Production of SNG from Biomass Using a Commercial-Scale Fluidized Bed Gasifier Integrated with Water Electrolysis

Abstract

Biomass gasification, as a thermochemical process, has attracted growing interest due to the increasing popularity of biofuel production based on syngas or pure hydrogen. Moreover, when integrated with CO₂ capture, this method of producing gaseous fuels can achieve negative CO₂ emissions, making it competitive with other production systems based on either fossil or renewable sources. This paper presents the results of a process and economic analysis of synthetic natural gas (SNG) production systems integrated with a commercial fluidized-bed gasification reactor based on Synthesis Energy Systems (SES) technology. The study examines the potential integration of the system with a water electrolyzer at two levels of coupling: one providing oxygen for the gasification process, and the other eliminating the need for CO₂ separation before the SNG synthesis stage. Using a single gasification unit with a raw biomass feed rate of 60 t/h, the system produces 188 t/d of SNG. Integration with a water electrolyzer increases SNG production to 259 and 621 t/d. For cases without electrolyzer integration and under the assumption of zero emissions from biomass processing, the application of CO₂ separation enables the achievement of negative CO₂ emissions. This creates an opportunity for additional revenue from the sale of CO₂ emission allowances, which can significantly reduce SNG production costs. In this analysis, the break-even CO₂ price, above which the SNG production cost becomes negative, is USD 251/t CO₂. In systems integrated with water electrolysis, the cost and carbon footprint of the electricity consumed in the electrochemical water-splitting process have a decisive impact on both the overall SNG production cost and its carbon intensity.

1. Introduction

Limiting global warming to 2 °C (or preferably 1.5 °C) requires the implementation of various classes of technologies, including those aimed at removing carbon dioxide from the atmosphere. These are known as “Negative Emissions Technologies” (NETs). This term generally refers to deliberate human actions designed to remove CO₂ emissions from the atmosphere [1]. The assessment and positioning of NETs should address various aspects related to their operation, including effectiveness (understood as the ability to achieve the intended objectives), efficiency (both thermodynamic and economic), deployment potential, risk, and synergy with other climate policy instruments [2]. In this context, it is also emphasized that a comprehensive evaluation of energy and resource-based technologies requires the inclusion of ESG (Environmental, Social, Governance) aspects, which directly affect investment conditions, market valuation, and long-term development prospects [3].

Among NETs, bioenergy technologies with carbon capture and storage (Bioenergy with Carbon Capture and Storage—BECCS) play a particularly important role [1,4,5,6,7,8]. It is estimated that the overall negative emission potential of BECCS technologies amounts to approximately 0.5–5 GtCO₂ per year (achievable by 2050), at a cost in the range of 100–200 USD per ton of CO₂. The contribution of BECCS technologies is expected to account for 10–20% of the total estimated mitigation potential of all NET measures by 2050 [6]. Using the TIAM-UCL model [9], study [10] presented scenario-based research results supporting the thesis that BECCS technologies play a fundamental role in achieving global CO₂ reduction goals by the year 2100. Literature reports and the current state of development of various technological modules comprising negative emission systems justify the need for intensive basic and applied research, as well as R&D efforts, focused on further development of BECCS technologies. Collecting data on technological and economic characteristics and utilizing results from demonstration installations should help identify optimal technological configurations and support investment processes for large-scale facilities.

Within BECCS technologies, particularly in the context of large-scale production, the use of solid biomass as a feedstock in gasification processes plays a significant role, either for direct energy generation [11] or for the production of low-CO₂ energy carriers such as hydrogen [12,13,14] and synthetic natural gas (SNG). According to IEA reports and European Commission guidelines, natural gas remains one of the main energy carriers; however, due to its limited resources and availability, the use of a synthetic substitute appears to be a promising option [15]. Carbon-neutral SNG produced from biomass seems to be one of the potential ways to decarbonize markets dependent on natural gas. Currently, biomass gasification is commercially used for electricity or heat generation. The technology for producing SNG from synthesis gas still requires further development and optimization to ensure full commercial and industrial viability. So far, only a limited number of pilot installations have been built that integrate biomass gasification with syngas methanation [16]. A list of selected pilot installations is presented in

Table 1. Reference list of biomass gasification and methanation plants.

Plant/Project/Location	Reported SNG Capacity	Gasifier Type/ Methanation Technology	Efficiency/Current Status	Reference
GoBiGas (Phase1) Gothenburg, Sweden	~20 MW biomethane	Indirect/steam gasification (DFB), Catalytic methanation (commercial)	≥65% biomass → SNG Large demo; injected biomethane to grid	[17]
Güssing Bio-SNG demo Güssing, Austria	~1 MW	Dual fluidized-bed steam gasification (DFB) Fluidized-bed methanation	Reported in project papers, Early full-chain demonstration	[18]
TU Wien pilot chain, Vienna, Austria	10–100 kW (pilot)	100 kW DFB biomass gasifier Small fluidized bed/lab units	Efficiency in academic reports, Academic pilot for optimization	[19]
MILENA + OLGA (ECN) The Netherlands	0.8 MWth pilot; planned 1 MWe demo	MILENA indirect gasification + OLGA tar removal Catalytic methanation tested	Claimed proven at pilot scale, Proven at pilot scale; commercial proposals	[20,21]
VESTA (Amec Foster Wheeler), pilot Nanjing, China	~100 Nm3/h	Syngas-fed methanation demo, VESTA catalytic methanation	Validated process and efficiency, Small-scale demo of VESTA methanation	[22]
Korean research, pilots South Korea	Bench → pilot scales (kW–MW)	DFB + other pilot gasifiers Lab/pilot; BTL (biomass to liquid; diesel, SNG, Fisher-Tropsh process)	Long-term operation and testing of the pilot-scale system; not commercial demo	[23]
Japanese PtG/methanation, pilots Japan (various sites)	12.5–100 Nm3/h pilots	CO2+H2 methanation (not biomass) Commercial methanation modules	Proven for PtG Relevant technology; applicable to biomass syngas	[24]

.

SNG production from biomass is usually carried out through thermochemical or biochemical conversion [25,26]. Biochemical methane production technologies have been used for many years; however, they suffer from low efficiency and sensitivity to process conditions (temperature, pH, and feedstock type) [27]. Additionally, when injecting biomethane into the gas grid, gas conditioning and purification systems are required to meet the necessary quality standards [28]. Thermochemical conversion of biomass to SNG typically consists of two main components: a gasification reactor and a methanation reactor. Moreover, to increase the hydrogen content in synthesis gas, integration with electrolysis systems is often employed [29,30,31,32]. The most used gasification reactors are based on the following technologies: pressurized O₂-blown circulating fluidized bed (CFB) gasification, atmospheric indirect steam-blown gasification, and pressurized bubbling fluidized bed (BFB) hydrogasification. For large-scale systems enabling the production of large volumes of synthesis gas, some of the most advanced commercial and pilot-scale solutions include technologies developed by Uhde/HTW (High-Temperature Winkler) [33,34,35], KRW (Kellogg–Rust–Westinghouse) [36,37,38], U-Gas GTI/SES (Synthesis Energy Systems) [39], and KBR Transport Reactors [40,41]. A summary of fluidized-bed gasification technologies operating at a commercial scale is provided in [42].

