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Energy Conversion and Management: X

journal homepage: www.journals.elsevier.com/energy-conversion-and-management-x

Hydrogen and hydrogen-derived fuels through methane decomposition of

natural gas – GHG emissions and costs

Sebastian Timmerberg

a,b,⁎

, Martin Kaltschmitt

, Matthias Finkbeiner

Hamburg University of Technology, Germany

Technische Universität Berlin, Germany

ARTICLE INFO

Keywords:

Hydrogen production

Methane decomposition

Pyrolysis

Blue hydrogen

ABSTRACT

Hydrogen can be produced from the decomposition of methane (also called pyrolysis). Many studies assume that

this process emits few greenhouse gas (GHG) because the reaction from methane to hydrogen yields only solid

carbon and no CO

. This paper assesses the life-cycle GHG emissions and the levelized costs for hydrogen

provision from methane decomposition in three configurations (plasma, molten metal, and thermal gas). The

results of these configurations are then compared to electrolysis and steam methane reforming (SMR) with and

without CO

capture and storage (CCS). Under the global natural gas supply chain conditions, hydrogen from

methane decomposition still causes significant GHG emissions between 43 and 97 g CO

-eq./MJ. The bandwidth

is predominately determined by the energy source providing the process heat, i.e. the lowest emissions are

caused by the plasma system using renewable electricity. This configuration shows lower GHG emissions

compared to the “classical” SMR (99 g CO

-eq./MJ) but similar emissions to the SMR with CCS (46 g CO

-eq./

MJ). However, only electrolysis powered with renewable electricity leads to very low GHG emissions (3 g CO

eq./MJ). Overall, the natural gas supply is a decisive factor in determining GHG emissions. A natural gas supply

with below-global average GHG emissions can lead to lower GHG emissions of all methane decomposition

configurations compared to SMR. Methane decomposition systems (1.6 to 2.2 €/kg H

) produce hydrogen at

costs substantially higher compared to SMR (1.0 to 1.2 €/kg) but lower than electrolyser (2.5 to 3.0 €/kg). SMR

with CCS has the lowest CO

abatement costs (24 €/t CO

-eq., other > 141 €/t CO

-eq.). Finally, fuels derived

from different hydrogen supply options are assessed. Substantially lower GHG emissions, compared to the fossil

reference (natural gas and diesel/gasoline), are only possible if hydrogen from electrolysis powered by renew-

able energy is used (>90% less). The other hydrogen pathways cause only slightly lower or even higher GHG

emissions.

1. Introduction

In the light of climate change mitigation and the resulting urge to

decrease greenhouse gas (GHG) emissions, hydrogen is seen as an im-

portant component for future energy systems because its energetic use

does not lead to direct CO

emissions. Additionally, hydrogen as an

energy carrier shows a broad range of existing and potential use cases,

e.g., within the electricity, transport, industrial, and heating sector. It

can be directly used as hydrogen or alternatively used to synthesize

hydrocarbons used as fuels similar to natural gas or diesel/gasoline,

within existing supply chains and applications [1–6].

A pre-requisite for an increased hydrogen use, in the context of

climate change mitigation efforts, is hydrogen provision with zero or at

least low GHG emissions. The most prominent technological concepts

are the hydrogen production from natural gas through steam methane

reforming (SMR) combined with CO

capture and storage (CCS) and

water electrolysis powered by electricity from renewable sources of

energy [7–10]. Thus far, both processes play only a minor role within

global hydrogen production. Only 12 large-scale CCS projects are in

progress globally [11] of which 2 are related to hydrogen [12]. Fur-

thermore, hydrogen from water electrolysis covers less than 1% of the

global hydrogen demand [1].

Another option for hydrogen production with potentially low GHG

emissions is the decomposition of methane from natural gas sometimes

referred to as pyrolysis. This process decomposes methane into its

elements hydrogen and solid carbon (CH

→ C + 2 H

). The carbon is

not combusted within this process; i.e. the GHG CO

is not produced.

Instead, the provided solid carbon can be disposed under demarcation

https://doi.org/10.1016/j.ecmx.2020.100043

Received 5 February 2020; Received in revised form 23 April 2020; Accepted 24 April 2020

⁎

Corresponding author at: Eissendorfer Str.40, 21073 Hamburg, Germany.

E-mail address: [email protected] (S. Timmerberg).

Energy Conversion and Management: X 7 (2020) 100043

Available online 04 May 2020

(http://creativecommons.org/licenses/BY-NC-ND/4.0/).

from the biosphere (i.e. GHG neutral). Alternatively, the carbon could

be used as a raw material (e.g. as carbon black [13,14]) contributing to

the short or long term atmospheric CO

inventory.

Different configurations of methane decomposition processes have

been studied and a limited number of these processes have been

brought to the market. These conversion processes show substantial

differences in the selection of energy supply, reactor layout, and used

catalyst [15,16].

The available assessments of such methane decomposition systems

do not draw a clear picture about hydrogen GHG emissions and costs

due to (e.g.) a wide range of technological parameters and different

assumptions on the energy supply chain. Parkinson et al. (2019) [7]

published a study considering steam methane reforming (SMR), coal

and biomass gasification, electrolysis, and nuclear hydrogen supply

technologies. Only limited attention is given to methane decomposition

processes by considering only a generic configuration with an overall

process efficiency of 53% related to the higher heating value (HHV).

The configuration combusts natural gas for the required process heat.

Under the assumption of a natural gas supply chain characterized by

lower than average global GHG emissions, methane decomposition is

found to produce hydrogen with GHG emissions of 6.1 kg CO

-eq./kg

being 52% lower than hydrogen from steam methane reforming

(SMR). Methane decomposition is identified as the hydrogen tech-

nology with lowest CO

abatement cost among all investigated alter-

natives.

These results are based on a preceding study investigating hydrogen

production costs and GHG emissions of a methane decomposition

system using a molten metal reactor with a catalytic active Ni-Bi alloy

[17]. Also here, methane decomposition produces hydrogen at low

costs and lower costs than the alternative steam methane reforming

(SMR) with CO

capture and storage (CCS). At a low CO

emission price

above ca. $30/t CO

, methane decomposition is found to produce hy-

drogen at an economically competitive level to steam methane re-

forming.

Parkinson et al. (2017) [18] investigate a molten metal reactor that

applies molten iron. The process heat is provided either by combustion

of natural gas, hydrogen, or the application of an electric arc [18]. As

no natural gas supply chain GHG emissions are considered here, hy-

drogen production is characterized by very low GHG emissions (0 to

3.1 kg CO

-eq./kg H

). However, the configuration of the methane

decomposition system (i.e. choice of the energy source providing the

process heat) has shown to have a strong impact on the GHG emissions.

The system using hydrogen is found to emit the lowest GHG emissions

and the process applying an electric arc has highest. Hydrogen pro-

duction costs by methane decomposition are in the same range or even

lower than from steam methane reforming. One reason is that solid

carbon (mostly carbon black) is considered to be a valuable and mar-

ketable product. However, the carbon black and a potential use (i.e. the

eventual release of the CO

into the atmosphere by increasing GHG

emissions) is not considered further.

Another configuration of a methane decomposition process is the

use of plasma reactors. One example is the Kvaerner CB&H process.

Existing literature focuses primarily on hydrogen production costs, and

life-cycle GHG emissions are not considered. However, a low climate

impact of this process is assumed due to the reaction chemistry leading

to no direct CO

emissions [16,19–23]. Low hydrogen production costs

result from methane decomposition. This is especially true if a revenue

for the produced carbon is considered. Different approaches are used to

determine the hydrogen costs in relation to the carbon black selling

price. Dagle et al. (2017) [16] compare the hydrogen production costs

to the DOE cost targets of $4/kg. A small-scale plasma methane de-

composition system is found to produce hydrogen only below the cost

target if the carbon product is sold at more than ca. $0.9/kg carbon. The

hydrogen costs of $6 to $7/kg result if the produced carbon is not sold

[14,19]. Furthermore, the impact of the production capacity is in-

vestigated and hydrogen costs between $6/kg for large-scale up to $14/

kg for small-scale systems are concluded (no revenue from the carbon

product) [22]. The carbon is partly seen as the main product and hy-

drogen only as a by-product that is (e.g.) combusted in a gas-fired

power plant [19].

