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Citation: Full, J.; Hohmann, S.; Ziehn,
S.; Gamero, E.; Schließ, T.; Schmid,
H.-P.; Miehe, R.; Sauer, A.
Perspectives of Biogas Plants as
BECCS Facilities: A Comparative
Analysis of Biomethane vs.
Biohydrogen Production with
Carbon Capture and Storage or Use
(CCS/CCU). Energies 2023,16, 5066.
https://doi.org/10.3390/
en16135066
Academic Editors: Hamidreza
Gohari Darabkhani and
Abdel-Hamid Soliman
Received: 7 June 2023
Revised: 22 June 2023
Accepted: 28 June 2023
Published: 30 June 2023
Copyright: © 2023 by the authors.
Licensee MDPI, Basel, Switzerland.
This article is an open access article
distributed under the terms and
conditions of the Creative Commons
Attribution (CC BY) license (https://
creativecommons.org/licenses/by/
4.0/).
energies
Article
Perspectives of Biogas Plants as BECCS Facilities: A Comparative
Analysis of Biomethane vs. Biohydrogen Production
with Carbon Capture and Storage or Use (CCS/CCU)
Johannes Full 1, 2, * , Silja Hohmann 1,2, Sonja Ziehn 1, Edgar Gamero 1,2, Tobias Schließ 1, Hans-Peter Schmid 3,
Robert Miehe 1,4 and Alexander Sauer 1,2
1Fraunhofer Institute for Manufacturing Engineering and Automation IPA, Nobelstraße 12,
70569 Stuttgart, Germany
2Institute for Energy Efficiency in Production (EEP), University of Stuttgart, Nobelstraße 12,
70569 Stuttgart, Germany
3WS Reformer GmbH, Allmandring 35, Dornierstraße 14, 71272 Renningen, Germany
4Institute of Industrial Manufacturing and Management (IFF), University of Stuttgart, Allmandring 35,
70569 Stuttgart, Germany
*Correspondence: johannes.full@ipa.fraunhofer.de
Abstract:
The transition to a carbon-neutral economy requires innovative solutions that reduce
greenhouse gas emissions (GHG) and promote sustainable energy production. Additionally, carbon
dioxide removal technologies are urgently needed. The production of biomethane or biohydrogen
with carbon dioxide capture and storage are two promising BECCS approaches to achieve these goals.
In this study, we compare the advantages and disadvantages of these two approaches regarding their
technical, economic, and environmental performance. Our analysis shows that while both approaches
have the potential to reduce GHG emissions and increase energy security, the hydrogen-production
approach has several advantages, including up to five times higher carbon dioxide removal potential.
However, the hydrogen bioenergy with carbon capture and storage (HyBECCS) approach also faces
some challenges, such as higher capital costs, the need for additional infrastructure, and lower energy
efficiency. Our results give valuable insights into the trade-offs between these two approaches. They
can inform decision-makers regarding the most suitable method for reducing GHG emissions and
provide renewable energy in different settings.
Keywords:
HyBECCS; hydrogen; BECCS; biogas; biohydrogen; biomethane; CDR; NET;
carbon-negative hydrogen; steam methane reforming; SMR
1. Introduction
The urgent need to mitigate climate change has led to the development of innovative
technologies that can reduce greenhouse gas (GHG) emissions and promote sustainable
energy production. Additionally, negative emission technologies (NETs), also known as
carbon dioxide removal (CDR) technologies, are crucial for limiting human-induced global
warming to less than 2 ◦C above pre-industrial times [1,2].
Biogas, a renewable energy source produced by the anaerobic digestion of organic
waste, has emerged as a promising alternative to fossil fuels [
3
]. During the process of
biogas production, microorganisms break down organic matter in an oxygen-free environ-
ment. The result is a gas mixture that is mainly composed of methane (CH
4
) and carbon
dioxide (CO
2
) [
4
]. The CH
4
contained in biogas can be purified and is then referred to as
biomethane [
5
]. Once the biogas has been purified to methane, it can be used in various
ways, e.g., as a fuel for transportation or for industrial applications. It can also be injected
into and transported through the natural gas grid. In biomethane production with carbon
dioxide capture and storage (CCS), the biogenic CO
2
released during the anaerobic diges-
tion is captured and permanently stored. However, biomethane is a greenhouse gas itself
Energies 2023,16, 5066. https://doi.org/10.3390/en16135066 https://www.mdpi.com/journal/energies
Energies 2023,16, 5066 2 of 16
when emitted into the atmosphere, and its use in combustion engines or combined heat
and power (CHP) units results in CO2emissions.
Alternatively, biogas can be processed by steam reforming to produce hydrogen
(H
2
) [
6
,
7
]. H
2
can also be used as a fuel for transportation or injected into the natural gas
grid [
8
,
9
]. An advantage of H
2
over biomethane is that it can be used decentrally without
emitting CO
2
or other greenhouse gases, as it is a carbon-free energy carrier. Furthermore,
during the steam-methane reforming (SMR) process, in addition to the CO
2
in the biogas,
biogenic CO
2
is generated as a product and can be captured and stored. This leads to a
higher CO
2
removal potential compared to biomethane production with CCS. However,
energy losses resulting from the conversion processes must be considered. Technologies
that combine biohydrogen production with CCS are referred to as Hydrogen Bioenergy
with Carbon dioxide Capture and Storage (HyBECCS) approaches [10].
Biogas reforming for hydrogen production is a promising area of research and de-
velopment. Significant progress has been made in the efficiency and scalability of the
technology [
11
–
13
]. Furthermore, several companies and research institutions are actively
engaged in advancing biogas reforming processes, optimizing catalysts, improving reaction
kinetics, and exploring their integration with CCS technologies. Some examples include the
Canadian company Xebec Adsorption [
14
], the French Air Liquide [
15
], and WS Reformer
in Germany [
16
]. Similarly, pilot projects and demonstration plants are being developed, in-
dicating a growing interest in harnessing the potential of biogas reforming as a sustainable
pathway for hydrogen production (see for example [17–19]).
For CO
2
storage, there are several options. One common method is injecting the CO
2
into underground geological formations, such as depleted oil and gas reservoirs, saline
aquifers, or coal seams [
2
,
20
]. Furthermore, there are also several options for the long-term
use of captured carbon dioxide (CCU) [
21
]. One example for CCU is the production of
building materials, such as cement, concrete, and mortar, which can help reduce greenhouse
gas emissions by replacing GHG-intensive materials in the building sector. As the captured
and stored CO2is from biogenic sources, its storage or long-term use can lead to negative
emissions, and the process can be considered a CDR approach or NET [22,23].
