abate sectors, substantial iron and steel industry decarbonization will increase production cost significantly (>120 $/ton) [(ETC, 2018)]. The core issue of decarbonizing it is not lack of technological solutions but that these solutions carry high abatement costs which directly affects market share, trade, and labor.

This study focuses on the full process decarbonization of steel making, including the three primary/secondary processes discussed above and any necessary pretreatments (such as sintering and coking in BF-BOF production) to produce hot HM[1]. Specific integrated decarbonization methods that recover part of the energy input (e.g., quench gas reusing, top gas recycling, waste heat for CCS, or H2 production) are discussed on a case basis.

Blast Furnace + Basic Oxygen Furnace (BF-BOF)

BF-BOF route employs a blast furnace (BF) to reduce the iron ore to molten iron and subsequently refined to steel in a basic oxygen furnace (BOF). As the dominant technology for primary steelmaking, BF-BOF route produced 71% of global crude steel production, over 1279 million tons in 2018 [(Worldsteel Association, 2019]]. Integrated BF-BOF operations (figure 3) include pelleting, sintering, coking, and iron making (in BF) plus steelmaking (in BOF). This study covers the integrated route carbon emission and energy consumption, where assumptions are listed in table 1.

Table 1. CO2 emission using integrated route BF-BOF technology [(Orth et al. 2007]]

Process	Emission (kg-CO2/ton-HM)*	Emission (kg-CO2/ton-HM)**
BF	1514	1476
Coke production	101	97
Sintering	276	260
Pelletizing	46	35
BOF steelmaking	229	193
Total	2225***	2061

* The U.S. average electricity carbon intensity case: CO2 460 kg/MWh

** The zero-carbon electricity case

*** 2016 global weighted average for the top fifteen steel production countries is 2238 kg/ton crude steel HM, covering >85% global steel production from BF-BOF [Hasanbeigi and Springer, 2019].

The single biggest contributor to integrated BF-BOF steeling making CO2 emission is mainly driven by the requirement of carbon, usually coke, as the reductant. The potential to further minimize CO2 emissions with equipment upgrades and operation optimization is limited [(Cameron et al., 2019)]. This study targets low-carbon heat and low-carbon reductant for BF specifically, such as H2 and biomass-based material. Other assumptions that may be applied include (1) zero-carbon electricity supply, (2) ore fines to avoid agglomeration, (3) fine coal to avoid coking. Combining these approaches could eliminate CO2 emission from coking, sintering, and pelletizing completely, yielding in maximumly 20% CO2 decrease for a facility.

Electric Arc Furnace (EAF)

EAF is the most common way of producing secondary (recycled) steel from steel scrap feedstocks. EAF contributes ~24% of global steel production, over 430 million tons (Mt) in 2018 [(Worldsteel Association, 2019)]. It is the major steel production method for NAFTA countries (59%), and EU (41%) [(Worldsteel Association, 2019)]. As the most important electrification opportunity in the steelmaking industry, EAF production is intrinsically low-carbon compared with the integrated BF-BOF route and is easiest to modify. Studies show that carbon footprint per ton of EAF steel can be as low as 0.23~0.46 ton CO2 depending on iron type (pig iron or scrap), electricity sources and efficiencies. This would be only 10%~20% of conventional BF-BOF operations [(Kirschen et al., 2011)]. A typical EAF facility has about 1 Mt steel production capacity in comparing with a typical 3 Mt or large capacity of integrated BF-BOF mill [(DOE, 2000)], requiring less up-front capital to invest in modifications.

Limitations prevent EAF from playing a larger role in decarbonizing the whole steelmaking industry. First and foremost, EAF takes recycled steel scraps as feedstocks and is therefore subject to supply limitation. Second, batch operation yields intermittent and discontinuous duty cycles causing power quality problems for transmission and generation [(Seker et al., 2017)]. Both limitations prevent EAF from easy penetration deeper into the global steelmaking profile. In contrast, the higher penetration of intermittent renewables power generation may lead to increased market share and use.

Direct Reduction of Iron (DRI)

EAF also consumes the products of direct reduction of iron (DRI), also referred as sponge iron. DRI is as pure as pig iron and is an ideal feedstock to EAF efficiency gains. As a feedstock, EAF can take any fraction of sponge iron (zero to 100%). The DRI-EAF combination allows for higher electrification and lower emission if low-carbon feedstocks and electricity are used. The production of steel from the DRI-EAF route exceeded 90 million tons in 2018 (5% global production) [Worldsteel Association, 2019], with DRI sponge iron production over 100 million tons [(Midrex, 2019)]. India (coal feedstock) and Iran (gas feedstock) are the leading countries in producing DRI.

DRI production requires lower temperatures for its direct reduction reaction and is a solid-state process at temperatures below the melting point of iron (1200 °C). Reduction gas (commonly a mixture of H2 and CO syngas) is typically made from either natural gas or coal. Two of the main reduction reactions in the kiln: Fe2O3 + CO and FeO + CO, are still the main sources of CO2. The current DRI-EAF route using natural gas has only 62% the carbon footprint as a traditional integrated BF-BOF route [(European commission, 2018)]. It also has a better deep decarbonization potential, as the reduction gas is easily replaced with higher H2 mixtures or even full hydrogen [(Midrex H2, 2020)] while BF-BOF faces greater difficulty in higher H2 use due to facility retrofit barriers (see “Hydrogen in BF and DRI” below).

Both EAF steelmaking pathways’ flow diagram are shown jointly in figure 4.

Novel Approaches

The above summaries cover the overwhelming majority of world steel production (>99%). Multiple novel technologies under development show great potential to replace the dominant steel production pathways in the far future but not yet commercially available. These include the HIsarna smelting ironmaking process and molten oxide electrolysis (MOE), both anticipated to enter pilot plant testing in the short-term future.

HIsarna is a direct bath-smelting reduction technology that combines coal preheating and partial pyrolysis with the smelting reduction vessel working as its core reaction container [(Stel et al., 2013)]. It can allow non-coking coal and low-cost iron ores (outside BF quality range) to produce iron with 20% less carbon footprint [(Quader et al., 2016)]. Commercial level successfulness for this technology is expected in 10-20 years [(Yan, 2018)].
MOE can allow electricity as the only energy source and reduction agent for steelmaking [(Boston Metal, 2020)][ (Allanore et al., 2013)]. Its carbon footprint is therefore chiefly determined by electricity sources.

While promising, novel processes such as these are outside the scope of this study, which focuses on existing facility decarbonization, and only discussed cursorily.

In this study, we use three hypothetic plants to represent the global steelmaking asset base (Table 2): One integrated BF-BOF plant, one EAF plant with steel scrap as feedstock, and one DRI-EAF configuration. The data in Table 2 is representative. We recognize that EAF can take feedstock from DRI sponge iron (e.g., India & Iran), BF pig iron (e.g., China), and steel scraps (most OECD countries) and process them together [(Hasanbeigi and Springer, 2019)]. Similarly, the DRI carbon footprint will vary if syngas is produced from coal-based process or gas-based process [(Midrex, 2019) and Table 2]. As such, our analyses are representative and inclusive but not comprehensive.

Table 2. Data inputs for steel production scenarios.

Production methods	BF-BOF	EAF	DRI-EAF
Global production share (%)	71%	24%	5% (coal-based 1% + Gas-based 4%)
Primary reactors – CCS suitable** (kgCO2/ton)	1476 [(Orth et al., 2007)]	0	1048 (coal-based) 522 (gas-based) [(Holling and Gellert, 2018)][ (Dey et al., 2015)]
Pre-treatment reactors: not CCS suitable (kgCO2/ton)	585 [(Orth et al., 2007)]	420 [(EPA, 2012)]	307 [(Barati, 2010)]
Electricity intensity (kWh/ton)	356 [(Hasanbeigi et al., 2011)]	918 [(Hasanbeigi et al., 2011)]	380 (coal-based DRI) 313 (gas-based DRI) [(Hasanbeigi et al., 2011)]
DRI-EAF electricity intensity (kWh/ton)	N/A	N/A	918 [(Hasanbeigi et al., 2011)]
Electricity carbon intensity (kg/MWh)	460 [(EIA, 2019)]	460 [(EIA, 2019)]	460 [(EIA, 2019)]
Hot metal carbon intensity (kgCO2/ton)	2225	842	1953 (coal-based) 1395 (gas-based)***
Global weighted average (kgCO2/ton)	1857* (Electricity emission: 246 kgCO2/ton-HM, 13.3%)

References: [(Orth et al., 2007)] [(Hasanbeigi et al., 2011)] [(EIA, 2019)] [(EPA, 2012)][ (Holling and Gellert, 2018)][(Dey et al., 2015)][ (Barati, 2010)]

*On average for 2017, roughly 1.9 ton of CO2 were emitted for every ton of steel produced, accounts for approximately 6.7% of global GHG emission [(Worldsteel Association, 2017)]. These 3 hypothetical models’ weighted average match the global carbon emission from iron & steel industry.

**In this paper, CCS applies only on large point source CO2 emission from the primary production reactors such as BF top-gas and DRI exit gas.