Methane decomposition systems can also use gas reactors either

with or without catalysts. Zhang et al. (2018) [24] use a least cost linear

optimisation model to identify optimal reactor design parameters. The

model is applied in four scenarios defined by different assumptions

about a potential catalyst regeneration (e.g. non-oxidative regeneration

of catalyst is available) as well as the value of the carbon product

(disposal vs. selling). The provided hydrogen is subsequently used in a

fuel cell for electricity generation. If the catalyst cannot be regenerated,

electricity costs and GHG emissions are higher than the electricity

production in combined cycle power plants combusting natural gas and

applying CO

capture and storage (CCS). If catalyst regeneration is

available, methane decomposition and a combined cycle power plant

with CO

capture and storage (CCS) emit similar amounts of GHG.

However, methane decomposition leads to much higher CO

abatement

costs, e.g., due to the fuel cell. Furthermore, a heat exchange gas reactor

is assessed for methane decomposition [9,10,13,25]. Such a reactor

uses the flow of a solid bed material in the opposite direction of the gas

enabling a heat exchange between gas leaving and entering the reactor.

This concept is compared with two thermal gas reactors, one using a

catalyst and the other one not. The hydrogen is used in a gas turbine for

electricity generation. The reference is an electricity provision from a

natural gas-fired power plant. Even the best methane decomposition

configuration requires a carbon revenue of 600 to 700 €/t to reach cost

parity [9]. A different study examines various heat exchange gas reactor

systems with electrolysis as well as steam methane reforming partly

including CO

capture and storage. In a small-scale hydrogen produc-

tion scenario, methane decomposition is found to produce hydrogen at

similar costs to electrolysis and even significantly lower costs than

small-scale steam methane reforming (SMR). If the produced carbon is

used for steam gasification, hydrogen costs are 54% lower compared to

steam methane reforming and 24% lower than electrolysis [10].

The combination of methane decomposition within a gas reactor

with hydrogen processing to gasoline via methanol synthesis is eval-

uated by Machhammer et al. (2018) [26]. Hydrogen is alternatively

delivered from electrolysis powered by electricity from wind turbines or

fossil-based electricity from the grid. Hydrogen delivery from methane

decomposition is found to produce gasoline at 35 to 50% lower costs

than wind powered electrolysis, but with similar GHG emissions.

While many studies conclude positive economic effects of methane

decomposition against alternative hydrogen production pathways, no

publication exists covering the bandwidth of different methane de-

composition systems. Thus, no publication investigates the impact of

system configurations on GHG emissions as well as on costs. Only one

review study [15] is available comparing the technological status of

different methane decomposition configurations. However, no com-

parative study brings together the technological and economic as-

sumptions made in different studies. Therefore, there is not a study

comparing the different methane decomposition systems regarding

costs and GHG emissions under similar boundary conditions. This study

aims at filling this research gap. Accordingly, this assessment en-

compasses the following research questions:

- What are central differences between various methane decomposi-

tion process configurations currently under discussion?

- Which impact do these differences have regarding GHG emissions

and hydrogen production costs?

Existing studies about single methane decomposition configurations

conclude a bandwidth of GHG emissions and costs. Higher and lower

hydrogen costs as well as GHG emissions with competing technologies

are found. The performance of the different methane decomposition

system configurations is thus also compared to alternative hydrogen

S. Timmerberg, et al. Energy Conversion and Management: X 7 (2020) 100043

production technologies. The following additional questions arise:

- How does hydrogen provision from methane decomposition perform

regarding GHG emissions and costs compared to steam methane

reforming (SMR), SMR with carbon dioxide capture and storage

(CCS), and water electrolysis?

- What are the CO

abatement costs for hydrogen production and

derived fuels?

As the hydrogen production and use is discussed through a climate

change mitigation perspective, the performance of methane decom-

position systems is discussed in the context of a large-scale im-

plementation within the global energy system. The impact of this

general boundary condition is discussed in detail.

The analysis is structured as follows: first, a literature review on

considered technologies including techno-economic parameters is pre-

sented in section 2 and contains a description of three methane de-

composition technology configurations (i.e. plasma, molten metal, and

thermal gas reactor systems). Then in section 3, alternative hydrogen

production technologies (SMR and CCS, electrolysis) competing with

these methane decomposition technologies are presented. Both sections

include a discussion of selected techno-economic parameters. To pro-

vide comparable data the chemical engineering plant cost index

(CEPCI) is used to adjust economic parameters to €

2018

values.

Deviations in the literature values are discussed and a consistent

parameter set is derived for each technology. Subsequently, section 4

presents the overall methodology and system boundaries used to assess

hydrogen cost, GHG emissions, and CO

abatement costs. Then the

different supply chains considered are defined within section 5. The

results are discussed in section 6. Section 7 includes a sensitivity ana-

lysis as assumptions that show spatial differences can have a strong

impact on the results. This contains an additional analysis of the con-

sequences of the produced solid carbon being considered as a product

(i.e. carbon black). Section 8 shows costs, GHG emissions, and CO

abatement costs if the hydrogen produced by the different technologies

assessed so far is used for the production of the hydrocarbon-based fuels

methane and gasoline/diesel (i.e. substitutes for fuels based on crude oil

and/or natural gas). Finally, the most important findings are summar-

ized and discussed.

2. Methane decomposition

Methane decomposition (also called methane pyrolysis or methane

cracking) is a chemical process splitting methane, or in general hy-

drocarbons, into its elemental components hydrogen and solid carbon

(Equation (1)). The governing reaction is endothermic; the necessary

energy can come from different sources of energy.

Methane enters and hydrogen leaves this decomposition process

both in a gaseous state, whereas the produced carbon is a solid. Oxygen

is not involved at all within this process (i.e. no CO or CO

is produced).

Thus, for the product gas upgrading there is no need of an additional

CO or CO

separation. Therefore, this process is less complex than e.g.

the “classical” steam methane reforming (SMR) process [27,28]. De-

pending on the required hydrogen purity and the hydrogen conversion

rate, such processes might operate without any additional gas cleaning

or upgrading. This might be the case if the produced hydrogen is used

purely as a gas for combustion as it is realized within a plant located in

Nebraska (Table 2). If a high purity of the provided hydrogen is needed,

a subsequent separation step of hydrogen and methane is necessary.

If only hydrogen without the carbon is the desired product, the

theoretical efficiency of the process is 59% (Equation (2)). The re-

maining energy contained originally within the natural gas is stored as

carbon. In real applications the efficiency is lower, e.g. due to heat

losses. Stoichiometrically, 21 kg of solid carbon are produced per 1 GJ

of hydrogen (the higher heating value (HHV) is used as a reference

throughout this paper).

+ =CH g C s H g H kJ mol( ) ( ) 2 ( ) 74.52 /

K4 2 298

(1)

HHV H

HHV CH H

2 ( )

( ) 59%

theo

(2)

Fig. 2 shows three categories of continuous methane decomposition

systems that differ in relation to the reactor type, the use of a catalyst,

and the source of process-related energy. Most of the conceivable

combinations of reactor type, catalyst, and energy supply can be found

in the literature. The technological development status covers all stages

between advanced R&D activities to commercially available processes.

However, none of these commercially available processes produce

carbon and high purity hydrogen silumtaneously (Table 2).

2.1. Process technologies

Below the process technologies assessed here are described and

characterized in detail.

2.1.1. Plasma reactor systems

Plasma is an ionized state of a gas containing free charge carriers

(i.e. it is therefore electrically conductive) [29]. Two types of plasma

are applied for methane decomposition.

1) In a thermal plasma or a “hot” plasma the temperature is homo-

genously distributed. The chemical decomposition process of the

methane is observed within a high-temperature environment al-

lowing it to reach chemical equilibrium.

2) In a non-thermal or “cold” plasma, the electrons show a much

higher temperature than the heavier species such as neutrons and

electrons (i.e. the electrons can have temperatures of several

10,000°K whereas the complete gas is much colder (e.g. room

temperature) [29,30].

