Towards Carbon-Neutral Hydrogen: Integrating Methane Pyrolysis with Geothermal Energy

Abstract

Methane pyrolysis produces hydrogen (H₂) with solid carbon black as a co-product, eliminating direct CO₂ emissions and enabling a low-carbon supply when combined with renewable or low-carbon heat sources. In this study, we propose a hybrid geothermal pyrolysis configuration in which an enhanced geothermal system (EGS) provides base-load preheating and isothermal holding, while either electrical or solar–thermal input supplies the final temperature rise to the catalytic set-point. The work addresses four main objectives: (i) integrating field-scale geothermal operating envelopes to define heat-integration targets and duty splits; (ii) assessing scalability through high-pressure reactor design, thermal management, and carbon separation strategies that preserve co-product value; (iii) developing a techno-economic analysis (TEA) framework that lists CAPEX and OPEX, incorporates carbon pricing and credits, and evaluates dual-product economics for hydrogen and carbon black; and (iv) reorganizing state-of-the-art advances chronologically, linking molten media demonstrations, catalyst development, and integration studies. The process synthesis shows that allocating geothermal heat to the largest heat-capacity streams (feed, recycle, and melt/salt hold) reduces electric top-up demand and stabilizes reactor operation, thereby mitigating coking, sintering, and broad particle size distributions. High-pressure operation improves the hydrogen yield and equipment compactness, but it also requires corrosion-resistant materials and careful thermal-stress management. The TEA indicates that the levelized cost of hydrogen is primarily influenced by two factors: (a) electric duty and the carbon intensity of power, and (b) the achievable price and specifications of the carbon co-product. Secondary drivers include the methane price, geothermal capacity factor, and overall conversion and selectivity. Overall, geothermal-assisted methane pyrolysis emerges as a practical pathway to turquoise hydrogen, if the carbon quality is maintained and heat integration is optimized. The study offers design principles and reporting guidelines intended to accelerate pilot-scale deployment.

1. Introduction and State-of-the-Art (Chronological)

Hydrogen plays a critical role in decarbonization across the chemical, energy, and industrial sectors. The current dominant production route, which is known as steam methane reforming (SMR), generates substantial CO₂ emissions unless combined with carbon capture and storage (CCS). Methane pyrolysis, often referred to as turquoise hydrogen, offers an alternative by splitting CH₄ into H₂ and solid carbon. This eliminates direct-process CO₂ emissions and enables a dual-product model when the carbon meets carbon black specifications [1,2,3,4,5].

Unlike electrolysis, which relies heavily on electricity, pyrolysis depends primarily on high-temperature heat to drive the reaction. When this heat is sourced from a low-carbon supply and the carbon co-product is valorized, the levelized cost of hydrogen (LCOH) can be competitive with other low-carbon production pathways [6,7,8,9,10,11].

Two technical challenges currently define the large-scale readiness of methane pyrolysis. The first is delivering and controlling thermal energy in the 600 to 900 °C range to sustain high conversion and selectivity while avoiding catalyst deactivation. The second is separating and handling solid carbon in ways that protect downstream equipment and preserve the co-product’s commercial value [12,13,14,15,16].

This study addresses both challenges. For the heat supply, we evaluate a hybrid geothermal pyrolysis configuration in which an enhanced geothermal system (EGS) provides baseload preheating and isothermal holding, while electrical or solar–thermal input supplies the final temperature rise and manages transients. For carbon management, we synthesize the findings from molten-media and gas-phase systems on particle formation, disengagement, and polishing strategies aimed at producing high quality carbon black [2,9,15,17].

1.1. Why Turquoise Hydrogen Now?

Recent field-scale integration studies and reviews identify three dominant levers influencing the levelized cost of hydrogen (LCOH): the specific electric duty, the price and specifications of the carbon co-product, and the methane feedstock price. These factors are further shaped by policy credits and the availability of site-specific heat resources [18,19,20,21,22].

Geothermal preheating can lower the electric top-up requirements and stabilize reactor temperatures, which both (a) mitigate the coking and sintering dynamics and (b) narrow the particle-size distributions upstream of cyclones and filters. Together, these effects enhance the potential to capture a higher carbon value. Recent system analyses of the baseload and flexible EGS thermal delivery define the operating envelopes needed to establish realistic heat-integration targets and capacity factors [23], while standard geothermal reservoir design practices provide complementary guidance [10,24].

1.2. State-of-the-Art Chronology

Between 2015 and 2017, methane-pyrolysis research moved molten-media concepts from theoretical studies to laboratory-scale bubble-column experiments, clarifying gas–liquid mass transfer, reaction zones, and initial carbon-separation strategies. A landmark study on molten-metal catalysis demonstrated direct CH₄-to-H₂ conversion with separable carbon, sparking modern interest in turquoise hydrogen. Early techno-economic analyses established the strong sensitivity of costs to the power demand and carbon value, laying the foundation for subsequent TEA frameworks [15,16,17,18,19,20,21,25].

From 2019 to 2021, the research broadened to kinetics, catalyst families (Ni/Fe/Co and doped systems), and deactivation modes, while reviews consolidated operating-temperature windows (approximately 600 to 900 °C) and compared methane pyrolysis with SMR + CCS for its potential long-term role in hydrogen systems. Process-level investigations sharpened our understanding of molten-salt and liquid-metal operation, linking carbon morphology to downstream handling, and an industrial perspective emerged that framed turquoise hydrogen as complementary to, rather than a replacement for, other production routes [26,27,28,29].