***Conversion of DRI to hot metal in weight is assumed 90% (2018 data, 100 Mt DRI [(Midrex, 2019)] produced 90 Mt HM [(Worldsteel Association, 2019)]). HM carbon intensity from DRI-EAF include both DRI carbon emission and EAF carbon emission (electricity only)

Using these data and production scenarios, we assess multiple decarbonization options applied to existing facilities/pathways, including H2, biomass, top-gas CCS, and zero-carbon electricity. Existing plants’ retrofit is essential, since most production capacity is in Asia Pacific (e.g., China) and most facilities have more than 25 years average capital life remaining [(IEA industry, 2020)]. We compare the potential, production cost, and supply requirement among these decarbonization options using the current integrated BF-BOF route as a baseline.

Hydrogen in BF-BOF and DRI

Chemically, H2 is carbon-free and capable of satisfying both heating (direct combustion) and reduction requirements (replacing coke and CO) for steelmaking. Today, almost all H2 supply is produced from fossil fuel, with global demand exceeding 73.9 million tons in 2018 [(IEA H2, 2019)]. H2 production consumes 6% of global natural gas and 2% of global coal, emitting 830 million tons of CO2. As such, current hydrogen production is far from carbon-free on an LCA basis. However, blue H2 (fossil fuel + CCS H2 production) and green H2 supply (renewable electricity + water electrolysis H2 production) show potential and are reasonably mature, with potential for near-term cost decline and production growth [(Hulst, 2019)][ (Dickel, 2020)]. For this study, blue H2 is selected to be steam methane reforming (SMR) + 89% CCS production. Adapting H2 into iron making (BF and DRI) has great potential to proceed to deep-decarbonization and with carbon-free/carbon-neutral endmembers as a function of feedstock. Preheating of H2 gas is found to be required for DRI injection in literature (see table 3) and therefore included. Similar preheating requirement does not show up in the BF injection due to inherent hot air blast design.

Table 3. H2 assumptions summary.

H2 price values	Hydrogen production price ($/kg)	Electricity consumption MWh/ton DRI	Wind elec price $/MWh	Basic cost ($/Nm3)	Total: basic + preheat ($/Nm3)
H2 green	6.64 [(Friedmann et al., 2019)]	N/A	N/A	0.536	0.582
H2 blue (89% CCS)	1.93 [(Friedmann et al., 2019)]	N/A	N/A	0.156	0.201
H2 preheat	N/A	0.23 [(Vogl et al., 2018)]	119 [(Vogl et al., 2018)]	0.046	N/A

Sources: [(Friedmann et al., 2019)][ (Vogl et al., 2018)]

BF-BOF hydrogen injection

Yilmaz et al. [(Yilmaz et al., 2017)] show that using H2 as an auxiliary reducing gas for BF to partly replace CO derived from either coal or coke can reduce CO2 emission by 21.4%. Pure H2 injection into the BF by tuyeres through its raceway at the bottom of the BF, replacing 120 kg/t pulverized coal with 27.5 kg/t heated H2 injection. Simulations showing that the energetic state is not changed significantly if only auxiliary reducing gas is replaced when operating with H2 relative to the reference case using pulverized coal, suggesting minor BF retrofit requirement and universal application potential. With this approach, each 1 ton CO2 emission reduction requires 95 kg of H2 so the cost of zero-carbon H2 determines the associated cost increase of low-carbon steel production (HM). Schematics of green H2 feeding into BF is shown in figure 5.

Unsurprisingly, existing BF have operational requirements and designs that limit higher H2 substitution and full H2 operation [(Lyu et al., 2017)]. Further increasing H2 concentration in the CO + H2 mixture will gradually transform the exothermic reaction to endothermic, lowering down the temperature and greatly affecting the basic chemistry inside the BF [(Longbottom and Kolbeinsen, 2008)]. The effect of adding H2 to BF includes the optimum temperature, gas utilization rate, reaction rate, and etc. that the overall content of H2 in gas-injection BF should be 5%-10% considering all limitations [(Yilmaz et al., 2017)]. Extreme high H2 penetration in BF-route based steelmaking equipment will be very challenging.

To substitute reducing agents like coke with hydrogen in a BF-BOF, 27.5 kg hydrogen is required per ton HM production, which would decrease carbon emissions 21.4% (0.46 ton-CO2/ton steel production). At scale, 35.2 million tons of hydrogen for BF-BOF route 1279 million tons production will be consumed. For comparison, 73.9 million tons H2 served markets in 2018 (global refining consumed 38.2 million tons of H2; global ammonia production consumed 31.5 million tons) [(IEA H2, 2019)]. Using hydrogen to decarbonize BF-BOF steelmaking would consume the same amount of hydrogen and all hydrogen production must be low-carbon (e.g., blue or green).

Table 4. Cost increase per ton steel HM with hydrogen substitution and carbon tax avoided.

Cost comparison	Price	Cost increase ($/ton-HM)	Marginal CO2 abatement cost ($/ton-CO2)
27.5 kg/ton production H2 cost to reduce 0.46 ton-CO2/ton-HM
Hydrogen SMR	1.28 $/kg	35 $/ton	246 $/ton
Hydrogen Blue: SMR 89% CCUS	1.93 $/kg	53 $/ton	120 $/ton
Hydrogen Green	5.57 $/kg	153 $/ton	368 $/ton
0.46 ton-CO2/ton production avoided carbon tax
Carbon price	60 $/ton	28 $/ton	N/A
Carbon price	120 $/ton	57 $/ton	N/A
Carbon price	300 $/ton	142 $/ton	N/A

H2 cost sources: see appendix

As shown in Table 4, H2 substitution with green H2 will be cost competitive today if the carbon price is 300 $/ton-CO2. Blue H2 from blue H2 (SMR 89% CCS) is cost competitive if carbon price is 120 $/ton-CO2. This means hydrogen fuel substituion is a pathway to BF-BOF decarbonization and would require very large volumes of hydrogen production world-wide if deployed in large scale.

Hydrogen in DRI

DRI is a proven technology to use H2-rich gas for steel making from iron ore, producing over a 100 million tons of iron and ultimately over 90 million tons of steel in 2018. The reducing gas used for DRI production is syngas, produced from either coal gasification or SMR. Increasing H2 fraction in reducing gas for DRI production is simpler than replacing pulverized coal with H2 in a BF. In a gas-based DRI production process, up to 30% natural gas can be substituted by hydrogen directly without changing the process [(Midrex H2, 2020)]. Preheating and other pretreatment of injected hydrogen might be needed depending on hydrogen quality and quantity [(Vogl et al., 2018)]. Gas-based DRI process can be adapted to 100% hydrogen operation with minor equipment retrofit – and have been.

Gas based DRI

The total cost of DRI depends to a large extent on hydrogen prices. Production of the hydrogen process is depended on the availability of clean electricity or carbon emission prices. In current applications, the proportion of H2 and CO after reformer is approximately 55% and 36%. Use of natural gas in DRI is widespread [(Vogl et al., 2018)], especially in Iran, Malaysia and other regions with rich natural gas resources. In a gas-based DRI plant, a reformer is first used to convert the natural gas into two main reducing gases (H2 and CO) which then enter into the reaction vessel shaft for chemical reduction of ore. According to Midrex [(Midrex H2, 2020)], DRI systems have the potential to accept mixtures with different CO + H2 concentrations: up to 30% of NG can be substituted by H2 without changing the process and 100% replacement will be possible with minor retrofit (provided an economic supply of hydrogen). European steelmakers are experimenting with the use of green hydrogen in steelmaking, but currently there are very few commercial systems.

Model analysis

In this study, we consider the economics of hydrogen in DRI production and its GHG emission reduction performance. Calculations are based on MIDREX’s actual plant data at Cleveland-cliffs [(Chevrier, 2018)]. The production data and raw material input data of the plant can be found in the appendix. For the chemistry of DRI production, hydrogen can substitute for natural gas at a volume ratio of 3:1 (3 m3 of hydrogen would replace 1 m3 of methane). Some additional energy would also be needed for a preheating step (Table 3) to meet operational temperature requirements [(Vogl et al., 2018)].

The zero-carbon hydrogen production methods have different costs, which affect DRI plant economics. For example, Vogl et al. [(Vogl et al., 2018)] shows how renewable power is used to produce hydrogen and the preheat step to reduce DRI-related CO2 emission, theoretically reducing emissions to only 2.8% of BF. Some relevant data for H2 assumption comes the production study showing 650 Nm3 of H2 yielded 1 ton of DRI hot-metal [(Chevrier, 2018)] with hydrogen sourced either from SMR or electrolysis.

Using previously mentioned assumption, we set the replacement rates of H2 to 30%, 90%, and 100%, respectively. The prices of the used natural gas 0.1223 $/Nm3 and H2 prices from table 3. For the calculation of CO2 emission intensity, we assume that the CO2 produced from DRI is the same assumption as identified in the gas-DRI model: 522 kg-CO2/ton-DRI (table 2). For hydrogen, assuming green H2 from renewable electricity and complete combustion of H2 to emit no CO2 onsite. The CO2 emission intensity of green and blue H2 equals its life-cycle assessment (LCA) results (sources and assumptions see appendix):

Table 5. DRI-gas H2 injection analysis.