The syngas methanation process consists of two exothermic reactions (1) and (2) [26]:

CO + 3H₂ = CH₄ + H₂O − 206 kJ/mol

(1)

CO₂ + 4H₂ = CH₄ + 2H₂O − 164 kJ/mol

(2)

The methanation reaction is most often carried out in catalytic reactors with a fixed or fluidized bed [33,34,35]. An alternative to catalytic reactors is a microbiological reactor for biomethanation [43].

The process and economic efficiency of SNG production from biomass reported in the literature exhibits a wide range of values resulting from differences in the applied gasification technologies, system configurations, and process scale.

Wan et al. [34] propose a process model in Aspen for wood gasification integrated with an electrolysis unit producing hydrogen used in the syngas methanation process. The energy efficiency of the proposed process reaches about 61% with an 89% carbon conversion. The estimated SNG production price is about USD 101/MWh. Cormos et al. [44] conducted a process analysis of SNG production from woody biomass with an additional CO₂ removal system for an industrial scale of 500 MWth. The process model in ChemCAD assumes steam gasification of woody biomass, CO₂ removal using MDEA, and catalytic methanation of syngas. In the proposed system, an energy efficiency of about 69% was achieved, with CO₂ emissions of 3 kg/MWh and a production cost of SNG of about EUR 53/MWh.

Katla et al. [45] analyzed three configurations of a fluidized-bed biomass gasification system with an additional hydrogen production installation and utilization of the resulting CO₂. The cold gas efficiencies (CGE) obtained from the simulation were in the range of 63 to 77%, and the price of the produced SNG ranged from EUR 57 to EUR 111/MWh depending on the plant configuration used.

Conversely, Cui et al. [46] conducted an analysis of biomass gasification with oxygen of 80–96% purity, finding a high dependence of the obtained gas quality on the oxygen concentration. The economic analysis, based on Chinese raw material and energy costs, showed that the proposed technology could be competitive with plants featuring an integrated electrolysis system.

Di Bisceglie et al. [47] conducted a thermodynamic optimization of the gasification and methanation system, proposing the use of heat produced during the exothermic methanation reaction to supply the energy needed in the gasification reactor. A summary of recent studies on SNG production based on biomass gasification is presented in

Table 2. Summary of recent studies on SNG production in systems integrated with biomass gasification.

Ref.	System Configuration	Reactor Type/Technology/Model	Role of the Electrolyzer	Production Scale	Remarks
[34]	▪ Biomass gasification ▪ Electrolyzer (PEM) ▪ Methanation	▪ Reactor DFB (dual fluidized bed) ▪ Reactor model: thermodynamic equilibrium (Gibbs)	▪ H2 supply for syngas composition adjustment prior to methanation	▪ Biomass: 100 kg/h (dried wood)	▪ Production efficiency: 60.6% ▪ Production cost: 101 USD/MWh (2023)
[44]	▪ Biomass gasification ▪ CO2 removal ▪ Methanation ▪ Power production	▪ CFB, ▪ HTW ▪ Reactor model: thermodynamic equilibrium (Gibbs)	▪ None	▪ Biomass: 744.7 MWth (dried wood) ▪ SNG: 500 MWth	▪ Production efficiency: 69% ▪ Production cost: 14.76 EUR/GJ (53 EUR/MWh, 2023)
[45]	▪ Biomass gasification ▪ Electrolyzer (−) ▪ CO2 removal ▪ Methanation	▪ DFB/CFB (3 cases) ▪ Reactor model: thermodynamic equilibrium (Gibbs)	▪ H2 supply for syngas composition adjustment prior to methanation ▪ O2 utilization in the gasification process	▪ Biomass: 100 kg/h (dried wood chips) ▪ SNG: 0.34–0.87 MWth	▪ Production efficiency: 69.1–75.6% ▪ Production cost: 100–112 EUR/MWh (2022)
[46]	▪ Biomass gasification ▪ CO2 removal ▪ Methanation ▪ Biomass drying ▪ Power production (ORC)	▪ Not specified ▪ Reactor model: thermodynamic equilibrium (Gibbs)	▪ None	▪ Biomass: 25 t/h ▪ (Straw—raw biomass) ▪ SNG: 0.34–0.87 MWth	▪ Production efficiency: 60.4–60.8% (including net power consumption) ▪ Production cost: 1.88–1.96 CNY/mn3, (2019)
[47]	▪ Biomass gasification ▪ CO2 removal ▪ Methanation	▪ DFB ▪ Reactor model: thermodynamic equilibrium (Gibbs)	▪ None	▪ Biomass: 100 kWth (hazelnut shells)	▪ Production efficiency: 79%
[48]	▪ Biomass gasification ▪ CO2 removal ▪ Electrolyzer (SOEC) ▪ Methanation	▪ CFB (3 cases) ▪ Plug flow model	▪ H2 supply for syngas composition adjustment prior to methanation	▪ Biomass: 15 MWth (wood pellets)	▪ Production efficiency: 44–62%

.

Water electrolysis is a mature and reliable technology for producing clean hydrogen, allowing for the mitigation of carbon emissions and fulfilling energy demands and strict emission factors. It can also be incorporated into SNG production plants to produce hydrogen necessary to convert syngas into methane in the catalytic methanation process [49,50].

The most common electrolysis units are alkaline (AEL) and proton exchange membrane (PEM) reactors. AEL typically operates at 60–90 °C and 1–30 bar, achieving electrical efficiencies of 60–70% (LHV) with a specific electricity consumption of approximately 50–55 kWh·kg⁻¹ H₂. PEM electrolysis operates at 50–80 °C and pressures up to 30–70 bar, with efficiencies of 65–75% (LHV) and a specific electricity consumption in the range of 48–54 kWh·kg⁻¹ H₂ [51,52,53]. Other solutions currently at the demonstration or small-scale research level include solid oxide electrolyzers (SOECs) and anion exchange membranes (AEMs) [53].

The development directions for fifth-generation electrolyzers (post-2020) indicate that this period should enable the transition to widespread deployment, as well as from the megawatt to the gigawatt scale. The key development targets include reducing capital costs below 200 USD/kW, achieving high durability (>50,000 h), and attaining high efficiency (up to 80%, LHV basis) [53].

The idea of integrating electrolytic hydrogen and biomass gasification was previously mentioned in a couple of publications [32,54,55,56,57,58,59]. Clausen [32] proposed a new system connecting a gasification reactor to produce syngas with a pressurized solid oxide electrolysis cell to produce hydrogen as well as internally perform the methanation reaction, due to the addition of nickel to the electrode material. Based on thermodynamic calculations, the authors claim to have obtained almost 100% of carbon conversion and >80% energy efficiency. Naderi et al. [55] presented a review of modeling approaches to biomass to gas technologies. Giglio et al. [58] proposed two different options to integrate biomass gasification with high-temperature electrolysis. In their Aspen Plus model, the authors used CFB gasification units with a different configuration of the electrolysis process. Based on thermodynamic calculations, the energy efficiency ranged from 66.8 to 71.7%. Menin et al. [60] proposed a model of biomass gasification technology coupled with electrolysis, water gas shift reforming, and biomethanation, which enables the operation of the methanation reactor at milder conditions compared to catalytic conversion.