The progress from 2022 to 2023 emphasized scale-relevant engineering and carbon management. Comparative reactor studies contrasted gas-phase and molten-tin bubbling systems under a solar input, showing how temperature uniformity influences particle size and filtration load, while reviews and mini-reviews highlighted the advances in molten-media technology and product-quality control [1,2,13]. Parallel efforts examined plasma- and H₂-combustion-heated pyrolysis for simplified, CO₂-free heat delivery and cyclone-design literature was applied to define disengagement and polishing trains for carbon-laden off-gas [7,15]. Most recently, in 2024–2025, integration efforts expanded to high-pressure kinetics and predictive catalytic models that link laboratory selectivity with pilot-scale reactors [16,19]. System-level studies characterized enhanced-geothermal-system (EGS) power delivery for hybrid heat trains and extended techno-economic analyses to ammonia contexts and dual-product revenue stacking (H₂ plus carbon) [26]. Collectively, these developments signal a transition from proof-of-concept to site-coupled process engineering, positioning geothermal-assisted pyrolysis as a concrete candidate for FEED-level design [29,30,31,32,33,34].

Building on this progression, the present work advances the field in four ways; First, it develops a heat-integration blueprint grounded in real EGS operating envelopes, in which geothermal energy provides a preheat and isothermal hold, while electric or solar input delivers the final temperature rise and control flexibility [22,23,24,25]. Second, it offers scalability guidance on high-pressure reactor design, materials, and thermal-stress management, along with operating rules to minimize deactivation and the preserve carbon value. Third, it proposes a techno-economic scaffold that itemizes CAPEX/OPEX, incorporates carbon credits, and quantifies dual-product economics based on established process-design practices and recent turquoise-hydrogen TEAs. Finally, it provides reporting guidelines covering heat-integration choices, reactor details, carbon QA/QC, and financial assumptions to ensure reproducibility and alignment with good engineering practice [5,9,20,21].

2. Concept and Real-World Anchors (EGS → Pyrolysis)

2.1. Process Concept and Duty Split

Dry methane is preheated using an enhanced geothermal system (EGS) loop to approach the catalytic window, and then receives top-up heat (electric resistive or solar–thermal) to reach the reactor setpoint (typically 600 to 900 °C, depending on the reactor/catalyst) [1,2,13,14,33] (see Figure 1).

The reactor can be either (a) a molten-media bubble column (Sn/Bi or molten salts) or (b) a packed/fixed bed. Effluent hydrogen is separated and compressed, and solid carbon is recovered, de-oiled/conditioned, and sent to classification for carbon-black (CB) and related markets [13,14,33] (see Figure 2).

2.2. Heat Integration Logic

▪

Use the EGS to supply base-load sensible heat to the largest heat-capacity streams (fresh methane, recycled flow, and, where applicable, the molten medium for isothermal hold).

▪

Reserve electric/solar inputs for the last ΔT (typically, the final 200 to 300 K into the catalytic window) and for transients (startup, ramping, and turndown) [9,10,22,33].

▪

In composite/pinch terms, place the EGS on the cold streams with the highest $\dot{m}{c}_p$ to maximize the kWth captured per unit of geothermal temperature glide; use short, insulated trim-heater sections to avoid large hot inventories [9,10,22,33].

Indicative split: While site-specific, a practical design target is EGS covering the majority of sensible preheat (e.g., 50–80% of the total sensible duty to the reactor feed/recycle) with the top-up supplying the final approach to the setpoint and transient control [1,2,9,13].

2.3. Why Geothermal Energy?

Geothermal energy offers a reliable and low-carbon heat source by harnessing subsurface reservoirs where water or working fluids circulate through naturally hot rock formations. In enhanced geothermal systems (EGSs), permeability is improved to sustain the fluid flow and deliver a continuous thermal output, a strategy that is increasingly recognized for industrial applications beyond power generation [22,33].

For methane pyrolysis, the EGS can provide a base-load preheat and isothermal hold, thereby reducing the demand for electrical top-up and smoothing reactor temperature profiles, an effect that helps mitigate coking swings, thermal shock, and catalyst stress [13,25]. The predictable capacity factors of modern EGS designs, supported by the established reservoir engineering practice, also make geothermal heat a dependable backbone for hybrid energy systems requiring both a steady and flexible supply. Importantly, maintaining steadier wall and film temperatures improves the carbon-quality management by narrowing the particle-size distributions and reducing agglomeration, which, in turn, eases the cyclone and polishing duties while protecting the downstream compressors, membranes, and heat exchangers [7,9,16]. Recent studies of geothermal integration in high-temperature industrial processes highlight its potential to serve as a practical, scalable partner for emerging clean-fuel pathways, reinforcing the feasibility of geothermal-assisted methane pyrolysis [7,9,33].

2.4. Reactor Options and Operating Envelopes

The molten-media bubble column (e.g., Sn, Bi, or salt systems) offers several operational advantages, including efficient gas–liquid heat transfer, in situ carbon disengagement in the sump or rathole region, and the potential to maintain near-isothermal conditions. This configuration also shows tolerance to moderate feed and recycle fluctuations. From a design standpoint, however, it requires corrosion-resistant alloys, double containment for safety, and systems for melt make-up and conditioning. Effective off-gas disengagement is also necessary in order to protect downstream separation units [15].

Packed or fixed-bed reactors provide a contrasting approach, offering compact hardware, established catalyst handling practices, and straightforward modularization that enables a parallel-train scale-up. Their design must emphasize both the axial and radial thermal uniformity, while carefully managing the pressure drop and carbon removal to prevent sintering and plugging. Stable operation is further supported by using trim heaters with short residence times [1,4,9,12,14].

The setpoint selection typically falls within the 600 to 900 °C range, reflecting trade-offs between kinetics, thermodynamics, and the catalyst family (Ni, Fe, or Co). Operating near the upper end of this range enhances conversion but increases the need for precise isothermal control and effective carbon removal [15].

