Towards green iron and steel industry: opportunities for MILENA biomass

gasification technology in Direct Reduction of Iron G. Aranda Almansa

P. Kroon

May 2016

ECN-E—16-022

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Acknowledgement

This report is framed within WP.4 of the knowledge-funding project “K3. Improvement

and alternative applications of MILENA gasification technology” (5.3486.04.01). The

authors would like to thank the reviewers for the fruitful discussion and the

improvement of this work.

Abstract

The iron and steel industry is an energy-intensive sector, and an important source of

CO2 emissions. Some technological options for net energy saving and CO2 emission

reduction include recovery of exhaust heat, process gas recovery, and use of non-fossil

energy sources. In this sense, the use of biomass could contribute to the shift towards a

greener iron and steel industry. However, biomass oxygen must be removed at least

partially in order to ensure the suitability of biomass as reducing agent. The removal of

oxygen can be applied to the biomass via slow pyrolysis for the production of solid

charcoal or to by CO2 + H2O removal from syngas produced from biomass gasification.

This report analyses the use of producer gas from biomass gasification (in particular,

producer gas from MILENA indirect gasification) as reducing agent in DRI processes.

Direct reduction of iron (DRI) consists of the conversion of iron ore to quality metallic

iron in solid state in one step using a reducing gas. In natural gas based DR processes,

oxygen is removed from the feed iron ore by syngas produced from natural gas

reforming. Gasification can be an interesting option in those cases where there is a

combination of expensive natural gas supply and abundant, low-cost coal or biomass

resources. The implementation of biomass gasification in DRI processes could

contribute to the shift towards a “greener” iron and steel industry. The large scale (~400

MWth) of gasification plants required for a typical DRI plant makes it unlikely that

biomass can completely replace fossil fuel consumption in the short term, but given the

size of planned biomass- and waste gasification plants as well as the recent

developments in legislation over the need for reduction of CO2 emission, DRI could

become a feasible application for biomass and waste gasification in the medium/long

term. An alternative for the implementation of biomass and waste in the short term

might be the partial replacement of coal or natural gas by biomass, either by

implementing a dedicated biomass gasifier in a natural gas-based DRI process or by co-

gasification of biomass and coal in case of a coal gasification-based process.

The main quality requirements of reducing gas in DRI processes include a high

(H2 + CO)/(CO2 + H2O) ratio, as well as removal of dust and sulphur. The main

advantages of MILENA include the possibility of producing a N2-free syngas without the

need for an ASU unit, and the relatively high content of gaseous hydrocarbons in the

producer gas, which promote the carbon content in the product. The composition of

producer gas from biomass gasification is not in principle the most suitable for DRI

application, since it has a large concentration of CO2 and H2O. However, the excess

oxygen in the producer gas can be removed by proper gas cleaning and upgrading (dust

and tar removal, water removal, desulphurization, CO2 removal) using conventional

technologies.

4

An economic analysis has revealed that biomass gasification at current prices is not very

attractive. In the case of a natural gas-based DRI plant with a 50 MWth biomass unit a

positive NPV is reached at biomass cost of 4 USD/GJ or lower. This changes if subsidy

schemes are implemented, which reduce investment cost and improve profitability. In

such a situation biomass gasification can then economically replace part of natural gas

at biomass cost below 9 USD/GJ (50 MWth gasification plant) and below 11 USD/GJ

(100 MWth gasification plant). In a coal gasification based DRI plant, biomass gasification

only makes economic sense under specific and unlikely conditions of low biomass cost

and high gasification capacities (< 4 USD/GJ biomass price for a 100 MWth plant). This

improves if coal and CO2 prices raise.

Abbreviations

ASU: Air separation unit.

BF: Blast furnace.

BF-BOF: Blast furnace-basic oxygen furnace.

CDRI: Cold direct reduced iron.

COG: Coke oven gas.

DRI: Direct reduction of iron (process) /Directly-reduced iron (product).

EAF: Electric arc furnace.

HBI: Hot briquetted iron.

HDRI: Hot direct reduced iron.

IRR: Internal Rate of Return.

NPV: Net Present Value.

OHF: Open hearth furnace.

USD: American dollar ($).

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Contents

1. Introduction 6

2. Direct Reduction of Iron (DRI) 8

2.1 Introduction 8 2.2 Reactions involved in DRI 13

3. Suitability of producer gas from biomass gasification for DRI applications 19

3.1 Gasification plant size 19 3.2 Producer gas composition 22 3.3 Gas cleaning requirements 23 3.4 Opportunities of ECN technology for DRI applications 23

4. Economic analysis of the feasibility of biomass gasification in a DRI plant 27

4.1 Introduction 27 4.2 Results: no subsidies considered 29 4.3 Results: application of subsidies to the biomass plant 32

5. Conclusions 37

6. References 39

Appendix A. Sample cost figures 42

6

1 Introduction

The iron and steel industry is an energy-intensive sector, and an important source of

CO2 emissions [1]. Innovations for the decrease of overall energy consumption and CO2

emissions are being developed [1][2]. Some technological options for net energy saving

and/or net CO2 emissions reduction include recovery of exhaust heat, process gas

recovery, and use of non-fossil energy sources [2]. Therefore, the use of biomass could

contribute to the shift towards a “greener” iron and steel industry.

There are two main different routes for iron production: blast furnace (BF) and direct

reduction of iron (DRI). In a blast furnace process, fuel, iron ore and flux (limestone) are

continuously fed in the top of the furnace. Oxygen-enriched air is injected at the bottom

of the furnace, so the chemical reactions take place throughout the furnace as the

material moves downward [3]. In the blast furnace, the iron ores are reduced by the

carbon monoxide generated from the coke [4]. The molten iron product of the BF

process is called pig iron. On the other hand, direct reduction of iron consists of the

conversion of iron ore to quality metallic iron in the solid state in one step. In a DRI

process, oxygen is removed from the feed iron ore in a furnace by reducing gas [3]. The

product of this process, direct reduced iron, is often called sponge iron due to its porous

nature [1]. The feed for the vast majority of DR furnaces is natural gas (which is

reformed to CO and H2 prior to the shaft furnace), but there is increasing interest in the

use of other gases, e.g. syngas from coal gasification, coke oven gas, offgas from other

metallurgical processes, etc. [1][3][5].

In this context, European projects such as ULCOS [6][7] and SHOCOM [4][8] aim at the

development and implementation of innovative low-carbon technologies in the iron

and steel industry. One of the approaches considered consists of the use of biomass.

The problem of the implementation of biomass into the iron and steel industry is

related to its high oxygen content (ca. 40 wt.%). In fact, the iron production process

requires a reducing agent for the chemical reduction of iron ores, thus the high oxygen

content hinders the suitability of biomass as reducing agent. Therefore, oxygen must be

removed at least partially in order to ensure the applicability of biomass. For this,

different approaches can be considered: the removal of oxygen can be applied either to

the starting biomass (namely via slow pyrolysis for the production of solid charcoal), or

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to the intermediate syngas if biomass gasification is applied. In the first case, charcoal

(with an oxygen content of approximately 15-20 wt.%) can be either injected into a

blast furnace as reductant to replace coal or can be incorporated into coal blends as

secondary feedstocks [4][7]. In the second case, syngas must further undergo an

upgrading process for the removal of oxygen present in form of H2O and CO2 in order to

be applied as reducing agent. Moreover, depending on the fuel composition,

contaminants such as sulphur compounds must be also removed from the syngas.

Another possibility for syngas is its application in iron ore pelletizing plants, not as

reducing gas as in the case of DRI processes, but as replacement of natural gas in

combustion [9].

With this overview, this report focuses on the use of producer gas from biomass

gasification (in particular, producer gas from MILENA indirect gasification) as reducing

agent in DRI processes. The MILENA technology [10] offers certain improvements with

respect to other existing indirect gasification technologies, which include a single-vessel

design with only one bed material circulation mass flow restriction, the implementation

of a settling chamber instead of cyclone for gas/bed material separation, the possibility

of generating N2-free gas without the need for an air separation unit due to the

separation between the gasification and combustion zones, and the total conversion of

the biomass. In addition, the MILENA configuration is well suited for chemical looping

applications (e.g. in-situ CO2 removal) due to the existence of two different reaction

zones with reducing and oxidizing atmospheres. The success of the commercialization

of the MILENA technology will ultimately depend on its capacity to get adapted to the

market challenges of feedstocks and applications of syngas. Therefore, it is necessary to

pave the way for MILENA to shift into new applications in order to increase its potential

for successful commercial implementation. One of the possible new markets for

MILENA gasification might be the iron and steel industry. This issue will be addressed in

this document.

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2 Direct Reduction of Iron

(DRI)

2.1 Introduction

More than 1.6 billion tons of steel are manufactured every year [1][11][12]. Globally,

steel is produced via two main routes [1][12]: the blast furnace-basic oxygen furnace

(BF-BOF) route, and the electric arc furnace (EAF) route, which are shown in Figure 1.