As the capacity of electrolyzers increases, the local supply of low-cost oxygen also grows, which, according to analyses, can significantly improve the economics of its energy and industrial applications—especially in cases where the cost of producing or transporting O₂ from air separation units (ASU) has previously been a barrier [61,62].

The use of oxy-fuel combustion can contribute to increased process efficiency and simplification of CO₂ capture, thereby enhancing the attractiveness of oxy-fuel combustion in the energy sector, the cement industry, and the waste-to-energy sector [63,64].

Affordable and readily available oxygen may also promote the development of solid fuel gasification technologies, including BECCS, toward hydrogen and synthetic fuel production—provided that production systems are co-located within industrial clusters and O₂ logistics costs are minimized [61,62,65,66,67].

This paper presents an analysis of the potential for large-scale industrial production of low-emission synthetic natural gas (SNG) using biomass gasification technology in a fluidized bed based on the SES (Synthesis Energy System) process. The main innovation of this study lies in the assessment of large-scale SNG production based on a commercially available fluidized-bed biomass gasification technology (SES), rather than on conceptual or pilot-scale systems commonly reported in the literature. The study further introduces and compares two distinct strategies for integrating water electrolysis into the gasification–methanation pathway: one focused on oxygen supply for the gasification process and the other aimed at tailoring the syngas composition to achieve SNG production without the need for CO₂ separation. This dual integration framework provides new insights into the trade-offs between process complexity, carbon utilization, and system efficiency.

2. Materials and Methods

2.1. Goal of This Study

This paper presents the results of both process and economic analysis of SNG production using biomass gasification as a feedstock material. The economic analysis was performed using assumptions specific to the Polish energy market and assuming an annual system availability of 90%.

Simulations were run for the following four different plant configurations:

• Case A (base case): SNG production without CO₂ sequestration. Captured CO₂ due to adjustment of the H₂/CO₂ ratio before the methanation reaction is released into the atmosphere.
• Case B: SNG production with CO₂ sequestration. Captured CO₂ is compressed to 100 bar and prepared for transport to the injection site.
• Case C: SNG production with CO₂ sequestration (as above). Integration with water electrolysis. Electrolyzer sized to supply oxygen for gasification. Produced hydrogen is fed upstream of the methanation reactor. Elevated H₂ flow reduces CO₂ removal demand before SNG synthesis (adjustment of the H₂/CO₂ ratio to methane reaction stoichiometry).
• Case D: SNG production with CO₂ sequestration (as in point 2 and 3). Integration with water electrolysis. The electrolyzer capacity is selected to provide a hydrogen flow that enables achieving the desired gas composition upstream of the methanation unit, eliminating the need for CO₂ capture.

An important aspect in the assessment of currently operating and developing production systems is the carbon intensity of production. For this reason, all analyzed cases were evaluated in terms of CO₂ emissions per unit of produced SNG, highlighting the potential to achieve so-called negative emissions. Negative CO₂ emissions in the analyzed SNG production system were quantified based on a carbon balance and the biogenic origin of carbon contained in biomass. The net CO₂ emission was calculated as the difference between indirect emissions associated with electricity consumption and the amount of captured CO₂ (biogenic), according to the following equation:

$${\mathrm{E}}_{{\mathrm{C}\mathrm{O}}_2}=\left({\mathrm{N}}_{\mathrm{c}\mathrm{o}\mathrm{n}\mathrm{s}\mathrm{u}\mathrm{m}.}-{\mathrm{N}}_{\mathrm{p}\mathrm{r}\mathrm{o}\mathrm{d}.}\right){\mathrm{E}\mathrm{F}}_{{\mathrm{C}\mathrm{O}}_2}-{\mathrm{E}}_{{\mathrm{C}\mathrm{O}}_2,\mathrm{c}\mathrm{a}\mathrm{p}\mathrm{t}\mathrm{u}\mathrm{r}\mathrm{e}\mathrm{d}}$$

(3)

where

E_CO2—net CO₂ emissions from the system;

N_consum—electricity consumption;

N_prod—electricity production;

EF_CO2—emission factor of electricity generation, kg CO₂/MWh;

E_{CO2, captured}—CO₂ captured.

The determination of CO₂ emissions associated with SNG production did not take into account upstream emissions or emissions related to the subsequent transport and end use of SNG.

Figure 1 presents general block diagrams of the considered SNG production system, along with an indication of potential CO₂ emission sources associated with the production process.

2.2. SES Technology Reactor Modeling

SES gasification technology, previously known as U-Gas, uses oxygen/steam fluidized bed gasification to produce synthesis gas. It is a commercially proven technology, with five plants operating in China (12 gasification reactors), producing methanol and gas for fuel (aluminum production plants). The proposed model is based on a Gibbs reactor connected in series with stoichiometric reactors. Additional stoichiometric reactors are added to simulate specific gasification reactions such as the CO-shift reaction and methane and ammonia production. The model was made in a ChemCAD process simulator [68] and is described in detail in the publications [40,42]. The results of the model validation based on data from a large-scale commercially available SES plant were presented in [69]. To increase the accuracy of the energy balance, enthalpy of biomass formation was included in the model.

It was shown in [40] that the effects of the enthalpy of formation influence the calculation of the thermodynamic equilibrium temperature, which also leads to different equilibrium compositions of the produced syngas. The method for calculating the enthalpy of formation is presented in [42,70].

2.3. Computational Model of a Methane Synthesis Unit

Figure 2 presents the flowsheet of the SNG synthesis system simulated in ChemCAD. The system consists of three Gibbs reactors in series, heat exchangers, and units for moisture and CO₂ removal, which are simulated in ChemCAD by Flash and Component Separator units. After the first reactor, the unreacted gas is cooled in a heat exchanger (HTRX1) and partially recirculated to improve reaction efficiency and control temperature. In the analyzed case, the recirculation ratio was set at 55%, which allowed the process gas temperature to be reduced below 600 °C in the first reactor. The effect of the recirculation ratio on gas temperature and mole fraction of CO and H₂ in the synthesis gas is shown in Figure 3. The gas, cooled to 260 °C, was directed to the second reactor and, after being cooled again to 220 °C (HTRX2), to the third synthesis reactor. After exiting the final reactor, the gas was cooled to 35 °C (enabling low-temperature steam production: HTRX3 and boiler feedwater preheating: HTRX4) and then directed to the moisture removal units (water vapor condensation, molecular sieves) followed by the PSA system, where CO₂ was separated. Finally, SNG was compressed to 60 bar, enabling its injection into the high-pressure gas transmission system. The stream properties are summarized in

Table 3. Basic parameters of selected streams in the SNG synthesis unit (stream numbering according to Figure 2). Case A: SNG production without CO₂ sequestration.