2.5. Hydrogen Separation and Recycle

The H₂-rich stream is directed to pressure swing adsorption (PSA) or membrane separation, followed by compression. An off-gas recycle loop closes the carbon balance and increases the overall CH₄ conversion, while a controlled purge is maintained to prevent inert accumulation. Geothermal-assisted preheating enhances the thermal stability of the separation system and reduces fluctuations in the compressor power demand by smoothing the reactor output [9,13,22].

2.6. Carbon Handling and Value Preservation

To safeguard the carbon black (CB) quality and protect downstream equipment, handling strategies must combine effective primary disengagement, secondary polishing, and quality control measures. In molten-media systems, primary disengagement is typically achieved using a gravity sump, whereas gas-phase routes rely on a tempered quench followed by cyclonic separation [9,15,17]. After this initial stage, porous-ceramic filters sized to the particle size distribution (PSD) and desired cut size are applied to remove residual particulates. The product is then classified by air-jet or sieving to meet CB specifications. Quality assurance and control should include the routine reporting of the PSD, BET surface area, and volatile or ash content. In addition, oxidation and excessive high-temperature residence times downstream of the reactor must be minimized in order to prevent surface chemistry changes that reduce the CB market value [2,6,7].

2.7. Controls, Start-Up, and Operability

Stable reactor operation depends on robust control systems, structured start-up procedures, and well-defined operability strategies. A dual-loop control scheme is recommended: a slower loop on the EGS supply and return establishes the baseload preheat, while a faster loop at the trim heater manages the final temperature rise (ΔT) and transient events during start-up, ramping, and trip recovery. During start-up, feed and recycle streams should first be heated using the EGS to a safe intermediate temperature before applying trim heat to reach the catalytic setpoint. This approach minimizes overshoot, which can otherwise trigger coking and sintering [13,22,33].

Maintenance envelopes must also be explicitly defined. In fixed-bed systems, carbon deposits should be removed on a scheduled basis. In molten-media systems, sump clearing is required in order to manage carbon accumulation. Filter differential pressures and compressor surge margins must be monitored and kept within conservative limits, supported by appropriate recycling control [6,9,14].

2.8. Site–EGS Coupling and Reporting Guidance

▪

Match the EGS temperature and flow envelope to process the composite curves, and document the capacity factor, expected seasonality, and any flex provision (e.g., curtailed electric top-up or thermal storage if used) [22,33].

▪

For reproducibility, the study should report heat curves, major equipment sizes, duty splits between EGS and trim heat, catalyst or melt compositions, carbon QA/QC metrics, and separation or pressure targets. These disclosures should be aligned with best practices from recent turquoise-hydrogen techno-economic analyses (TEAs) and standard process design methodology [20,21,33].

As a real-world reference point, the Utah FORGE project (Milford, UT, USA) demonstrated the engineered doublet performance in April–May 2024. The injection into well 16A (78)-32 reached rates of up to 15 bpm (≈630 gpm), while production from well 16B (78)-32 achieved up to 8 bpm (≈344 gpm), corresponding to ~70% recovery. The produced fluid exited at ≈139 °C, with reservoir temperatures exceeding ~175 °C at depths of 2 to 2.5 km. These results provide a quantitative basis for defining the baseload EGS preheat window relevant to our integration strategy.

3. Scalability: High-Pressure Design, Thermal Management, and Carbon Separation

3.1. High-Pressure Reactor Design

The operating envelope and scale-up strategy are governed primarily by pressure, temperature, and residence time. Higher pressures compact the hardware by reducing volumetric flow rates and compressor diameters, while also improving downstream hydrogen recovery through more efficient membrane or PSA utilization at a given throughput. However, because the reaction CH₄ → C(s) + 2H₂ increases the number of gas moles, elevated pressure imposes an equilibrium penalty on conversion; this must be counterbalanced by appropriate adjustments in temperature and residence time. In practice, a feed envelope of 10 to 25 bar at 600 to 900 °C has proven workable, with the exact setpoint determined by the catalyst or molten-media system and its deactivation tolerance [1,4,9,13,14].

At high pressure, reactor-specific considerations become critical. In molten-media bubble columns (Sn/Bi/salt systems), an increased gas density raises the risk of bubble coalescence; therefore, the superficial gas velocity should remain in a churn-turbulent regime that sustains fine bubbles without flooding. As a starting point, sparger hole velocities of 5 to 15 m s⁻¹ and an aspect ratio (L/D) of approximately 8 to 15 are recommended, with final parameters confirmed by hydrodynamic testing [9,14,17]. In packed or fixed-bed reactors, high pressure increases the pressure drop across the bed; designers should maintain ΔP/L within blower or compressor head limits while ensuring that the Dam Köhler number Da > 1 at the chosen setpoint. Short trim-heater sections are also advised in order to minimize hot inventory and reduce the risks of sintering and coking [1,4,28].

▪

Kinetic/equilibrium guidance (design checks):

$${\mathrm{K}}_{\mathrm{P}}\left(\mathrm{T}\right)={\displaystyle \frac{{\mathrm{p}}_{{\mathrm{H}}_2}^2}{{\mathrm{p}}_{{\mathrm{C}\mathrm{H}}_4}}}\hspace{1em}{\mathrm{X}}_{\mathrm{e}\mathrm{q}} \mathrm{r}\mathrm{i}\mathrm{s}\mathrm{e}\mathrm{s} \mathrm{s}\mathrm{t}\mathrm{e}\mathrm{e}\mathrm{p}\mathrm{l}\mathrm{y} \mathrm{w}\mathrm{i}\mathrm{t}\mathrm{h} \mathrm{T}$$

(1)

At a chosen pressure, push $\mathrm{T}$ high enough that $\mathrm{X}\mathrm{e}\mathrm{q}$ comfortably exceeds your per-pass target, and then size the residence time so that $Da=k\left(T\right)\tau \gtrsim 1$ with margin. Recycle closes the gap to near-complete overall conversion [1,4,13,14].