This paper compares biomethane production from biogas with CCS with biohydrogen
production from biogas with CCS. The analysis considers the technical, economic, and
environmental aspects of each approach. The aim is to provide insights into the trade-offs to
be considered in terms of energy efficiency, their potential for negative emission generation
and economic potentials. First, a general energy efficiency analysis is presented. For this, a
use case is defined that involves the use of biomethane or hydrogen as a fuel in heavy-duty
vehicles. Next, the negative emission potential (NEP) for each process option is calculated
and compared. Finally, a discussion about the associated costs and profitability of both
processes is presented.
2. Basics
2.1. Biomethane Production through Biogas Purification
Biogas is produced through the anaerobic digestion of organic waste [
3
,
24
]. It consists
mainly of methane (CH
4
) and carbon dioxide (CO
2
). Typically, the amount of CH
4
in biogas
is between 55 vol% and 70 vol% [
4
]. Other gaseous components like hydrogen sulfide
(H
2
S), hydrogen (H
2
), and nitrogen (N
2
) can be present in small quantities. Biogas can
be purified to biomethane using various technologies such as pressure swing adsorption
(PSA), membrane separation, or cryogenic distillation [
5
,
25
]. The purification process
removes CO
2
and impurities such as water and trace gases to increase the CH
4
content
of the gas [
26
]. In terms of physical properties, biomethane and methane are identical, as
they are the same substance. The different name only refers to their origin and production
process. While “methane” refers to any type of methane, including methane derived from
fossil resources, biomethane specifically designates methane obtained from biogas [27].
Energies 2023,16, 5066 3 of 16
2.2. Biohydrogen Production through Biogas Steam Reforming
Biogas steam reforming is a process used to produce H
2
from biogas. The process
involves the conversion of CH
4
into gaseous H
2
and CO
2
through a reaction with steam
and the parallel occurring carbon monoxide (CO) shift. According to Rostrup-Nielsen and
Christiansen, the process is described by the following two reactions [28]:
n CO2+ CH4+ H2O(g) ↔3 H2+CO+nCO2;∆H = +206.15 kJ/mol (1)
CO + H2O(g) ↔H2+ CO2;∆H = −41.2 kJ/mol (2)
where n describes the molar ratio of CO
2
to CH
4
in the feed gas. This ratio is between
0.43 and 0.82, as the molar amount of CH
4
is between 55% and 70% for typical bio-
gas plants, assuming ideal gas conditions [
4
]. Assuming the complete conversion of
the C feedstock into CO
2
, the overall stoichiometric reaction, obtained by combining
Equations (1) and (2), is [29]
n CO2+ CH4+2H2O(g) ↔4 H2+ (n + 1) CO2;∆H = + 164.95 kJ/mol (3)
2.3. Carbon Dioxide Removal
NETs are essential to counterbalance exceedingly high GHG emissions and to limit
global warming to 2
◦
C above pre-industrial levels [
1
]. NETs consist in removing CO
2
from
the atmosphere and storing it for long periods, effectively reducing the overall concentration
of CO
2
in the atmosphere. Negative emissions correspond to the amount of removed and
stored CO
2
that exceeds the GHG emissions caused during the entire process of generating
such carbon removals. This means that these GHG emissions must be deducted from the
stored CO
2
to quantify the amount of negative emissions [
30
]. For process comparisons
based on similar technologies, the maximum possible negative emissions can be estimated.
For this purpose, all GHG emissions are neglected, and only the maximum captured
amount of biogenic (or atmospheric) CO
2
is considered. This is a comparative value
referred to as negative emission potential (NEP) [23].
CDR involves the capture and storage of atmospheric CO
2
from direct air carbon
capture approaches (DACCS, direct air carbon capture and storage) and of biogenic CO
2
,
e.g., from the energetic use of biogenic waste (BECCS, bioenergy with carbon capture and
storage). The most common method of CO
2
storage is geological storage, which involves
injecting CO
2
into deep geological formations such as depleted oil and gas reservoirs,
saline aquifers, and unmineable coal seams [
2
,
31
]. Another option for CO
2
storage is
mineralization, which involves the reaction of CO
2
with naturally occurring minerals to
form stable carbonates [
32
]. This process can occur naturally over long periods. However,
it can be accelerated through various methods like mineral carbonation. This involves the
reaction of CO
2
with magnesium and calcium silicate minerals to form stable carbonates.
In addition to the permanent storage for CO
2
, some carbon capture and utilization (CCU)
approaches can be considered CDR, as long as the utilized carbon is durably stored in
the respective product. Examples are the production of long-term materials like high-tech
plastics or construction materials [33,34].
2.4. The HyBECCS Concept
HyBECCS is an umbrella term for processes in which H
2
is produced from biogenic
residual and waste materials and the resulting CO
2
is captured and permanently stored.
It can also be seen as a subsidiary branch of bioenergy with carbon capture and storage
(BECCS) with the particularity that H
2
is produced as an energy source. The technical
approach can be split into four basic process steps: 1. substrate biomass pretreatment,
2. the production of biohydrogen and biogenic CO
2
, 3. the separation of the product gases
CO
2
and H
2
, and 4. their processing for the use of H
2
and long-term storage or the use of
biogenic CO
2
, including the permanent CO
2
storage or use itself [
10
]. For each of the four
Energies 2023,16, 5066 4 of 16
steps, there are different technology options. A main technological advantage of BECCS
and HyBECCS approaches is the energy-efficient capture of biogenic CO
2
as it generally
occurs as a point source. It provides a double effect on climate mitigation by providing
GHG-free energy and the storage of biogenic CO
2
with the potential to provide negative
emissions. The basic requirements are, however, the deduction of all GHG emissions
occurring over the entire process chain to determine the amount of negative emissions,
economic viability, and a reliable long-term CO
2
storage [
30
]. Considering biogas plants,
there are several possibilities to retrofit existing plants to HyBECCS facilities [
35
]. The
technical approach considered in this work combines biogas-steam reforming with CCS, as
described in the following section.