H2 replacement rate	Base Case: 0%	Case 1: 30%	Case 2: 90%	Case 3: 100%
NG consumption Nm3 / ton DRI	266.67	186.67	26.67	0
H2 consumption Nm3 / ton DRI	0	240.00	720.00	800.00
NG cost, $/ton DRI	32.62	22.83	3.26	0
Green H2
Carbon abatement (kg-CO2/ton-DRI steel)	0	113.76	341.28	379.20
Fuel cost: NG + H2 ($/ton-DRI steel)	32.62	162.40	421.96	465.22
Carbon abatement cost ($/ton-CO2)	N/A	1140.83	1140.83	1140.83
Blue H2 (SMR + 89% CCS)
Carbon abatement (kg-CO2 / ton-DRI)	0	131.40	394.20	437.00
Fuel cost: NG + H2 ($/ton-DRI)	32.62	71.20	148.34	162.20
Carbon abatement cost ($/ton-CO2)	N/A	293.57	293.57	293.57

Model details see Appendix

The calculation results in table 5 show that the use of H2 instead of natural gas for DRI production will significantly reduce CO2 emissions but at substantially higher costs. Blue H2 and green H2 different by roughly a hundred $/ton-DRI in production cost (HM) but by 1000 $/ton-CO2 in marginal CO2 abatement cost. Blue H2 provides the best current substitution option for natural gas in DRI production, which is reliable, technically available, and relatively low in cost for most markets (see CCS retrofit DRI below).

Japan’s Mitsubishi Heavy Industry is building the world’s largest steel plant capable attaining net-zero emission in Austria, adopting DRI with hydrogen injection [(Kawakami, 2020)]. The project stresses the importance of low-cost hydrogen to achieve cost competitive steel production. Hydrogen Europe [(Hydrogen Europe, 2017)] also summarized projects adopting hydrogen for steel making (e.g., SALCOS project, HYBRIT projects), all focusing on DRI replacing BF to adopt more hydrogen injection potentials.

Hydrogen injection summary

As shown in figure 6, all hydrogen injection technologies can provide a practical carbon reduction which is close to its decarbonization potential limits, since both blue and green H2 has very low LCA results. Both green and blue hydrogen can already deliver energy and reduction agent in a safe and close to carbon neutral way. Given the overwhelming majority (71%) of steelmaking is from BF-BOF operations and facility lifespans are long, hydrogen injection can already provide a technically acceptable solution for retrofit decarbonization. Blue H2 appears to add much less cost per unit HM production than green H2 in most markets and cases. Green H2 injection could be regarded as a version of electrification penetration as well, since it adopts zero-carbon electricity to be replace fossil fuel (see Combined technologies set section).

Two significant limitations remain. First, decarbonization potential for BF-BOF hydrogen injection is about 20% – unlikely to qualify as “deep decarbonization”. Either a combined technology sets or replacement DRI based primary steel production would be needed to increase its decarbonization potential. Second, the cost of green H2 is high and unlikely to be cost competitive in most markets. Significant improvement is required on both electrolyzer and zero-carbon electricity prices to lower hot metal production cost to commercial ranges.

Biomass feedstocks for hydrogen production can result in very different hydrogen LCA. Recent research [(Mehmeti et al., 2018)] have compared the midpoint GWP LCA of hydrogen production pathways, finding biomass-based hydrogen production can have either higher or lower LCA than SMR baseline. Another study [(Antonini et al., 2020)] found hydrogen production from biomethane with CCS will lead to net negative emissions in all invested cases, showing promising greenhouse gas reduction potential. Hydrogen production from biomass is highly uncertain for 1) various feedstocks 2) complicated processes, and 3) cost uncertainty. This paper did not estimate hydrogen production from biomass. Solid biomass substitution is discussed in the following section.

Solid biomass in BF-BOF and DRI

Given the challenges discussed above using hydrogen gaseous fuel to decarbonize iron & steel production, solid biofuel could prove a more useful pathway. Biomass, especially solid biofuels, provides a promising option for both low-C heat and possible low-C coking feedstock for use in primary production.

Biomass feedstocks are never truly carbon neutral. The actual abatement of CO2 using bio-charcoal is sensitive to many factors, most importantly LCA and LUC of the biomass. The carbon abatement potential is very sensitive to land-use change (LUC) and cultivation practices, and carbon footprint greatly depends on the land, production, processing, transport, and final application [(Johnson, 2009)]. As many have documented, biomass must be grown, harvested, processed and transported with minimal life-cycle CO2 emission for it to achieve substantial CO2 reductions through fossil fuel substitution [(DOE, 2016)] and some biomass has a documented low life-cycle carbon footprint under the correct operational circumstances.

The CO2 emission intensity of typical BF-BOF integrated facilities can reach up to 2 tons CO2 per ton of steel [(Material Economics, 2018)]. Since the reduction of iron ore in a blast furnace is entirely dependent on the carbon provided mainly by coal and coke, biomass energy is recognized as a potential alternative for its potentially sustainable carbon content and under the right circumstances solid biofuels can substitute readily into conventional feed systems, exhibiting key physical properties (i.e. mechanical strength) needed during hot-metal production. Studies by Helle et al., [(Helle et al., 2016)] and Wiklund et al. [(Wiklund et al., 2013)] have evaluated the injection of a biomass-based reducing agent into the BF, chiefly as charcoal produced from wood (bio-charcoal). Bio-charcoal making is a slow pyrolysis process under temperature about 300-400 °C. As the most widely commercialized woody biomass process technology, bio-charcoal has carbon content the highest, up to 85%-98% [(Mayhead et al., n.d.)], most chemically suitable for iron making, chemical reduction and replacement of coke.

The results show that using biomass-based reducing agents produced from torrefaction have the best operational properties. Torrefaction (figure 7) is heating biomass to 250-300 °C in absence of oxygen, which enhances biomass properties (e.g., energy density and strength) and makes torrified wood, or bio-coal [(Ribeiro et al., 2018)][ (Mayhead et al., n.d.)] with properties similar to fossil coal and can replace coking coal. High-quality solid fuels are essential in BF iron making, and many common biomass fuels do not meet the required standards. Biomass quality can be further improved by drying and removing volatiles.

Some case studies show that completely replacing fossil fuel injection with biofuels can reduce greenhouse gas emissions of steelmaking by up to 25% [(Natural resources Canada, 2016)]. Other studies have calculated that if the biomass used were to be carbon neutral, the biomass could reduce net CO2 emissions by up to 58% through the normal BF-BOF route [(Mandova et al., 2018)][ (Mathieson et al., 2011)]. However, the practical application of biomass has major restrictions [(Fick et al., 2013)] and there are still significant technical limitations to using biomass to completely replace fossil fuels in the BF-BOF process:

Price: At present, coke (coal after the coking process) is roughly $200/ton, compared with the cost of bio-charcoal at $295/ton~$525/ton. From a purely economic point of view, biomass cannot compete with coal today [(Suopajärvi and Fabritius, 2013)].
Physical properties: Physical properties (such as mechanical strength, etc.) are not the same for bio-charcoal as coal or coke, and manufacturing performance standards may not be guaranteed. Bio-coke [(Seo et al., 2020)] used directly to replace coke in BF must have properties similar to conventional coal [(Suopajärvi et al., 2013)];
Supply chain quality: Biomass resources are unevenly distributed, and the global supply chains are not mature and often not well governed. Brazil is the largest producer of bio-charcoal, with 9,893,000 tons [(NationMaster, 2020)], followed by India (1,728,000), the United States (940,000) and China (122,000). In those markets, bio-charcoal could credibly serve a fraction of their steel industries. In contrast, the European Union receives 70% of its current bio-charcoal from Africa [(TFT Research, 2015)], which has heightened existing concerns about deforestation, loss of biodiversity, and eco-colonialism. In Japan and Korea, no local supplies exist, prompting similar concerns [(ICEF, 2020)].

Many countries have undertaken research on the application of biomass in BF-BOF ironmaking with promising results.

In Brazil [(Fujihara et al., 2005)], small blast furnaces have completely substituted bio-charcoal for coke and coal.
Japanese research suggests that pressed woody biomass can be used to prepare metallurgical coke after mixing with coal, achieving partial decarbonization. [(Ueki et al., 2014)]
German research indicates that when using biomass coke powder to completely replace coal powder, the amount of carbon dioxide input in the blast furnace has been reduced by up to 45%. [(Babich et al., 2010)]
Finnish research suggests that although the replacement rate of biomass coke in the blast furnace can only reach about 25%, it may still be economically feasible considering future coke prices and pollutant emissions. [(Suopajärvi, 2015)]

For simplicity, feedstock availability and robust analysis, only woody biomass pyrolysis produced solid bio-charcoal with >80% carbon content is considered in the following modeling for BF and coal-based DRI, including replacement ratio, decarbonization potential, cost, LCA result and LUC effect. Other feedstocks are not modeled. Bio-gas substitution for gas-based DRI is straightforward technically, with key considerations of cost and carbon footprint limitations.