Based on these two plasma types, plasma applications for methane

decomposition are classified into cold (less than1,000 K) and hot

(>1,000 K) processes. Cold plasma processes typically show lower

conversion efficiencies compared to hot plasma processes [16]. How-

ever, cold plasma processes show a higher selectivity compared to hot

plasma processes [31]. Possible by-products of the methane decom-

position reaction include ethyne, benzene, and ethane [13,32]. Most

plasma systems operate without a catalyst [16].

Distinct advantages of plasma processes are the low inertia and the

fast start up of the system; i.e. plasma processes could most likely be

combined with a fluctuating electricity supply from renewable energy

sources of such as wind power or solar radiation. Furthermore, only

limited methane purification is needed [30,31].

Several plasma processes for methane decomposition have been

developed in recent years (Table 2). The most prominent examples are

the Kvaerner process and the process of Monolith Materials both using a

hot plasma generated through graphite coils targeting carbon black

production. In both processes, the hydrogen is only by-product

(Table 2).

2.1.2. Molten metal reactor systems

Also in molten metal reactors methane is split into hydrogen and

carbon black. Here, methane is injected at the bottom of a reactor

containing liquid metal at high temperatures and hydrogen leaves the

reactor at the top.

This concept shows two significant benefits:

1) The molten metals allow an efficient heat transfer.

2) Carbon black rises to the surface of the metal allowing for simple

carbon removal [15].

Different reactor materials such as stainless steel and quartz glass

S. Timmerberg, et al. Energy Conversion and Management: X 7 (2020) 100043

have been tested with different molten metals such as tin, lead, and

copper [33,34]. Also, the use of iron has been investigated theoretically

[18]. Experiments show that higher temperatures lead to higher hy-

drogen yields [34]. By using a catalytic active metal alloy (Ni, Bi), the

yield of hydrogen can be increased [35]. The produced carbon as-

cending to the surface of the molten metal may contain traces of the

metal potentially requiring additional cleaning steps [35]. Heating of

the metal and/or the heat transfer medium can be achieved through

burning of natural gas or hydrogen, by electricity based resistant

heating, by inductive heating, or through an electric arc.

The company Arenius developed a pilot-scale system applying

molten metal reactors for methane decomposition [16] (Table 2). Fur-

ther information is not available on other activities of molten metal

applications for methane decomposition.

2.1.3. Conventional gas reactor systems

Methane decomposition is also investigated in conventional gas reactors

such as tubular fixed-bed and fluidized-bed reactors. Additionally, processes

with and without metal and carbon-based catalysts have been assessed. But

both types of catalysts show fast deactivations as the produced carbon black

is deposited on the catalysts’ active parts [36].

Separating the carbon deposited on the catalyst surface and re-

activating the catalyst is challenging. Combusting the carbon off the

catalyst is one possibility [15,37]. Alternatively, the carbon can be used

for additional hydrogen production through gasification with water

vapour (i.e. Boudouard reaction and water–gas-shift-reaction) [10,28].

However, both concepts result in solid carbon being converted to CO

and therefore contradicting the idea of reducing the CO

emissions.

The use of a carbon-based catalyst is still in an early R&D stage.

Pilots have been utilizing metal-based catalyst or not using any catalyst

at all [15]. Universal oil products developed the Hypro process using a

fluidized-bed reactor with a Ni catalyst at 1,150 K followed by a cata-

lyst regeneration with air; i.e. only hydrogen and not carbon was pro-

duced [37] (Table 2).

2.2. Techno-economic parameters

Table 3 compiles information on configurations, energy balance,

and the cost of different methane decomposition systems segmented

into plasma, molten metal, and gas reactor systems.

•Plasma systems. Most of the identified studies assess plasma sys-

tems. Investment estimations cover a broad range, which cannot be

explained by the difference in considered cost elements because

only one source provides this information (Fig. 3). The required

electricity as well as methane demand is, in most cases, estimated

close to the theoretical minimum of 221 MJ

Methane

/kg H

•Molten metal systems. Economic parameters available for such

systems do not show a very broad range because the available

parameters come from a similar research group. Also, the bandwidth

of investments for configurations with conventional reactors is ra-

ther narrow. The given difference is most likely due to the as-

sumption of different reactor systems; i.e. low costs result from a

rather simple gas reactor compared to high cost caused by a complex

heat exchange reactor. The required energy demand depends also on

the choice of the energy source. Again, methane demand is close to

the theoretical minimum if electric heating is applied.

•Gas reactor systems. The costs of the catalyst used within these

systems are only taken into account as initial costs [9,10,24,26]; i.e.

no regular renewal of the catalyst is considered. Only one study

considers that a regeneration of the catalyst might not be available,

and thus the catalyst needs to be renewed [24]. If no regeneration is

available, a carbon catalyst leads to lower cost than the application

of a Ni-based catalyst. Still, the carbon catalyst costs alone are 4.0 €/

kg H

(assuming catalyst costs of 0.95 €/kg and an expected catalyst

demand of 0.7 kg carbon/kg catalyst [24]).

Table 1

Techno-economic parameters of considered thermal decomposition configurations derived from literature (values in brackets indicate bandwidth).

Reactor concept Catalyst Heat supply Carbon yield [kg C/kg H

] Electricity consumption [kWh/kg H

] CH

consumption [MJ/kg H

] Investment [€/(kg/h H

)] Annual O&M cost [% of Invest.]

Thermal plasma No Thermal plasma 3.0 13.9 (11.1 – 17.8) 223.0 (222.1 – 242.3) 27,750 (3,331–151,914) 3.0

Molten metal Yes CH

3.0 0.0 (-0.5 – 0.3) 272.7 (252.6–272.7) 26,934 (23,233–30,634)

Gas reactor No CH

3.0 0.0 (0–2.3) 299.0 (266.8–332.5) 19,822 (8,506–36,073)

S. Timmerberg, et al. Energy Conversion and Management: X 7 (2020) 100043

Based on the investigated concepts (Table 3), three concepts with

the following basic assumptions are further investigated:

(1) the plasma reactor applies a thermal plasma powered by electricity,

(2) the molten metal reactor shows catalytic activity and methane

combustion provides heat,

(3) the gas reactor applies a thermal decomposition (i.e. no catalyst)

and methane provides heat.

A set of techno-economic parameters are derived (Table 1) for each

of these methane decomposition systems. For all systems, a bandwidth

is included covering minimum and maximum values found in the lit-

erature. Extreme values are not considered. The available information

on the plasma systems falls out of range and a value is derived based on

the values for gas reactors as the reactor design shows similarities.

3. 3. Reference and alternative hydrogen production

The following presents hydrogen provision systems as a reference

and as an alternative for hydrogen production by the methane de-

composition discussed in section 2.

3.1. Steam methane reforming (SMR)

Steam methane reforming (SMR) is the globally dominant hydrogen

production process [1]. This process applies four basic steps:

•Contaminants such as sulphur or chloride compounds are removed.

•Methane reacts with water steam yielding carbon monoxide and

hydrogen (Equation (3)).

•The hydrogen yield is increased through the reaction between

carbon monoxide and additional water steam to carbon dioxide and

additional hydrogen (water gas shift reaction, Equation (4))

•The raw hydrogen is purified typically through pressure swing ab-

sorption (PSA).

The two chemical reaction steps show a net energy demand (en-

dothermic). It is covered through the combustion of additional methane

plus the tail gas stream leaving the pressure swing absorption (PSA)

unit containing mainly CO

, H

, and some unreacted CH

and CO.

Steam methane reforming (SMR) processes typically produce excess

steam to be used for electricity generation being in the range of the

electricity demand (i.e. zero net electricity production results)

[8,44–46].

+ + =CH (g) H O(g) CO 4 H H 206. 2 kJ/mol

4 2 2

(3)

+ + =CO H O CO H H 41. 2 kJ/mol

2 2 2

(4)

The steam methane reforming (SMR) process can be extended with

a CO

capture unit to reduce the GHG emissions. This process is char-

acterized by two distinct CO

sources: CO

production through process

chemistry and through energy supply. Thus, removing CO

can be

achieved at three locations: from the raw hydrogen entering the pres-

sure swing absorption (PSA), from the tail gas leaving the PSA, or from

the flue gas leaving the furnace. Depending on the technical config-

uration between 54 and 90% of the CO

can be captured [44,45].