3. Process Descriptions and Main Assumptions
This section defines and describes the two process options to be compared in this
work: biomethane production with CCS (process option 1) and biohydrogen production
through biogas-steam reforming with CCS (process option 2). The various stages of each
process option with a focus on the differences are described and the main assumptions for
their comparison are outlined.
An overview of the two process options is provided in Figure 1. The first stage of both
process options involves the preparation of the feedstock, followed by biogas production
through the anaerobic digestion of organic waste in large vessels that provide an oxygen-
free environment for microorganisms to break down the organic matter [
3
]. Different types
of organic waste can be used, including agricultural waste, food waste, and sewage [
36
,
37
].
Energies 2023, 16, x FOR PEER REVIEW 4 of 17
2.4. The HyBECCS Concept
HyBECCS is an umbrella term for processes in which H2 is produced from biogenic
residual and waste materials and the resulting CO2 is captured and permanently stored.
It can also be seen as a subsidiary branch of bioenergy with carbon capture and storage
(BECCS) with the particularity that H2 is produced as an energy source. The technical ap-
proach can be split into four basic process steps: 1. substrate biomass pretreatment, 2. the
production of biohydrogen and biogenic CO2, 3. the separation of the product gases CO2
and H2, and 4. their processing for the use of H2 and long-term storage or the use of bio-
genic CO2, including the permanent CO2 storage or use itself [10]. For each of the four
steps, there are dierent technology options. A main technological advantage of BECCS
and HyBECCS approaches is the energy-ecient capture of biogenic CO2 as it generally
occurs as a point source. It provides a double eect on climate mitigation by providing
GHG-free energy and the storage of biogenic CO2 with the potential to provide negative
emissions. The basic requirements are, however, the deduction of all GHG emissions oc-
curring over the entire process chain to determine the amount of negative emissions, eco-
nomic viability, and a reliable long-term CO2 storage [30]. Considering biogas plants, there
are several possibilities to retrot existing plants to HyBECCS facilities [35]. The technical
approach considered in this work combines biogas-steam reforming with CCS, as de-
scribed in the following section.
3. Process Descriptions and Main Assumptions
This section denes and describes the two process options to be compared in this
work: biomethane production with CCS (process option 1) and biohydrogen production
through biogas-steam reforming with CCS (process option 2). The various stages of each
process option with a focus on the dierences are described and the main assumptions for
their comparison are outlined.
An overview of the two process options is provided in Figure 1. The rst stage of
both process options involves the preparation of the feedstock, followed by biogas pro-
duction through the anaerobic digestion of organic waste in large vessels that provide an
oxygen-free environment for microorganisms to break down the organic maer [3]. Dif-
ferent types of organic waste can be used, including agricultural waste, food waste, and
sewage [36,37].
Figure 1. Process options and system boundaries (A and B) for biogas usage (own representation).
Figure 1. Process options and system boundaries (A and B) for biogas usage (own representation).
In process option 1, the second stage is separating the CH
4
from the other gas compo-
nents in the biogas. This is typically performed by PSA that uses adsorbent materials to
selectively adsorb CO
2
and impurities, leaving behind purified biomethane, as described in
Section 2.1 [
25
,
27
,
38
]. Alternatively, membrane separation or water scrubbing can be used.
For process option 2, the biogas is fed into a steam reforming process, as described
in Section 2.2. The resultant gas mixture is subjected to further treatment, including a
water-gas shift to increase the H
2
and CO
2
concentration, and gas separation through PSA
Energies 2023,16, 5066 5 of 16
to gain the product fractions CO
2
and H
2
. Relevant reaction equations for this process
option are derived below.
The next step for both process options is CO
2
capture and storage. In process option 1,
the biogenic CO
2
from the biogas supply is captured after the separation of the biomethane.
In process option 2, biogenic CO
2
is present in the biogas fuel and feed and enriched
during biogas burning, reforming and CO-shift steps. After the H
2
separation, the tail gas
is redirected to the burner to be oxidized, resulting in further CO
2
. The aggregated CO
2
can be captured from a single exhaust gas stream. The essential difference between the
two process options is that in process option 1, only the CO
2
present in the biogas can be
captured. Part of the carbon content of the original biomass is bound in the CH
4
and is
released during the decentralized use of the methane. In contrast, in process option 2, the
entire carbon content of the biogas is released during the SMR step and can be captured
from the “Exhaust Gas” stream (cf. Figure 2) as CO2.
Energies 2023, 16, x FOR PEER REVIEW 6 of 17
3.3 kg CO2 + 2.0 kg CH4 + 4.5 kg H2O(g) ↔ 1 kg H2 + 8.8 kg CO2; ∆H = +5.73 kWh/kgH2
(4)
This reaction is endothermic and, thus, energy must be provided to drive the reaction
towards H2 and CO2 production Typically, this energy is supplied in the form of heat,
generated by the oxidation of a part of the biogas and of the tail gas after H2 separation.
Figure 2 shows the schematic structure of the SMR process with the respective material
and energy ows.
Figure 2. Flow diagram of the steam methane reforming process step within process option 2 (own
representation).
As depicted in Figure 2, the ∆H in reaction (3) representing the endothermic heat of
the reaction has to be provided by the burner being part of the SMR unit. Additionally,
there is heat demand for steam generation and preheating the feedstock to typical opera-
tion temperatures in the reformer of around 800 °C, as well as for compensating wall heat
losses and latent heat of the products. The total heat energy supplied amounts to approx.
25 kWh per kg of H2 produced. This value is based on empirical data from existing biogas
SMR units and is taken as an assumption in this paper. The combustion of biogas with air
is described by the following equation:
n CO2 + CH4 + 2 (O2 + m N2) → 2 H2O(g) + (n + 1) CO2 + m N2; ∆H = −802.25 kJ/mol
(5)
where n describes the molar ratio of CO2 to CH4 in the feed gas and m describes the ratio
of N2 to O2 in air. Usually air contains around 79 vol% N2 and 21 vol% O2 [45]. By convert-
ing the units and referring to 1 kg CH4, Equation (5) can be rewrien as follows:
1.65 kg CO2 + 1 kg CH4 + 4 kg O2 + 13.17 kg N2 ↔ 2.25 kg H2O + 4.4 kg CO2 + 13.17 kg N2
(6)
It can be seen that 62.5% of the CO2 in the exhaust gas originates from the combustion
of methane, while 37.5% comes from the biogas.