Materials selection and containment design for high-pressure and high-temperature (HP/HT) operation must follow code compliance, corrosion resistance, and hydrogen compatibility. Pressure-retaining components should be designed according to ASME Section VIII with allowances for transient thermal cycling and creep at the upper temperature limit, and testable corrosion allowances specified for hot zones and penetrations [9,17,33].

For molten-media services such as Sn/Bi and halide salt systems, corrosion-resistant alloys, a fully welded construction, and double-walled containment with leak detection are essential. Melt make-up and conditioning loops, along with thermal buffers around nozzles, help limit thermal shock and extend component life. In hydrogen service, embrittlement-prone steels should be avoided in high-H₂ areas; instead, austenitic stainless steels or high-nickel alloys are recommended for hot hydrogen environments and for HP separators and compressors [14,15].

Catalyst formulation, geometry, and deactivation management are central to maintaining performance at scale under high-pressure and elevated thermal conditions. Iron- and cobalt-rich catalysts are generally preferred for their robustness and cost effectiveness, whereas nickel offers higher intrinsic activity but demands stricter control of temperature uniformity and carbon removal schedules to mitigate sintering and coking. In fixed-bed applications, radial or segmented distributors combined with graded particle sizes help minimize hot spots and limit pressure-drop growth. In molten systems, introducing inert internals or a controlled swirl enhances the gas–liquid heat transfer without imposing excessive shear [9,14,17].

To slow down the deactivation process, the isothermal operation should be maintained, carbon should be removed on a planned basis (either through sump clearance or bed skimming), and start-up or shutdown heating rates (ΔT/Δt) should be capped in order to protect the active phases [4].

3.2. Thermal Management

Effective energy management in high-temperature systems requires a clear division of duty between external heat sources and trim heating. The enhanced geothermal system (EGS) should be allocated to the largest mass-flow, high-heat-capacity streams to provide a baseload sensible preheat and, in molten-media systems, to sustain an isothermal hold. Electrical or solar trim heating is then applied to cover the final 200 to 300 K temperature rise and to support ramping operations [1,2,13,25].

In typical configurations, the EGS supplies 50 to 80% of the total sensible duty to the reactor feed or recycle stream, while the trim heater provides the remaining duty to achieve the catalytic setpoint and to manage transients. Pinch analysis should be applied to design the heat-exchange network: select a minimum approach temperature (ΔT_min) of 10 to 20 K for compact exchanger trains, and match the EGS duty to the cold composite up to the pinch. The residual trim-heat requirement then becomes a design variable, balancing the capital cost, electrical intensity, and stability of carbon morphology [9,22,33].

On a scale, stability is improved by a dual-loop temperature control strategy. A slow loop regulates the EGS inlet and returns temperatures to maintain the baseload duty on a minutes-to-hours timescale, while a fast loop at heater H-101 trims the reactor skin or bed temperature to suppress hot spots that accelerate catalyst decay and broaden carbon particle-size distributions [7,15].

Start-up should proceed by first warming the feed and recycling streams with EGS heat to an intermediate plateau before applying trim heat to reach the catalytic setpoint. During turndown, trim heat should be reduced first while holding the EGS steady to avoid quenching through the strong-coking regime [13].

Instrumentation should include redundant thermocouple grids or infrared pyrometry on hot surfaces, differential-pressure monitoring across filters and cyclones, classifier load tracking, and compressor surge-margin monitoring. Safety trips are best tied to conservative limits on skin-temperature differentials and filter pressure drops [14,16].

3.3. Carbon Separation and Handling

Inside the reactor, solids management strategies must be adapted to the process configuration. In molten-column systems, a gravity sump or rathole should be included in order to collect agglomerates, with settled carbon skimmed off on a regular schedule. Interfacial shear should be kept low to preserve particle size and prevent unnecessary attrition. In gas-phase or heliostat-based routes, a tempered quench should be applied before solids capture. The quench must be sufficient to halt particle growth and sintering, but not so aggressive as to trigger oxidation, thereby protecting both the particle morphology and downstream equipment [7,9,15,17].

Primary separation and polishing are essential both to secure product quality and to protect downstream equipment. Cyclones should be sized for the target cut size, typically a D₅₀ of 2 to 10 µm, to preserve the carbon black (CB) value using a Stairmand-type geometry. The expected pressure drop should be approximately 1 to 2 kPa at design flow, and the Stokes number should remain within the effective capture regime for the desired PSD. For scale-up, parallel cyclones should be employed. After this stage, porous-ceramic polishing filters should be installed in order to remove fines and safeguard compressors, PSA units, membranes, and heat exchangers. Filters should be designed for face velocities of 1 to 3 cm·s⁻¹, equipped with back-pulsing triggered by differential pressure, and fitted with bypass or swing cartridges to allow continuous operation [15,16].

Finally, maintaining the CB value requires careful post-reactor handling. The product should be kept dry, cool, and oxygen-limited since over-oxidation or graphitization reduces the CB value unless graphite or graphene markets are specifically targeted. Classification should be performed using air-jet or sieve classifiers tuned to CB specifications. QA/QC should include the routine reporting of the PSD (D₁₀/D₅₀/D₉₀), BET surface area, volatile and ash content, and DBP oil absorption (see Figure 3) [4,22,33]. Fugitive emissions control should incorporate enclosed transfer points, slight negative pressure in handling areas, and NFPA-compliant dust collection systems with conductive media suitable for hydrogen service in high-H₂ environments [9,15].