Variations and combinations of production routes also exist.

The integrated BF-BOF route produces steel predominantly using raw materials

such as iron ore, coal, limestone and recycled steel. Firstly, iron ores are

reduced to iron, also called hot metal or pig iron. Then the iron is converted to

steel in the BOF. After casting and rolling or/and coating, the steel is delivered

as coil, plate, sections or bars. About 70% of steel is produced using the BF-BOF

route.

Steel made in an EAF uses electricity to melt recycled steel. Depending on the

plant configuration and availability of recycled steel, other sources of metallic

iron such as direct-reduced iron (DRI) or hot metal can also be used. The

downstream processes are similar to those of the BF-BOF route. About 29% of

steel is produced via the EAF route.

The open hearth furnace (OHF) makes up about 1% of the global steel

production. The OHF process is very energy intensive and is in decline due to

its environmental and economic disadvantages. Only 4 furnaces of this type are

known to be in operation.

Conventional steel plants require high capital expenses and raw materials of stringent

specifications. Coking coal is needed to make a coke strong enough to support the

burden in the blast furnace. Integrated steel plants of less than 1 million tons annual

capacity are generally not economically viable. The coke ovens and sintering plants in

an integrated steel plant are polluting and expensive units [13]. Moreover, the iron and

steel industry is an important source of CO2 emissions, accounting for 6.7% of the total

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world CO2 emissions [1][12]. On average, 1.8 ton CO2 are emitted per every ton of steel

produced.

Figure 1. Routes for production of steel [11][12].

Direct reduction of iron is defined as the conversion of iron ore to quality metallic iron

in the solid state in one step using reducing gas. This definition is opposed to the

indirect reduction or smelting, where the iron produced is taken in molten state [1].

Indirect reduction has been dominated for the past 100 years by the blast furnace for

the production of iron from iron ore [1]. DRI has grown from virtually no volume at the

end of the 1960s to over 70 million ton/year in 2012 [1]. There has always been an

interest in lower-cost processes that neither require large scale to be economical, nor

expensive raw materials such as metallurgical coke [1].

In a gas-based direct reduction process, oxygen is removed from the feed iron ore

(where iron is in form of iron oxide) in a furnace by reducing gas [3]. The product of the

process, directly-reduced iron, is often called sponge iron due to its porous nature [1].

Directly-reduced iron (DRI) is a high-quality metallic product produced from iron ore

that is used as a feedstock in electric arc furnaces, blast furnaces and other iron and

steelmaking applications. Hot briquetted iron (HBI) is a compacted form of DRI designed

for ease of shipping, handling, and storage [14]. The reducing gas used in the DRI

process can be produced from different sources: reforming of natural gas, coal

gasification, coke oven gas, etc. [3][5].

The advantages of DRI include [13]:

The product has about the same iron content as pig iron, typically 90–94%

total iron, so it is an excellent feedstock for the electric furnaces used by mini

mills, allowing them to use lower grades of scrap for the rest of the charge or

to produce higher grades of steel.

Hot-briquetted iron (HBI) is a compacted form of DRI designed for ease of

shipping, handling, and storage.

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The direct reduction process uses in general pelletized iron ore or natural

“lump” ore.

The direct reduction process can use natural gas contaminated with inert

gases, avoiding the need to remove these gases for other use. However, any

inert gas contamination of the reducing gas lowers the effect (quality) of that

gas stream and the thermal efficiency of the process.

It is suitable in those cases in which there is an available source of gas nearby

(it is more cost effective to ship the iron ore rather than the gas).

The world’s DRI output in 2013 was 75.2 million tons sponge iron (see Figure 2), which

implies an increase of 2.8% with respect to 2012 production and of 85% with respect to

2001 [14]1. Currently there are hundreds of DRI plants with sizes ranging from 10 kton/y

(rotary kilns) to 2 Mton/y (shaft furnaces). The world DRI industry is expected to grow

considerably over the next few decades. Approximately 16 million tons of DRI capacity

is currently under construction. According to MIDREX®, the capacity will increase 5

million tons/year and more over the next decade [14]. The prospects in the short- and

long term will largely depend on the price and supply of natural gas. In areas without

access to low cost natural gas, alternative technologies such as the (co-) use of syngas

or coke oven gas to replace (part of) natural gas are being explored and implemented in

order to make use of existing resources and lessen the dependency on natural gas [14].

The worldwide DRI production is expected to reach 200 million ton/year around 2030

[14].

Figure 2. World DRI production (in Mton/year) [14]. CDRI: Cold direct reduced iron; HBI: Hot briquetted

iron; HDRI: Hot direct reduced iron.

The MIDREX® process, developed and owned by MIDREX® Technologies Inc., currently

accounts for about 63% of world production [3][14]2. Other DR processes are, for

example, HYL-ENERGIRON and Purofer (shaft furnace/moving bed), FIOR, FINMET and

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1 To put it into perspective, the iron produced using blast furnace technology is over 1 billion ton/y [1].

2 The Midland-Ross Corporation began their first shaft furnace plant using natural gas in 1969 [1].

12

Circored (fluidized bed), Inmetco, Iron Dynamics and FASTMET (rotary hearth), etc. [1].

MIDREX and HYL processes account for 75% of the overall DR production [1]. Table 1

summarizes the main features of some DRI processes.

Table 1. Operating conditions of MIDREX, HYL and FIOR DRI processes [27].

Process MIDREX HYL III FIOR

Feed iron ore charge Pellet/lump Pellet/lump Fines

Capacity (Mton/y) 0.25 -1.2 0.25 – 1.5 0.5 - 1

Reactor type Countercurrent

shaft furnace

Countercurrent

shaft furnace Fluidized-bed

Residence time (h) 3 - 5 3- 5 1.5 - 2

Pressure (atm) 1 5 10

Gas temperature (°C) 800-885 900-960 850

H2/CO gas (mol/mol) 1.5 – 1.8 0.25 - 5 5 - 6

Feed fuel Natural gas,

COREX offgas

Natural gas,

COREX offgas Natural gas

Reformer agent (natural gas) CO2 and steam Steam Steam

Metallisation degree (%) 88-94 92-94 93

Carbon content in product (%) 1-3 1.8 – 4.5 1.5

Product type DRI, HBI DRI, HBI DRI, HBI

Share in world production (%)

[year] 63.2 [2013] [14] 15.4 [2013] [14] < 1 [1998] [27]

A layout of the MIDREX® process is shown in Figure 3. This process mainly uses natural

gas. The reduction by-products CO2 and H2O, along with unreacted H2 and CO, are

recycled to the process to minimize energy consumption and to produce additional

reducing gas [15]. The MIDREX® process uses a reformer for the catalytic conversion of

natural gas to syngas using the recycled gas [15], which is called near-stoichiometric

reforming [1]. In addition to providing the reducing gas, the MIDREX® Reformer also

provides the energy needed for the reduction reactions within the MIDREX® Shaft

Furnace [15]. The reforming takes place in two steps: firstly, a non-catalytic steam

reforming (primary reformer); and secondly, catalytic CO2 reforming (secondary

reformer) [3].

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Figure 3. Schematic diagram of the standard MIDREX process [1].

2.2 Reactions involved in DRI

The shaft furnace is the main equipment in a DRI process. Iron-bearing material is

introduced into the top of a cylindrical, refractory-lined vessel, where it descends by

gravity flow and is contacted by upward flowing reducing gas. The reducing gas, which is

primarily hydrogen and carbon monoxide, reacts with the iron oxide to reduce (remove

the oxygen content) and carburize the material prior to discharge. From there the

product can be discharged as CDRI, HDRI, HBI or any combination [16]. An overview of

the reactions involved are summarized in Table 2.

The hot H2 and CO contained in the gas reduce Fe2O3 into metallic iron (Fe), according

to reactions (1)-(6) [1][16]. The by-products of reducing reactions are CO2 and H2O. Also

carburizing reactions ((7)-(9)) and carbon deposition reactions ((10)-(12)) take place

[1][16].The reaction of wüstite (FeO) with syngas (reactions (3) and (6)) control the

speed of the chemical reaction and the velocity of production of reduced iron [3].

Even though the carburizing reactions are not as important as the reduction of iron, it is

desirable to have at least a certain amount of carbon in the DRI product [1]. Ideally,

there should be at least enough carbon to reduce any remaining oxygen in the pellet

product in the downstream process. Any extra carbon present can be burned in the

electric arc furnace downstream to generate heat. Reactions (10) and (11) are coupled

with each other by the water-gas shift reaction. Reaction (12) occurs at high

temperatures and is implemented commercially by adding methane to the hot reducing

gas before injection into the shaft furnace [1].

14

Table 2. Reactions involved during DRI process [1][16].

Reaction Exothermic/

endothermic

CO/CO2 or

H2/H2O

required

Reaction

no.