Biomass in BF-BOF

Our analysis focuses on applications of bio-charcoal and bio-coal (often mixed with coal for coke making) as replacements for solid fossil fuels in BF-BOF steelmaking. Raw material inputs to the BF base model are shown in table 6. We consider the possibility of biomass substitution both in the main reduction reaction process in the blast furnace and heating fuel substitution, excluding subsequent processes such as exhaust gas treatment or heat recovery and utilization. For BF raw materials, we compare five replacement options: coking coal, pulverized coal, nut coke, coking plant residues, and sintering solid fuel. Under the current technical limitations, it is known that the estimated replacement rate of these five raw materials using charcoal can be achieved [(Wiklund et al., 2013)]:

Table 6: Biomass input assumptions [(Wiklund et al., 2013)]

Initial materials	Demand kg/ton HM	Bio-charcoal replace ratio (%)	CO2 emission per unit fossil fuel (kg/kg)
Cokemaking (coking coal)	300	2%~10%	3.11
BF tuyere injection (pulverized coal)	150	0%~100%	2.33
BF nut coke replacement	45	50%~100%	3.11
BF briquette 4 (coking plant residues)	10	0%~100%	3.11
Sintering solid fuel 5	76.5	50%~100%	3.11

The basic replacement model reveals that 311.5 kg of charcoal can be used to replace coal consumption at a maximum for an integrated BF-BOF production. For the baseline scenario (table 7), the model assumes carbon-neutral biomass, i.e. representing the maximum amount CO2 abatement and lowest abatement cost biomass (later referred as ideal biomass). Additional cost due to transportation would occur addition cost. The model also includes the LCA result of bio-charcoal production for its global warming potential (GWP) and additional land use change (LUC) for biomass production. Abatement cost is calculated by dividing added fuel cost (in $, bio-charcoal more expensive than fossil coal) and its carbon abatement value (ton-CO2).

Table 7. Bio-charcoal replacing coal in BF-BOF under different cost/carbon footprint.

Sub-case	Baseline – ideal biochar	500 km transportation – ideal biochar	Biochar LCA GWP	Biochar LCA GWP + LUC
Abated emission (kg-CO2/ton-HM)	851.8	851.8	451.1	122.8
Decarbonization potential (%)	38.3%	38.3%	20.3%	5.5%
Charcoal unit cost ($/ton)	295~525	328~558	295~525	295~525
Replacement cost ($/ton-HM)	92~164	102~173	92~164	92~164
Original coal fuel cost ($/ton-HM)	34.2
Carbon abatement cost ($/ton-CO2)	67.8~151.9	80.0~164.0	128.0~286.8	470.3~1053.9

Sources: cost and carbon footprint assumption see appendix.

The results show that ideal biomass (i.e., carbon neutral charcoal) in BF-BOF would perform well in BF-BOF settings, with both subsantial decarbonization potential (38.3% vs. 21.4% with H2) and modest cost (both cost per ton HM production and abatement cost ($/ton-CO2)).

Unfortunately, ideal biomass does not exist, and the LCA cases indicates that nearly half of the potential carbon mitigation is negated by charcoal production’s carbon footprint. Land use change (LUC) commonly makes this problem worse – negating nearly all carbon abated.

From carbon abatement cost point of view, biomass substitution can be either one of the best options (<100 $/ton-CO2, with ideal biomass) or the one of the worst options (>700 $/ton-CO2) based largely on LCA and LUC effects. As such, solid biomass options for steel decarbonization (and many other low-carbon applications) must be very carefully assessed, curated, managed, and regulated from a carbon footprint perspective to avoid counterproductive results [(Tanzer et al., 2020)]. All steps matter: harvesting from woody biomass sources (LUC), biomass processing emission control (LCA), and charcoal production method. Compared to many biomass scenarios, blue H2 is substantially better in both carbon footprint and cost.

Biomass in coal-based DRI

It appears that coal-based DRI production (i.e., India, Malaysia) can accept 100% biomass substitution and can tolerate a wide range of feedstocks: straw, normal charcoal, and bamboo charcoal. The basic model of DRI production plant parameters are shown in table 8. In these facilities, the main function of feed-coal is to act as a reducing agent and react with the ore; some energy required for the kiln reactions also comes from the coal. Total coal demand for DRI production is 853 kg/ton DRI sponge iron.

Table 8. DRI – coal-based model.

Material input/output	Flow rate (kg/h)	Consumption (ton/ton DRI)
Kiln feed-Iron ore	30000	1.587
Kiln feed-coal	10293	0.545
Inject coal	5837	0.309
Coal consumption	16130	0.853
Output DRI	18900	1
Output CO2	19816	1.048

Sources: [(Dey et al., 2015)]

In considering biomass as DRI fuel, H. Han et al. [(Han et al., 2015)] studied straw, bamboo charcoal, and regular charcoal in a main reaction vessel (RHF). We assume that biofuels such as charcoal only replace feed-coal and assume 100% replacement rate (table 9). Estimated demand for each source of bio-charcoal is slightly different due to its product carbon content (i.e., one cannot assume 1:1 replacement).

Table 9. Biomass replacement in DRI coal.

Biomass type	Straw	Bamboo Charcoal	Charcoal
Demand (ton/ton-DRI)	3.37	0.8	1.03
Bio-charcoal C-content	20.89%	87.50%	68.45%
Biomass cost ($/ton-DRI)	118.5~140.7	203.3~600	303.0~539.2
Original coal/coke cost ($/ton-DRI)	85.34
Cost increase ($/ton-DRI)	33.1~55.3	117.9~514.7	217.6~453.8
Carbon abatement cost ($/ton-CO2)	31.6~52.8	112.5~490.9	207.6~432.8

Sources: [(Han et al., 2015)]

Table 9 assumes an ideal biomass scenario for coal substitution, i.e., it does not include carbon footprint estimates from production LCA or land use change. Including those factors would increase the cost and carbon footprint estimates, similar to the BF-BOF case above.

Similar to hydrogen injection analysis results, biomass substitution has higher decarbonization potential associated with DRI-based pathways compared to BF-BOF and involves the same displacement fuel and higher have the lowest cost and lowest footprint compared to the other biomass feedstock substitution today (in part due to residual or waste biomass use). However, straw is also the hardest to commercialized since its carbon content is the lowest at only 20% (compared to ~80% for bamboo char and biomass charcoal). Biomass substitution in DRI-based pathways will require additional study, prototype testing, and demonstration to verify estimates and potential for viable large-scale use.

Direct electrifications: energy flux requirement and carbon footprint

Although industrial sector is one of the well-known hard-to-abate sectors to decarbonize, electrification is commonly presented as a decarbonization option. The most immediate opportunity to consider is replacing the current electrical load used in steel facilities with zero-carbon electricity sources. However, given that current steel production remains dominantly BF-BOF for primary steel production (71%) with EAF mostly the secondary steel production (24%), applying zero-carbon electricity globally could only decarbonize global steel production a maximum of 13.3% (table 2).

To increase beyond this small fraction, deeper levels of electrification are required. For example, while EAF using steel scrap remains 24% of global production today, increasing DRI-EAF fraction for primary steelmaking has dual effect in decarbonization: the process is intrinsically more energy efficient that reduces the carbon emission, and it also allows higher electricity fraction in the total energy consumption profile, allowing bigger role for zero-carbon electricity in decarbonization. Higher penetration of electricity would require growth of electric loads reflecting the energy flux requirements of production – in short, requiring additional zero-carbon electricity generation.

In this section, we present three scenarios featuring zero-carbon electricity: substitution for current electricity supplies in the existing global production share; full BF-BOF plant replacement with DRI-EAF in primary steelmaking; and novel (revolutionary) technology (e.g., molten oxide electrolysis, MOE) replacing existing plants and using zero-carbon electricity. The first two scenarios are technically mature and available for deployment now. The novel technology options are not yet available at commercial scale but remain interesting considering options to achieve zero-carbon primary steel production in the long-term.

The zero-carbon electricity assumption is for simplicity to avoid discussion of various renewable LCA results and demonstrate its maximum decarbonization potential. Local costs estimates must assess renewable electricity supply to each iron and steel facilities case by case, and grid-based electricity would require more complicated LCA results.

Zero-carbon electricity power supply under current production profile

Electricity consumption for steel making is significant: BF-BOF routes consumes 356 kWh/t production and EAF route consumes 918 kWh/t production [(Dey et al., 2015)]. For coal-based and gas-based DRI production, electricity takes 8% of the total energy consumption (17.9 GJ/ton and 14.1 GJ/ton respectively), or 380 kWh/t production for coal based DRI and 313 kWh/t HM production for gas based DRI. Today, most facilities require continuous electricity supply, either from the local grid or from captive generation facilities. In most facilities, elextricity is almost entirely provided by fossil fuels, which provide the necessary high capacity factors (one noteworthy exception is Sweden, where steel plants have access to grid power with high fractions of both hydropower and nuclear).