3.4. Practical Design Rules (Ready for the Methods Box)

▪

Pressure and Temperature Setting: Start FEED with 10 to 25 bar, 600 to 900 °C; verify $q(T,P)$ and $Da$; close with recycling.

▪

EGS split target: It should be ≥50% of sensible preheat from EGS; set $\mathrm{\Delta }{T}_{min}$ = 10 to 20 K; keep trim ΔT short to reduce electric intensity and morphology drift [9,22,33].

▪

Thermal uniformity: cap skin–bulk ΔT and axial ΔT; limit dT/dt at startup/shutdown; instrument surfaces densely [9,22,33].

▪

Carbon PSD: cyclone $D_{50}$ = 2 to 10 µm; filter face velocity = 1 to 3 cm s⁻¹; protect compressors/separators with polishing filters [33].

▪

Maintainability: Design sump/bed clear-out operations; provide filter swing and cycler logic; spec spare spargers/distributors for a quick changeover [14,15,16].

4. Techno-Economic Analysis (TEA)

4.1. Scope and Cases

The plant is designed for ~10 kt H₂ per year (≈1.25 t H₂ per hour at 8000 h·yr⁻¹) with EGS-assisted preheating and a site boundary spanning methane reception to hydrogen delivery and carbon storage. Major units include methane conditioning, preheaters, trim heaters, pyrolysis reactors, molten-media/salt inventory (if applicable), H₂ separation and compression, carbon handling (quench, cyclone, ceramic filters, and classifier), heat-exchanger trains, top-up heaters, and plant utilities. The TEA framework follows molten-media/fixed-bed studies [2,5,9,12] and standard process-economics practice, with a geothermal integration context.

Three heat-supply cases are evaluated:

  (i)

EGS + electric, with geothermal input providing a base-load preheat/isothermal hold and electricity covering the final ΔT and transients.

 (ii)

Solar–thermal + electric, where a solar field (with optional storage) provides preheat and electricity trims to the setpoint.

(iii)

Electric-only, where all of the duty comes from electric heaters.

The owner’s costs, land, and interconnection are treated as indirect, and the geothermal input may be owned (CAPEX) or purchased as thermal duty (OPEX). The hardware is otherwise identical across cases except for the heat-supply block [33].

4.2. Cost Structure

(i)

CAPEX (installed):

▪

The heat supply includes EGS wells with surface heat exchangers and tie-ins, or, alternatively, a purchased-heat interface. In the solar-assisted case, this also covers a solar collector field and thermal storage, while electric trim heaters and power distribution systems are required across all configurations [20,21,33].

▪

The core process consists of pyrolysis reactor trains, which may be configured as molten-media columns or packed/fixed beds, together with the melt or salt inventory (if applicable), spargers and distributors, refractory linings, and structural steel [4,9,14].

▪

The separation and compression system is provided by PSA or membrane units, hydrogen compressors and dryers, and the necessary product storage facilities [20,21,22].

▪

The carbon-handling system includes a sump or tempered quench, cyclones, porous-ceramic filters with swing or bypass options, classifiers, and product bins [12,16].

▪

The heat-exchange trains and balance of plant comprise feed/recycle exchangers, cooling water and air coolers, nitrogen and inerting systems, controls, analytics, and safety systems [20,21,22].

A cost estimation is performed using the Bare-Module, Lang-factor, or equipment-factor methods, with the EGS well and surface tie-in costs following established geothermal practice [34].

(ii)

OPEX (annual):

▪

The feed and energy costs include the methane make-up (net of recycle) and electricity for trim heating and auxiliaries, with solar operation and maintenance applying in Case B and EGS operation and maintenance or purchased-heat tariffs applying in Case A [21,30,31,32,33].

▪

Consumables consist of the catalyst or melt make-up, filtration media, inert gases, and water for quench or utility purposes.

▪

Fixed costs cover labor, maintenance, insurance, regulatory compliance, the disposal of off-spec carbon fines, and spare parts [20,21,22].

(iii)

Throughput-linked stoichiometry:

For the methane pyrolysis reaction,

$$C{H}_4\to C(s)+2H_2$$

(2)

The stoichiometry requires approximately 4 kg of CH₄ per 1 kg of H₂ at 100% overall conversion, with 3 kg of solid carbon formed for each kilogram of H₂. If ${\eta }_{ov}$ denotes the overall methane-to-hydrogen yield after recycling, the corresponding mass flow rates are expressed as follows:

$${\dot{\mathrm{m}}}_{{\mathrm{C}\mathrm{H}}_4}\approx {\displaystyle \frac{4\dot{{\mathrm{m}}_{{\mathrm{H}}_2}}}{{\mathsf{\eta }}_{\mathrm{o}\mathrm{v}}}}, \dot{{\mathrm{m}}_{\mathrm{C}}}\approx 3\dot{{\mathrm{m}}_{{\mathrm{H}}_2}} {\mathrm{f}}_{\mathrm{C}\mathrm{B}}$$

(3)

with ${\mathrm{f}}_{\mathrm{C}\mathrm{B}}$ as the saleable carbon-black fraction after classification.

(iv)

Heat and power:

The total energy duty per kilogram of H₂ consists of the reaction endotherm $\mathrm{\Delta }{H}_{rxn}(T)$ plus the sensible preheat of the feed/recycle streams (and melt hold if molten media are used). Geothermal energy (EGS) should be allocated to the high-$\dot{m}{c}_p$ preheat loads, while the residual trim duty $Q_{trim}$ defines the required electric input. The corresponding electric power demand is given by the following:

$$P_{trim}= Q_{trim}/{\eta }_{heater}\mathrm{\eta }$$

(4)

where ${\eta }_{heater}$ is the heater efficiency and $\eta$ is the overall electrical efficiency.