Reduction reactions

3 𝐹𝑒2𝑂3 + 𝐶𝑂 ↔ 2 𝐹𝑒3𝑂4 + 𝐶𝑂2 Exothermic 10-5

(1)

𝐹𝑒3𝑂4 + 𝐶𝑂 ↔ 3 𝐹𝑒𝑂 + 𝐶𝑂2 Endothermic 0.6 – 0.7 (2)

𝐹𝑒𝑂 + 𝐶𝑂 ↔ 𝐹𝑒 + 𝐶𝑂2 Exothermic 1.7 - 2 (3)

3 𝐹𝑒2𝑂3 + 𝐻2 ↔ 2 𝐹𝑒3𝑂4 + 𝐻2𝑂 Exothermic 10-5

(4)

𝐹𝑒3𝑂4 + 𝐻2 ↔ 3 𝐹𝑒𝑂 + 𝐻2𝑂 Endothermic 0.6 – 0.7 (5)

𝐹𝑒𝑂 + 𝐻2 ↔ 𝐹𝑒 + 𝐻2𝑂 Endothermic 1.7 - 2 (6)

Carburizing reactions

3 𝐹𝑒 + 𝐶𝐻4 ↔ 𝐹𝑒3𝐶 + 2 𝐻2 Endothermic (7)

3 𝐹𝑒 + 2 𝐶𝑂 ↔ 𝐹𝑒3𝐶 + 𝐶𝑂2 Exothermic (8)

3 𝐹𝑒 + 𝐶𝑂 + 𝐻2 ↔ 𝐹𝑒3𝐶 + 𝐻2𝑂 Exothermic (9)

Carbon deposition reactions

2 𝐶𝑂 ↔ 𝐶 + 𝐶𝑂2 Exothermic (10)

𝐶𝑂 + 𝐻2 ↔ 𝐶 + 𝐻2𝑂 Exothermic (11)

𝐶𝐻4 ↔ 𝐶 + 2 𝐻2 Endothermic (12)

The DRI process takes place within the range 800-1050°C [13]. The operation

temperature must be enough to burn off the carbon and oxygen content of the iron

ore, but must stay below the iron melting point. Below 650°C, the kinetics of the

reactions is slow. On the contrary, above 1200°C, iron softening starts. A preferred

operating temperature for DRI of most types of iron oxide feed materials is 815°C [17].

The kinetics of DRI depends on the chemical species used for reduction, the

configuration of the reactor system, and the internal structure of the iron ore supplied

to the system [1].

Natural gas cannot be used directly for reduction of iron ore because it decomposes to

form soot at a temperature below which the reduction of iron oxide can take place.

Natural gas fulfils different roles: feedstock to produce syngas via steam reforming,

partial oxidation or autothermal reforming; fuel for heat supply in the furnace; and

coolant and carburizing agent (see reaction (7)) [1].

Since the DRI product is pyrophoric, a cooling stage is needed before the discharge of

the sponge iron. The cooling is performed by a mixture of gases (CH4, CO2, CO, H2, H2O)

with 75% CH4. During the cooling process, also methane reforming takes place in-situ.

The reforming reaction is endothermic, thus not only produces reducing gas, but also

favours the cooling process itself [3].

The feed for the vast majority of gas-based DR furnaces is natural gas (which is

reformed to CO and H2 prior to the shaft furnace), but there is increasing interest in the

use of other gases [1], e.g. syngas from coal gasification, coke oven gas (COG) 3, or

offgas from other metallurgical processes. However, currently there are not commercial

DRI processes that uses biomass as reducing agent [1]. An overview of the possibilities is

summarized in Table 3. Important factors to take into account with respect to the

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3 Coke oven gas is a gas by-product of coal carbonization to produce coke in the steel industry.

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reducing gas include the insurance of reasonable process kinetics, and the fact that

without the liquid-phase separation (unlike blast furnace process), most impurities in

the reductant gas will end up in the DRI product [1]. Therefore, higher-purity reductants

are required.

Table 3. Data of DRI plants using MIDREX® process with different reducing gases [1][16].

Reducing gas Plant reference Reducing gas train H2/CO gas Start-up

Natural gas More than 60 modules in operation

MIDREX® reformer 1.5 – 1.7 Since 1969

Natural gas FMO, Venezuela Steam reformer, heater + MIDREX® reformer

3.2 – 3.9 1990

COREX offgas4

ArcelorMittal, Saldanha, South Africa

CO2 removal + heater 0.3 – 0.4 1999

COREX offgas JSW Projects Limited

CO2 removal + heater 0.5 – 0.6 2014

Coal gasifier JSPL Angul I, India CO2 removal + heater 2 2014

Table 4. Composition of different gas-based DR process feed gases (data from [1], except for MILENA

composition).

Composition (% mol)

Natural gas

Syngas 5

Corex offgas

Coal gasification (India)

6

Coal gasification (China)

Coke oven gas

MILENA dry syngas

7

H2 - 15 40 – 52 44 - 59 46 - 51 22.8 CO - 48 32 - 48 22 - 44 17 - 24 34.1 CO2 0 - 8 28.3 2 - 3 2 – 2.5 2.5 24.5 H2O - 2.8 0 – 0.3 0 16 - 17 0 N2 0 – 11 3 0.4 – 1.5 0.3 – 0.6 3 - 4 2 CH4 80 - 96 2.8 6 – 12 9 – 16 3 - 12 11.1

C2H6 1.5 – 15 - 0.25 0 – 0.22

0.4-2 total CxHy

5.5 total CxHy

C3H8 0.1 - 4 - - -

C4H10 0 – 1.6 - - -

C5H12 0 – 0.5 - - -

C6H14 0 – 0.4 - - -

H2/CO - 0.3 0.8 – 1.6 1 – 2.7 2.1 – 2.8 0.7 (H2+CO) /(H2O+CO2)

- 2.03 21-8 - 50 26.4 – 41.2 3.2 - 4 2.3

Table 4 summarizes the composition of different gases that can be used (directly or

indirectly) in DRI processes. The composition reported in Table 4 refers to inlet feed

gases, which in turn have to be upgraded to reducing gas. The upgrading processes

include cleaning of both the raw syngas and the recycled top gas (e.g. scrubbing of

particles and/or water removal); separation of CO2 and other gas species; in the case of

reforming of natural gas, catalytic conversion in the reformer and downstream

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4 COREX® is a metallurgical process developed by Siemens VAI Metals Technologies GmbH. The COREX® Plant uses a melter/gasifier to simultaneously produce hot metal and export syngas [5].

5 It is uncertain whether the composition of gases reported in Table 4 taken from [1] are expressed using the same basis (raw gas or upgraded gas), or which type of conditioning has been applied. Therefore, comparison between gas compositions should be made with caution.

6 Syngas composition depends on the type of coal, the type of gasifier and the operating conditions.

7 Test with beech wood, 845°C gasification temperature, Austrian olivine as bed material, 24 June 2014. Composition after water removal.

16

adjustment of the reformed gas (e.g. by partial oxidation); and adjustment of the inlet

temperature [1].

The quality of the reducing gas is expressed as the ratio of reductants (CO + H2) with

respect to oxidants (CO2 + H2O) in the gas mixture [17]. Globally, the (CO + H2)/(CO2 +

H2O) ratio of the reducing gas must be ≥ 2.1 for the stoichiometric iron reduction

reactions to take place [1]. However, in order to take full advantage of the inherent

chemical efficiency of a countercurrent shaft reduction furnace, the quality of the

reducing gas should be at least 8 [17]. In actual practice, this ratio has values of 10-12

[1].

Besides the content in CO, H2, CO2 and H2O, the feed gases also contain methane and

other gaseous hydrocarbons. The only disadvantage of the presence of methane in the

reducing gas is that it does not easily decompose to carbon in the lower part of the

shaft furnace as heavier hydrocarbons do. This is important since high-carbon DRI is

generally in greater demand than lower-carbon materials [1]. However, the CH4

contained in the coolant gas can undergo in-situ reforming to CO and H2 in the lower

part of the shaft furnace [1].

Commercially available gasification technologies can be coupled to a shaft furnace to

produce any form of DRI (cold DRI, hot DRI, or HBI). Midrex has developed a number of

commercial technologies using syngas from natural gas and coal sources. These

technologies include: MXCOL®, COREX®/ MXCOL® and the MIDREX® Thermal Reactor

System™ (TRS®) [5]. As an example, in the MXCOL® process (Figure 4), the gasification

syngas option includes gas cleaning and conditioning systems, which prepare the syngas

for reheating to the ideal temperature for use as reducing gas. The offgas from the

reduction furnace is mixed with fresh syngas after scrubbing and CO2 removal, reheated

and recycled to the furnace. An example of the application of this technology is the

Jindal Steel & Power Ltd. Plant, which uses syngas produced in a Lurgi gasifier from

indigenous coal gasification [5]. In cases where natural gas availability is uncertain or

when energy costs rise, the gasification option can provide a beneficial alternative [5].