Summing up, the two process options consist of several identical process steps but
also show some dierences: The preparation of the feedstock, the biogas production in
the biogas plant and the product gas treatment are identical for both processes. To com-
pare both processes from an ecological point of view, these identical process steps can be
excluded from the comparison according to the so-called “black-box” approach [46,47].
Also, for the economic comparison, identical plant components can be neglected.
The main dierences between the two process options are: (i) The additional biogas
SMR step in process option 2. (ii) The higher amount of captured CO2 leading to more CO2
to be compressed, transported, and stored in process option 2. Both (i) and (ii) increase
the investment and operational costs of process option 2. (iii) The dierent products with
their respective technology options for heavy-duty transportation: biomethane and bio-
genic CO2 in process option 1 versus biohydrogen and more biogenic CO2 in process op-
tion 2. Further dierences are the technological and cost dierences between H2 and bio-
methane in compression and transportation.
Figure 2.
Flow diagram of the steam methane reforming process step within process option 2
(own representation).
After its separation, the CO
2
is compressed for transportation either via pipelines or in
containers by truck. Storage sites are often located offshore, which may require additional
transport by ship. Which option is more economically and environmentally viable must
be decided for each case specifically. Transport over short distances can be carried out by
truck and ship, while transport via pipeline involves higher expenditures, but becomes
viable in the long term if CO
2
is transported over long distances and when the amounts of
CO
2
transported are higher [
39
,
40
]. Finally, the CO
2
is stored to prevent its emission into
the atmosphere, e.g., in geological formations, such as depleted oil and gas reservoirs or
saline aquifers [2].
It is assumed that the use of both chemical energy carriers H
2
and CH
4
provided in
process options 1 and 2 is decentralized and that no carbon capture occurs during their use.
For example, vehicles can be fueled, or heat can be supplied. Two cases are defined for
exemplification: Case A (see system boundary A in Figure 1) compares the biomethane
from process option 1 to the biohydrogen produced via process option 2 in terms of their
chemical energy content as secondary energy carriers, expressed by the lower heating value
(LHV). As depicted in Figure 1, the system boundaries for case A range from the biomass
supply to the biomethane and H2production.
Case B (see system boundary B in Figure 1) compares the useful energy genera-
tion potentials of both process options for heavy-duty transport applications. In process
option 1
, the useful energy from biomethane is generated by bio-liquefied natural gas
(LNG) combustion engines. In process
option 2
, the energy from H
2
is generated with fuel
cell power trains. Hence, the system boundary B is set from the biomass supply to the
use of biomethane and H
2
, respectively, for heavy-duty transportation (system boundary
B in Figure 1). Burning liquefied biomethane in gas engines can reach efficiencies up to
44% [
41
]. State-of-the-art fuel cell systems for electric truck powertrains peak at efficiencies
Energies 2023,16, 5066 6 of 16
of 63% [
42
–
44
]. In the following, with regard to further technological development and
optimization, high efficiencies of 44% (for bio LNG engines) and 63% (for H
2
fuel cell
engines) are assumed for both process options.
Relevant reaction equations for Process option 2 are derived in the following: An
average biogas composition of 37.5 vol% CO
2
and 62.5 vol% CH
4
is assumed [
4
]. By
converting the units and referring to the product of 1 kg H
2
, reaction Equation (3) can be
written as follows:
3.3 kg CO2+ 2.0 kg CH4+ 4.5 kg H2O(g) ↔1 kg H2+ 8.8 kg CO2;∆H = +5.73 kWh/kgH2(4)
This reaction is endothermic and, thus, energy must be provided to drive the reaction
towards H
2
and CO
2
production Typically, this energy is supplied in the form of heat,
generated by the oxidation of a part of the biogas and of the tail gas after H
2
separation.
Figure 2shows the schematic structure of the SMR process with the respective material
and energy flows.
As depicted in Figure 2, the
∆
H in reaction (3) representing the endothermic heat of
the reaction has to be provided by the burner being part of the SMR unit. Additionally,
there is heat demand for steam generation and preheating the feedstock to typical operation
temperatures in the reformer of around 800
◦
C, as well as for compensating wall heat losses
and latent heat of the products. The total heat energy supplied amounts to approx. 25 kWh
per kg of H
2
produced. This value is based on empirical data from existing biogas SMR
units and is taken as an assumption in this paper. The combustion of biogas with air is
described by the following equation:
n CO2+ CH4+ 2 (O2+mN2)→2 H2O(g) + (n + 1) CO2+mN2;∆H = −802.25 kJ/mol (5)
where n describes the molar ratio of CO
2
to CH
4
in the feed gas and m describes the ratio of
N
2
to O
2
in air. Usually air contains around 79 vol% N
2
and 21 vol% O
2
[
45
]. By converting
the units and referring to 1 kg CH4, Equation (5) can be rewritten as follows:
1.65 kg CO2+ 1 kg CH4+4kgO2+ 13.17 kg N2↔2.25 kg H2O + 4.4 kg CO2+ 13.17 kg N2(6)
It can be seen that 62.5% of the CO
2
in the exhaust gas originates from the combustion
of methane, while 37.5% comes from the biogas.
Summing up, the two process options consist of several identical process steps but
also show some differences: The preparation of the feedstock, the biogas production in the
biogas plant and the product gas treatment are identical for both processes. To compare both
processes from an ecological point of view, these identical process steps can be excluded
from the comparison according to the so-called “black-box” approach [
46
,
47
]. Also, for the
economic comparison, identical plant components can be neglected.
The main differences between the two process options are: (i) The additional biogas
SMR step in process option 2. (ii) The higher amount of captured CO
2
leading to more CO
2
to be compressed, transported, and stored in process option 2. Both (i) and (ii) increase the
investment and operational costs of process option 2. (iii) The different products with their
respective technology options for heavy-duty transportation: biomethane and biogenic
CO
2
in process option 1 versus biohydrogen and more biogenic CO
2
in process option 2.
Further differences are the technological and cost differences between H
2
and biomethane
in compression and transportation.
4. Technology Comparison
4.1. Considerations on Product Application
In this section, the two products, H2and CH4, are compared regarding their product
properties. This comparison is independent of the two use cases described in Section 3and
intends to give a broader view on possible applications.