The captured CO

needs to be stored in order to avoid its release

into the atmosphere. Global storage capacities are estimated between

8,000 and 55,000 Gt CO

[47]. For comparison, in 2018 about 37 Gt

were emitted globally [48]. Based on these optimistic figures even

in a 1.5 °C climate change target, global storage capacities will not be a

limiting factor in this century [49]. However, spatial distribution of

storage possibilities might be a limitation if no sufficient transport

chains are established. Pipelines or ships as technically mature options

can transport CO

to the storage. A subsequent storage of CO

is pos-

sible in geological formations such as aquifers, in unminable coal

seams, or in depleted oil and gas reservoirs. Different concepts have

been tested. Still, further experience is needed at scale. One important

aspect is a reliable monitoring of injected CO

. However, no such CO

chain has been established commercially so far, and thus no reliable

costs values are available [50].

Techno-economic parameters of large-scale steam methane re-

forming (SMR) processes are shown in Table 4. Although this process is

state of the art, the methane demand shows a considerable range. If CO

capture is applied, the average methane consumption increases by 5%.

However, also the bandwidth and the uncertainty increases.

Table 2

Commercial methane decomposition projects.

Process; company name Project development status Process / project information

CarbonSaver;Atlantic hydrogen

[38,39]

Pilot plant commissioned in 2009 in New Brunswick (Canada);

demonstration plant announced

- Production of hydrogen enriched natural gas (ca. 20%

hydrogen) and carbon black

- Thermal plasma torch reactor operating at 1 750 – 2 800 K

BASF, Lidne and Thyssen-Krupp [26] - Non-catalytic methane decomposition

- High degree of heat integration

CB&H; Kvaerner [16,19,20,31] Pilot plant commissioned in 1992 (2 000 Nm

/h H

); Demonstration

plant (7600 Nm

/h H

) built in Canada but decommissioned without

operation

- Production of carbon black and hydrogen

- Flexible feedstock; natural gas to heavy oil residues

- Graphite electrode used

GasPlas [31,40] No information on further activities of Gasplas available today - Decentralised hydrogen production for hydrogen

refuelling stations

- Microwave non-thermal plasma (microwave) operating at

atmospheric pressures and 450 – 650 K

- Up to 6 kW microwave power was tested

Monolith Materials [41,42] Pilot plant operating for 4 years until 2018;commercial plant in

Nebraska (USA) under construction (announced commissioning in 2020)

- Production of carbon black; hydrogen is by-product to be

used in coal-fired power plant

- Thermal plasma process

EGT Enterprises [16,43] Demonstration plant announced - Production of carbon black and hydrogen

- Electrically heated chemical reactor operating at 1350 –

1500 K

- Electricity production by hydrogen combustion in gas

turbine and by using the carbon in a direct carbon fuel cell

Carbotopia Pilot plant operating ,several thousand hours” between 2010 and 2011

(13 kg carbon and 4.3 kg hydrogen per day)

- Production of carbon nanotubes and hydrogen

- Fluidized bed gas reactor with metal-based catalyst

HYPRO; Universal Oil Products (UOP)

[37]

- Production of hydrogen

- Fluidized bed reactor with Ni/Al

catalyst operating at

1150 – 1450 K

- Regeneration of catalyst through combustion with air

S. Timmerberg, et al. Energy Conversion and Management: X 7 (2020) 100043

Additionally, due to the CO

capture, the overall electricity consump-

tion of the process increases but it remains of minor importance com-

pared to the demand for methane. The average investment increases by

16%, however the bandwidth and the uncertainty increases.

Table 5 shows techno-economic parameters of steam methane re-

forming (SMR) with and without carbon capture. The costs of the ne-

cessary CO

transport and storage are estimated to 10 €/t CO

[45,46,51].

3.2. Electrolysis

Water electrolysis is an electrochemical process splitting water into

hydrogen and oxygen. Direct current powers this endothermal reaction

(Equation (5)). The process does not lead to direct CO

emissions. Thus,

this option represents an alternative hydrogen production pathway

with potentially low GHG emissions.

+ =H O H 0.5 O H 285.8 kJ/mol

2 2 2

(5)

Table 3

Techno-economic parameters of different thermal decomposition configurations.

Source Reactor

concept

Catalyst Heat supply Nominal

capacity

[kg/day]

Carbon

yield [kg

C/kg H

]

Electricity

consumption

[kWh/kg H

]

Methane

consumption

[MJ/kg H

]

purification

or use case

Investment

[€/(kg/h

)]

Cost

elements in

Investment

Annual O&M

cost [% of

Investment]

Plasma processes

[19]

TP No TP 88,668 3.0 12.2 222.1 n/a 25,336 n/a 1.0%

[16] TP No TP 1,914 3.1 16.1 304.8 n/a

151,914 n/a n/a

[22] TP No TP 4,000 3.0 14.3 223.5 PSA 35,470 E, C, I 18.6%

[21] TP No TP 18,263 3.0 17.8 223.5 PSA

106,354 n/a 3.9%

[20] TP No TP 13,683 2.8 11.7 222.1 n/a

111,568 n/a 5.0%

[23] TP No TP 402,901 3.0

11.1 242.3 n/a 3,331 n/a 2.0%

Molten metal systems

[18] MM No EA 547,945 3.0 14.3 222.1 PSA 26,487 E, F 5.0%

MM Future

catalytic

molten

metal

EA 547,945 3.0

6.5 222.1 23,974

MM CH

547,945 3.0 0.0 252.6 23,233

MM H

547,945 3.7 0.0 274.3 24,386

[17] MM Ni-Bi CH

273,973 3.0 −0.5 272.7 PSA 30,634 E, I, M 2.0%

Gas reactor systems

[26] BR No EH 27,397 3.0 7.2 222.1 n/a

32,850 n/a n/a

[24]

FBR Nickel CH

253,950 3.0 2.3 332.5 PSA 13,798 E, I, P, C 4.0%

FBR Carbon 294.7 13,892

FBR No 294.7 13,892

[9] GR No CH

26,344 3.0 0.0 306.3 Product gas for

electricity

production

11,268 E, I, P 2.0%

GR No EH 22,698 3.0 17.7 224.4 8,506 2.0%

FBR Nickel Carbon 26,002 1.7 1.2 221.4 25,604 2.0%

HER No EH 19,358 3.0 19.8 228.8 12,463 2.0%

[10] HER No CH

2,158 3.5 0.0 266.8 Membrane 35,962 E,C 2.0%

HER + G No CH

2,158 0.5 0.3 155.6 26,263 2.0%

All values given in higher heating values; Abbreviations: TP: Thermal plasma, MM: Molten metal, BR: Batch reactor, FBR: Fluidized bed reactor, GR: Gas reactor,

HER: Heat exchange reactor, G: Gasification, EA: Electric arc, EH: electric resistance heating, E: Equipment, F: Factor used to come from equipment cost to

investment, no detailed information on cost elements, C: Contingency, I: Civil cost, P: Project cost such as engineering or management

a: Mean value presented, bandwidth is presented in source

b: Methane demand in study is less than theoretical limit; adjusted to minimal methane demand based on reaction equation

c: Hydrogen is used in fuel cell for electricity production, associated cost are subtracted; Case with Ni assumes that technology exists to separate carbon from Ni

Table 4

Techno-economic parameters of steam methane reforming (SMR) without and with carbon capture technology (CCS).

Nominal H

capacity [kg/

day]

CCS technology Rate of CO

captured from

total

Electricity consumption [kWh/

kg H

]

Methane consumption [MJ/kg

]

Investment [€/(kg/h

)]

SMR (without carbon capture)

[52] 1,102,032 no 0% 0.2 175.1 8,537

[53] 379,387 no 0% 0.6 215.9 12,583

[54] 503,686 no 0% 0.0 211.0 11,518

[8]

324,202 no 0% 0.4 192.4 9,415

[4] 162,101 no 0% 0.0 203.1 19,213

[7] n/a no 0% 0.0 189.0 14,780

[45] 215,856 no 0% −1.1 175.5 19,007

SMR with carbon capture

[52] 1,200,000 amine 90% 1.3 185.3 11,164

[53] 379,387 amine 90% 1.1 215.9 14,575

[54] 503,686 amine

90% 0.0 288.7 39,715

[8]

324,202 amine 56% 1.0 177.6 10,712

[45] 215,856 amine 90% 0.0 192.8 33,948

related to flue gas

process produces 37 MJ/kg H

of steam

process provides 11 MJ/kg H

of steam

S. Timmerberg, et al. Energy Conversion and Management: X 7 (2020) 100043

So far, two main electrolysis technologies are applied on a utility-

scale: the alkaline and the proton exchange membrane electrolysis.