The first commercial application of the MIDREX® technology using syngas from coal

gasification was commissioned in 1999 in South Africa. Another plant in India

commissioned in 2014 [18] is designed to use indigenous high-ash coal and iron ore to

produce DRI.

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Figure 4. MXCOL gasifier option [5].

Midrex in partnership with Praxair has also created two options for utilizing coke oven

gas (COG) via the TRS® (Thermal Reactor system) for DRI production. The first option

uses and recycles COG for situations where the COG can be specifically allocated for DRI

production. In this case, a CO2 removal step is necessary for the recycle offgas. The

second option allows using some of the fuel value of their COG for other purposes

besides DRI production [5]. JSW Steel Ltd. and Midrex have modified the existing

MIDREX® Direct Reduction Plant in Dolvi, India, the first to use coke oven gas (COG) as a

supplement to natural gas for DRI production. This feature provides the flexibility to

operate the plant efficiently under a wide range of parameters [5][19].

Table 5 summarizes the opportunities and limitations of syngas-based processes in DRI

applications.

ECN-E—16-022 18

Table 5. Opportunities and limitations of coal- and biomass/waste gasification in DRI applications.

Technology Opportunities Limitations Alternatives

Coal gasification

Combination of high natural gas prices or difficulty in natural gas supply, abundant and low-cost local coal resources, and penalties for CO2 emissions not being a critical factor [5][14] (e.g. India [5][14], Brazil [9], China).

The typical size of coal gasification plants matches well the very large scale required for DRI applications (~400 MWth).

The composition of syngas from coal (with high CO and H2, and low CO2 and H2O) is very suitable for DRI applications. This in turn reduces the need for further gas conditioning (e.g. water and CO2 removal), which reduces cost and complexity of the gasifier island.

Large experience in coal gasification. Proven technologies available.

Competition with other abundant, low-cost natural gas supply (e.g. North America [14]).

Environmental concerns.

Capture and sequestration of CO2 to reduce environmental impact.

Replacement of part of the coal with biomass or waste (co-gasification).

Biomass/waste gasification

Option when there is a combination of high natural gas prices/difficult natural gas supply, abundant and low-cost biomass resources available, high penalties of CO2 emissions, and interest to shift towards “greener” iron/steel industry.

The size of the gasification plant required for typical commercial DRI plants (~360-400 MWth) is much larger than the current scale of biomass/waste gasification plants (<100 MWth). Thus, biomass cannot totally replace fossil fuel consumption in the short-medium term.

Unless co-gasified in entrained-flow units, dedicated gas cleaning (dust and tar removal, water removal, CO2 removal) is required.

Replacement of part of fossil fuel consumption with biomass/waste. Options: co-gasification of coal and biomass/waste, implementation of a biomass gasifier train in parallel with the natural gas reforming train.

ECN-E—16-022 19

3 Suitability of producer gas from biomass gasification

for DRI applications

3.1 Gasification plant size

An important first consideration to properly assess the feasibility of using biomass

gasification for DRI applications is the size of the required gasification plant. Typical

capacities of DRI plants range between 0.4-1.8 Mton/y [14]. Taking into account that

the energy requirement of the coal gasifier is 13 GJ (3.1 Gcal) of coal per ton of reduced

iron [17], this implies that the required gasification capacity for a 0.8 Mton/y plant is

360 MWth. This estimated gasification capacity matches with the range of size of coal

gasification plants currently used for metallurgical applications (Table 6). It can be

clearly seen that the average capacity largely exceeds the typical size of currently

operational biomass/waste gasification plants (100 MWth syngas output for biomass

gasification, and 112 MWth for waste gasification), as displayed in Figure 5. However,

the size of a number of planned biomass- and waste gasification plants (~300-400 MWth

syngas output) shows that DRI could be a feasible application in the medium/long term.

A possible alternative to make the iron/steel industry greener in the short term might

be the partial replacement of natural gas or coal by indigenous biomass and waste

resources. Opportunities are foreseen in those cases where there are abundant, low-

cost, sustainable biomass resources, the price of natural gas or coal is high, and the

penalty of CO2 emissions is a factor to take into account.

20

(a)

(b)

Figure 5. Capacity of planned and commercial biomass (a) and waste (b) gasification plants [23].

ECN-E—16-022 21

Table 6. Coal gasification plants used for production of reducing gas for metallurgical applications.

Plant Location Syngas application Start date Gasification

technology

Feedstock/

oxidant *

Syngas output

(MWth)** Gas cleaning Reference

AO Aluminij Kazachstana Gasification Plant

Pavlodar, Kazakhstan

Fuel gas for aluminium calciner

2007 ZVU pressure gasification

Coal (1060 ton/day), oxygen

200 Not reported [20]

Jindal Steel & Power, Lim., Angul 1

Angul, Odisha, India

Syngas for steel metallurgy

2014 Lurgi fixed-bed dry bottom

High-ash coal 738 (225000 Nm

3/h

reducing gas)

Lurgi GmbH’s Rectisol

[5][18][24]

Jindal Steel, Barbil plant Barbil, Odisha, India

Syngas for steel metallurgy

2011 Envirotherm CFB process

27%-ash coal (1100 ton/day).

330 (100000 Nm

3/h

fuel gas) Not reported [25]

Wenshan Aluminum Co., Ltd. fuel gas plant

Wenshan, Yunnan, China

Syngas for aluminium industry

2014 Agglomerating fluid bed

Coal 60 Not reported [26]

* As a reference, 488 kg dry coal is necessary for the production of 1 ton DRI [17]. Assuming an average plant capacity of 0.8 Mton/y [14] (i.e. 100 ton/h), this means ~ 1170 ton/day coal.

** As a reference, 931 Nm3 syngas is required for the production of 1 ton DRI [17]. Assuming an average plant capacity of 0.8 Mton/y [14] (i.e. 100 ton/h), this implies a required syngas flow

of 93100 Nm3/h.

ECN-E—16-022 22

3.2 Producer gas composition

As presented in Section 2, a key for the suitability of syngas to DRI applications is the

quality ratio, (CO +H2)/(CO2 + H2O). This means that the gasification unit should ideally

maximize the production of CO and H2. This is thermodynamically favoured by

operating at high temperatures or lower pressures.

As can be seen in Figure 6, where the effect of temperature on the quality ratio is

plotted for both wet- and dry MILENA producer gas from biomass gasification, it is

necessary to remove the water content of the producer gas so that the quality ratio of

the reducing gas, (CO +H2)/(CO2 + H2O), can be above the stoichiometric value of 2.1.

Even so, the composition of the dry MILENA producer gas is far below the value of 8

considered to be the lower limit value for commercial operation [17]. These results

show that the high content of CO2 and H2O in the MILENA producer gas (and in general,

in producer gas from biomass gasification) makes the gas not ideally suitable for its

direct use in DRI applications. Removal of H2O (via gas cooling) and CO2 (either via

conventional processes, in-situ CO2 removal by chemical looping adsorption/desorption

or dedicated ECN technology for CO2 removal), as well as conventional removal of dust

and sulphur, are required as gas conditioning prior to the feeding in the shaft furnace.

Figure 6. Effect of the water content of the producer gas from MILENA on the suitability as reducing gas

for DRI.

However, producer gas from biomass gasification contains other components, namely

CH4 and other hydrocarbons. The presence of gaseous hydrocarbons in the gas seems

to be beneficial, since they are relatively easy converted to soot in the lower part of the

furnace (carburizing reactions), and this increases the carbon content of the product. A

metallization degree of 92% and a carbon content of 1.5% are considered as

commercial standard properties for direct reduced iron in natural gas-based DRI plants

[17]. The carbon content in the DRI product ranges from 0.5-4% [1]. In this sense, the

relatively high content of methane and other gaseous hydrocarbons in producer gas

from MILENA gasification is an advantage for its application in DRI processes.

ECN-E—16-022 23

3.3 Gas cleaning requirements

Besides the quality of the gas composition, discussed in Section 3.2, the syngas needs to

fulfil a number of additional specifications with respect to contaminant levels. The most

stringent cleaning requirement is syngas desulphurization prior to its injection in the

shaft furnace unit, due to the fact that sulphur and phosphorus make the final steel

product brittle and weak [1]. It has also been reported that certain elements contained

in coal ash (e.g. Si) can react with FeO to form low-melting fayalite (Fe2SiO4), which

interferes with the reduction process [1].