CH
4
has a higher volumetric energy density than H
2
, which means it contains more
energy per unit volume [
48
]. This makes CH
4
generally more suitable for applications
where space is limited. However, H
2
has a higher energy content per unit mass, which
Energies 2023,16, 5066 7 of 16
makes it more efficient for applications where weight is a concern [
49
]. CH
4
and H
2
are
both flammable and explosive above certain concentrations [
50
]. However, H
2
has a wider
flammability range and can ignite at lower concentrations. With proper handling and
storage, both gases can be used safely [51].
Both biomethane and H
2
are considered to play key roles in future energy provision,
e.g., as substitutes for natural gas [
52
,
53
]. They can be used for transportation, heating,
power generation, and in industrial processes, as described briefly in the following.
CH
4
is commonly used as a fuel for vehicles, especially in the form of compressed nat-
ural gas (CNG) or LNG [
54
,
55
]. CNG is used in light-duty vehicles such as cars, while LNG
is used in heavy-duty vehicles like trucks and buses [
56
,
57
]. H
2
can be used with fuel-cell
vehicles (FCVs) as well as modified internal combustion engine vehicles [
58
]. Furthermore,
CH
4
as well as H
2
can be used for heating and power generation in residential, commercial
and industrial applications. H
2
, however, generally requires a specific environment for
combustion due to its lower volumetric energy density, faster laminar flame speed, and
higher combustion temperatures (1600
◦
C) compared to CH
4
(1300
◦
C) [
59
]. Subsequently,
conventional gas engines must first be either retrofitted or replaced with gas turbines that
are H2-ready and thus adequate for the use of 100% H2.
4.2. Energy Efficiency
Comparing process options 1 and 2, as described in Section 3, the chemical energy
contents of the produced gases are a critical factor for energy efficiency comparison. There-
fore, the available thermal energy produced by a combustion of the gases, expressed by the
mass-specific lower heating value (LHV), was considered. As described in Section 2.2, the
reactions of biomethane to CO
2
and H
2
proceed under energy input. The thermal energy for
the endothermic reaction is obtained via the oxidation of biogas. Since CO
2
is completely
oxidized, the thermal energy is obtained via full oxidation of the CH4in the biogas.
For the following calculation, it is further assumed that biogas consists of 62.5 vol%
CH
4
and 37.5 vol% CO
2
. This is an average value based on existing biogas processes, as
described in Section 2.2. Equation (7) is derived from Equation (4) under consideration
of the 25 kWh thermal energy input required for the overall SMR process, as described
in Section 3.
2.0 kg CH4+ 4.5 kg H2O(g) + 25 kWhth →1.0 kg H2+ 5.5 kg CO2(7)
The chemical energy content of CH
4
and H
2
was calculated with Equation (8) using the
LHV for the quantities given. The LHV of CH
4
is 13.9 kWh/kg and of H
2
33.33 kWh/kg [
60
].
Ei= LHV ×mi(8)
E
i
is the total chemical energy content for the considered mass of the species i [in kWh]
and m
i
the mass of the species i [in kg]. In this case, 2.0 kg of CH
4
has an energy content of
27.8 kWh. Thus, 52.8 kWh of energy input, divided into 2.0 kg CH
4
(LHV) and thermal
energy of 25 kWh, leads to 33.33 kWh of chemical energy produced in the form of 1 kg H
2
(LHV), as shown in Table 1. Therefore, the efficiency of the considered steam-reforming
process is 63% in terms of the chemically stored energy content of the product H
2
in relation
to the overall energy input.
Table 1.
Energy balance for the production of 1.0 kg H
2
by biogas steam reforming (process option 2,
system boundary A).
Energy Input Energy Output
Chemical energy content CH427.8 kWh 0.0 kWh
Chemical energy content H20.0 kWh 33.33 kWh
Thermal energy 25.0 kWh 0.0 kWh
Total 52.8 kWh 33.33 kWh
Energies 2023,16, 5066 8 of 16
To compare the energy efficiency of CH
4
and H
2
in the heavy-duty transportation
sector (case B), the efficiencies of the corresponding technologies must be included. As
listed in Section 3, gas engines for liquefied biomethane can reach efficiencies up to 44%,
while fuel cell systems with batteries for H
2
peak up to 63% [
42
–
44
]. The efficiencies can be
included using the following equation.
Ein = Eout/η(9)
where E
in
is the energy in kWh, E
out
is the usable energy in kWh and
η
is the efficiency of
the corresponding technology.
For biomethane, providing 1 kWh of usable energy for transport requires an energy
input of 2.27 kWh at an efficiency of 44%. For H
2
, the calculation must also take into
account the energy efficiency of its production via steam reforming with a value of 63.1%,
as shown above and in Table 2. Thus, for a 63% efficiency of the fuel cell system with a
battery, the total efficiency of process option 2 for case B is 39.8%. This means that to supply
1 kWh of usable energy in the form of H
2
, an energy input of 2.52 kWh is needed. Hence,
using H
2
produced in process option 2 means a loss of approx. 4.2% of the usable energy in
the form of propulsion energy for heavy-duty transport compared to process option 1.
Table 2.
Required energy input for the production of 1.0 kWh usable energy (process options 1 and 2,
system boundary B).
Process Option 1 Process Option 2
Usable Energy 1.0 kWh 1.0 kWh
Efficiency (heavy-duty transport) 44.0% 63.0%
Relative Efficiency (production) 100% 63.1%
Total Efficiency 44.0% 39.8%
Energy Input 2.27 kWh 2.52 kWh
However, this is within the range of several uncertainties due to the assumptions
made, e.g., assumed powertrain efficiencies and different driving behaviors. Furthermore,
the compression of the two gases, CH
4
and H
2
, are not considered. To convert CH
4
gas into
LNG, an energy loss of 10–20% can be assumed (1.39–2.78 kWh/kg CH
4
) [
61
]. For H
2
com-
pression to 400 bar, an energy loss of about 10.8% (3.61 kWh/kg H
2
) can be assumed [
62
].
Since the energy consumptions for both applications are associated with uncertainties and
are in a similar order of magnitude, they can be neglected in the calculations.
In conclusion, however, it can be said that for Use Case B, the efficiency losses that
occur in process option 2 due to the reforming process step (Use Case A) can be counter-
balanced by better efficiency in the FCEV power train, leading to the useful energy for
heavy-duty transport being in a similar order of magnitude for both process options.