Solid oxide electrolysers are demonstrated so far on a small-scale only.

•Alkaline electrolysis uses a water based alkaline solution (KOH or

NaOH) as an electrolyte. Alkaline systems can be operated under

transient conditions and down to partial loads between 20 and 40%

[55]. After roughly 90,000 h (7 to 12 a) of operation, the electrodes

and diaphragms need to be replaced [55,56].

•Proton exchange membrane (PEM) electrolysis uses a membrane as

an electrolyte. System efficiencies are between 47 and 86%; this is

the same order of magnitude compared to the alkaline electrolysis

technology. However, such electrolysers show a better performance

when operated based on electricity with a fluctuating behaviour.

Since the investment costs of proton exchange membrane (PEM)

electrolyser systems are substantially higher compared to alkaline sys-

tems, in the next sections only the latter are considered [55–57]. For the

respective hydrogen provision systems, the overall efficiency from

electricity to hydrogen covers a range between 74 and 77%. The costs

also cover a broad bandwidth (Table 6). For the following calculations a

stack replacement after 10 years is assumed [57] costing 50% of the

initial investment [58].

4. Methodology

The target of this paper is to compare different technologies for

hydrogen production with a focus on methane decomposition systems.

Additionally, the hydrogen production pathways are compared to the

case that the hydrogen is further processed to liquid hydrocarbon fuels

(e.g. gasoline, Diesel) and to the gaseous fuel methane (i.e. crude oil

and natural gas substitutes). Hydrogen and fuel production are eval-

uated regarding cost and GHG emissions throughout the lifetime of the

production plants. The following utilizes the current dominating pro-

duction pathways for comparison purposes.

A framework for a comprehensive comparison is set-up considering

a near-term and large-scale implementation of these processes (i.e. for a

hydrogen and fuel production in quantities relevant to the global en-

ergy industry and thus the climate) (Fig. 1). Energy supply chains are

selected accordingly and cover current global average conditions. The

electricity supply is considered in two cases that can be implemented

worldwide. Either the hydrogen production receives electricity from the

existing power grid or a separate electricity supply based on renewable

sources of energy. The energy supply reflects the status of the energy

systems regarding cost and emission related factors. Techno-economic

parameters for hydrogen production technologies and auxiliaries are

derived from the literature reflecting large-scale, state-of-the art tech-

nology (section 2 and 3). Besides an average value, a bandwidth of

techno-economic parameters of hydrogen production technologies are

assumed in order to account for technology related uncertainties. The

calculations are also conducted for the minimum and maximum values

of the bandwidth and displayed as error bars in the results.

Hydrogen production through methane decomposition produces

solid carbon as a by-product. It can potentially be sold as carbon black.

However, a large-scale hydrogen production, as considered here, sig-

nificantly exceeds the carbon black market size. Thus, no further use of

the solid carbon is considered; i.e. this carbon is disposed to avoid an

impact on global climate. Nevertheless, the impact of marketing carbon

black for hydrogen production in much smaller quantities is addressed

in an excursus. The boundary conditions can show significant regional

differences (e.g. financial parameters, natural gas supply chain emis-

sions). Resulting deviations in cost and GHG emissions are discussed

within a sensitivity analysis.

The levelized cost of hydrogen LCOH and of the subsequent pro-

vided fuel LCOF are used as estimates for hydrogen and fuel costs

(Equation (6)). They consider the costs of the production plant c

, the

costs of energy powering the hydrogen and subsequent fuel production,

and the costs for operation and maintenance c

o&m

. Costs are considered

on an annual basis and normalized by the annual production of hy-

drogen p

respectively of fuel p

. The weighted average cost of capital

WACC is used to annualize the cost of the production plant.

GHG emissions are estimated based on the carbon footprint ap-

proach [60] using global warming potentials (GWP) with a 100 year

time horizon [61]. Natural gas/methane is a major input for some of the

considered hydrogen production processes. Methane is a short-lived gas

and therefore shows a stronger radiative forcing over a shorter time-

period. Thus, the impact of a shorter time-period (20 years) on the GHG

emission estimation is considered in the sensitivity analysis (section 7).

abatement cost are derived from the levelized costs and the

GHG emission estimations by setting GHG emission reductions in re-

lation to additional cost (Equation (7)). The reference ref are currently

dominant production pathways (i.e. hydrogen produced through steam

methane reforming and fossil fuels). Table 7 summarizes variables and

indices.

+ +

LCOH or LCOF

c c

e o m

h or f

WACC n

(1 )

(6)

=CO abatementcost LCOH F LCOH F

GHG GHG

/ /

i ref

ref i

(7)

Table 5

Techno-economic parameters of considered steam methane reforming (SMR) with and without carbon capture derived from literature review (values in brackets

indicate bandwidth).

captured from total Electricity consumption [kWh/kg H

] Methane demand [MJ/kg H

] Investment [€/(kg/h H

)]

SMR (without carbon capture) 0% 0 (-1.1 – 0.6) 185.6 (175.1 – 215.9) 12,583 (8,537–19,213)

SMR with carbon capture 90% 0.9 (0 – 1.3) 194.9 (177.6–288.8) 14,573 (10,712 – 39,715)

Table 6

Techno-economic parameters of alkaline electrolysis systems (values in brackets show published bandwidth).

Electricity consumption [kWh/kg H

] Investment [€/(kg/h H

)]

[6] 51.3 (48.3–77.5) 61,063 (31,376 – 218,174)

[59] 52.6 60,765

[7] 51.4 41,217 (20,518 – 51,294)

[58] 53.6 (48.0 – 60.6) 28,127 (21,610 – 36,349)

Own assumptions 52.2 (48.0–77.5%) 47,928 (19,370 – 218,174)

S. Timmerberg, et al. Energy Conversion and Management: X 7 (2020) 100043

5. Data

The technology and energy supply chain input data that is used for

the subsequent assessments are presented below, following the defini-

tions in the methodology (section 4) about the hydrogen production

and subsequent fuel production. Table 8 gives an overview about

considered cases and input data.

Throughout the calculations, a weighted average cost of capital

(WACC) of 5% is assumed. The economic lifetime is defined to be

30 years for power and chemical plants; it is 20 years for PV systems

and wind turbines.

5.1. Electricity supply

Electricity is provided by two variants:

(1) Gas combined cycle (CC) power plants with a high capacity utili-

zation reflecting global power generation systems based on fossil

energy;

(2) Renewable sources of energy globally available (i.e. wind and solar

irradiation) without any connection to the grid.

Electricity production in gas combined cycle power plants provides

electricity with a high overall efficiency of 59%. Investments are as-

sumed to be 815 €/kW and annual non-energy related O&M costs sum

up to 19 €/(kW a) [62]. Furthermore, a capacity factor (i.e. share of

actual energy output compared to theoretical maximum output per

year) of 95% is defined.

Electricity production from renewable sources of energy is achieved

with a combined wind and photovoltaic (PV) system. Average invest-

ment are 1,025 €/kW for PV and 1,269 €/kW for wind turbines in 2018

[63]. O&M cost are estimated to be 1.5% for wind turbines and 0.5% for

PV systems related to the overall investment costs [2]. A capacity factor

of 40% for wind and 20% for PV electricity production are assumed to

being slightly above global average [63] as state of the art technology is

assumed. A combination of wind and PV technology yields a higher

capacity factor of 57% compared to the respective individual systems as

these energy sources show a small temporal overlap estimated to sum

up to 5% [64].