Using 2018 global steelmaking statistics and baseline electricity carbon intensity (460 kg/MWh), electricity represents 13.3% of the total steelmaking CO2 emissions. Since China’s electricity carbon intensity is higher (711 kg/MWh in 2013), electricity there contributes 20.9% of total CO2 emissions. Uncertainties of these estimates come from: (1) significant variations in electricity carbon intensity from country to country; and (2) variations in electricity share to total primary energy country to country. Even given these uncertainties, analysis reveals that zero-carbon electricity power supplies have limited decarbonization potential for steel industry under current production profiles (table 10). Using zero-carbon electricity as a strategy, deep decarbonization of steel production must involve replacing BF-BOF with DRI-EAF or adding additional pathways.

Table 10. Substitution of zero-carbon electricity into current global steel production under different electricity carbon footprint assumptions.

Steelmaking options	BF-BOF	EAF	DRI-EAF	Total
Global Production share	71%	24%	5% (1% coal-based + 4% gas-based)*	100% 1857 kgCO2/t (see table 2)
Electricity: baseline CO2 intensity (Baseline: 460 kg/MWh)	163.8 kg	422.3 kg	597.1 kg + 566.3 kg (coal-based + gas-based)	N/A
Electricity: high carbon intensity [(Compare your country, 2020)] (China: 711 kg/MWh)	253.1 kg	652.7 kg	922.9 kg + 875.2 kg (coal-based + gas-based)	N/A
Weighted electricity carbon emission (Baseline: 460 kg/MWh)	116.5 kg	101.3 kg	6.0 kg + 22.7 kg (coal-based + gas-based)	13.3% 246.2 kgCO2/t
Weighted electricity carbon emission [(Compare your country, 2020)] (China: 711 kg/MWh)	179.7 kg	156.6 kg	9.3 kg + 35.0 kg (coal-based + gas-based)	19.1% 380.6 kgCO2/t

*[ (Midrex, 2019)], from 2018 data, the conversion rate of DRI to crude steel is assumed 90%.

Deep electrification using DRI+EAF for BF-BOF replacement

In this scenario, secondary EAF-steel in the total steelmaking profile maintains the same share and role, limited to scrap recycling and scrap feedstock. In contrast, combined DRI-EAF production increases dramatically and replaces BF-BOF as primary steel production method in hypothetical future production is calculated by altering production share:

Table 11. Substitution of DRI-EAF with zero-C electricity supply for BF-BOF production

Steelmaking options	BF-BOF	EAF	DRI-EAF	Total
Production share (Baseline, current global profile)	71%	24%	5% (1% coal-based + 4% gas-based)	100% 1857 kgCO2/t
Weighted electricity carbon emission (Baseline: 460 kg/MWh)	116.5 kg	101.3 kg	6.0 kg + 22.7 kg (coal-based + gas-based)	13.5% 246.2 kgCO2/t
Production share (Medium DRI penetration profile, hypothetical future)	51%	24%	25% (5% coal-based + 20% gas-based)	100% 1713 kgCO2/t
Weighted electricity carbon emission (Baseline: 460 kg/MWh)	83.5 kg	101.3 kg	29.9 kg + 113.3 kg (coal-based + gas-based)	19.1% 328.0 kgCO2/t
Production share (High DRI penetration profile, hypothetical future)	26%	24%	50% (10% coal-based + 40% gas-based)	100% 1534 kgCO2/t
Weighted electricity carbon emission (Baseline: 460 kg/MWh)	42.6 kg	101.3 kg	59.7 kg + 226.5 kg (coal-based + gas-based)	28.0% 430.1 kgCO2/t

As shown in table 2, DRI-EAF plants are much less carbon intensive than traditional BF-BOF route, and deep electrification via DRI-EAF replacement in table 11 could significantly reduce carbon emission from steelmaking in two ways:

Lower carbon intensity: Even with no improvement in baseline electricity carbon intensity, DRI-EAF would reduce 8% carbon emission if it grows to 25% of global steel production through replacement of BF-BOF. Higher substitution rates of 50% of global steel production would directly reduce 17% carbon emission.
Higher electricity energy contribution: Considering electricity carbon emission share of the total emission, global growth to 25% DRI-EAF through BF-BOF replacement (medium DRI penetration) would increase this fraction from 13.5% to 19.1% and increase to 50% displacement (High DRI penetration) would grow this fraction to 28%. If all electricity used is zero-carbon, 25% DRI-EAF can yield 25% total emissions reduction and 50% DRI-EAF can yield 40% reduction.

DRI-EAF is technically available and could play an essential role for decarbonizing steelmaking industry. This would require enormous new supplies of zero-carbon power generation. For example, the 25% DRI growth-substitution case requires 450 TWh of zero-carbon electricity additional annual generation to supply the new DRI-EAF systems – roughly the same as all France (table 12). At high (85%) capacity factors, this would require 60 GW of new zero-carbon power generation. For intermittent systems with lower capacity factors, additional generation (oversupply) would be needed with additional costs for storage and/or with firm power provided by fossil resources, reducing the overall system effectiveness (see table 12). The high-DRI substitution case would require 1010 TWh additional generation – roughly the same as all of Japan.

Table 12. Zero-carbon electricity demand under DRI penetration scenarios.

Zero-C electricity demand

DRI-EAF-coal (TWh/yr)

DRI-EAF-gas

(TWh/yr)

Total (TWh/year)

Installed capacity (GW): 85% capacity factor

Installed capacity (GW): 35% capacity factor

Medium DRI penetration

93.8

355.9

449.7

60.4

146.7

High DRI penetration

211.1

800.8

1011.9

135.9

330.0

In summary to table 10, 11, and 12, table 10 considers how much decarbonization current production coul get with zero-C electricity under different electricity footprint and substition assumptions. Table 11 considers how much more decarbonization can the whole industry get if certain amount of primary steel HM production from BF-BOF is replaced from DRI-EAF. Table 12 further discussed how much electricity flux is required for such replacement transition to happen. DRI-EAF is found to be an essential part to decarbonization and electrification of the current BF-BOF dominated production profile.

Cost of hot metal and carbon abatement using zero-carbon electricity

Assuming 120$/MWh for zero-carbon electricity costs, results appear promising [(Friedmann et al., 2020)]. Since the same zero-carbon electricity source is assumed for all production pathways, the carbon abatement costs ($/ton-CO2) are the same. But decarbonization potential and added cost per ton hot metal (HM) are significantly different. Self-referenced case (taking its own production pathway as baseline) reveals that all EAF involved technologies has decarbonization potential >30%, as high as 40%. Including the intrinsic carbon reduction due to pathway switching (i.e., BF-BOF reference case, taking BF-BF pathway as baseline), secondary steel production using scrap for EAF could achieve 80% decarbonization. Both DRI-based pathways could be >40% less carbon intensive as well. This significant improvement can be achieved at less than 70 $/ton-HM cost increase. For these cases, zero-carbon electricity penetration could prove a low-cost, high-effectiveness abatement solution by replacing BF-BOF with any other production pathways.

Full electrification of steel HM production with advanced technology

Although many different approaches have been proposed to achieve deep decarbonization for steelmaking, significant amount of fossil fuel remain in use today and for the foreseeable future. Additional emissions reductions would require either carbon capture and storage (CCS) retrofits (see next section) or revolutionary approaches based on electrical primary production. One example of a revolutionary primary steelmaking approach is molten oxide electrolysis (MOE), which may have long-term potential for low-carbon steelmaking. Since electricity is the only energy source during the whole production process, the carbon footprint is solely determined by the carbon footprint of electricity. One company, Boston Metal, has successfully demonstrated the production of primary steel using their MOE technology [ (Boston Metal, 2020)]. In their system, about 4 MWh are needed to produce 1 ton steel HM.

MOE steelmaking is a continuous hot-operation process and requires constant power supply, ideally at low cost and high reliability. Economic models developed by Boston Metal show that MOE could be cost competitive with electricity prices at $15/MWh – a very difficult threshold without subsidies, especially for firm power. With a $30/ton-CO2 carbon price, MOE could be cost competitive with $35/MWh electricity [(Boston Metal, 2020)]. Both $35/MWh and $15/MWh prices are much lower than the wholesale industrial electricity prices in most countries and generally far from high capacity-factor carbon-neutral generation. These cost and reliability barriers are significant challenges for large scale replacement of BF-BOF with MOE systems. Not just MOE, most decarbonization approaches involve electricity as energy supply (e.g, green hydrogen) would require very cheap electricity inputs to be market relevant [(Bataille et al., 2020)].

On a systems level, the challenge is multiplied by the additional power requirements necessary to run the substitute plants. Replacing all BF-BOF steel production (1279 million tons/y) with MOE would require 5,116 TWh electricity consumption, almost 20% of 2018 total global electricity consumption (26,700 TWh) [(IEA electricity, 2020)]. In 2018, the world generated a record 4,185 TWh from hydropower, which is well suited to the MOE process and relatively cheap. To provide the additional load MOE would require, the world’s current hydropower generation would have to increase more than 120%. Gernaat et al. [(Gernaat et al., 2017)] have estimated the new low-cost hydropower potential to be 5,670 TWh/yr, mostly in South America, Africa, and the Asia-Pacific region. The geography of hydropower potential is highly correlated to current and future steel production (i.e., Asia Pacific and other developing economies) but not at sufficient generation levels.