4.3. Negative Emission Potential
The NEP represents the amount of negative emissions that are possible if all GHG
emissions caused along the entire value chain up to the use or storage of the product
gases are neglected, as described in Section 2.3. It can be used to compare the two process
options described in Section 3following the “black box” approach, where identical process
steps are excluded from the comparison [
46
,
47
]. To determine the NEP, the theoretical
maximum amount of storable biogenic CO
2
is calculated for the process options. Therefore,
the amount of CO
2
generated via biogas production in the biogas plant is considered first.
It is assumed, as described in Section 4.2, that biogas consists of CH
4
(62.5 vol%) and CO
2
(37.5 vol%). Thus, 1 Nm
3
biogas consists of 0.375 m
3
CO
2
and 0.625 m
3
CH
4
. Furthermore,
the biogas was considered an ideal gas. According to the ideal gas law [
63
], this leads to
the following equation being applicable:
pVk= nkRT, (10)
Energies 2023,16, 5066 9 of 16
where p is the pressure in Pascal, V
k
is the volume of the species k in m
3
, n
k
is the amount
of the species k in mol, R is the general gas constant (in J/mol
·
K), and T is the temperature
in K. From the ideal gas law, a molar ratio of 0.6 mol CO
2
/mol CH
4
is obtained for the
assumed average composition of biogas. This corresponds to a mass ratio of 1.65 kg CO
2
/kg
CH4and means that 1.65 kg of CO2is produced via the biogas plant per kilogram of CH4
produced in process option 1. In process option 2, an additional 2.75 kg of CO
2
is produced
from heat supply through biogas combustion and reforming, when the same amount of
biogas containing 1 kg of CH
4
is supplied as input stream. Adding this amount to the
biogenic CO
2
in the biogas leads to a total of 4.4 kg CO
2
to be captured in process option 2.
In summary, the biomethane production (process option 1) results in an NEP of 1.65 kg
CO
2
per kg CH
4
produced, while the HyBECCS approach (process option 2) shows a NEP
of 4.4 kg CO
2
for the same biomass input. This corresponds to about 2.7 times the amount
of storable biogenic CO
2
of process option 2 compared to process option 1. Furthermore,
depending on the biogas quality (CH
4
content), this ratio deviates, as shown in Figure 3.
The NEP of process option 2 increases to up to 3.3 times the amount of process option 1 for
a CH
4
content in the biogas of 70 vol%. For a CH
4
content in biogas of 55 vol%, the NEP
for process option 1 is still 2.2 times higher than that of process option 1.
Energies 2023, 16, x FOR PEER REVIEW 10 of 17
Figure 3. Ratio of biogenic CO2 production of process option 2 vs. process option 1 for dierent CH4
volume fractions in biogas (own representation).
4.4. Economic Comparison
The costs required and revenues to be expected for the two process options can vary
signicantly depending on the specic technology and scale of the project. However, some
general considerations can be made.
Costs that arise in both process options can be neglected in the comparison, e.g., the
main technologies used for upgrading biogas to biomethane are PSA and membrane sep-
aration [64]. This is also required for the purication of the biohydrogen and can therefore
be neglected for the comparison [65]. Additionally, there may be costs associated with
obtaining permits, certications, and approvals for the biomethane as well as the biohy-
drogen production, depending on the regulations in the specic country or region. These
costs can also vary depending on the project location and regulatory environment and are
neglected in this work.
The costs for biogas steam reforming to produce H2 include the capital costs of the
reforming unit, which is the main equipment required for the process. Therefore, the cap-
ital costs for process option 1 are generally lower than for process option 2. This is primar-
ily because additional plant components for the reforming process step are needed in pro-
cess option 2. The costs for the SMR upgrade have to be analyzed specically for each
case. However, the additional costs for the SMR upgrade have to be compensated by a
higher income from the sale of the products in order to be economically feasible. The in-
come side is described in the following.
Furthermore, the dierent sources of income with their respective market prices, to-
day and in the future, can be compared. In process option 1, the marketable products are
CH4 and negative emissions, whereas, in process option 2, the marketable products are H2
and negative emissions. The total income for each process option depends on the market
prices of the respective products today and in the future during the lifetime of the plant
as well as the generated amount of each product. A total of 3.6 kg of CH4 is necessary for
the production of 1 kg of H2, as described in Section 3. Process option 2 therefore requires
Figure 3.
Ratio of biogenic CO
2
production of process option 2 vs. process option 1 for different CH
4
volume fractions in biogas (own representation).
4.4. Economic Comparison
The costs required and revenues to be expected for the two process options can vary
significantly depending on the specific technology and scale of the project. However, some
general considerations can be made.
Costs that arise in both process options can be neglected in the comparison, e.g.,
the main technologies used for upgrading biogas to biomethane are PSA and membrane
separation [
64
]. This is also required for the purification of the biohydrogen and can
therefore be neglected for the comparison [
65
]. Additionally, there may be costs associated
with obtaining permits, certifications, and approvals for the biomethane as well as the
Energies 2023,16, 5066 10 of 16
biohydrogen production, depending on the regulations in the specific country or region.
These costs can also vary depending on the project location and regulatory environment
and are neglected in this work.
The costs for biogas steam reforming to produce H
2
include the capital costs of the
reforming unit, which is the main equipment required for the process. Therefore, the capital
costs for process option 1 are generally lower than for process option 2. This is primarily
because additional plant components for the reforming process step are needed in process
option 2. The costs for the SMR upgrade have to be analyzed specifically for each case.
However, the additional costs for the SMR upgrade have to be compensated by a higher
income from the sale of the products in order to be economically feasible. The income side
is described in the following.
Furthermore, the different sources of income with their respective market prices, today
and in the future, can be compared. In process option 1, the marketable products are CH4
and negative emissions, whereas, in process option 2, the marketable products are H
2
and
negative emissions. The total income for each process option depends on the market prices
of the respective products today and in the future during the lifetime of the plant as well
as the generated amount of each product. A total of 3.6 kg of CH
4
is necessary for the
production of 1 kg of H
2
, as described in Section 3. Process option 2 therefore requires
3.6 times
the amount of biogas input per kg of produced energy carrier. Considering
negative emissions, however, process option 2 has the potential to produce about 2.7 times
the amount of storable biogenic CO2to be captured and stored, as shown in Section 4.3.
The current market prices of CH
4
and H
2
vary depending on the region and quality.