GHG are emitted during manufacturing, assembly, and operation of

these electricity provision systems. For onshore wind turbines, a value

of 6 g CO

-eq./kWh is assumed for electricity production [65]. GHG

emissions of electricity production from PV technologies are assumed to

Fig. 1. (Graphical abstract) System boundaries and setup as well as major assumption.

Fig. 2. Categories of methane decomposition processes.

S. Timmerberg, et al. Energy Conversion and Management: X 7 (2020) 100043

be 31 g CO

-eq./kWh being between GHG emission for mono-silicon

and cadmium telluride systems [66].

5.2. Methane supply

Natural gas is considered to be the methane source used for hy-

drogen production. Average cost for natural gas in UK, Netherlands,

Germany, US, and Canada in 2018 are used as a reference with 4.1 €/GJ

[67].

Associated GHG emissions of a global average supply chain are

comprised of CO

emissions e.g. for production, gas upgrading, and

transport to the final customer. Additionally, emissions of unburnt

methane show a significant impact due a relatively high global

warming potential with 30 g CO

-eq/(g CH

) in a 100 year and

85 gCO

-eq/(g CH

) in a 20 year perspective [61]. For this investiga-

tion, CO

emissions for the natural gas supply chain are assumed to sum

up to 17.2 gCO

/MJ

considering emissions for natural gas production,

long distance transport and distribution in a high pressure system [68].

Average methane leakage is assumed to be 1.7% as estimated for the

global natural gas supply [69].

5.3. Hydrogen production

Techno-economic parameters of hydrogen production technologies

are shown in sections 2.2 and 3. O&M costs are assumed to be 3% and

related to the overall investments unless stated differently.

GHG emissions for the manufacturing and commissioning of molten

metal reactor system are estimated to be 0.2 kg CO

-eq./kg H

[70].

Additional GHG emissions for the used molten metal are estimated to be

0.2 kg CO

-eq./kg H

, reflecting hydrogen production on an industrial

scale [70]. Similar -GHG emissions for manufacturing and commis-

sioning of the other chemical processes are assumed. Electrolyser sys-

tems show higher values of 0.4 kg CO

-eq./kg H

[71].

5.4. Fuel production based on hydrogen

Substitutes for “classical” conventional fuels can be produced based

on hydrogen and carbon carriers (i.e. CO, CO

). If these fuel substitutes

show similar fuel characteristic as conventional fuels, they can be in-

tegrated into the existing energy system without any major changes to

infrastructures, supply chains, applications, use behaviour, etc. (i.e.

drop in).

Such fuel provision processes are often discussed under the premise

that hydrogen is produced by water electrolysis (called power-to-liquid

(PtL) or power-to-gas (PtG) processes). However, different hydrogen

production routes can also be applied. Thus, two prominent fuel pro-

duction processes are investigated for the production of

(1) Synthetic methane (SNG) based on a thermo-catalytic methanation

process for substituting natural gas and

(2) Liquid hydrocarbons based on a Fischer-Tropsch (FT) process for

substituting fuels provided from crude oil.

Table 9 shows techno-economic parameters used here for the me-

thanation and Fischer-Tropsch (FT) process, if CO

is used as a carbon

source.

The CO

required as input for the fuel production costs ca. 30 €/t

reflecting CO

e.g. captured from biogas or bioethanol production

[6]. Heat integration is not considered between hydrogen production

and the subsequent fuel synthesis.

6. Results: Hydrogen production

Below, the costs, the GHG emissions, and the CO

abatement costs

are presented for the various hydrogen production cases. Table 8 pro-

vides an overview of the cases and related input parameters re-

presenting e.g. world-average natural gas supply chain conditions.

Error bars indicate uncertainties in parameters with the hydrogen

production technology.

6.1. GHG emissions

Fig. 3 shows estimated GHG emissions associated with the con-

sidered hydrogen production routes. Four levels of GHG emissions can

be distinguished.

•Highest and smallest GHG emissions are related to electrolysis. The

electricity source has a paramount impact on the GHG emissions. If

low GHG emissions are targeted, hydrogen production in the elec-

trolyser must be powered by a low GHG intensive electricity source.

If the electricity source emits 270 g CO

-eq./kWh – which is ca. 50%

lower than the world average of 520 g CO

-eq./kWh [72] – GHG

emissions levels of electrolysis hydrogen leads to similar GHG

emissions as hydrogen produced in steam methane reforming

(SMR).

•The second lowest GHG emissions arise for hydrogen produced from

methane decomposition with renewable electricity in plasma sys-

tems and steam methane reforming (SMR) including CO

capture

and storage (CCS). However, GHG emissions can be reduced by 72%

maximum compared to steam methane reforming (SMR). Thus,

Fig. 3. GHG emissions estimation of hydrogen production (grey background

indicates methane decomposition systems using natural gas as basis for process

energy; electricity from combined cycle power plants (CC) or renewable energy

(RE); methane decomposition in molten metal (MM) and thermal gas (TG)

system; steam methane reforming (SMR) without or with CO

capture and

storage (+CCS)).

Table 7

Variables and indices.

Variables Indices

Energetic efficiency theo theoretical

cCost eenergy

pAnnual production pProduction plant

WACC Weighted average cost of capital fFuel

GHG Greenhouse gas o&m Operation and maintenance

iSupply route

ref Reference technology

The central value is the mean of four European supply chains with pipelines

transport Russia (7,000 km), Middle East (4,000 km), Norway with CCS tech-

nology (1,300 km) and LNG transport [68].

S. Timmerberg, et al. Energy Conversion and Management: X 7 (2020) 100043

above 28% of the GHG emissions are still emitted and longer term

GHG reduction targets (e.g. global GHG neutrality according to the

Paris Agreement by 2050 [73]) cannot be achieved.

•GHG emissions of hydrogen from steam methane reforming (SMR)

and remaining methane decomposition system configurations are in

a range between 11 and 14 kg CO

-eq./kg H

Thus, these methane

decomposition systems show only a small benefit in GHG emission

reductions. I.e. they should not be introduced globally from a cli-

mate change perspective.

GHG emissions of hydrogen produced in plasma methane decom-

position systems and in electrolysers are substantially lower if elec-

tricity from renewable sources is used. The released GHG caused by the

respective technology is determined by the electricity source. Thus,

modifying the electricity source allows for a change to the GHG emis-

sions of these technologies still in the aftermath.

Substantial GHG emissions arise also from the overall supply chain

of the natural gas contributing up to 96% of the hydrogen related GHG

emissions. These GHG cannot be prevented through the use of methane

decomposition systems or CO

capture and storage (CCS). They can

only be reduced if the GHG emissions would be decreased throughout

the overall natural gas supply chain (section 7.1).

6.2. Production and CO

abatement cost

Fig. 4 shows the levelized production and CO

abatement costs of

hydrogen produced by the different systems. Thus, no clear pattern

exists between hydrogen costs, GHG emissions, and CO

abatement

costs.

The highest costs are related to the lowest GHG emissions of hy-

drogen (electrolysis powered with renewable energy). However, the

lowest cost of hydrogen with reduced GHG emissions is also associated

with low levels of GHG emissions (steam methane reforming (SMR)

with CO

capture and storage (CCS)). Applying CCS to SMR increase the

costs by only 20% and result with the lowest CO

abatement costs of

24 €/t CO

-eq. However, a higher uncertainty exists in the parameters

of the steam methane reforming (SMR) process with CO

capture as the

error bars indicate. Even higher hydrogen costs than in methane de-

composition systems are within the uncertainty range. Furthermore,

transport and long-term CO

storage costs of 10 €/t CO

-eq. are

considered here characterised by high uncertainties (i.e. they could be

higher than 20 €/t CO

-eq. [7]).

Systems with a substantial electricity demand (i.e. plasma methane

decomposition and electrolysis) lead to the highest hydrogen provision

costs. The total energy demand, including electricity and natural gas, of

plasma systems is similar to the other methane decomposition systems

Table 9

Techno-economic parameters of hydrogen-to-fuel processes using CO

as carbon source (based on [6]); equipment cost are related to a plant capacity of 200 MW

fuel

)

(brackets indicated bandwidth).