CCUS retrofit

It has long been understood that CO2 could be captured from an existing or new steel plant and stored indefinitely underground [(IPCC, 2005)][ (IEA, 2016)]. This is chiefly due to the large volumes and high concentrations of CO2 at many iron & steel facilities and the small number of large emitting sources within integrated plants. In part, this reflects the ability of carbon capture to manage and eliminate the by-product process chemical remissions from iron ore refining as well as emissions from high-temperature heat. CCUS is widely accepted as the key bridge from today’s fossil energy society to the renewable future [(Bain and Wilcox, 2017); (IEA CCUS, 2020)], especially given the vintages of current steel production [(IEA ETP, 2020)]

In a conventional primary production facility, most of the emissions exit the BF-BOF directly, with small volumes also coming from the coking and sintering units. Capturing these emissions would require post-combustion applications to these sources. From a typical DRI plant, most CO2 exits the SHAFT and would require post-combustion capture there. Alternatively, operators could apply pre-combustion capture to blue-hydrogen production at the front-end of a DRI system (or for substitution with coal in the BF-BOF).

Many of the world’s primary steel production facilities sit near viable CO2 storage sites (Figure 11). This is true of the US Great Lakes, China’s eastern provinces, around the North Sea, the Eastern Block nations, Brazil, and some of India’s largest plants. No formal estimate exists regarding what fraction of steel emissions could be effectively managed by CCUS applications. However, the estimated global storage capacity is between 10-20 trillion tons, suggesting ample capacity for CO2 emissions from steel production.

Retrofit of blast furnace

Typical BF exhaust gas contains a mix of gases: typically, 17-25% CO2, 20-28% CO, 1-5% H2, and 50-55% N2 [(Kuramochi et al., 2011)]. Separation of CO2 from the exhaust gas mixture can significantly increase the capture rate of the carbon capture facility and reduce cost per ton CO2 avoided. The difference of capture potential is demonstrated below with Oxygen Blast Furnace CCS and traditional BF CCS.

CCS process on an Oxygen Blast Furnace (OBF):

Top-gas-recycling in a blast furnace (TGR-BF) technology, i.e. Oxygen Blast Furnace (OBF), is less carbon intensive for its inherent ability to capture and disposal of the CO2 of the BF top gas, which implies additional cost as $56/to-CO2 [(Wilcox, 2020)]. The amine-based/piperazine solvent system (MDEA/Pz) modeled to capture CO2 from BF top-gas could reduce 47% emission for an integrated steel mill using OBF process.

OBF-connected carbon capture looks promising for several reason. In the proposed process, the near 100% oxygen blast replaces traditional hot blast, which produces top-gas enriched in CO2 for more efficient capture. The remaining top-gas is CO-enriched and readily recycled to reduce coke and pulverized coal consumption, further reducing plant emissions. Oxygen blast and CCS retrofit is the prerequisite to recycle the top-gas and therefore subjected to additional capital cost. The techno-economic comparison shows that capital cost and energy cost dominate the CO2 avoidance cost (over 80%), making the cost per ton CO2 sensitive to both fuel prices and interest rates. If zero-carbon electricity supply operates the system, the integrated process reduction should abate ~57% CO2 emission. Other research [(Pal et al., 2016)] shows that TGR-BF has the highest CO2 avoidance rate comparing with other CCS retrofits: 0.78~0.82 tCO2/t hot metal, equivalent to 36%~38% capture rate. Avoidance cost per ton CO2 is estimated to be $48~$71/tCO2.

Traditional BF-process based CCS:

Air-blown BF with CCS (BF-CCS) has lower CO2 avoidance potential (rates of 0.33~0.36 ton-CO2/ton-HM, equivalent to 15%~17% capture rate). Avoidance cost per ton CO2 is estimated at $45~$71/ton-CO2. Comparing with OBF-based CCS retrofit, air-blown type BF-CCS is more technically mature, less capitally intensive. However, in terms of per ton CO2 abatement cost, BF-CCS does not show any cost advantage over OBF-CCS. Many other estimates fall in the same range [(Hooeya et al., 2013)][ (Kuramochi, 2011)][ (Ho et al., 2011)][ (Arasto et al., 2013)]. For this study, $60/tCO2 for TGR-BF based CCS retrofit and $58/tCO2 for air-blown BF based CCS retrofit serve as the basis for comparison.

Retrofit of DRI systems

CCS retrofit for DRI system is similar to BF retrofit: high CO2 concentration leads to more efficient CO2 capture. DRI-CCS retrofit captures CO2 from the DRI reactor exhaust gas since the separation of CO2 is much easier as the reducing gas is hydrogen rich, producing water vapor. Water vapor can be easily separated from BF exhaust gas (unlike N2 and CO). Gas-based DRI has an additional CCS-related decarbonization path using blue hydrogen, in which the CO2 capture occurs prior to use in the DRI reactor.

The Al Reyadah project in Abu Dhabi, UAE, is the sole example of CCS applied to an existing steel mill. The project was commissioned as a joint venture between Abu Dhabi National Oil Company (ADNOC) and Masdar, the Abu Dhabi Future Energy Company, with the goal of demonstrating the viability of CCS in steel production and to show regional and global leadership in decarbonization. The Al Reyadah [(CSLForum, 2020)][ (Sakaria, 2017)] plant uses SMR for syngas production and then feed it as reducing gas to a HYL DRI plant for sponge iron production. The off-gas from the process consists of CO2 and H2O, which is the source of capture for CCS facility. Byproduct CO2 , ~800,000 tons CO2/y, is transported 42 km by pipeline to the Bab field, where it is injected and stored as part of an enhanced oil recovery project. The project costs were ~$122M (2016 USD).

This project provides a clear example of how other gas-based DRI plants might be decarbonized. However, since most such plants are in Iran, it is unlikely that many existing gas-DRI plants will follow the Al Reyadah example (lack of political interest). For a new DRI plant, Al Reyadah provides a sense of project capital and operating costs as well as construction timeline. Model studies [(Carpenter, 2012)] showing that CCS for DRI-based reactors could be as low as 25 $/ton-CO2 (Nth plant optimum) and this study borrows the result for analysis. In contrast, studies of. MIDREX DRI plants lack standalone CCS examples [(Santos, 2014)].

To date, there has been no example of retrofitting and existing BOF-BF plant for CCUS. Plans for a US project, the New Steel Intl. project, have not yet matured. The project aimed to build new BOF-BF systems in Michigan and Ohio integrated with carbon capture systems but has not reached final investment decision [(GCCSI, 2017)].

Selected combined technology sets

The key basis to apply multiple technology sets is to increase the decarbonization potential: As identified, H2, biomass, zero-carbon electricity, and CCS retrofit are all promising options for steelmaking decarbonization. In some facilities, several of these technologies are compatible and could be applied together (e.g., hydrogen + zero-carbon electricity+bioenergy + CCS retrofit). Some technology combinations are less compatible with each other and require additional study to assess viability of comined systems.

Hydrogen + zero-carbon electricity

Using H2 (which can be green H2 that produced from zero-C electricity) and zero-C electricity for BF-BOF can abate up to 28.8% of the carbon emission. If using gas-based DRI production, however, this decarbonization potential is surprisingly high: 78% decarbonized reference to DRI-gas itself and 86% is taking BF-BOF technology as reference. Considering the fact that the H2 can be produced from zero-C electricity, electrification appears promising if gas-based DRI is the primary production pathway.

Table 13. Fractional decarbonization potential combining hydrogen and zero-C electricity.

Technology	BF-BOF	DRI-gas
H2 injection abatement potential (%) – self reference	21.4%	37.4%
Zero-C electricity abatement potential (%) – self reference	7.4%	40.6%
Combined abatement potential (%) – self reference	28.8%	78.0%
Combined abatement potential (%) – BF-BOF reference	28.8%	86.2%

* “self reference” takes its own production method emission as reference (e.g., DRI using Zero-C electricity comparing with DRI baseline). BF-BOF reference takes BF-BOF production emission as reference (e.g., DRI using Zero-C electricity comparing with BF-BOF baseline), the same for table 14.

Biomass + CCS retrofit

A discussed above, biomass can be low-carbon and is sometimes considered carbon neutral. Biomass conversion (biocoke reduction or combustion) emits CO2 onsite, which can be captured, leading to additional carbon footprint reductions. In practice, land-use changes (LUC) and full life-cycle analysis (LCA) reveal that the carbon footprint can vary dramatically and is rarely carbon negative [(Campbell et al., 2018)]. However, under the right circumstances, biomass energy + CCS (BECCS) is a viable deep decarbonization pathway for steel production, and currently the only pathway with the potential to be carbon negative.