Stream No.	t, °C	m, kg/h	CH4, %v.	H2, %v	CO2, %v	H2O, %v
1001	35	20,610	6.5	73.1	17.9	0.4
1002	185	45,890	17.6	48.8	12.0	19.5
1007	260	20,610	30.5	20.4	5.6	41.8
1008	431	20,610	35.1	7.3	2.2	52.8
1010	284	20,610	39.7	1.1	1.7	56.8
1017	35	7289	95.3	2.7	0.4	0.0
1018	118	787	0.0	0.0	99.0	1.0
1019	109	11,984	0.0	0.0	0.0	100.0

.

2.4. Process Assumption for the SNG Production System

An analysis of the potential for producing synthetic natural gas (SNG) from biomass was carried out using results obtained from a process model developed in the ChemCAD simulation environment. This model represents an SNG production system integrated with biomass gasification, raw gas treatment, SNG synthesis, and water electrolysis. The model enables the evaluation of key performance indicators for an SNG production facility, such as mass and energy balances, syngas composition, energy consumption, and CO₂ emissions. The overall process flow diagram is shown in Figure 4. For the simulation, a single gasification reactor was assumed, capable of processing 60 tons per hour of raw biomass with a 40% moisture content. With an assumed annual availability of 7884 operating hours, this corresponds to a biomass throughput of 473,040 tons per year. The fuel properties used in the analysis are summarized in

Table 4. Feedstock biomass properties.

Parameter	Symbol	Unit	As Received	Dry	Biomass Feed to the Reactor (20% Moisture)
Coal	C	%	31.42	52.37	41.89
Hydrogen	H	%	2.48	4.13	3.31
Nitrogen	N	%	0.13	0.22	0.17
Sulphur	St	%	0.01	0.02	0.01
Oxygen	O	%	24.26	40.43	32.35
Moisture	Wt	%	40.00	0.00	20.00
Ash	A	%	1.70	2.83	2.27
LHV	Wd	kJ/kg	9742	17,903	13,824
HHV	QS	kJ/kg	11,300	18,833	15,069

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The analyzed SNG production system consists of the following elements:

• An oxygen and nitrogen compression system;
• A biomass drying system;
• A biomass gasification system with gas cooling and purification;
• A CO conversion system;
• A gas cooling system;
• A carbon dioxide removal system (Case B, C);
• A SNG synthesis system;
• A water electrolyzer (Case C, D);
• A char and SNG combustion system (heat production for biomass drying).

The specifications of the technological equipment were chosen based on commercial availability and technological maturity, cost and efficiency, and specific technological characteristics matching fuel characteristics and plant setup.

2.4.1. Oxygen and Fuel Preparation Systems

The analyzed system considers two alternative approaches for oxygen supply. In the first option (Cases A and B), oxygen was delivered from an external source at typical conditions of 32 °C and 8.5 bar and subsequently compressed on site to the operating pressure of 40 bar. In the second option (Cases C and D), oxygen was generated locally using an electrolysis unit. Carbon dioxide recovered during the upgrading of synthesis gas and SNG purification was compressed to 40 bar and employed as a transport medium for fuel injection into the gasification reactor.

Raw biomass was first transferred by a stacker–loader and a belt conveyor system to a vibrating screen for classification into fine and coarse fractions. Before being supplied to the reactor, the biomass was ground and dried. The coarse fraction was conveyed to a crusher via a belt conveyor, while both the fine fraction and the crushed coarse material were transported by belt and bucket conveyors to a drum dryer unit.

Heat for the drying process was supplied indirectly through hot exhaust gases produced by the combustion of char and a portion of the generated SNG [71,72]. The partially dried biomass, with a moisture content of approximately 20%, was then stored in buffer tanks. At that moisture content, biomass LHV remains at about 14MJ/kg, required for efficient conversion in a fluidized bed [42]. Meanwhile, vapors and exhaust gases from the dryer were cleaned of dust before being released into the atmosphere. Energy consumption associated with the mechanical processing of biomass (such as grinding and screening) and its transport to the reactor via conveyors has not been accounted for in the model.

2.4.2. Gasification System

The gasification unit comprises a fuel dosing section, a gasification reactor, and a gas conditioning and cooling section. Dried biomass was transported via belt, bucket, and screw conveyors to the raw material tank. The reactor is equipped with three feeding lines, each capable of handling up to 50% of the reactor’s capacity; under normal conditions they operate at one-third load each. Fuel is delivered to the reactor through screw and pneumatic feeders, with three nozzles introducing it into the fluidized bed. Compressed CO₂ serves as the carrier gas.

The gasification reactor, based on SES (formerly U-Gas) technology, operates as a fluidized bed reactor at 30 bar, using oxygen and steam as gasifying and fluidizing agents supplied to the reactor’s lower section. The hot process gas exits the reactor and passes through two cyclones for solid particle removal. The separated char and ash are recycled to enhance carbon conversion.

Heat contained in the hot synthesis gas (around 1000 °C) is recovered in heat exchangers, generating steam at multiple pressure levels. A portion of the medium-pressure steam is reused internally, while excess steam is expanded in a turbine to generate electricity. After cooling to 180 °C, the gas passes through additional particulate separation and wet scrubbing stages, where inorganic contaminants, nitrogen compounds, and residual hydrocarbons are removed. Scrubber water is continuously recirculated, and the loss is made up by adding water condensed from cooling. A controlled purge stream is sent to wastewater treatment.

2.4.3. Process Gas Cleaning and Conversion

After leaving the gasification unit, the raw gas undergoes CO conversion (CO shift), cooling, desulfurization, and CO₂ separation. The CO-shift stage is crucial, as it supplies about 37% of the hydrogen derived from biomass in the analyzed cases. The incoming gas already contains sufficient moisture, so no additional steam is required (the H₂O/CO molar ratio before the shift must exceed 2).

Because low temperatures favor higher CO conversion but slower reaction rates, a two-stage process—with high- and low-temperature reactors and interstage cooling—is used [72,73,74]. In this setup, gas from the first stage is cooled to about 200 °C before entering the second (low-temperature) reactor. The cooling step also produces medium-pressure superheated steam (60 bar), which is used for power generation.

The shifted gas is then reheated to around 360 °C using this steam and passes through a ZnFe₂O₄ bed for deep desulfurization [75]. To achieve the proper gas composition for SNG synthesis, part of the CO₂ is removed and/or external hydrogen is added. In this analysis, the gas composition entering the SNG synthesis unit is assumed to match the stoichiometric requirements of the reaction.

$${\mathrm{C}\mathrm{O}}_2+{4\mathrm{H}}_2\leftrightarrow {\mathrm{C}\mathrm{H}}_4+{2\mathrm{H}}_2\mathrm{O} ∆\mathrm{H}=-165 \mathrm{k}\mathrm{J}/\mathrm{m}\mathrm{o}\mathrm{l}$$

As a result, a high-purity carbon dioxide stream (typically exceeding 99% concentration) is obtained as a by-product, which can be sold, transported, or stored. Given the pressures at which the gas exits the gasification reactor, physical absorption is the most energy-efficient CO₂ separation method. For this analysis, CO₂ capture using Selexol technology—with an assumed separation efficiency of 92%—was selected.