Fuel process Efficiency (hydrogen to fuel, HHV) Investment [€/kW

fuel

] Annual O&M cost related to investment

Catalytic methanation (natural gas substitute) 72% (66%-78%) 195 (29–293) 4%

Fischer-Tropsch (FT) fuels (crude oil substitute) 65% (56%-74%) 412 (309–721)

Fig. 4. Levelized hydrogen production cost and CO

abatement cost (reference

is steam methane reforming; grey background indicates methane decomposi-

tion systems using natural gas as basis for process energy electricity from

combined cycle power plants (CC) or renewable energy (RE); methane de-

composition in molten metal (MM) and thermal gas (TG) system; steam me-

thane reforming (SMR) without or with CO

capture and storage (+CCS)).

Table 8

Considered cases for hydrogen production and fuel production (* indicates that electricity demand is negligible and no

additional electricity supply case is considered).

S. Timmerberg, et al.

Energy Conversion and Management: X 7 (2020) 100043

and thus not attributed to the higher hydrogen costs. Electrolysis sys-

tems consume ca. 30% less energy than methane decomposition sys-

tems and roughly the same energy as steam methane reforming (SMR)

concepts. But electricity is characterized by 128 to 183% higher costs

compared to natural gas. Additionally, electricity produced from re-

newable energy shows a lower availability and thus leads to a lower

capacity factor for the hydrogen production system and thus ad-

ditionally higher costs

. Therefore, systems with a substantial elec-

tricity demand can produce hydrogen only at similar costs, if the costs

of electricity from renewable energies decrease to a level of the natural

gas prices.

The methane decomposition systems show substantial differences in

the CO

abatement costs (141 to 2,060 €/t CO

-eq.) although hydrogen

costs and GHG emissions are in a similar range. The high sensitivity of

the CO

abatement costs can partly be explained by the marginal dif-

ference in GHG emissions compared to the reference production system.

The thermal gas methane decomposition systems produce hydrogen

with only 2% lower GHG emissions than the steam methane reforming

process (SMR).

7. Sensitivity analysis: Hydrogen production

The sensitivity analysis investigates the impact of different

boundary conditions. It reflects the performance of the hydrogen pro-

duction technologies, e.g., under different regional circumstances.

7.1. GHG emissions

The GHG emissions of the natural gas supply chain have a strong

impact on the GHG emissions of the considered hydrogen production

(Fig. 6). Methane decomposition systems, and especially plasma sys-

tems powered by electricity from renewable sources of energy, show

the strongest relation because the GHG emissions from the natural gas

supply chain are the major source of the overall GHG emissions. The

effect of the supply chain is lower for steam methane reforming (SMR)

as combustion related emissions play a stronger role.

Thus, if the natural gas GHG supply chain emissions are lower than

global average conditions (base case), the GHG emissions of methane

decomposition decrease more compared to steam methane reforming

and vice versa. For example, under European supply chain conditions

(10.1 and 17.0 g CO

-eq./MJ [74]), the plasma methane decomposition

using electricity from renewables (RE) produces hydrogen with 67 to

77% lower GHG emissions than steam methane reforming. Under global

conditions the GHG emissions are only 55% lower. Thus, the strong

dependency of the natural gas supply chain has to be considered if

hydrogen is to be traded internationally. The choice of a natural gas

resource with low GHG emissions (i.e. the choice of an exporting

country) can show a strong effect on the hydrogen GHG emissions and

can outweigh the choice of hydrogen production technology.

However, the sequence of technologies remains the same in terms of

GHG emissions for a broad range of natural gas supply chain GHG

emissions. But above ca. 27 g CO

/MJ emissions from the supply chain,

methane decomposition systems using natural gas as process energy

source, could lead to higher GHG emissions than steam methane re-

forming. At very low supply chain GHG emissions, the plasma methane

decomposition powered by electricity from renewables allows very low

GHG emission levels similar to electrolysis powered by renewable

electricity. However, such low supply chain emissions occur only in a

very limited number of cases. Furthermore, current research indicates

that supply chain emissions especially caused by methane leakages are

underestimated [75,76].

Here, GHG emissions are assessed under a 100-year global warming

potential (GWP). But this assumption does not shows a higher validity

in estimating the impact on global warming than using other time

frames [61]. For example, a 20-year GWP emphasizes the short-term

effects on the climate. As methane leakages are one major share in

natural gas supply chain GHG emissions, global average supply chain

emissions increase by 65% under a 20-year GWP (Fig. 5).

7.2. Production and CO

abatement cost

Hydrogen production costs show a strong dependency on the energy

costs (Fig. 6). The energy costs make>62% of the overall costs for all

technologies. The relation is stronger if the share of energy costs is

higher. But energy costs are only one cost driver and investments can be

another. Changes in the weighted average cost of capital lead to

stronger changes in hydrogen production costs for systems showing

higher investment demand, i.e. the electrolysis option and all systems

using electricity from renewable source of energy because they are

characterized by high initial investments. Additionally, systems using

electricity from renewable sources show a higher dependency due to a

lower utilization of the system (lower capacity factor) and thus a higher

impact of investments.

7.3. Excursus: Impact of carbon black production

The methane decomposition yields solid carbon as a by-product. If

this is considered as a marketable product, it can significantly impact

cost and the GHG emissions of hydrogen production [7,9,13,16]. De-

pending on the process characteristics carbon is produced with different

structures [13]. Carbon black shows the largest global demand from

these various carbon products. Over 90% of the global carbon black

produced, so far, is used in tires and other rubber products as reinfor-

cing fill – among others – increasing the abrasion resistance of the

product [16]. The market size of carbon black today is ca. 16.4 Mt/a

[7]. The production of this amount of carbon black and solid carbon by

methane decomposition systems corresponds to a hydrogen production

of 5.5 Mt/a being 7% of the global hydrogen demand (73 Mt/a in 2018

[77]). Due to these market relations, the calculations presented above

do not consider solid carbon as marketable side product.

For an application in smaller quantities or (e.g.) for the first me-

thane decomposition systems, carbon credits and returns through

marketing of carbon black could be considered. Currently, carbon black

is mostly produced from heavy crude oil fractions processing in the

furnace black and oil-furnace process. This processes also yields hy-

drogen typically used for providing heat for the process as well as ex-

ternally [16]. The production leads to GHG emissions of 2.62 kg CO

eq./kg carbon black [78]. These production-related GHG emissions

could be avoided if carbon black from methane decomposition would

be used instead. Substantial emissions saving in the range of 8 kg CO

eq./kg hydrogen could be attributed. However, a detailed life-cycle

analysis considering the consequences of the implementation is neces-

sary in order to account e.g. for substitution effects.

Prices for carbon products range from 400 to 2,000 €/t for carbon

black itself and significantly higher prices of > 1,000,000 €/t can be

achieved for high grade special carbon products [13].Fig. 7 shows that

for a carbon black revenue between 500 and 750 €/t hydrogen by

methane decomposition systems can be produced at zero cost. This

explains why commercialisation projects target carbon black produc-

tion so far (Table 2).

It seems possible that low cost carbon from methane decomposition

systems could find new applications, such as, in construction materials,

replacing metallurgical coke in steel production, or as soil amendment

[13,14]. This means an additional demand for solid carbon that would

possibly not be created without the methane decomposition process and

thus no carbon credit would apply. Furthermore, it is necessary to

Underlying cost for electricity produced in combined cycle power plants

result to 33.6 €/MWh compared to 41.7 €/MWh from a combined PV and wind

system.

S. Timmerberg, et al. Energy Conversion and Management: X 7 (2020) 100043

investigate if this new application leads to long-term storage of the

carbon or if it would be released to the atmosphere as CO

after some

time.

8. Results: Fuel production based on hydrogen

Fig. 8 and Fig. 9 show GHG emissions and production costs of liquid

fuel (e.g. gasoline, Diesel, kerosene) and methane each derived from

hydrogen. The sizes of the bubbles represent the standard deviation (i.e.

they indicate uncertainties in the techno-economic assumptions). The

synthesized liquid and gaseous fuels are compared against the proper-

ties of conventional fuels. For liquid fuels well-to-wheels GHG emis-

sions of 89 g CO

-eq./MJ

HHV

(94.1 g CO

-eq./MJ

LHV

according to EU

Fuel Quality Directive) and a crude oil price of 10 €/GJ (2018, [67]) are

considered. The same assumptions from section 5.2 for natural gas are

applied.