Table 14. Added carbon abatement potential with biomass and CCS retrofit, and zero-C electricity

Technology	BF-BOF	DRI-gas
Biomass abatement potential (%) – self reference	38.3%	53.7%
CCS retrofit abatement potential (%) – self reference	47.0%	26.8%
Combined Biomass + CCS abatement potential (%) – self reference	85.3%	80.6%
Combined Biomass + CCS abatement potential (%) – BF-BOF reference	85.3%	82.9%
Zero-C electricity (ZCe) abatement potential (%) – self reference	7.4%	40.6%
Combined Biomass + CCS+ ZCe abatement potential (%) – self reference	93.6%	121.1%
Combined Biomass + CCS+ ZCe abatement potential (%) – BF-BOF reference	93.6%	118.6%

Analysis reveals that a BECCS retrofit could reduce an existing facility~80% but still could not achieve a carbon-negative (CO2 removal) footprint. If zero-C electricity was added, carbon abatement potential would further increase. To achieve carbon negative steel production, all three pathways must applied to DRI-based production.

Combined technologies set summary

The limits of the combined technology options underscores how hard a sector steel is to abate [(Carpenter, 2012)]. The only theoretical possible way to achieve carbon negative steel production involves replacing BF-BOF production with DRI-based primary steel pathway, using ideal biomass as a fuel, and adding both CCS retrofit with reliable zero-carbon electricity. All the other combinations could yield substantial hot-metal production emissions abatement. All face significant cost increase and technical barriers.

BF-BOF based production is particularly stubborn. Key producing nations, notably China, Japan, Korea, Germany, and the US, should consider substitution with DRI-based primary steel production if the main focus is decarbonization, especially for older facilities. Sweden and SSAB have already made this choice, enabled by low-cost, low carbon, firm electric power from large hydro and nuclear [(SSAB, 2020)].

Discussion and Comparisons

Given the limits detailed above, more and better options are urgently needed to decarbonize steelmaking. Given the urgency of climate action, today’s available options should be deployed as soon as practical, and the most promising options for decarbonizing steel production are H2, biomass, zero-carbon electricity, and CCS retrofit. Each of the decarbonization technology, separately and in combination, has potential limits (see figure 12 blue bars) based on production chemical or operations. All these options should be further analyzed, developed and tested, suggesting an innovation agenda for policy makers as well as a deployment agenda.

Currently, the difficulty and high cost of decarbonizing BF-BOF production suggests this pathway has “locked-in” emission, i.e., emission will persist for decades without attempts to mitigate it. The lack of technology options to reduce deeply the emission from BF-BOF steelmaking limit even the most aggressive decarbonization technology set, biomass + CCS + zero-carbon electricity (Figure 13). This means any BF-BOF capacity existing or being constructed now will be a potential emitter for 40 or more years in a world moving towards net-zero [(IEA ETP, 2020)]. Considering the limits of biomass supply, CCS storage availability, LCA and LUC effect, the practical situation of BF-BOF pathway decarbonization limits require urgent policy attention.

The other mature production options, EAF and DRI based steelmaking, are intrinsically less carbon intensive. EAF-scrap is secondary steelmaking (e.g., recycled steel making) and scrap steel supply sets practical limits to its scaling potential. A policyto grow recycling could help improve the fraction of secondary steel production share, especially in developing countries; however, it would be unlikely to reduce primary steel production. Gas-based DRI and coal-based DRI production have the greatest potential to accept different decarbonization technologies: gas-based to hydrogen and coal-based to biomass and CCS. Hydrogen production can be green (electrolysis) and complement electrification policy developmet, provided adequate zero-carbon power supplies, most likely through addition of generation. Biomass and CCS are subjected to their geographical limitations (carbon storage and biomass supply), although global transportation newtworks exist for biomass and could exist for CO2 [(ICEF, 2020)].On the other hand, production costs will limit adoption of any decarbonization technology beyond purely technical barriers (figure 14). The estimated increase to cost per ton hot-metal production ($/ton-HM) only includes the marginal cost increase and, not surprisingly, biomass and hydrogen involved technologies appear more expensive, despite their value to deep decarbonization. From the perspective of hot-metal production costs, CCS and zero-carbon electricity appear better options but with modest total decarbonization potential. Using $400/ton-HM as standard average cost for steelmaking, CCS and zero-carbon electricity could control cost increases within $100/ton-HM (<25%), while most deep-decarbonization options yield cost increases >50% (+$200/ton-HM) and in some cases >100% (+$400/ton-HM)

Figures 13 and 14 demonstrate the dilemma of steelmaking decarbonization and why the sector is hard-to-abate: cost effective ways approaches are limited in potential and adoption of high decarbonization options would lead to high cost burdens for producers. This dilemma requires policy measures, either incentives or regulations, sufficient to speed decarbonization in steelmaking industry [(e.g., ETC 2020)].

From the perspective of cost per ton CO2 abatement (figure 15), ideal biomass, CCS, and zero-carbon electricity can deliver relatively low-cost emissions reduction (<$200/ton-CO2), with CCS retrofits appearing to have both low cost profile and substantial potential. CCS retrofits are also compatible with biomass substitution. Wherever CCS is viable, it appears to be most promising option given its substantial potential and relatively low cost (both on a $/ton-HM and $/ton-CO2 basis). Other studies reach the same finding [(Bataille et al., 2020)]. In contrast, green hydrogen today is extremely costly in most markets, while blue hydrogen should be seriously considered more broadly. Where CCS is viable, retrofits could include both blue hydrogen and top-gas capture with some economic benefits in shared infrastructure.

Findings and conclusions

Finding 1: Multiple approaches exist today to decarbonize existing iron & steel production. These include (a) partial or complete substitution of fossil fuels with low carbon hydrogen or biofuels, (b) CCS retrofits, (c) replacement of current electricity supplies with low-C electricity, (d) low-carbon biomass substitution of coke with biocoke or charcoal, and replacement of gas- or coal-based DRI plants with biogas or zero-c hydrogen. While modest decarbonization is possible by substituting today’s electric power supplies with low-C electricity, it is not possible to completely electrify existing facilities.

Finding 2: All approaches to steel decarbonization lead to substantial cost increases. The primary reason is the high cost of substitute fuels relative to fossil fuels. Carbon-neutral biomass, low-C hydrogen, and high-capacity zero-C power all cost more today than current fossil-fueled systems. Although the costs of these alternatives are dropping, it is unlikely that they will be cost competitive with unabated fossil systems in the next 10-20 years.

Finding 3: Many approaches to decarbonizing steel face substantial technical challenges. Some of these challenges are intrinsic, such as improving the heat content and mechanical strength of biocoke. Others are systemic, such as integration of CCUS or redesigning fuel feed systems. Given the slow rate of replacement and capital upgrades in existing systems, it is likely that owners and operators of today’s facilities would tolerate only minor cost increases.

Finding 4: Existing BF-BOF facilities are inherently challenging to decarbonize. They could be abated with a mix of approaches; zero-C hydrogen for heat, biomass for coking and for heat, and CCUS can reduce GHG emissions individually or combined. Different geographies, economies, and infrastructure will determine the cost and viability of these applications.

Finding 5: DRI with hydrogen + EAF with zero-C power is the most mature low-emission pathway. Gas-based DRI systems are commercially available at scale and one commercial plant operates on hydrogen today. EAF systems operate around the world at scale. Combined, these systems could yield 80% or greater CO2 reductions. While the ability to change existing plants is limited (e.g., most gas-based DRI plants are in Iran), some systems worldwide may prove amenable to retrofit and modification, and ultimately replacement.

Finding 6: Substantial progress is being made in pilots and innovation. Unfortunately, progress remains slow and, in most nations, decarbonizing steel is not a focus of either policy measures or an innovation agenda. New approaches should be encouraged and supported politically, including applied research (e.g., retrofit fuel systems and better heat recovery), pilots and demonstrations, and advanced production approaches.

Finding 7: Policy measures are required to achieve deep abatement and avoid dislocations. Painful outcomes such as loss of market share or critical manufacturing, carbon leakage, and job loss are likely with ill-planned or implemented climate policies. Slow or incomplete decarbonization are alternative outcomes from protectionist measures and insufficient focus.

These seven findings prompt a set of conclusions for investigators, policy makers, and potential investors in steel production and in steel decarbonization. The most important conclusion is that existing steel production facilities are inherently challenging and costly to abate. This means that a range of policies should be considered to accomplish deep decarbonization from steel production at existing sites. Given the importance of steel production to many economies and nations, including dimensions of national security and labor, priority should be extended to steel production decarbonization.

An important consideration is resource planning. All the approaches for steel decarbonization discussed (hydrogen, zero-c electricity, biomass) have applications in decarbonizing other sectors (e.g., transportation or heating). Given the resource limits of any given nature, especially for biomass, power infrastructure, and CO2 storage resource, policy makers should consider how to make best use of resources and capital to accomplish decarbonization and maintain competitiveness. In this framework, biomass resources may be best used to decarbonize steel instead of power sector (where more options and economic alternatives exist), requiring a policy preference for that market applications. Similarly, transmission infrastructure build-out for steel could be very large, and my provide less value to nations than alternative uses for low-carbon power (e.g., for electric vehicles). Understanding these tradeoffs requires additional analysis, e.g., coupled system modeling or levelized cost of carbon abatement (LCCA) analysis.