To ensure effective CO₂ removal, the gas must be cooled to approximately 35 °C before absorption. This cooling occurs in three stages: during the process, low-pressure steam (4.5 bar) is generated, feedwater is heated to about 100 °C, and an external water coolant is utilized.

2.4.4. SNG Synthesis

The methanation system consists of three reactors connected in series, where the catalytic conversion of carbon oxides and hydrogen into methane takes place [76,77] (Figure 2). Typically, nickel-based catalysts are used in the process [76].

After the first reactor, the resulting mixture of methane and unreacted gases is cooled to approximately 260 °C (production of superheated steam at 60 bar) and partially recirculated to increase the hydrogen conversion rate and to control the process temperature so that it does not exceed 700 °C. The gas is then directed to the next reactor and, after leaving the reaction zone, is again cooled to 260 °C (production of superheated steam at 60 bar). After the final reactor, the gas is cooled to 140 °C (for steam generation at 5 bar) and then to 35 °C (boiler feedwater heating to 100 °C). It is subsequently directed to the moisture removal units (via condensation and molecular sieves) and to the PSA unit, where the remaining CO₂ is removed. The resulting methane, with a purity of approximately 97%, is then compressed to 60 bar before being fed into the natural gas transmission system.

See also Section 2.3.

2.4.5. Electrolyzer

In Cases C and D, the calculations assume an alkaline electrolyzer with parameters based on the GHS (Green Hydrogen Systems, X Series) technology. The basic parameters of the electrolyzer are presented in

Table 5. Basic parameters of alkaline electrolyzer: GHS-X SERIES ¹.

Parameter	Unit	Value
Demineralized water consumption	kg/kg H2	<9.1
H2 purity	% vol	99.97
Stack efficiency	kWh/kg H2	51.9
System efficiency	kWh/kg H2	54.7

¹ Green Hydrogen Systems.

.

2.4.6. Additional Units

Before being transported to a storage location, carbon dioxide leaving the Selexol system is compressed to 100 bar with a multistage compressor.

There are three types of superheated steam produced in the system, with pressures of 60, 18, and 4.5 bar. According to the calculations, turbine systems are able to generate power ranging from 15.2 to 38.4 Mwe, depending on the considered case. Auxiliaries in this system include the use of boiler water compression and an additional combustion boiler. The boiler is used to combust gasification char and part of the produced SNG to generate the heat needed to dry biomass. A summary of the system configuration data is shown in

Table 6. Plant specification and assumptions for the considered production scenarios.

Specification	Unit	Values
Oxidant production
Oxygen production	-	Case A, B: O2 is produced outside of the considered model; Inlet parameters: 32 °C/8.5 bar; Oxygen purity: 98.95% vol. Case C, D: O2 is produced in electrolyzer system model; Assumed oxygen purity: 100% vol
Oxygen compression	-	Three-step compressor with inter stage cooling Outlet O2 pressure: 40 bar
Gasification island
Reactor	-	SES fluidized bed
Pressure	bar	30
Ratio O2/C	kg O2/kg C	0.8 (calculated) 0.33 with respect to biomass mass stream (calculated)
Ratio steam/C	kg H2O/kg C	1.0 (calculated) 0.42 with respect to biomass mass stream (calculated)
Carbon conversion	%	95.0
Syngas LHV	kJ/Nm3	7624 1 (calculated, dry)
CGE (cold gas efficiency)	%	71 1 (based on LHV)
Gas cooling	-	Convective cooling, produced steam at 60 and 18 bar
Gasifying agent	-	Oxygen Steam 60 bar (produced in the system)
Fuel	-	Dried biomass (20% m. moisture content)
Fuel transport gas	-	CO2, 7500 kg/h
Initial gas processing	-	Cyclones, water scrubber
Gas conditioning and WGS reactor
WGS (CO conversion)	-	Two-step reactor, CO conversion: 95.2% (calculated)
Desulphurization	-	Adsorption ZnFeO4
Claus process	-	Not included
CO2 separation (if included)	-	Selexol, effectiveness: 63 (Case C)–78% (Case B)
SNG synthesis
Configuration (see also Figure 3)	-	Three reactors connected in series Partial recirculation of the produced gas after first reactor; Recirculation ratio 55%
Gas cooling		Convective coolers, steam production (60, 4.5 bar) and BFW heating (105 °C)
Gas composition at the system inlet	-	CO2/H2: 4/1
Hydrogen conversion	%	99 (calculated)
SNG purity	%	95 (calculated)
Biomass drying
Heat source	-	Combustion of char and part of SNG produced
Final moisture content	% m.	20%
Additional units
Energy production	-	Steam turbine, 60/18/4 bar
Cooling water	°C	15/26
CO2 compression	-	Seven-step compression unit with interstage cooling Outlet CO2 parameters: 100 bar/20 °C

¹ Raw gas after gasification reactor.

.

2.5. Production Cost Calculation—Methodology

The basic economic parameters used to estimate the costs of SNG and electricity production are given in

Table 7. Basic economic assumptions.

Parameter	Value	Comment
Biomass price	6.66 EUR/GJ	Price assumed according to market pricing, average for 2024 [78]
Capacity factor	90%	Yearly availability, according to DOE/NETL [79]
Oxygen price	83.9 USD/t	Based on own data for commercial use
Carbon Dioxide price	83.9 USD/t	Based on own data for commercial use
Electricity price	311.29 PLN/MWh	Monthly market electricity price, Polish market, average price for 2024 [51]
Carbon tax	66.47 EUR/t CO2	CO2 Emissions Futures Contracts, average for 2024 [80]
USD and EUR valued in a year	2023, December	rate EUR/PLN: 4.3065 rate USD/PLN: 3.9799 Average rates NBP 1, 2024 [81]
Operation and maintenance costs	4.3 to 5.8% of total investment cost	Calculated separately for each case, including chemicals, water, waste disposal, insurance, tax, renewals [79].
CO2 transport and storage costs	USD 42.11/t	Calculated using data acquired for year 2024, including rail transport, ship transport and storage in Northern Sea location [82,83]

¹ NBP: Central Bank of the Republic of Poland.

. This table contains data on the main costs related to the operation of the installation, and the values presented were determined based on market price analyses and source materials.

The capital expenditure (CAPEX) calculations were conducted using an exponential investment assessment and price growth index method. As previously demonstrated in [84], the methodological approach employed in these calculations has already been outlined in preceding analyses. As demonstrated in

Table 8. Parameters used to estimate purchased equipment cost.