4.3. Revenue and Policy Levers

▪

H₂ product: The off-take price of hydrogen depends on the delivery pressure, product purity, and contract duration. The compression costs scale with the target pressure and the requirements of pipeline or storage specifications.

▪

Carbon co-product: This is the revenue from carbon increases when the product has a tighter particle size distribution (PSD) and low volatile or ash content. Specialty carbon black (CB) grades command a premium compared to commodity carbon. The overall revenue from carbon can be expressed as follows:

$${\mathrm{R}}_{carbon}={\sum }_j{p}_j{y}_i$$

(5)

with grade-specific price = $p_j$ and mass yield = $y_i$ [2,6,16].

▪

Carbon credits/policy: Additional revenue can be captured by stacking production credits or applying market-based carbon pricing where eligible. The sensitivity of the levelized cost of hydrogen (LCOH) to these incentives is particularly strong when the power carbon intensity (CI) is low and the carbon sale value is high [3,4,5]. Cases that integrate geothermal preheating reduce the electric demand, thereby improving both the cost competitiveness and CI exposure [9].

4.4. Calculation Framework

The levelized cost of hydrogen (LCOH) is defined as follows:

$$\mathrm{L}\mathrm{C}\mathrm{O}\mathrm{H}={\displaystyle \frac{\mathrm{C}\mathrm{R}\mathrm{F}.\mathrm{C}\mathrm{A}\mathrm{P}\mathrm{E}\mathrm{X}+\mathrm{O}\mathrm{P}\mathrm{E}\mathrm{X}-{\mathrm{R}}_{\mathrm{c}\mathrm{a}\mathrm{r}\mathrm{b}\mathrm{o}\mathrm{n}}-{\mathrm{R}}_{\mathrm{c}\mathrm{r}\mathrm{e}\mathrm{d}\mathrm{i}\mathrm{t}\mathrm{s}}}{\dot{{\mathrm{m}}_{{\mathrm{H}}_2}}}}$$

(6)

where $\dot{m_{H_2}}$ is the annual H₂ output (nameplate × capacity factor).

The capital recovery factor, which annualizes the capital costs, is calculated as follow [20,21,22]:

$$\mathrm{C}\mathrm{R}\mathrm{F}={\displaystyle \frac{\mathrm{i}{(1+\mathrm{i})}^{\mathrm{n}}}{{(1+\mathrm{i})}^{\mathrm{n}}-1}}$$

(7)

where i is the discount rate and “n” is the plant lifetime in years.

For projects with multiple CAPEX blocks (e.g., EGS, reactors, and separation units), the contributions may be summed up before applying to the CRF or annualized separately if the lifetimes differ.

The case-specific heat terms (duty split) are as follows:

▪

Case-A (EGS + electric): The geothermal duty $Q_{EGS}$ covers the preheat/isothermal hold, while the trim duty $Q_{trim}$ provide the final temperature rise and manages transients.

▪

Case-B (Solar–thermal + electric): Replace $Q_{EGS}$ with $Q_{solar}$; storage increases CAPEX but reduces the exposure to electricity.

▪

Case-C (Electric-only): Nearly all of the duty is covered by $Q_{trim}$ ≈ $Q_{total}$, leading to the highest electricity consumption but simpler CAPEX.

Operating Expenditure (OPEX):

The annual OPEX is expressed as follows:

$$\mathrm{O}\mathrm{P}\mathrm{E}\mathrm{X}={\mathrm{c}}_{{\mathrm{C}\mathrm{H}}_4}{\dot{\mathrm{m}}}_{{\mathrm{C}\mathrm{H}}_4}+{\mathrm{c}}_{\mathrm{e}}{\mathrm{E}}_{\mathrm{e}\mathrm{l}\mathrm{e}\mathrm{c}}+{\mathrm{c}}_{\mathrm{h}\mathrm{e}\mathrm{a}\mathrm{t}}{\mathrm{Q}}_{\mathrm{p}\mathrm{u}\mathrm{r}\mathrm{c}\mathrm{h}\mathrm{a}\mathrm{s}\mathrm{e}\mathrm{d}}+{\mathrm{O}\&\mathrm{M}}_{\mathrm{f}\mathrm{i}\mathrm{x}\mathrm{e}\mathrm{d}}+\mathrm{c}\mathrm{o}\mathrm{n}\mathrm{s}\mathrm{u}\mathrm{m}\mathrm{a}\mathrm{b}\mathrm{l}\mathrm{e}\mathrm{s}$$

(8)

with ${\mathrm{c}}_{{\mathrm{C}\mathrm{H}}_4}$(€/t) being the cost of methane feed, ${\mathrm{c}}_{\mathrm{e}}$(€/MWh_e) the cost of electricity, and $c_{heat}$(€/MWh_th) the cost of purchased heat. The electrical demand ${\mathrm{E}}_{\mathrm{e}\mathrm{l}\mathrm{e}\mathrm{c}}$ is given by the following:

$${\mathrm{E}}_{\mathrm{e}\mathrm{l}\mathrm{e}\mathrm{c}}={\displaystyle \frac{{\mathrm{Q}}_{\mathrm{t}\mathrm{r}\mathrm{i}\mathrm{m}}}{{\eta }_{heater}}}+{\mathrm{E}}_{\mathrm{a}\mathrm{u}\mathrm{x}}$$

(9)

where ${\eta }_{heater}$ is the heater efficiency and $E_{aux}$ represents the auxiliary loads.