Only three hydrogen supply routes lead to synthesized liquid or

gaseous fuels associated with lower GHG emission than the fossil re-

ference. And, only hydrogen from electrolysis powered by electricity

from renewables leads to substantially lower GHG emissions (-94%).

Plasma methane decomposition powered with renewable energy and

steam methane reforming (SMR), including CO

capture and storage

(CCS), achieve only 16 to 25% lower GHG emissions than the fossil

reference. The remaining hydrogen supply routes lead to even higher

GHG emissions. Thus, only electrolysis powered with electricity from

wind and/or solar energy allows the synthesizing of fuel that can be

applied to meet the given long-term global warming mitigation goals.

Fuel synthesis based on plasma methane decomposition leads to

similar GHG emissions, but higher costs than steam methane reforming

(SMR) with CO

capture and storage (CCS). Thus, methane decom-

position systems do not show a benefit under global circumstances. The

abatement costs of fuel synthesis based on electrolysis with re-

newable energy and on steam methane reforming (SMR), including CO

capture and storage (CCS), are similar for liquid fuels (457 and 485 €/t

-eq.). Thus, higher GHG emission reductions through the electro-

lyser system compensates for higher hydrogen costs. For methane

synthesis, the lower GHG emission using electrolysis outweigh the

higher costs compared to SMR with CCS. CO

abatement costs of 508 €/

t CO

-eq. result if electrolysis produces hydrogen compared to 916 €/t

-eq. for SMR with CCS.

Fig. 5. GHG emissions of hydrogen production vs. natural gas supply GHG

emissions (grey area indicates bandwidth of methane decomposition systems

using natural gas a process energy; global warming potential (GWP, 100 year is

default); electricity from combined cycle power plants (CC) or renewable en-

ergy (RE); methane decomposition in molten metal (MM) and thermal gas (TG)

system; steam methane reforming (SMR) without or with CO

capture and

storage (+CCS)).

Fig. 6. Sensitivity analysis regarding changes in the economic boundary conditions (electricity from combined cycle power plants (CC) or renewable energy (RE);

methane decomposition in molten metal (MM) and thermal gas (TG) system; electrolysis (EL); steam methane reforming (SMR) without or with CO

capture and

storage (+CCS)).

Fig. 7. Hydrogen production cost as function of solid carbon revenue.

S. Timmerberg, et al. Energy Conversion and Management: X 7 (2020) 100043

9. Final considerations

Hydrogen can be produced through methane decomposition

yielding hydrogen and solid carbon. Different technological approaches

exist and three process configurations are assessed here (plasma,

molten metal, and a thermal gas reactor system) regarding life-cycle

GHG emissions and the levelized hydrogen production costs. These

systems are compared to electrolysis and steam methane reforming

(SMR) with and without CO

capture and storage (CCS).

The assumptions about the supply chain GHG emissions determine

the absolute performance of the methane decomposition configura-

tions, because the supply chain emissions account for>65% of the

hydrogen related GHG emissions under global average supply chain

conditions. However, the relative performance of methane decom-

position systems is robust and the GHG emissions for providing the

process energy are the key factor. Accordingly, plasma-based methane

decomposition systems using electricity from renewable sources (i.e.

the process energy is provided with (very) low GHG emissions produce

hydrogen with significantly lower GHG emissions than the other me-

thane decomposition configurations. Combusting natural gas for pro-

viding the process heat, as in the molten metal and thermal gas con-

figurations, releases relative higher GHG emissions due to the natural

gas supply chain and additionally through combustion. Furthermore,

these configurations show a higher heat demand compared to the

plasma system. Under the global average natural gas supply chain

conditions, the GHG emissions caused by the plasma systems are 45 to

55% lower.

The GHG emissions of the process heat for the methane decom-

position systems also determine the GHG emission performance com-

pared to electrolysis and steam methane reforming (SMR). However,

the supply chain emissions affect the GHG emissions of the different

hydrogen production pathways to varying degrees. Therefore, the

boundary conditions can change the relative performance. Under global

average natural gas supply chain GHG emissions, systems producing

heat by combustion of natural gas produce hydrogen with similar GHG

emissions as the “classical” steam methane reforming (SMR). Under

these boundary conditions, they are not a viable alternative hydrogen

production technology from a climate protection perspective. Still, the

plasma-based methane decomposition system using renewable elec-

tricity emit similar low GHG compared to steam methane reforming

with CO

capture and storage. The situation changes if lower than

global average GHG supply chain emissions are assumed. For example,

in a European gas supply, the methane decomposition configurations

using fossil energies for the process heat can produce hydrogen with 20

to 45% lower GHG emissions than steam methane reforming (SMR).

More realistic estimations of GHG emissions are potentially made

when considering higher GHG supply chain emissions. Latest research

indicates that global GHG emissions (i.e. emissions of unburnt me-

thane) released throughout the overall provision of natural gas are

underestimated [76]. Real methane emissions of the oil and gas in-

dustry exceed estimated emissions by 60% in the US [75]. Furthermore,

natural gas from unconventional sources (such as shale gas) is likely to

lead to substantially higher emissions [79]. Furthermore, it seems un-

likely that supply chain emissions decrease substantially because

powerful mechanisms are not in place aiming at the reduction of the

supply chain emissions specifically.

Only hydrogen production by electrolysis powered by electricity

from renewable energy sources is independent of the natural gas supply

chain and leads to (very) low overall GHG emissions. Furthermore, this

is the only hydrogen production route that allows for the synthesizing

of fuels (methane or gasoline / diesel / kerosene equivalents) with low

GHG emission levels. The other hydrogen production routes lead to life-

cycle GHG emissions similar or even higher than the fossil energy

carriers (i.e. the current situation).

The hydrogen production costs are reversely affected by the energy

source used to provide the process heat of methane decomposition

systems. The plasma methane decomposition process produces hy-

drogen at higher costs than the methane decomposition systems that

combust natural gas. However, under global average supply chain

conditions, the lower GHG emissions outweigh higher costs so that the

plasma-based system using renewable electricity produce hydrogen

with lower CO

abatement costs (141 €/t CO

-eq.). However, steam

methane reforming with CO

capture and storage produce hydrogen at

similar GHG emissions levels as the plasma system, but the costs are

significantly lower and so are the CO

abatement costs.

Under the given assumption of a global natural gas supply chain, the

methane decomposition systems do not show cost or GHG emission

benefits. However, receiving a revenue for the produced carbon could

change the hydrogen production costs significantly. Already at mod-

erate carbon prices, the hydrogen production costs can be very low. As

the current market size of carbon black is too small for large scale ap-

plication of methane decomposition processes for hydrogen production

(7% of global hydrogen demand), a small-scale application of this

process is conceivable.

10. Funding and acknowledgements

The authors would like to thank the Hamburg University of

Technology (TUHH) for carrying out this research based on the pro-

vided base funds.

Fig. 8. GHG emissions and cost of liquid fuel production through Fischer-

Tropsch process depending on hydrogen production route (EL: electrolysis,

methane decomposition with MM: molten metal and TG: thermal gas reactor,

SMR: steam methane reforming, CCS: CO

capture and storage).

Fig. 9. GHG emissions and cost of methane production through catalytic me-

thanation process depending on hydrogen production route (EL: electrolysis,

methane decomposition with MM: molten metal and TG: thermal gas reactor,

SMR: steam methane reforming, CCS: CO

capture and storage).

S. Timmerberg, et al. Energy Conversion and Management: X 7 (2020) 100043

CRediT authorship contribution statement

Sebastian Timmerberg: Conceptualization, Methodology, -

Investigation, Writing - original draft, Writing - review & editing.

Martin Kaltschmitt: Resources, Funding acquisition, Writing - review

& editing. Matthias Finkbeiner: Supervision.

Declaration of Competing Interest

The authors declare that they have no known competing financial

interests or personal relationships that could have appeared to influ-

ence the work reported in this paper.

Acknowledgements

The authors would like to thank Madeline Waters for her thorough

proof reading.

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