No.	Plant Component	Scaling Parameter S0	S0 Value	Unit	Scale Factor f	Co [mln USD] 1	Base Year	Source
1	Biomass processing and drying	Raw biomass feed	83,333	kg/h	0.75	3.840	2005	[86]
2	Gasification island (gasifier, syngas cooler, preliminary gas cleaning, fines/ash handling)	Therma input (fuel)	258	MWth	0.67	18.498	2017	[87]
3	CO2 compression (transport gas)	Compression power	10	MWe	0.67	1.260 2	2002	[88]
4	O2 compression	Compression power	10	MWe	0.67	1.690 2	2002	[88]
5	CO2 drying and compression	Compression power	13	MWe	0.67	3.968 2	2002	[88]
6	CO shift	Gas stream	161	Mg/h	0.67	0.866	2005	[86]
7	Sulphur removal, adsorption	Sour gas stream	81	Mg/h	0.67	1.204	2005	[86]
8	Selexol (CO2 removal)	Pure CO2 captured	327	Mg/h	0.67	8.800 2	2002	[88]
9	SNG synthesis 3	Thermal output, SNG	175	MWth	0.67	6.376	2012	[77,89]
10	Off gas boiler	Therma input (fuel)	236	MWth	0.67	8.222	2007	[79]
11	BFWP 4	Water stream	158,425	kg/h	0.33	0.096	2005	[86]
12	Steam turbine	ST gross power	136	MWe	0.67	15.871 2	2002	[88]
13	Electrolysis	Power input	50	MWe	0.73	17.765	2024	[90]

¹ Equipment purchase cost. ² Cost of equipment calculated from overnight capital costs using Peters and Timmerhaus factors. ³ Catalyst initial fill included. ⁴ Boiler feed water pump.

, the base scales and scaling exponents for the components of the production facilities were derived based on both literature data and in-house expertise, while capital expenditures specified for the base year were calculated for the current year using CEPCI (see Figure 5 for details). The calculation of total investment costs (TICs) was performed by applying the Peters and Timmerhaus factors, as detailed in

Table 9. Factors for total investment cost estimation [54].

Investment Cost Component	% of TPEC
Total purchased equipment cost (TPEC)	100.0
Purchased equipment installation	39
Instrumentation and controls	26
Piping	31
Electrical systems	10
Buildings (including services)	29
Yard improvements	12
Total installed cost (TIC)	247.0
Indirect costs
Engineering	32
Construction	34
Legal and contractors’ fees	23
Project contingency	37
Total indirect costs	126.0
Total project investment	373.0

[85].

Levelized Cost of SNG Production (LCOSNG) Calculation Methodology

LCOSNG calculations were performed based on the LCOE (levelized cost of energy) calculation methodology according to the Cost Estimation Methodology for NETL Assessments of Power Plant Performance [79]. The adopted methodology was similar to the methodology used for the Levelized Cost of Hydrogen Production calculation presented in a previous analysis [42] and the Levelized Cost of CO₂ Capture presented in [84].

Table 10. Basic assumptions for LCOSNG calculation methodology.

Parameter	Value	Notes
%Equity	50%	Assumed share of equity and debt for the analyzed project, following NETL assumptions [91]
%Debt	50%
requity	10%	Assumed following NETL assumptions [91]
rdebt	6.5%	Assuming average value of WIBOR 6 M 1 factor 4.5% + margin 2% [92]
ETR	19%	Average CIT 2 value for Polish market [93]
dn	5%	Average straight-line depreciation rate for period of 20 years
z	20
y	30	Assumed following NETL assumptions [91]
i	2.5%	The long-term average annual dynamics of the CPI index were adopted in accordance with the guidelines for the use of uniform macroeconomic indicators [94]

¹ WIBOR—Warsaw Interbank Offer Rate—Polish indicator representing interest rate on loans between banks, usually defines base value for variable interest rate on loans. ² CIT—Corporate Income Tax.

presents the assumptions adopted for the LCOSNG calculations.

3. Results

3.1. Gasification Reactor

The mass and energy balance of the gasification system is presented in

Table 11. Mass and energy balance in the gasification reactor.

Stream	t [°C]	p [bar]	Mass Flow [kg/h]	Chemical Enthalpy [MW]	Physical Enthalpy [MW]	Total [MW]
Biomass 1	43.4	1.0	45,141.0	188.3	1.4	189.7
Oxygen (99% v.)	47.2	40.0	15,220.0	0.0	0.0	0.0
Transport gas (CO2)	100.0	40.0	7500.0	0.0	0.1	0.1
Natural gas (steam reformer)	25.0	2.0	665.2	10.3	0.0	10.3
BFW, 60 bar	100.0	60.0	36,926.1	0.0	3.1	3.1
BFW, 18 bar	100.0	18.0	5246.0	0.0	0.5	0.5
Process water (scrubber)	61.1	35.0	2800.0	0.0	0.1	0.1
Total input	-	-	110,833.0	188.3	5.2	193.5
Process gas	178.7	27.1	86,450.2	139.8	20.9	160.7
Steam, 60 bar	540.0	60.7	15,926.1	0.0	15.1	15.1
Steam, 18 bar	227.5	18.2	5246.0	0.0	4.0	4.0
Char	25.0	1.2	1962.6	8.6	0.0	8.6
Waste water (from scrubber)	179.9	27.1	1248.2	-	0.2	0.2
Losses 2	-	-	-	-	-	4.9
Total output			110,832.2	148.3	40.2	193.5

¹ Moisture content: 20%. ² Heat losses (reactor: 2% of the fuel chemical enthalpy; heat loss due to char cooling and other processes).

. The system consists of a gasification reactor, raw gas cooling (production of steam at 60 and 18 bar), and a gas scrubber.

The gasification of 45.1 t/h of semi-dried biomass produces 86.5 t/h of raw syngas. The process also generates 34.9 t/h of steam at 60 bar and 5.2 t/h at 18 bar. After satisfying the steam demand of the gasification reactor, a net steam output of 15.9 t/h at 60 bar remains available. The solid residue from the gasification process (char) contains 48 wt.% elemental carbon, assuming an elemental carbon conversion of 98%, and exhibits a lower heating value of 15.7 MJ/kg. This char is utilized to supply thermal energy for biomass drying. Following wet gas cleaning in a scrubber, the entire raw gas stream is directed to the water–gas shift (WGS) unit, where carbon monoxide is converted to enhance hydrogen production. The cold gas efficiency of the gasification process, based on the lower heating value, is 71%. The characteristic properties of the cleaned raw gas at the gasifier outlet are reported in

Table 12. Raw gas characteristics.

Parameter	Unit	Value
Gas yield	kg/h	86,450
Temperature	°C	179
Pressure	bar	27
LHV (HHV)	MJ/kg	4.90 (5.82)
Gas composition	% vol.
CO		16.4
CO2		24.0
H2		20.1
H2O		28.8
N2		0.1
CH4		3.2
Ar		0.1

.

3.2. SNG Production Plant

Figure 6, Figure 7 and Figure 8 present a schematic diagram of the production plant as well as the calculated values of the most important streams for the analyzed scenarios. The gasification reactor remains unchanged in all three scenarios; therefore, its cold gas efficiency stays constant at 71%. The SNG production efficiency for all analyzed cases is comparable and amounts to approximately 57% (for Cases C and D, the calculations also include the electricity consumed for hydrogen production in electrolyzers). In all cases efficiency is also comparable with other research detailed in Table 2. Slightly lower values compared to some recent studies may be attributed to the use of fuels with very high calorific value that do not require drying [34,44,45,46,47], or to accounting approaches in which not only the chemical enthalpy of the produced SNG but also the generated heat is included as a useful product [45]. In Cases A and B, the SNG production rate equals 7821 kg/h. The addition of extra hydrogen to the synthesis section increased the SNG output to 10,781 kg/h and 25,857 kg/h for Cases C and D, respectively.