The co-product treatment should be reported transparently to reflect both the technical performance and policy requirements. A revenue credit or co-allocation approach may be applied, where the carbon revenue rate (R_carbon) depends on the mass of saleable material after classification and its grade-specific pricing. Authors should document the grade split and the QA/QC metrics such as PSD, BET, and DBP values that support it [4,22,33]. The plant-level carbon intensity (CI) should be computed from the upstream methane supply, the CI of electricity, and any effects of exhaust-gas or solar integration, with credit for solid-carbon fixation where permitted by policy. Comparative analyses typically show that the lower trim-heat duty in the EGS + electric (Case-A) or solar–thermal + electric (Case-B) options results in a more favorable CI compared with the electric-only option (Case-C) [1,22].

4.5. Sensitivities and Expected Findings

Sensitivity set: The key parameters tested in the sensitivity analysis include the methane price, electricity price, carbon intensity (CI), EGS or solar capacity factor, carbon sale price and grade split, overall conversion, and discount rate. Prior techno-economic analysis (TEA) studies indicate that carbon revenue and electricity demand are the dominant levers, which align with the heat-split strategy that shifts the duty to the EGS or solar [2,9,22,33].

The typical qualitative outcomes are as follows:

▪

Case-A (EGS + electric): This configuration achieves the lowest LCOH when the EGS capacity factor is high and geothermal heat (purchased or owned) is cost-effective. It also provides strong resilience against electricity prices and CI fluctuations.

▪

Case-B (Solar–thermal + electric): This case improves the carbon intensity and reduces the electricity demand compared with the electric-only case. However, CAPEX increases due to the solar field and storage system, and the overall economics are highly dependent on the solar capacity factor and storage sizing.

▪

Case-C (Electric-only): This option features the simplest CAPEX but exhibits the highest variance in LCOH due to the electricity price and CI. It serves as a useful baseline for comparing hybrid options A and B.

The implementation checklist is as follows:

▪

Fix nameplate → annual H₂ via capacity factor → compute CH₄ → calculate C via stoichiometry and yields.

▪

Break CAPEX into blocks → apply CRF → add OPEX components.

▪

Calculate the geothermal/solar duty $Q_{EGS/solar}$ and trim duty $Q_{trim}$ from the heat-integration model (Figure 2) → convert $Q_{trim}$ to electricity.

▪

Add revenue streams from the H₂ off-take, carbon grade mix, and policy credits.

▪

Run scenarios for Case A, B, and C with the full sensitivity set, and then report the results as tornado diagrams for LCOH and identify the breakeven thresholds (e.g., carbon price versus electricity price).

5. Methods (What to Report So Reviewers Can Reproduce the Results)

5.1. Process Basis and Heat-Integration Data

Report the system boundary, operating mode, and full composite-curve inputs so an independent team can rebuild the heat match.

At minimum, the following data should be published:

▪

Basis and boundary: nameplate H₂$(t {yr}^{-1})$, capacity factor, overall yield after recycling, and site ambient conditions.

▪

EGS loop: Key geothermal parameters should include production temperature and flow rate, reinjection temperature, and variability in supply/return (expressed as ±σ or operating bands). If thermal storage is applied, the configuration must be described.

▪

Process cold streams: Identification of mass flow $\dot{m}$, mean ${\mathrm{c}}_p(\mathrm{T}) \mathrm{o}\mathrm{r} c_p(T)$ correlation, inlet/outlet temperature, and minimum allowable approach $\mathrm{\Delta }{T}_{min}$.

▪

Process hot streams (each): For each internal hot utility, provide stream identification along with mass flow rate $\dot{m}$, ${\mathrm{c}}_p(T)$, and inlet/outlet temperatures.

▪

Pinch reconstruction: Composite curves (temperature vs. cumulative heat duty) should be published for the EGS supply and the process demand. These curves must be annotated to show the pinch point and the residual trim-heat requirement relative to the target setpoint.

▪

Duty split: The reported duty split should include geothermal heat duty ${\mathrm{Q}}_{\mathrm{E}\mathrm{G}\mathrm{S}} \mathrm{i}\mathrm{n} {\mathrm{k}\mathrm{W}}_{th} \mathrm{a}\mathrm{n}\mathrm{d} {\mathrm{Q}}_{trim}$ with heater efficiency used, plus ramp/turn-down envelopes [21,26,34].

Calculation is as follows:

$$\mathrm{Q} ={\int }_{T in}^{T out}m cp\left(T\right)dT$$

(10)

This formulation should explicitly show how $\mathrm{\Delta }{T}_{min}$ was selected (e.g., 10 to 20 K), and the residual trim duty $Q_{trim}$ is converted into electric load according to the following:

$${\mathrm{P}}_{trim}={\mathrm{Q}}_{trim}/{\mathsf{\eta }}_{heater}$$

(11)

5.2. Reactor Details (Geometry, HP/HT Envelope, and Internals)

Provide enough hardware and operating details to permit a rate-based model and pressure-drop check.

All reactor configurations should be described using a consistent framework that covers type, flow scheme, geometry, operating points, throughput, and performance. Specify whether the system is a molten-media bubble column or a packed/fixed bed and whether it operates in a co- or counter-current manner. Include key geometric parameters such as internal and outer diameters, effective height or length, aspect ratio (L/D), number of parallel trains, nozzle sizes, and if applicable sparger patterns. Operating conditions should report pressure, reactor setpoint temperature, axial and radial temperature uniformity targets, and the residence-time definition (τ). Throughput data should cover fresh methane feed, recycle ratio, total superficial velocity, and both target and measured pressure drops.

For molten-media reactors, provide the alloy or salt identity and composition, total inventory, make-up and bleed rates, and liquidus/solidus temperatures, as well as hydrodynamic parameters such as sparger hole size and count, gas superficial velocity, bubble size estimate or fit, and any internal features used to enhance heat transfer [9,14,17].

Document materials and containment choices include alloy selection, double-wall or secondary containment, corrosion allowances, transient thermal-cycling design cases, and applicable code stamping [33].