However, some general price comparisons can be made based on available data. In the
United States, the retail price of CNG for transportation ranges from USD 2–4 per gasoline
gallon equivalent (GGE) (EUR 0.72–1.45 per kg natural gas [
66
]), whereas the retail price
of LNG for transportation ranges from USD 2–5 per diesel gallon equivalent (DGE) (EUR
0.68–1.69 per kg LNG [
66
]), both depending on the location and the supplier. The retail price
of H
2
for transportation ranges from USD 9.5–13.2 per kg (EUR 8.8–12.3 per kg), depending
on the location and the supplier [
67
]. In Europe, the fuel prices for transportation vary
from country to country. In the first quarter of 2022, the average fuel price range for
CNG in Europe was EUR 5.23 to EUR 12.51 per 100 km travelled (average EUR 7.24
per
100 km
), based on information submitted by nine member states [
68
]. Assuming an
average consumption of 3.64 kg of CNG per 100 km [
69
], this corresponds to a price range
of EUR 1.44 to EUR 3.43 per kg of CNG (Average: EUR 1.99 per kg). For LNG, the average
retail price range for the same period was from EUR 0.45 to EUR 2.81 per kg of LNG,
with an average price for Europe (EU-27) of EUR 1.86 per kg LNG [
70
]. With an average
consumption of 2.14 kg LNG per 100 km for heavy trucks [56], this corresponds to a price
range of EUR 0.96 to EUR 6.01 per 100 km (average: EUR 3.98 per 100 km). Average H
2
prices in the first quarter of 2022 ranged from EUR 9.00 to EUR 15.06 per 100 km (average:
EUR 11.22 per 100 km), based on information submitted by six member states. Assuming
an average consumption of 0.8 kg H
2
per 100 km [
71
], an average price range of EUR 11.25
to EUR 18.83 per kg of H
2
(average: EUR 14,01 per kg H
2
) is obtained. An overview of the
pump price ranges for different fuels in the European Union is shown in Table 3.
Table 3.
Overview of price ranges for different fuels in the European Union (average for
Q1 of 2022) [68,70].
Fuel Price (EUR/kg) Price (EUR/100 km) Reference
CNG 1.44–3.43
Average: 1.99
5.23–12.51
Average: 7.24 [68]
LNG 0.45–2.81
Average (EU-27): 1.86
0.96–6.01
Average (EU-27): 3.98 [70]
H211.25–18.83
Average: 14.01
9.00–15.06
Average: 11.22 [68,71]
Energies 2023,16, 5066 11 of 16
Summarizing, the current market prices of CH
4
are clearly lower than those of H
2
.
This is due to H
2
being a downstream product predominantly produced from CH
4
obtained
from natural gas [72]. However, the long-term price forecasts for H2indicate potential for
lower prices due to cost reductions through technological alternatives like electrolysis as
well as economies of scale [73].
Both process options generate negative emissions, when the biogenic CO
2
is not
released into the atmosphere but captured, transported to a storage site, and permanently
stored. However, generating negative emissions from biogenic CO
2
creates further costs
and will, therefore, only happen when they are overcompensated by an income. One option
is the sale of so-called carbon removal units (CRUs) issued for verified negative emissions
(in tCO
2
e) and can be sold to buyers who wish to claim them. Already today, several
private entities offer CRUs [
74
]. They stem from different carbon-removal approaches in
different countries with different underlying quality standards and show broad price ranges.
Examples are EUR 20/CRU for bio-based construction materials in France to EUR 535/CRU
for biochar in Sweden [
75
]. In November 2022, the European Commission proposed an
EU carbon-removal certification framework (CRCF) to establish common rules for the
monitoring, verification, and reporting of negative emissions for the voluntary carbon
removal market [
76
]. This EU initiative is still ongoing. However, this standardization
process within the geographical boundaries of one of the biggest carbon trading schemes
worldwide shows the awareness of the political bodies for the urgent need to create
a secure and credible playing field for the commercialization of CRUs. Summing up,
negative emissions are already today a marketable product, and, in the future, ongoing
standardization processes will increase the visibility, reliability, and, thus, the market
volume for negative emissions in Europe and worldwide.
As outlined in Section 4.3, process option 1 results in an NEP of 1.65 kg CO
2
per kg of
CH
4
produced, while process option 2 shows an NEP of 4.4 kg CO
2
for the same amount
of biomass input. The NEP represents the maximum amount of negative emissions to be
produced and qualified for CRUs in each option. Process option 1 generates 1.0 kg of bio-
LNG, while process option 2 generates 0.5 kg H
2
for the same amount of biomass input, as
outlined in Section 3. The following price ranges, also described above, give the following
price averages for the products: For H
2
, the price range of 0.93–3.72 EUR/kg H
2
results
in an average price of 2.325 EUR/kg H
2
. For LNG, the price range of
0.68–1.69 EUR/kg
LNG results in an average price of 1.185 EUR/kg LNG. For CRU, the price range of
20–535 EUR/CRU
results in an average price of 277.5 EUR/CRU. For process option 1,
this means that the products (LNG and CO
2
) can generate an income of 459.06 EUR/kg
of CH
4
produced. For process option 2, the products (H
2
and CO
2
) can generate an
income of 1222.16 EUR for the same amount of biomass input. In this simplified exemplary
calculation, process option 2 would generate more income. However, cost consideration is
necessary for final economic comparison and CRU pricing is still not fixed or legislated. The
calculation shows, however, that depending on the market value of the different products,
yields determine the superiority in terms of income of the process options and gives first
indications and orientation values.
5. Limitations
This paper focuses on comparing the biomethane vs. biohydrogen with CCS options
in terms of their energy efficiency, economic aspects, and negative emission potential. Other
environmental impacts are not considered. However, both approaches’ impacts on the
environment must be analyzed for a holistic assessment. Impacts on social sustainability
are neglected in this paper.
The energy efficiency for the steam reforming of biogas was calculated under the
assumption that an additional 25 kWh of thermal energy is required for the process. This
includes, on the one hand, the reformation energy but also, for example, the energy required
to heat the gases or to evaporate the liquid water. Depending on the ambient parameters or
energetic optimizations, the value for the required thermal energy can be higher or lower,
Energies 2023,16, 5066 12 of 16
resulting in a change in energy efficiency. This assumption is based on experience values
and should be validated. This also applies to all other assumptions, such as the efficiency
of the LNG or fuel-cell propulsion and the compression/cooling of the gases in Use Case B
or the average biogas composition.