Selected calculation results for all cases are summarized in

Table 13. Comparison of process parameters and emitted CO₂ for different SNG production plant configurations.

No	Parameter	Unit	Case A w/o CCS	Case B w/CCS 1	Case C w/CCS_El1 1	Case D El2
1	Biomass
	▪ Flow	kg/h	60,000.00	60,000.00	60,000.00	60,000.00
	▪ Chemical enthalpy	MWth	188.33 2	188.33	188.33	188.33
2	Cold Gas Efficiency 3	%	74.20	74.20	74.20	74.20
3	Electric energy
	▪ Nominal power input	MW	15.16	15.16	19.73	38.37
	▪ Power requirements	MW	5.02	7.67	11.50	24.79
	▪ Electrolizer power requirements	MW	0.00	0.00	102.62	516.92
	▪ Net production 4	GWh	79.95	59.01	−744.21	−3968.31
	▪ Energy usage	kWh/kg SNG	0.69	1.05	10.59
4	Water/steam requirements ▪ BFW ▪ Cooling water	kg/h kg/h	119,634.61 33,622.31	119,634.61 38,243.43	103,647.58 57,603.00	72,451.09 101,588.85
5	SNG production
	▪ Net production	kg/h	7821.27	7821.44	10,781.15	25,857.11
		t/y	57,405.57	57,406.87	84,998.57	203,857.43
	▪ SNG to biomass	kg/Mg biomass	121.35	121.36	179.69	430.95
	▪ SNG efficiency 5	%	57.3 5	57.3 5	56.9 6	56.58 6
6	CO2 emission
	▪ CO2 separated	kg/h	45,103.06	45,101.75	35,039.57	0.00
	▪ Total in situ CO2 emissions (SNG production)	kg/h	49,997.96	4894.97	4938.27	4941.58
	▪ CO2 emissions due to energy consumption 7	kg/h	−6054,25	−4468.26	56,353.68	300,492.11
	▪ Total yearly emissions	Mg/y	394,184.95	38,591.97	38,591.31	38,959.41
	▪ Total yearly emissions including energy production	Mg/y	346,452.22	−7906.34	483,225.72	2,408,039.23
	▪ Net CO2 emissions	kg/h	−6054.25	−49,570.01	21,314.00	300,492.11
		t/y	−47,731.73	−390,809.95	168,040.44	2,369,079.820.00
7	Emission factors ▪ Total emission from the plant	kg CO2/kg SNG	6.04	−6.14	2.44	11.81
	▪ Total emissions from the plant assuming zero CO2 emissions from biomass processing	kg CO2/kg SNG	−0.83	−6.81	1.98	11.62
8	Carbon capture efficiency 8	%	0.00	65.24	50.69	0.00
9	Carbon capture efficiency including chemical sequestration 9	%	27.67	92.92	92.86	92.85

¹ The CO₂ released in the production process is compressed and prepared for transport. ² Heat of combustion—HHV. ³ Ratio of the chemical enthalpy of the process gas (after the gasification reactor) to biomass (heat of combustion). ⁴ Annual production (plant availability: 90%). ⁵ Ratio of the chemical enthalpy of SNG to the chemical enthalpy of biomass (heat of combustion). ⁶ Electrolyzer power requirements included. ⁷ 597 kg CO₂/MWh [66]. ⁸ Efficiency of CO₂ removal in relation to the carbon content in the fuel (efficiency of CO₂ removal from the process gas—92%). ⁹ Efficiency of CO₂ removal including CO₂ used for SNG synthesis.

.

In response to increasingly stringent greenhouse gas emission regulations, advanced technologies are required to comply with strict limits on CO₂ emissions. Accordingly, all simulated scenarios were evaluated to quantify their CO₂ emissions and to examine the potential for achieving carbon-neutral or even carbon-negative performance during synthetic natural gas (SNG) production. The assessment accounts for process-related emissions arising from SNG generation as well as the carbon intensity of the electricity consumed (see also point 2.1). Under the assumption that biomass processing is CO₂-neutral, the calculated carbon footprint across the analyzed cases varied between –6.81 and 11.62 kg CO₂ per kg of SNG. Negative emissions were obtained for Cases A and B. In Case A, they resulted from surplus electricity generation, while in Case B they mainly originated from system integration with CO₂ capture. Relatively high emission intensities for the cases integrated with electrolyzers stem from the high energy consumption required for water electrolysis and from the assumption that the electrolyzers are powered by grid electricity with a carbon footprint of 597 kg CO₂/MWh [95] (the average electricity emission factor in Poland in 2023).

Using low-emission electricity with a carbon intensity of 100 kg CO₂/MWh (EU taxonomy limit) or zero-emission renewable electricity significantly reduces the carbon footprint of SNG produced in Cases C and D. In contrast, for Cases A and B, the overall process emission intensity increases because the negative emission effect from surplus electricity generation is reduced. Figure 9 presents a comparison of SNG production emission intensities for three levels of electricity carbon footprint: 597, 100, and 0 kg CO₂/MWh.

3.3. Results of Economic Calculations

In the next stage of the analysis, capital expenditure and operating costs (CAPEX, OPEX) were determined and the cost of SNG production (average cost of SNG production, LCOSNG) was estimated. The calculations were performed according to the methodology and assumptions outlined in Section 2 and presented in the previous analyses [54,69], as well as material and energy balances, main process streams characteristics, and investment cost estimates. The results of the calculations are presented in

Table 14. Economic calculation results for analyzed cases of SNG production systems integrated with biomass gasification.

Parameter	Case A w/o CCS	Case B w/CCS	Case C w/CCS_El1	Case D El2
	mln USD 2024 (USD/kWHHv)	mln USD, 2024 (USD/kWHHv)	mln USD, 2024 (USD/kWHHv)	mln USD, 2024 (USD/kWHHv)
CAPEX	193.49 (1793.48)	203.80 (1889.05)	322.35 (2017.97)	595.96 (1555.56)
OPEX total	56.84 (526.85)	38.2 (447.06)	107.61 (673.66)	342.48 (893.94)
▪ Raw materials	51.96 (481.65)	51.96 (481.64)	41.90 (262.28)	5.68 (14.82)
− Biomass	41.90 (388.35)	41.90 (388.34)	41.90 (262.28)	41.90 (109.36)
− Carbon Dioxide and Oxygen	10.07 (93.30)	10.07 (93.30)	-	−36.22 (−94.53)
▪ Media, Energy, media, chemicals, T&S and environmental costs	−3.96 (−36.71)	−12.91 (−119.66)	52.60 (329.28)	314.60 (821.17)
− CO2 emission allowances	-	−25.58 (−237.06)	−19.87 (−124.38)	-
− Electricity	−6.25 (−57.97)	−4.61 (−42.77)	58.20 (364.34)	310.33 (810.02)
− Others	2.29 (21.25)	17.28 (160.17)	14.27 (89.33)	4.27 (11.15)
▪ Fixed costs (including O&M costs)	8.84 (81.91)	9.18 (85.08)	13.12 (82.10)	22.20 (57.94)
LCOSNG (USD/MWhSNG)	107.66	95.81	134.32	164.61

.