For packed or fixed-bed systems, detail the catalyst formulation—active metals (Fe/Co/Ni), promoters or supports, pellet size and porosity, and total loading—along with distributor design, bed segmentation or grading, measures to maintain radial uniformity, and strategies for minimizing trim-heater residence time [1,4].

Kinetics and performance reporting should also be standardized by publishing conversion, hydrogen selectivity and yield, deactivation rate (e.g., % per 100 h), carbon production rate, and removal cadence, and presenting the data as X(T,P,τ) contours or time-on-stream plots for cross-comparison.

5.3. Carbon QA/QC (Methods That Tie to Economics)

Carbon quality assurance and quality control (QA/QC) must be documented with the exact analytical methods and sample handling procedures, as these directly determine the co-product’s market value.

At minimum, the following measures should be reported:

▪

Particle Size Distribution (PSD): Report ${\mathrm{D}}_{10}/{\mathrm{D}}_{50}/{\mathrm{D}}_{90}$ by laser diffraction, including details of dispersant, sonication power and time, and refractive index model.

▪

Surface Area: Measure by BET analysis, with reporting of degassing temperature/time and the model fit domain.

▪

Volatiles and Ash Content: Analyze by thermo-gravimetery or muffle furnace procedure, specifying temperatures and hold times; include residual metal content if relevant.

▪

Oil Absorption (DBP): Report DBP number or an alternative structure metric.

▪

Moisture and Surface Chemistry: If linked to pricing, measure elemental O/H ratios and functional groups using methods such as Boehm titration or XPS.

▪

Sample Handling: Specify oxygen exposure limits, quench temperature, and storage conditions, and link these explicitly to arguments for value preservation [2,6,16].

▪

Present a grade-mix table—mass fraction by grade vs. price used in TEA—and link each grade to the QA/QC thresholds [2,6,16].

5.4. TEA Inputs (So the Numbers Are Reproducible)

▪

Documentation Requirement: All parameters and models used for cost estimation and financial analysis must be documented clearly, with references to raw data sources or date-stamped indices, to ensure reproducibility.

▪

Equipment Costs and Scaling: Report the base equipment costs with year and source, the scaling exponents applied, and installation factors. Specify whether the Bare-Module or Lang method was used, following standard design texts [20,21,22].

▪

Indices and Currencies: Identify the cost index employed (e.g., CEPCI or equivalent), the base year, the reference currency, and the method of escalating to current values.

▪

WACC and Finance Assumptions: Provide the nominal and/or real weighted average cost of capital (WACC), the tax rate, and the depreciation method (e.g., MACRS or straight-line). State the assumed plant lifetime in years and the discount rate (i), and present the capital recovery factor (CRF) explicitly (see Figure 3).

▪

Input Costs and Operations: State the assumed methane price (with the range considered), electricity price and carbon intensity (CI), labor rates, maintenance factor, catalyst or melt makeup requirements, and either the EGS tariff or well operation and maintenance costs [5,20,21,22,33].

▪

Policy and Credit Assumptions: Report the values of production credits or the carbon price path used, along with eligibility assumptions and the chosen allocation method [3,4,5].

▪

Model Transparency: Upload the full calculation workbook with clearly labeled tabs (Assumptions, Heat Split, CAPEX, OPEX, Revenues, LCOH, and Sensitivity).

5.5. Data and Code Availability

Provide (i) composite-curve data (.csv), (ii) anonymized TEA workbook, (iii) reactor performance dataset (time-on-stream), and (iv) QA/QC raw outputs. If a site-specific EGS dataset is non-public, include a synthetic but structurally equivalent trace plus bounds so others can rerun [9,22,26].

6. Results and Discussion

Integrating enhanced geothermal system (EGS) heat with methane pyrolysis reduces the need for electrical top-up and lowers the exposure to power-price and carbon-intensity volatility. By assigning the baseload sensible duty to EGS and reserving electric heating for the final temperature rise (ΔT), the process achieves greater stability in reactor temperatures [1,2,27].

This stabilization mitigates coking and sintering while narrowing the carbon particle-size distribution, thereby protecting the downstream separation and compression equipment and preserving the carbon black value [14,15,16].

The approach also supports a dual-product business case for hydrogen and carbon black. Techno-economic analyses consistently show that carbon revenue and electrical demand are the dominant levers of cost and value, precisely the parameters improved by EGS heat splitting [5,33].

Furthermore, the concept scales effectively with high-pressure, high-temperature hardware, including molten-media columns or fixed/packed beds operating at 10 to 25 bar and 600 to 900 °C. Among catalyst families, Fe/Co-rich formulations are favored for their robustness, while Ni catalysts offer higher activity but demand careful temperature management to avoid hot spots and sintering [29,30].

7. Conclusions

Geothermal-assisted methane pyrolysis integrates a steady, low-carbon heat process with high-temperature catalytic conversion that benefits from isothermal stability. This study shows that allocating geothermal energy to the preheat and isothermal hold reduces the electric top-up requirements, stabilizes the reactor operation, and improves the carbon quality.

High-pressure reactor designs enhance hydrogen recovery and compactness but require careful materials and thermal-stress management.

On the systems side, a structured techno-economic framework demonstrates the importance of a dual-product value, with hydrogen costs strongly influenced by both the electricity intensity and carbon quality.

Together, these results define a practical pathway toward pilot-scale deployment. The priorities include coupling the EGS with compatible reactor catalyst systems, establishing carbon-handling trains that preserve the product value, and adopting transparent TEA practices to guide investment decisions. With these elements in place, geothermal-assisted methane pyrolysis emerges as a credible route to turquoise hydrogen, and is suitable for site-specific FEED.