For those nations where steel production plays an important economic role, a richer innovation agenda is warranted. A few nations (e.g., Sweden, Japan, Netherlands) are supporting pilots and pre-commercial demonstrations of advanced low-carbon technology options through public-private partnerships, grants, and broad RD&D support. Overall, this is rare and makes it likely that decarbonization will be slower and more expensive than necessary. Novel approaches, such as MOE or biocoke development, require specific dedicated research funds to deliver potential options to market in 10-20 years’ time. Given the long lead times required to bring new technologies to market, there is climate and economic competitiveness value in starting today.

Fundamentally, overt market-facing policies will be needed to avoid dislocations and speed decarbonization. These include:

Investments in low-carbon infrastructure enablers, such as low-carbon transmission systems, hydrogen pipelines, and CO2 storage hubs and clusters.
Support for domestic decarbonization with incentives. These could include revenue enhancements, such as grants, feed-in tariffs, and contracts for differences, or capital treatments, such as tax credits.
Green procurement, including authorization to purchase low-carbon steel made by domestic industry at elevated prices. This is particularly straightforward for infrastructure and military procurement.
Development of low-carbon production standards as a regulatory driver, matches with border tariffs to avoid leakage and offshoring of jobs and industry.
Deliberate early retirement and replacement of current steel-producing facilities with low-emission options, as well as a shift to increased scrap steel recycling using zero-carbon electric power.
International coordination, including sector “clubs” that include major steel-producing companies and nations. This could serve to develop international low-emission production standards for steel among buyers & sellers (akin to the Montreal Protocol), potential avoiding future challenges to the International Monetary Fund.

To hasten the development and deployment of decarbonization options, nations should adopt these measures and others. The inherent difficulty of steel decarbonization will require innovation in policy and market design that embrace multiple options and possibly all options. These policies will have implications for labor, trade, security, and climate, requiring care in construction. Ideally, the technical findings from this report and future work will help to advise that policy design process.

Appendix (additional materials)

Cost, heating value, and carbon footprint assumptions

Table A.1. Cost assumptions of different fuels

Assumptions	Values (lowest-highest)	Units
Natural gas cost	3.5	$/MMBtu
Natural gas cost	3.32	$/GJ
Coke cost	200	$/ton
Industrial coal cost	100	$/ton
H2-SMR no CCS	1.275 (1.05-1.5) [(Damen et al., 2007)]	$/kg
H2-SMR 53% CCS (blue)	1.545 (1.32-1.77) [(Damen et al., 2007)]	$/kg
H2-SMR 89% CCS (blue)	1.930 (1.71-2.15) [(Damen et al., 2007)]	$/kg
H2-wind/solar (green)	6.635 (6.02-7.25) [(Friedmann et al., 2019)]	$/kg
H2-hydro (green)	5.57 (4.8-6.34) [(Friedmann et al., 2019)]	$/kg
Electricity (baseline)	75 (60-90)	$/MWh
Electricity (Wind/solar LCOE)	42.5 (29-56) [(LAZARD, 2018)]	$/MWh
Electricity (hydro)	45 (30-60) [(Friedmann et al., 2019)]	$/MWh
Electricity (firm zero-carbon)	120 [(Friedmann et al., 2020)]	$/MWh
Biomass-Straw	38.5 (35.2-41.8) [(Kuhner, 2013)]	$/ton
Biomass-Bamboo Char	426.5 (253-600) [(Kuhner, 2013)]	$/ton
Biomass-Charcoal	410 (295-525) [(Wiklund et al., 2013)]	$/ton

In this report, if the cost is represented by a single value, it’s the mean value of the range of the cost. If the cost is represented by a range of values, it represents the lowest/highest range of costs. Biomass is represented by ranges since the cost assumption is greatly different for: feedstocks, regions, land use and etc.

Table A.2. Heating value assumptions of different fuels. [(engineeringtoolbox, 2020)]

Assumptions	Values (lowest-highest)	Units
Natural gas heating value	0.03684	GJ/Nm3
Natural gas heating value	0.04784	GJ/kg
Coke heating value	28.84	GJ/ton
Industrial coal heating value	26.00	GJ/ton
H2 heating value	0.11996	GJ/kg
Biomass-Straw heating value	N/A	N/A
Biomass-Bamboo Char heating value	31.00	GJ/ton
Biomass-Charcoal heating value	31.00	GJ/ton

Lower heating value is used for all fuels and mean value is used if the fuel has a range of heating values (e.g., coal heating value differs greatly due to quality control of the coal).

Table A.3. Carbon footprint assumptions (selected within range of reference)

Assumptions	Values (kg CO2-eq/kg-fuel or other specified)	Remarks
H2 SMR	12.13 [(Bhandari et al., 2014) ]	SMR no CCUS*
H2 Blue	5.7	SMR 53% CCUS*
H2 Blue	1.3	SMR 89% CCUS*
H2 Green	2.21 [(Bhandari et al., 2014)]	Electrolysis PEM renewable energy, represented by wind**
H2 Coal based	24.2	Coal gasification*
H2 Grid electrolysis	29.54 [(Bhandari et al., 2014)]	Grid electrolysis with PEM, 0.51 ton/MWh**
Industrial coal	2.33 [(EPA, 2011)]	Coal and coke – Mixed (industrial sector)***
Coke	3.11 [(EPA, 2011)]	Coal and coke – coal coke***
Charcoal	3.1 [(Sitoe, n.d.)]	Charcoal combustion emission rates***
Bio-charcoal LCA GWP	1.46 [(Campbell et al., 2018)][ (Puettmann, 2016)]	Equivalent to 40% wood to biochar mass conversion rate [(Campbell et al., 2018)] and 0.65 kg CO2-eq/kg-feedstock absorbed [(Puettmann, 2016)]  CO2 credit 1.63 kg CO2-eq/kg  1.46 kg CO2-eq/kg LCA
Bio-charcoal LUC GWP	34 kg/GJ [(Muazu et al., 2017)]	Wood chip pelletizer, 6.0 MJ/kg water removed, 45.8 km2/yr land use for 60,000 t. (medium estimation)

*Production marginal carbon footprint

**LCA analysis carbon footprint

***Combustion carbon footprint

Carbon footprint assumptions has different boundaries since they are borrowed from different literatures. Fossil fuels carbon footprint is the most underestimated but used for it is the convention to calculate steelmaking carbon footprint, i.e., in steelmaking carbon footprint analysis, only direct combustion emission rate is considered instead of LCA of fuels. The analysis result of steelmaking and fossil fuels’ carbon footprint represents the actual onsite carbon emission.

For H2 carbon footprint, LCA result is borrowed if it’s from water electrolysis, include the carbon footprint of electricity. If H2 is produced from fossil fuels (SMR or coal gasification + CCS), marginal production carbon footprint is counted, excluding other factors (e.g., plant building, transportation). Blue (brown/gray) hydrogen carbon footprint is underestimated comparing with green hydrogen since it has much smaller boundary.

Great uncertainty exists for the blue hydrogen production LCA if upstream methane emission is taken into consideration. While GWP is typically used as single-number metric, the actual greenhouse gas effect is harder to be quantified [(Kleinberg, 2020)]. Here we present a simple multiplier table if one is interested in the upstream methane emission effect of blue hydrogen production.

Table A.4. Blue hydrogen upstream methane emission

Specifications	Value (Units)	LCA correction multiplier of baseline blue H2 assumption (1.3 kg CO2-eq/kg-H2)
SMR natural gas consumption	165 MJ/kg-H2  3.45 kg-NG/kg-H2 [(Mehmeti et al., 2018)]	N/A
Methane leakage rate	2.3% [(Alvarez et al., 2018)]	N/A
GWP20 = 84 added emission	6.67 kg CO2-eq/kg-H2	6.13
GWP100 = 28 added emission	2.22 kg CO2-eq/kg-H2	2.71
Methane leakage rate	1.4% [(EPA, 2018)]	N/A
GWP20 = 84 added emission	4.06 kg CO2-eq/kg-H2	4.12
GWP100 = 28 added emission	1.35 kg CO2-eq/kg-H2	2.04

GWP estimation from [(Kleinberg, 2020)]

Table A.4 shows that if considering GWP at 100 years basis (GWP100), the LCA including upstream methane leakage emission will be 2~2.7 times of original 89% CCS SMR blue H2 production, making its LCA relatively the same with green H2. But if if considering GWP at 20 years basis (GWP20), the LCA including upstream methane leakage emission will be 4.1~6.1 times of original 89% CCS SMR blue H2, equivalent to 44%~65.4% of SMR direct emission. This paper’s blue H2 LCA result does not include upstream methane emission to keep consistency with literature’s LCA estimation of blue H2. One can correct the emission of blue hydrogen by using the multiplier in Table A.4. if interested.

Carbon footprint of biomass is specifically and detailed discussed in the biomass section due to its complexity.

Technical specific assumptions

Table A.4 DRI production plant case study specifications [(Chevrier, 2018)]

Case study	MIDREX Cleveland-cliffs
Production: ton DRI/h	200
Natural Gas consumption Nm3/h	53333
Natural Gas consumption Nm3/ton DRI	266.7
Natural Gas price $/GJ	3.32
Natural Gas heat value GJ/Nm3	0.03684
Natural Gas total cost $/ton DRI	32.6

Additional graphics

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[1] This report does not include further treatment, such as finishing and alloying