Foulds et al. [27] describe the cleaning and upgrading train of a TEXACO entrained-flow

gasifier used for DRI applications. Petcoke is gasified at 50 bar and a temperature up to

1350°C. The hot gas is quenched with water to remove slag and to partially clean the

gas. The saturated syngas is then water-scrubbed for the removal of entrained soot,

alkali metals, heavy metals, ammonia and chlorides. Then, the syngas is H2/CO adjusted

in a WGS unit before passing to an acid gas (CO2 and H2S) removal system. The sweet

gas then passes through an expander to generate power and reduce the pressure from

50 bar to the operation pressure of the DRI reactor (e.g. 1 bar in the case of a MIDREX

process). The gas is then mixed with a split of the recycled offgas from the DRI reactor,

heated to 850-900°C, and then fed to the DRI reactor.

A summary of the requirements of syngas in order to be fed to a DRI process can be

found in Table 7.

Table 7. Specifications of syngas for use as feed in MIDREX DRI process [18].

Parameter Range of values

H2/CO (mol/mol) 1 - 2

CH4 (% vol.) 0 - 15

CO2 (% vol.) 2 - 3

Sulfur (ppmv) 0 - 2508

Particulates (mg/Nm3) < 10

(N2 + Ar) (% vol.) < 0.5

(H2 + CO)/(CO2 + H2O) (mol/mol) > 10

Gas consumption (Gcal/ton DRI) ~ 2.2

3.4 Opportunities of ECN technology for DRI

applications

Table 8 compares MILENA with other natural gas- and coal gasification technologies.

The main advantages of MILENA include the possibility of producing a N2-free syngas

without the need for an air separation units (ASU) unit and the relatively high content

of gaseous hydrocarbons (which favours the carbon content in the product). However,

the producer gas from MILENA gasification has a relatively high content of CO2 and H2O.

xxxxxxxxxxxxssssssssxxxxxxxxxxxxxx

8 Due to the low S content of biomass, the concentration of sulfur compounds in syngas produced from biomass gasification is within this range. However, the fuel composition (e.g. in the case of waste gasification) must be taken into account for the design of the gas cleaning system.

24

This requires cleaning and upgrading of the gas prior to the feeding to the DRI furnace,

but this can be achieved with conventional technologies. Moreover, the mismatch

between the capacities of biomass gasification and typical DRI plants limits the current

application of biomass in the process to the replacement of only a fraction of the fossil

fuel consumption. In this case, two possibilities can be considered:

- In the case that biomass is intended to replace part of the feed of natural gas

in a gas-based DRI plant, a gasification island could be implemented in parallel

with the natural gas reforming and upgrading train, as shown in Figure 7. An

economic analysis of this option will be performed in Section 4. Another

possible option is the recycling of the gasification producer gas to the reformer

for the conversion of hydrocarbons (CH4, C2 gases, tars) in syngas, but in that

case the operating pressure of the gasifier should match that of the reformer.

Figure 7. Proposed layout for the implementation of biomass gasification in a natural gas-based DRI

process.

- In the case of a coal gasification-based DRI plant, the replacement of a

fraction of the coal by biomass could be carried out by co-gasification. In this

case, the implementation of a dedicated biomass gasification train (analysed in

Section 4) would increase the costs, thus the co-feeding of biomass and coal in

the existing coal gasifier appears as a more attractive option. In this sense,

torrefaction technologies could find opportunities to expand the application

markets. The proposed layout is plotted in Figure 8.

Figure 8. Proposed layout for the implementation of biomass in a coal gasification-based DRI process.

Table 9 summarizes the potential opportunities and limitations of different ECN

technologies for DRI applications with respect to conventional NG/coal processes.

ECN-E—16-022 25

Table 8. Overview of differences between MILENA gasification technology with commercial natural gas reforming/oxidation and coal gasification processes.

Air separation unit ASU unit required for partial oxidation/autothermal reforming of natural gas and for coal gasification. Not required in MILENA because of the use of indirect gasification.

Feedstock pre-treatment and feeding

- Natural gas pre-treatment: removal of liquid hydrocarbons, sulphur compounds (H2S, COS, mercaptans), heavy metals, etc. - Coal/biomass pre-treatment: Grinding and drying of biomass is in general more costly than for coal (biomass has a relatively high moisture content, and is fibrous). In both cases, lock hoppers are required for pressurized feeding into the gasifier.

Gasifier

- Partial oxidation and autothermal reforming of natural gas require the use of oxygen, which imposes more strict requirements to materials. Steam reforming operates at high pressures, and requires catalysts. Most of the large-scale coal gasification processes also operate with O2 and steam. - Operating temperature: MILENA indirect gasification operates at lower temperatures (700-900°C) than partial oxidation (1300-1500°C), entrained-flow gasification (1200-1500°C) or fixed-bed oxygen-blown gasification (Lurgi). This makes the material requirements less stringent, and simplifies the design (less refractory, no membrane walls required). - Operating pressure: MILENA indirect gasification operates up to 7 bar (due to limited possible solid circulation). The low operating pressure can be and advantage or a disadvantage. On the one hand, it matches well the DRI furnace pressure (e.g. 1 atm in the MIDREX process). On the other hand, partial oxidation units can operate at higher pressures (up to 70 bar), and coal gasification operates at much higher pressures (25-30 bar), which leads to more compact equipment, and thus to cost savings in construction materials. For the same output, MILENA equipment has a larger size, and is thus more expensive. Moreover, at high operating pressures, power can be produced from the expansion of the pressurized syngas in a turbine prior to the shaft furnace.

Syngas cleaning and conditioning

- Coal gasification: cooling, dust/soot removal, removal of alkalis, heavy metals and chlorides, acid gas removal (CO2, H2S), adjustment of pressure and temperature [27]. - Biomass gasification (including MILENA): dust removal, (OLGA) tar removal, cooling for water removal, acid gas removal, adjustment of temperature.

26

Table 9. Strengths and challenges of ECN technologies in DRI applications.

ECN technology Strengths/advantages Challenges Alternatives/solutions

MILENA gasification

Production of a N2-free gas without the need for an ASU unit

Integrated design.

High efficiency.

Suitable for biomass/waste applications.

High content of gaseous hydrocarbons (favour carbon content in product).

Commercially available.

Size does not currently match the large-scale of DRI plants.

MILENA producer gas contains significant concentrations of CO2 and H2O.

Need for construction of a dedicated biomass gasification island (fuel pre-treatment and feeding, gasifier, gas cleaning and conditioning).

Competition with other gasification technologies.

Replacement of part of fossil fuel (natural gas) consumption.

Use of conventional technologies for gas cleaning and upgrading (removal of water, CO2 and sulphur).

OLGA tar removal

Best suited for biomass gasification in those cases in which a separate gasifier is implemented.

Commercially available.

Typical coal gasifiers in DRI plants are high-temperature units with virtually no tar production.

-

Torrefaction

Attractive technology for the implementation of co-gasification of coal and biomass in large-scale entrained-flow gasifiers.

Suitable for coal gasification-based DRI plants, where a coal gasifier is already in operation.

Direct co-gasification in EF will avoid extra costs of dedicated equipment for feeding, pre-treatment, gasification, cleaning and upgrading of producer gas from biomass.

Torrefied biomass is expensive competition with coal.

ECN-E—16-022 27

4 Economic analysis of the

feasibility of biomass gasification in a DRI plant

4.1 Introduction

In this section, the economic profitability of the implementation of a biomass

gasification plant for the production of reducing gas in a European DRI plant is assessed.

For that, different scenarios, summarized in Table 10, have been considered.

Table 10. Cases studied in the economic analysis.

Scenario Case number

DRI plant, 360 MWth, based on natural gas Reference case 1

DRI plant, 360 MWth, based on coal gasification Reference case 2

Biomass gasification plant to replace part of natural gas Case 3

Biomass gasification plant to replace part of coal Case 4

The economic analysis has been performed for cases 3 and 4 under two different

conditions: no application of subsidies and application of subsidies. The assumptions

taken for the economic analysis can be observed in Table 11 and are explained in detail

in Appendix A. The energy and CO2 prices are in nominal terms. So in every future year

they are higher due to inflation and other price increases.

28

Table 11. Assumptions and reference values applied in the economic analysis (see Appendix A).

Parameter Value Source

Natural gas price (Europe imports, current

policies scenario, 2015)

9.8 USD-2013/GJ (HHV) [28]

Steam coal price (Europe imports, current

policies scenario, 2015)

98 USD-2013/ton;

3.9 USD-2013/GJ (LHV) [28]

Biomass price (Europe) 6 - 10 USD/GJ (LHV) [29]9

CO2 price (Europe, current policies scenario,

2015)

9.2 USD/ton [28]

10

CO2 emissions in DRI process (ton) - [30]

Subsidy (Dutch SDE+ incentive to gas from

biomass gasification, phase 1)11

(0.537 – 0.244) = 0.293

EUR/Nm3 (= 9.25 USD/GJ

HHV), 12 years

[32]

The used heating values are 35.2 MJ/Nm3 for natural gas (HHV), 25.1 GJ/ton (LHV) for

coal and around 17 GJ/ton (LHV) for biomass.