Results show that implementation of CO₂ compression, transport and storage allows the reduction of the levelized cost of SNG production by approximately USD 12/MWh SNG, representing an 11% decrease (from USD 107.66/MWh SNG to USD 95.81/MWh SNG). The calculated cost of SNG production is in line with the ranges resulting from previous publications [34,45,46,49]. This decrease accounts for revenues from the sale of CO₂ emission allowances due to negative CO₂ emissions, despite high CO₂ transport and storage costs resulting in increased OPEX. Implementation of H₂ production using electrolysis technology results in a significant increase in SNG production cost, despite its higher SNG production efficiency, mainly due to a high cost of electricity required for the electrolysis process. The production cost structure for the analyzed cases is presented in Figure 10.

As shown in Figure 10, the structure of SNG production cost can vary significantly for different case scenarios. The obtained SNG production cost for the most feasible case (Case B) is more than double the natural gas prices presented by TGE for BASE_Y-25 contracts in 2024 [96], which were equal to USD 45.65/MWh. Despite the increased costs of SNG production compared to natural gas prices, the biggest advantage for the analyzed technology is the possibility of reliable local SNG production using local resources, regardless of the current natural gas market situation. This can be easily compared to the situation in 2022, when natural gas shortages caused a sharp price rise. Natural gas prices presented by TGE for BASE_Y-23 contracts in year 2022 had an average price of USD 132.64/MWh with a price spike of USD 229.81/MWh in August 2022. An additional advantage of using biomass for hydrogen production is negative CO₂ emissions, which can lead to negative SNG production costs. The simulation shows that for the analyzed Case B, the LCOSNG becomes negative for CO₂ emission allowances prices exceeding USD 251/Mg (Figure 11).

Sensitivity analysis of the LCOSNG performed in the range of −30% to +50% is presented in Figure 12. The analysis shows the impact of biomass purchase costs, CO₂ emission allowance prices, electricity prices, and investment outlays on the percentage change in LCOSNG.

CO₂ transport and storage costs are a significant component of the SNG production cost; thus, sensitivity analysis for the LCOSNG cost impact was performed separately (Figure 13).

Analysis of Case D showed that the cost of electricity accounts for over 80% of the levelized cost of SNG production for Case D. Thus, minimizing electricity costs can play a major role in lowering the price of SNG production. Simulation of the impact of the price of electricity on the cost of SNG production is shown in Figure 14. For an electricity price of 0 PLN/MWh, LCOSNG drops below USD 33/MWh.

4. Conclusions

This paper presents and analyzes the potential for producing synthetic natural gas (SNG) using biomass fluidized-bed gasification technology, based on a commercial solution offered by Synthesis Energy Systems. The possibility of integrating the system with an electrolyzer installation was also investigated. The analysis was carried out for a gasification unit with a capacity of 188 MWth (raw biomass feed rate of 60 Mg/h). In the case of integration with an electrolyzer, two power levels were proposed: the first (103 MWe) to meet the oxygen demand of the gasification process, and the second (517 MWe) to eliminate the need for CO₂ separation prior to the SNG synthesis section.

Depending on the analyzed case, the SNG production rate varied between 188 (Cases A and B) and 621 Mg/day (Case D).

Under the assumed scale and configuration, the cost of SNG production ranged from 95 to 168 USD/MWSNG, exceeding current market prices of natural gas. For the biomass gasification system with CO₂ separation (Case B), it is possible to significantly reduce production costs as the price of CO₂ emission allowances increases. When the allowance price reaches 170 USD/Mg CO₂, the cost of SNG production falls to the current market price of natural gas, and at 251 USD/Mg CO₂, production costs can effectively reach zero.

The high production costs of systems integrated with electrolyzers result primarily from electricity consumption and its associated cost, which in Case D accounts for up to 80% of the total production cost. Improving the environmental and economic performance of these systems would require integration with on-site renewable energy generation, assuming that the additional investment costs would have a much smaller impact on production costs than purchasing electricity from the grid.

An important aspect of the analysis was the assessment of SNG production emissions for the considered technological variants. When grid electricity with a carbon intensity typical for Polish conditions is used, only the configurations not integrated with electrolyzers achieve net negative CO₂ emissions. Integration (Cases C and D) leads to a significant increase in the carbon intensity of the produced SNG, exceeding the carbon footprint associated with the extraction and transport of natural gas (upstream natural gas emissions: 9.7 g CO₂e/MJ).

Considering a CO₂ intensity of 100 kg/MWhe (the average value for electricity generation between 2020 and 2050, consistent with the EU’s target of achieving net-zero emissions by 2050), a significant reduction in CO₂ emissions is observed. The resulting emission levels were −2.37 and 1.95, respectively, for Cases C and D.

Although the integration of SNG production systems with water electrolysis is currently limited to pilot and demonstration installations, several factors indicate a realistic potential for their deployment at an industrial scale. First, both key subsystems—biomass gasification in fluidized beds and large-scale water electrolysis—are based on technologies that, when considered separately, have already reached high levels of technological maturity. Recent industrial projects confirm the technical feasibility of electrolyzers with capacities exceeding hundreds of megawatts [97], while the anticipated development of fifth-generation electrolyzers over the 2020–2050 horizon assumes achievable capacities at the gigawatt scale, accompanied by a significant reduction in capital expenditures and an increase in hydrogen production efficiency [53]. Consequently, the main challenge is not technological feasibility itself, but rather system-level integration and optimization of the combined operation of these technologies. In addition, ensuring stable access to low-cost, low-carbon electricity is essential to justify large-scale integration. From a process perspective, further challenges include stable operation at high annual availability, as well as efficient utilization of by-product oxygen and waste heat. In parallel, regulatory frameworks, CO₂ accounting methodologies, and support schemes for low- or negative-emission fuels will play a crucial role in enabling large-scale deployment. Overcoming these technical, economic, and regulatory barriers is key to transitioning integrated gasification–electrolysis–SNG systems from the demonstration stage to commercial implementation.

Moreover, the effective development of biomass gasification systems integrated with water electrolyzers to produce low-emission hydrogen or synthetic fuels will depend on the availability of feedstock and the advancement of infrastructure for CO₂ transport and storage.

In the case of Poland, there appears to be significant potential in woody biomass, which represents the most suitable feedstock for gasification processes. It is estimated at 13–16 million cubic meters per year [98].

It should also be noted that work on the development of CCS technologies related to CO₂ transport and storage has intensified. In Europe, an example is the Northern Lights project, which plans to demonstrate a system with a capacity of 3 million tons of CO₂ per year in the near future, as well as a joint Polish–Lithuanian initiative aimed at developing CO₂ transport infrastructure between 2025 and 2030 [77,85,99].