Considering the economic comparison and the wide price ranges, as well as the
different cost structures of both process options, requires a deeper economic analysis,
taking into consideration more influencing factors such as investment and operational
costs, location, and the time of operational initiation of the plant.
6. Summary and Conclusions
Climate change constitutes one of the most pressing challenges of our times. Inno-
vative technologies are needed that can reduce GHG emissions in all sectors. Action is
especially necessary in the energy sector, which is currently responsible for the largest
amount of emissions. A transition to cleaner energy sources like renewable energies and
carbon-free energy carriers like H
2
is thus urgently needed. Additionally, to limit human-
induced global warming to less than 2
◦
C compared to pre-industrial levels, NETs or CDR
technologies are indispensable.
In this paper, biomethane production from biogas with CCS (process option 1) was
compared to biohydrogen production via the SMR of biogas with CCS (process
option 2)
,
i.e., a HyBECCS approach. The analysis considers technical, economic, and environ-
mental aspects of the two options. The aim was to provide insights into the trade-offs
to be considered.
Considering energy efficiency, the production of biohydrogen in process option
2 results
in an energy loss of approximately 37% in terms of the absolute LHV of the prod-
ucts per kg of biomass or biogas input. Looking at usable driving energy for heavy-duty
transport applications, using H
2
produced in process option 2 still results in a comparable
loss of approx. 4.2% in terms of usable driving energy for the heavy-duty transport sector.
However, this is within the range of several uncertainties due to the assumptions made,
e.g., assumed powertrain efficiencies, LNG liquefaction (10–20% energy loss), and different
driving behaviors. In conclusion, the useful energy generation for heavy-duty transport
can be expected to be in a similar order of magnitude for both process options.
To determine the negative emission potential, the theoretical maximum amount of
storable biogenic CO
2
(NEP) was calculated for both process options. In comparison,
process option 1 results in an NEP of 1.65 kg CO
2
per kg of CH
4
produced, while the
HyBECCS approach (process option 2) shows an NEP of 4.4 kg CO
2
for the same amount
of biomass input. This corresponds to about 2.7 times the amount of storable biogenic
CO
2
. Depending on the quality of the biogas process step (CH
4
content in the biogas), even
more biogenic CO
2
can be captured and stored with the HyBECCS approach compared
to process option 1. The NEP of process option 2 increases to up to 5 times the amount of
process option 1 for a CH
4
content in biogas of 70 vol%. For a CH
4
content of biogas of
55 vol%
, the NEP for process option 2 is still 2.2 times higher than that of process option 1.
The costs required for the two process options can vary significantly depending on
the specific technology and scale of the reforming plant considered. Biogas SMR requires
additional equipment leading to higher investment costs. Further to this, the current market
prices for CH
4
are generally lower than for H
2
. However, the long-term price forecasts
for H
2
indicate a potential for lower prices due to cost reductions through technological
advances and economies of scale. Negative emissions are a marketable product already. In
the future, ongoing standardization processes will increase their visibility, reliability, and,
thus, market potentials in Europe and worldwide. This market potential correlates with
the NEP and is thus about 2.7 times higher for process option 2.
In conclusion, producing biohydrogen via the SMR of biogas offers the possibility
to capture between 2.2 and 5 times more of the carbon bound in biomass compared to
biomethane production. Captured biogenic CO
2
has the potential to create negative emis-
sions that can be marketed as a byproduct besides the resulting energy carrier. However, the
Energies 2023,16, 5066 13 of 16
production of biohydrogen from biomethane results in an energy loss of approximately 37%
in terms of the LHV of the product gases, but this loss can likely be partially compensated
by efficient driving technologies such as FCEVs.
7. Outlook
Negative emissions will gain relevance in the coming decades, further highlighting the
benefits of HyBECCS approaches such as process option 2 in this paper. Overall, they have
the potential to make a significant contribution to lowering GHG emissions and establishing
CO
2
sinks, thereby making the energy sector more sustainable. A deep economic analysis,
considering several influencing factors such as investment and operational costs, product
price forecasts, scale, location, and the time of a plant’s operational initiation, must be
carried out for a thorough comparison of the presented process options. Furthermore,
the ecological impact of both process options has to be analyzed in a holistic assessment,
including the GHG emissions caused throughout the entire lifecycle of each product couple.
Therefore, developing an approach to determine the positive and negative impacts on the
climate to identify the approach with the highest climate-change mitigation potential is
required. This includes the development of an approach to evaluate different CCS and CCU
options concerning their respective GHG mitigation potential. To allow for comparisons
with other HyBECCS and NETs, the central Key Performance Indicators (KPIs) of leveled
costs of carbon-negative H
2
(LCCNH) and leveled costs of negative emissions (LCNE)
must be calculated for both process options [
30
]. Comparing the KPIs is essential for cost
efficiency in NET and HyBECCS development and deployment.
Market integration of HyBECCS plants depends on establishing infrastructure for
transporting both H
2
and CO
2
. The different options and their future perspectives must
be analyzed considering their influence on the feasibility and economics of HyBECCS
approaches. Furthermore, the feasibility of specific HyBECCS plants depends on the
market for both products. Thus, analyzing the present and future market potential of H
2
and CO2in selected geographical areas is needed.
Author Contributions:
Conceptualization, methodology, formal analysis: J.F.; writing (original draft),
investigation, data curation, visualization: J.F., E.G., S.H., S.Z., T.S. and H.-P.S.; writing (review and
editing): R.M. and A.S.; funding acquisition: J.F., R.M. and A.S. All authors have read and agreed to
the published version of the manuscript.
Funding:
This research was funded by the German Federal Ministry for Economic Affairs and
Energy (grant number 03EI5407C); the Ministry of the Environment, Climate Protection and the
Energy Sector Baden-Wuerttemberg, Germany and the European Regional Development Fund
(ERDF) (grant number 2076391); and the German Federal Ministry of Education and Research
(grant number 03SF0669B).
Data Availability Statement: Data is contained within the article.
Acknowledgments:
The research shown in this paper was conducted within the projects “RhoTech”,
“SmartBioH2” and “H2Wood”. The authors gratefully acknowledge the financial support of the
German Federal Ministry for Economic Affairs and Energy, the Ministry of the Environment, Cli-
mate Protection and the Energy Sector Baden-Wuerttemberg, Germany, the European Regional
Development Fund (ERDF) and the German Federal Ministry of Education and Research.
Conflicts of Interest: The authors declare no conflict of interest.
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