Other assumptions taken for the analysis:

Size of DRI plant: 0.8 Mton DRI product/y (equivalent to 360 MWth [14]).

A gasification plant based on MILENA gasification, OLGA tar removal and additional

gas upgrading is implemented to replace a fraction of the natural gas or coal feed. It

is assumed that for some upgrading, like CO2 removal, the already existing

installation can be used. It is not assumed that the biomass is used in the same

gasifiers as coal. The total additional capital expenditure estimated for a 50 MWth

plant is 36.4 million USD-2015.

Operational hours of DRI and gasification plant: 8700 hours.

Installed capacity with biomass: 50 MWth (reference value); 50 – 150 MWth (range

for sensitivity analysis).

Biomass price: 6 USD/GJ (reference value, local agricultural residues in Europe [29]);

2-10 USD/GJ (range for sensitivity analysis). Yearly increase of the biomass price:

2.3%/y.

Financial parameters: interest rate 8%; tax rate (Netherlands): 29.6%; project life: 15

years; inflation level: 2.3%/y.

Sales revenues: difference in fuel costs + saving in CO2 emissions (costs of emission

rights) + subsidy (if applicable).

Scale factor applied to capital and operating costs: 0.7.

xxxxxxxxxxxxssssssssxxxxxxxxxxxxxx

9 The normal range is from 6 USD/GJ (agricultural residue) to 10 USD (expensive wood chips). The range is somewhat lower than 5-11 USD/GJ used by Irena [28].

10 This is the 2015 figure. In 2020 the price is 23 USD/ton (20 USD/ton with inflation correction) and in 2030 44 USD/ton (30 USD/ton with inflation correction) both for the current policy scenario. The inflation rate is 2.3%/year.

11 The Dutch incentive for sustainable energy (SDE+) [32] contains a basis amount per phase (0.537 €/Nm3 for gasification in 2015) and is each year corrected for the market price of natural gas (provisional figure in 2015: 0.244 €/Nm3). This results in a subsidy of 0.293 €/Nm3. In the calculation only the first phase subsidy is used. During the year next phases with higher subsidy are introduced, until the maximum subsidy amount of a certain year is reached. The figures in €/Nm3 for 2014 were: 0.483 and 0.262 (resulting in 0.221) and for 2016 are 0.625 and 0.215 (resulting in 0.410). From 2014 to 2016 the starting level for the subsidy on gasification has increased, and natural gas prices have declined in the Netherlands. The subsidy is given for 12 years and only for 7500 operating hours/year. The subsidy is currently not given to syngas but only to gas with a quality comparable to natural gas, which can be fed into the natural gas network.

ECN-E—16-022 29

US dollar Exchange rates: 1 USD = 0.78 EUR (2012); 0.75 EUR (2013 and 2014);

0.90 EUR (2015)

The profitability of the project has been assessed through the net present value (NPV)

of the investment. The economic evaluation has been carried out both in the case that

no subsidies for the use of biomass are of application, and in the case that subsidies (in

this work, the Dutch scheme of incentives for renewable energies as an example of

European subsidy) can be implemented in the project.

4.2 Results: no subsidies considered

Figure 9 shows the results of present values over the economic life of the project

applied to case 3, that is, replacement of 50 MWth natural gas with producer gas from

biomass gasification in a 360 MWth DRI plant. The reference price of biomass in 2015 for

biomass and natural gas are 6 USD/GJ (local agricultural residues) and 9.8 USD/GJ,

respectively. As can be seen, the project is not economically feasible under these

conditions without the implementation of subsidy schemes. Case 4 (i.e. replacement of

50 MWth coal with biomass gasification) is even less profitable, as can be observed in

Figure 10. In this case, the NPV of the investment is -102 million USD. This is due to the

fact that biomass cannot compete with coal in terms of cost (6 USD/GJ for biomass

compared to 3.9 USD/GJ for coal).

Figure 9. Cash flows of case 3: replacement of 50 MWth with biomass gasification in a natural gas based

DRI plant (6 USD/GJ biomass price, no subsidies applied).

-40

-35

-30

-25

-20

-15

-10

-5

00 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15

Pre

sen

t va

lue

(m

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SD-2

01

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)

Project year

30

Figure 10. Cash flows of case 4: replacement of 50 MWth with biomass gasification in a coal gasification

based DRI plant (6 USD/GJ biomass price, no subsidies applied).

Figure 11. Effect of the biomass price on the profitability of case 3 (replacement with biomass

gasification in a natural gas based DRI plant, no subsidies applied) at 50, 100 and 150 MWth.

A sensitivity analysis has been applied to case 3 in order to determine the threshold of

biomass costs and gasification capacity for the investment to be profitable without

need for subsidies. The results can be observed in Figure 11. The biomass price needs to

be below 4 USD/GJ (biomass-containing waste stream) if a 50 MWth gasification unit is

applied, whereas for a gasification capacity of 100 MWth or 150 MWth the project can be

economically feasible if biomass can be purchased below 6 USD/GJ (100 MWth) or

7 USD/GJ (150 MWth). The biomass price can be compared with the current import

value of 8 USD/GJ for wood chips in Rotterdam.

-120

-100

-80

-60

-40

-20

0

0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15

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(m

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)

Project year

-150

-100

-50

0

50

100

150

200

2 4 6 8 10

NP

V (

mill

ion

USD

-20

15

)

Biomass cost in 2015 ($/GJ)

50

100

150

ECN-E—16-022 31

Figure 12 shows the same figure for the coal case. There is no biomass price in which

the investment is profitable at the assumed coal price level. Additional analyses show

that this is also the case with a lower interest rate, double CO2 prices or lower biomass

prices.

Figure 12. Effect of the biomass cost on the profitability of case 4 (replacement with biomass

gasification in a coal based DRI plant, no subsidies applied) at 50, 100 and 150 MWth.

Table 12 shows the results from several sensitivity analyses. Instead of the energy price

scenario of the World Energy Outlook (WEO) 2014, the prices of the WEO 2012 can be

used. Because gas and CO2 prices are higher in this outlook, case 3 is more profitable at

the same biomass price of 6 USD/GJ. The gas and CO2 prices are also higher in the new

policy scenario of WEO 2014. Because coal prices are higher in WEO 2012 the economic

situation for case 4 improves a little but still remains unattractive. In the new policy

scenario to the WEO 2014 CO2 prices are higher but coal prices are lower, due to a

decline in demand. The economic situation of case 4 hardly changes in this other

scenario.

Table 12: Sensitivity analysis of energy prices and investment costs

Case 3 (gas) Case 4 (coal)

NPV (mln USD) IRR NPV (mln USD) IRR

Different energy prices

WEO 2012 prices current policy 5 10% -81 -

Base case WEO 2014 prices current policy -18 2% -102 -

WEO 2014 prices new policy 0 8% -101 -

Investment cost of 100 MWth biomass plant

Use of coal gasifier 36 mln USD 2015 does not apply -123 -

Base case: 59 mln USD 2015 8 10% -160 -

Higher 78 mln USD 2015 -110 -8% -278 -

-400

-350

-300

-250

-200

-150

-100

-50

0

2 4 6 8 10

NP

V (

mill

ion

USD

-20

15

)

Biomass cost in 2015 ($/GJ)

50

100

150

32

Table 12 shows also the effect of the investment cost (CAPEX) on the economic

situation of a 100 MWth biomass plant. If the coal gasifier could also be used for

biomass, but other additional investments are still needed, this does not make it very

profitable. If the biomass gasifier is more expensive, the profitability of producer gas

substantially declines. It should be mentioned that certain variable costs (in OPEX) are

directly related with rules of thumb to investment cost. This increases the effect of

investment cost on the profitability.

From this section it can be concluded that without subsidies applied to the biomass, it

will not be profitable to replace a fraction of coal with biomass under the conditions

expected. In the case of a natural gas-based plant, the project can be feasible under

certain conditions of low biomass cost and high gasification capacities. The feasibility is

influenced substantially by the gas prices and the investment cost. If biomass prices stay

at the current level and natural gas and CO2 prices raise, profitability increases. As an

example the base case of a 100 MWth plant with an IRR of 10% increases to a IRR of 27%

if the investment is done in 2025 instead of 2015. For the short-term, the

implementation of incentives to the use of biomass is necessary to make biomass

gasification in DRI plants economically feasible. This is analysed with more detail in

Section 4.3.

4.3 Results: application of subsidies to the

biomass plant

In this section, the effect of the implementation of subsidies to stimulate the use of

biomass is studied. For that, in consistency with the rest of the assumptions (European

conditions), the Dutch scheme of incentives to renewable energies (SDE+ [32]) has been

applied in the economic analysis. In the base cases, a gasification capacity of 50 MWth

will be added in a DRI plant, with a biomass price of 6 USD/GJ. The resulting net present

values of case 3 (natural-gas based plant) and case 4 (coal gasification based plant) are

depicted in Figure 13 and Figure 14, respectively. As can be seen, the application of

subsidies changes case 3 dramatically, since the overall investment becomes profitable

(NPV = 35 million USD; IRR 23%12

). However, even after the application of incentives,

the replacement of coal with producer gas from biomass gasification (case 4) remains

economically unfeasible, as shown in Figure 14 under these conditions (NPV -48 mln

USD).

xxxxxxxxxxxxssssssssxxxxxxxxxxxxxx

12 This substantial increase is also related to the fact that the subsidy in intended for gasification of biomass and upgrade this gas to natural gas quality. Some upgrade steps are not necessary for using the gas in DRI plants. So, if the Dutch government would add this gas to the SDE+ scheme, they would probably lower the subsidy level.

ECN-E—16-022 33

Figure 13. Cash flows of case 3: replacement of 50 MWth with biomass gasification in a natural gas

based DRI plant (6 USD/GJ biomass cost, Dutch SDE+ subsidy applied).

Figure 14. Cash flows of case 4: replacement of 50 MWth with biomass gasification in a coal gasification

based DRI plant (6 USD/GJ biomass cost, Dutch SDE+ subsidy applied).

A sensitivity analysis has been applied in order to determine the ranges of biomass cost

and gasification capacity under which the project is profitable. The results

corresponding to case 3 are plotted in Figure 15. As can be seen, if a 50 MWth

gasification plant is built, the project is economically feasible for biomass cost below

9 USD/GJ. If the gasification capacity is increased to 100 MWth, the range of feasible

-40

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34

biomass cost is enlarged up to ~ 11 USD/GJ. This means that it would be possible to use

higher-quality biomass sources (for example, the cost of wood chips from Scandinavia

to Europe is ~ 9-10 USD/GJ, and the cost of pellets from United States to Europe is

9-11 USD/GJ [29]).

Figure 15. Effect of the biomass cost and the size of the biomass plant on the profitability of case 3

(replacement with biomass gasification in a natural gas based DRI plant, Dutch SDE+ subsidy applied).

Figure 16 shows the results of the sensitivity analysis applied to case 4 (implementation

of biomass gasification in a coal gasification based DRI plant). In this case, it can be

observed that biomass gasification only makes economic sense under conditions of very

low biomass cost and high gasification capacities, a currently unlikely combination of

factors.

Figure 16. Effect of the biomass cost and the size of the biomass plant on the profitability of case 4

(replacement with biomass gasification in a coal gasification based DRI plant, Dutch SDE+ subsidy

applied).

-50

0

50

100

150

200

250

300

350

400

2 4 6 8 10

NP

V (

mill

ion

USD

-20

15

)

Biomass cost in 2015 ($/GJ)

50

100

150

-250

-200

-150

-100

-50

0

50

100

150

2 4 6 8 10

NP

V (

mill

ion

USD

-20

15

)

Biomass cost in 2015 ($/GJ)

50

100

150

ECN-E—16-022 35

The amount of subsidy for biomass gasification has changed over time. This is related to

energy prices but also to the expected cost of biomass gasification and upgrading and

the expected size of the installation. Companies with plans for installations can ask for

the subsidy when the scheme opens. If they get the subsidy for 12 years, it is not

possible to ask the next year again subsidy for the same installation. Table 13 shows the

effect of the different tender years. As can be seen, also due to the low coal prices

(which result in higher subsidies), the 2016 scheme can make biomass gasification to

substitute coal substantially better.

Table 13: Sensitivity analysis on financial incentives (Dutch SDE+ subsidy)

Case 3 (gas) Case 4 (coal)

NPV (mln USD) IRR NPV (mln USD) IRR

SDE subsidy 2013 23 18% -61 -

SDE subsidy 2014 22 18% -62 -

SDE subsidy 2015 (base case) 35 23% -49 -

SDE subsidy 2016 67 34% -17 -

ECN-E—16-022 37

5 Conclusions

The iron and steel industry is an energy-intensive sector, and an important source of

CO2 emissions, thus the development of technologies for the decrease of overall energy

consumption and CO2 emission is necessary. Some technological options include

recovery of exhaust heat, process gas recovery, and use of non-fossil energy sources. In

this sense, the use of biomass could contribute to the shift towards a greener iron and

steel industry. However, biomass oxygen must be removed at least partially in order to

ensure the suitability of biomass as reducing agent. The removal of oxygen can be

applied to biomass via slow pyrolysis for the production of solid charcoal or by CO2 and

H2O removal from syngas produced from biomass gasification.

This report has analysed the use of producer gas from biomass gasification (in

particular, producer gas from MILENA indirect gasification) as reducing agent in DRI

processes. Direct reduction of iron (DRI) consists of the conversion of iron ore to quality

metallic iron in solid state in one step using a reducing gas. In natural gas based DRI

processes, oxygen is removed from the feed iron ore by syngas produced from natural

gas reforming. Gasification can be an interesting option in those cases where there is a

combination of expensive natural gas supply and abundant, low-cost coal or biomass

resources. The implementation of biomass gasification in DRI processes could

contribute to the shift towards a “greener” iron and steel industry. The large scale

(~400 MWth) of gasification plants required for a typical DRI plant makes it unlikely that

biomass can completely replace fossil fuel consumption in the short term, but given the

size of planned biomass- and waste gasification plants as well as the recent

developments in legislation over the need for reduction of CO2 emission, DRI could

become a feasible application for biomass and waste gasification in the medium/long

term. An alternative for the implementation of biomass and waste in the short term

might be the partial replacement of coal or natural gas by biomass, either by

implementing a dedicated biomass gasifier in a natural gas-based DRI process or by co-

gasification of (torrefied) biomass and coal in case of a coal gasification-based process.

The main quality requirements of reducing gas in DRI processes include a high ratio of

(H2 + CO)/(CO2 + H2O), as well as removal of dust and sulphur. The main advantages of

MILENA include the possibility of producing a N2-free syngas without the need for an air

separation unit, and the relatively high content of gaseous hydrocarbons in the

producer gas, which promote the carbon content in the product. The composition of

38

producer gas from biomass gasification is not in principle the most suitable for DRI

application, since it has a large concentration of CO2 and H2O. However, the excess

oxygen in the producer gas can be removed by proper gas cleaning and upgrading (dust

and tar removal, water removal, desulphurization, CO2 removal) using conventional

technologies.

An economic analysis has been performed in order to assess the profitability of biomass

gasification in DRI plants. Without subsidies, the replacement of part of the coal

consumption in a coal gasification based DRI plant is not economically feasible under

any of the conditions considered in this study. In the case of a natural gas-based DRI

plant with a 50 MWth biomass unit a positive NPV is reached at biomass cost of

4 USD/GJ or lower at the background of the current policy scenario of the World Energy

Outlook 2014. The profitability is very sensitive for energy- and CO2 prices, CAPEX and

OPEX. Because a biomass price of 4 USD/GJ is very low and there are investment risks

additional incentives are needed. If the Dutch scheme for the incentive of renewables is

implemented, biomass gasification can economically replace part of natural gas at

biomass cost below 9 USD/GJ (50 MWth gasification plant) and below 11 USD/GJ

(100 MWth gasification plant). On the contrary, biomass gasification only makes

economic sense in a coal gasification based DRI plant under specific and unlikely

conditions of low biomass cost and high gasification capacities (< 4 USD/GJ biomass

price for a 100 MWth plant). As a conclusion, biomass gasification appears currently as

an economically attractive option for the replacement of part of natural gas if subsidy

schemes can be implemented. Depending on the actual development of energy- and

CO2 prices, profitability is expected to increase in the future.

ECN-E—16-022 39

6 References

(websites last accessed on May 2016)

[1] Battle, T.; Srivastava, U.; Kopfle, J.; Hunter, R.; McClelland, J. The direct

reduction of iron. In: Treatise on process metallurgy, volume 3: Industrial

processes. Elsevier (2014), ISBN 978-0-08-096988-6 [2] Oda, J.; Akimoto, K.; Sano, F.; Tomoda, T. Diffusion of energy efficient

technologies and CO2 emission reductions in iron and steel sector. Energy

Economics 29 (2007) 868-888

[3] Ashrafian, R.; Rashidian, M.; Amiri, M.; Urazgaliyeva, G.; Khatibi, M. Direct

reduction of iron ore using natural gas. NTNU (2011) [4] Hanrot, F.; Sert, D.; Delinchant, J.; Pietruck, R.; Burgler, T.; Babich, A.;

Fernandez, M.; Alvarez, R.; Diez, M.A. CO2 mitigation for steelmaking using

charcoal and plastic wastes as reducing agents and secondary raw materials.

1st

Spanish National Conference on Advances in Materials Recycling and Eco-

Energy. Madrid, 12-13 November 2009

http://digital.csic.es/bitstream/10261/18433/1/S05_4.pdf

[5] MIDREX®. MXCOL®. Using syngas to make DRI in the MIDREX® process.

http://www.MIDREX® .com/assets/user/media/MXCOL.pdf [6] ULCOS project. http://www.ulcos.org/en/research/substainable_biomass.php

[7] Rankin, W.J. Minerals, metals and sustainability. Meeting future material

needs. CRC Press/Balkema (2011), ISBN 978-0-415-68459-0

[8] Community Research and Development Information Service. SHOCOM project.

http://cordis.europa.eu/project/rcn/80349_en.html

[9] Carvalho, M.M.O.; Cardoso, M.; Vakkilainen, E.K. Biomass gasification for

natural gas substitution in iron ore pelletizing plants. Renewable Energy 81

(2015) 566-577

[10] van der Meijden, C.M. Development of the MILENA gasification technology for

the production of bio-SNG. PhD Thesis, Eindhoven University of Technology

(2010), ISBN: 978-90-386-2363-4, https://www.ecn.nl/publications/ECN-B--10-

016 [11] World Steel Association. Fact sheet. Steel and raw materials

http://www.worldsteel.org/publications/fact-

sheets/content/00/text_files/file0/document/fact_raw%20materials_2014.pdf

40

[12] World Steel Association. Fact sheet. Energy use in the steel industry

http://www.worldsteel.org/publications/fact-

sheets/content/02/text_files/file0/document/fact_energy_2014.pdf

[13] International Iron Metallics Association. Direct Reduced Iron (DRI)

http://metallics.org.uk/dri/

[14] MIDREX®. 2013 world direct reduction statistics. http://www.MIDREX®

.com/assets/user/news/MIDREX® _World_DRI_Stats.pdf

[15] MIDREX®. The MIDREX® reformer http://www.MIDREX® .com/process-

technologies/MIDREX® -ng/the-MIDREX® -reformer

[16] MIDREX®. The MIDREX® process http://www.MIDREX®

.com/assets/user/media/MIDREX® _Process-Brochure.pdf [17] Meissner, D.C.; Sanzenbacher, C.W. Method for the direct reduction of iron

using gas from coal. US Patent no. 4,173,465 (1979).

http://www.google.com/patents/US4173465

[18] Wieslaw, T.; Hughes, G. Coal gasification-based DRI production: Start-up and

operation of JSPL’s Angul I MXCOL® DRI plant (2015)

http://digital.library.aist.org/pages/PR-368-101.htm

[19] MIDREX. JSW Steel uses COG to supplement NG for DRI production. Midrex

successfully completes first phase integration. Press release (2015)

http://www.midrex.com/assets/user/news/COG_Press_release_Midrex_revie

w_10_April_2015.pdf

[20] Gasification Technologies Council http://www.gasification.org/what-is-

gasification/world-database/aluminij-kazachstana-gasification-plant

[21] Gasification Technologies Council http://www.gasification.org/what-is-

gasification/world-database/chiba-waste-gasification

[22] Gasification Technologies Council http://www.gasification.org/what-is-

gasification/world-database/gobigas-2

[23] Gasification Technologies Council. World gasification database

http://www.gasification.org/what-is-gasification/world-database/

[24] Gasification Technologies Council http://www.gasification.org/what-is-

gasification/world-database/angul-1

[25] Gasification Technologies Council http://www.gasification.org/what-is-

gasification/world-database/barbil-gasification-plant

[26] Gasification Technologies Council http://www.gasification.org/what-is-

gasification/world-database/wenshan-fuel-gas-plant [27] Foulds, G.A.; Rigby, G.R.; Leung, W.; Falsetti, J.; Jahnke, F. Synthesis gas

production: Comparison of gasification with steam reforming for direct reduced

iron production. Studies in Surface Science and Catalysis 119 (1998) 889-894

[28] International Energy Agency. World energy outlook 2014. ISBN: 978-92-64-

20805-6, International Energy Agency, Paris, France, October 2014.

[29] International Renewable Energy Agency. Biomass for power generation (2012)

https://www.irena.org/DocumentDownloads/Publications/RE_Technologies_C

ost_Analysis-BIOMASS.pdf

[30] Intergovernmental Panel on Climate Change (IPCC). 2006 IPCC guidelines for

national greenhouse gas inventories. Volume 3, industrial processes and

product use. Chapter 4, Metal industry emissions http://www.ipcc-

nggip.iges.or.jp/public/2006gl/pdf/3_Volume3/V3_4_Ch4_Metal_Industry.pdf [31] ECN Phyllis database https://www.ecn.nl/phyllis2/Browse/Standard/ECN-

Phyllis

ECN-E—16-022 41

[32] Netherlands Enterprise Agency. SDE+ 2015. Instructions on how to apply for a

subsidy for the production of renewable energy

http://english.rvo.nl/sites/default/files/2016/03/Brochure%20SDE-

plus%202015.pdf

42

Appendix A. Sample cost

figures

A sample of the energy prices used in the financial calculation can be found in Table A1.

It is based on the energy prices from the World Energy Outlook 2014 [28]. The WEO

gives only price information for a few years. To get data for the whole period a linear

line with the best fit is drawn between available data point. The last column shows the

subsidy level, based on the Dutch SDE+ of 2015 [32]. In the calculation the first year of

production is 2016 and the subsidy last for 12 years. The economic lifetime is set on 15

years. So in the net present value calculations of chapter 4, the last 3 years are without

subsidy.

Table A1. Energy prices and SDE subsidy sample .

Gas price Coal price Biomass

price

CO2 price Subsidy

(SDE 2015)

USD/GJ USD/GJ USD/GJ USD/ton USD/GJ

2015 9.8 3.9 6.0 9.2 -

2016 10.4 4.1 6.1 11.8 8.8

2017 10.9 4.3 6.3 14.3 8.3

2018 11.5 4.5 6.4 16.8 7.9

2019 12.1 4.7 6.6 19.3 7.4

2020 12.7 4.9 6.7 21.9 6.9

2021 13.3 5.1 6.9 24.4 6.5

2022 13.9 5.4 7.0 26.9 6.0

2023 14.5 5.6 7.2 29.4 5.5

2024 15.1 5.8 7.4 31.9 5.1

2025 15.6 6.0 7.5 34.5 4.6

2026 16.2 6.2 7.7 37.0 4.1

2027 16.8 6.4 7.9 39.5 3.7

2028 17.4 6.6 8.1 42.0 3.2

2029 18.0 6.8 8.2 44.6 -

2030 18.6 7.0 8.4 47.1 -

2031 19.2 7.2 8.6 49.6 -

2032 19.8 7.4 8.8 52.1 -

2033 20.3 7.6 9.0 54.7 -

2034 20.9 7.8 9.2 57.2 -

2035 21.5 8.0 9.5 59.7 -

2036 22.1 8.2 9.7 62.2 -

2037 22.7 8.5 9.9 64.7 -

2038 23.3 8.7 10.1 67.3 -

2039 23.9 8.9 10.4 69.8 -

2040 24.5 9.1 10.6 72.3 -

A sample of the cost figures is shown in Table A2. The first seven rows show the various

items that add up to the CAPEX. The CAPEX is shown for installations of 50, 100 and 150

MWth. This shows clearly the effect of the size of the installation.

ECN-E—16-022 43

The next nine lines show the operation cost in the first year (2016). It also includes the

capital costs and the cost of the biomass. Because costs are calculated in nominal

terms, the 2017 costs of most items are higher due to the assumed 2.3% inflation.

The last rows show the revenue for the different cases in saved gas or coal cost and in

CO2 emission rights cost. If the prices of gas and coal rise faster than the inflation the

cost balance becomes better in later years. Also the cases with subsidy are shown. In

later years the subsidy level declines due to no inflation correction in the subsidy level

and raising energy prices. So in later years the difference will decline with the cases

without subsidy.

Table A2.Cost figures.

Million USD 50 MWth 100 MWth 150 MWth

Investments:

Direct costs 23.6 38.4 51.0

Indirect costs 7.5 12.1 16.1

Fixed capital investment 31.1 50.5 67.1

Working capital 3.6 5.9 7.9

Start-up costs 2.5 4.1 5.5

CAPEX 36.4 59.1 78.5

Balance of the first operation year (2016):

Raw materials: biomass 9.6 19.2 28.8

Operating labour 2.4 2.4 2.4

Maintenance and repairs 3.2 5.2 6.9

Operating materials 1.6 2.9 4.1

Utilities 1.5 3.0 4.6

Other 2.7 4.6 6.3

Capital charge (including 8% interest) 3.6 5.9 7.8

OPEX 24.6 43.2 61.0

Revenues in 2016:

Case 3 gas 19.1 38.1 57.2

Case 3 gas + subsidy 32.2 64.5 96.7

Case 4 coal 8.2 16.4 24.5

Case 4 coal + subsidy 21.4 42.7 64.1

ECN-E—16-022 44

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